malaysia - ump libraryumplibrary.ump.edu.my/images/manual/serial_report/bmi_malaysia_… · oil...

Q2 2014www.businessmonitor.com

MALAYSIAOIL & GAS REPORTINCLUDES 10-YEAR FORECASTS TO 2023

ISSN 1748-4103Published by:Business Monitor International

Malaysia Oil & Gas Report Q22014INCLUDES 10-YEAR FORECASTS TO 2023

Part of BMI’s Industry Report & Forecasts Series

Published by: Business Monitor International

Copy deadline: January 2014

Business Monitor InternationalSenator House85 Queen Victoria StreetLondonEC4V 4ABUnited KingdomTel: +44 (0) 20 7248 0468Fax: +44 (0) 20 7248 0467Email: [email protected]: http://www.businessmonitor.com

© 2014 Business Monitor InternationalAll rights reserved.

All information contained in this publication iscopyrighted in the name of Business MonitorInternational, and as such no part of thispublication may be reproduced, repackaged,redistributed, resold in whole or in any part, or usedin any form or by any means graphic, electronic ormechanical, including photocopying, recording,taping, or by information storage or retrieval, or byany other means, without the express written consentof the publisher.

DISCLAIMERAll information contained in this publication has been researched and compiled from sources believed to be accurate and reliable at the time ofpublishing. However, in view of the natural scope for human and/or mechanical error, either at source or during production, Business MonitorInternational accepts no liability whatsoever for any loss or damage resulting from errors, inaccuracies or omissions affecting any part of thepublication. All information is provided without warranty, and Business Monitor International makes no representation of warranty of any kind asto the accuracy or completeness of any information hereto contained.

CONTENTS

BMI Industry View ............................................................................................................... 7

SWOT .................................................................................................................................... 9

Industry Forecast .............................................................................................................. 10Oil & Gas Reserves ................................................................................................................................ 10

Table: Malaysia Proven Oil & Gas Reserves And Total Petroleum Data, 2012-2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Table: Malaysia Proven Oil & Gas Reserves and Total Petroleum Data, 2018-2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Table: Blocks Offered In The Petronas Licensing Round 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Oil Supply And Demand .......................................................................................................................... 18Table: Malaysia Oil Production & Net Exports - Historical And Forecast Data, 2012-2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

Table: Malaysia Oil Production & Net Exports - Long-term Forecasts, 2018-2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

Gas Supply And Demand ......................................................................................................................... 23Table: Malaysia Gas Production, Consumption & Net Exports, 2012-2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Table: Malaysia Gas Production, Consumption & Net Exports, 2018-2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Refining And Oil Products Trade .............................................................................................................. 29Table: Malaysia Refining - Production & Consumption, 2012-2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

Table: Malaysia Refining - Production and Consumption, 2018-2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Revenues/Imports Costs ........................................................................................................................... 32

Key Risks To BMI's Forecast Scenario ....................................................................................................... 32

Industry Risk Reward Ratings .......................................................................................... 34Asia - Risk/Reward Ratings ....................................................................................................................... 34

Table: Asia's Oil & Gas Risk/Rewards Ratings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

The Upstream Leaders ............................................................................................................................ 35

Resource-Rich Countries Hit By State Involvement ....................................................................................... 37Table: Asia Upstream Sector Risk/Reward Ratings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Downstream Support .............................................................................................................................. 39Table: Asia O&G Downstream Risk/Reward Ratings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Malaysia - Risk/Reward Ratings ................................................................................................................. 44

Malaysia Upstream Rating - Overview ....................................................................................................... 44

Malaysia Upstream Rating - Rewards ........................................................................................................ 44

Malaysia Upstream Rating - Risks ............................................................................................................. 44

Malaysia Downstream Rating - Overview ................................................................................................... 44

Market Overview ............................................................................................................... 45Malaysia Energy Market Overview ............................................................................................................. 45

Overview/State Role ............................................................................................................................... 46

Licensing And Regulation ........................................................................................................................ 46

Government Policy ................................................................................................................................. 46

International Energy Relations ................................................................................................................. 48Table: Key Upstream Players . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Malaysia Oil & Gas Report Q2 2014

© Business Monitor International

Table: Key Downstream Players . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Oil And Gas Infrastructure ........................................................................................................................ 49

Oil Refineries ........................................................................................................................................ 49Table: Refineries In Malaysia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

Oil Storage Facilities .............................................................................................................................. 55Table: Oil Storage Facilities In Malaysia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

Oil Terminals/Ports ................................................................................................................................ 57

Oil Pipelines ......................................................................................................................................... 58

LNG Liquefaction Terminals .................................................................................................................... 59Table: Malaysia LNG Liquefaction Terminals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

LNG Import Terminals ............................................................................................................................ 61Table: Malaysia LNG Regasification Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

Gas Pipelines ........................................................................................................................................ 61

Competitive Landscape .................................................................................................... 63Competitive Landscape Summary .............................................................................................................. 63

Table: Key Players - Malaysian Energy Sector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

Company Profile ................................................................................................................ 65Petronas ................................................................................................................................................ 65

ExxonMobil ............................................................................................................................................ 74

Shell ...................................................................................................................................................... 77

ConocoPhillips ....................................................................................................................................... 82

Murphy Oil ............................................................................................................................................. 86

Other Summaries ..................................................................................................................................... 90

Regional Overview ............................................................................................................ 94Asia Overview ......................................................................................................................................... 94

Gas Is Hot ............................................................................................................................................ 94

Locking Eyes On Gas Production .............................................................................................................. 97

Australia's LNG Roadblocks Open Up New Opportunities Elsewhere ............................................................... 98

Asia Fights Against LNG Prices .............................................................................................................. 100

Seeking An Unconventional Rescue ......................................................................................................... 103

Coalbed Methane: Underrated Potential .................................................................................................. 106

Refining Woes ..................................................................................................................................... 106

Global Industry Overview ................................................................................................ 110

Appendix .......................................................................................................................... 117Asia - Regional Appendix ........................................................................................................................ 117

Table: Oil Consumption - Historical Data & Forecasts, 2011-2018 ('000b/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117

Table: Oil Consumption - Long-Term Forecasts, 2015-2022 ('000b/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118

Table: Oil Production - Historical Data & Forecasts, 2011-2018 ('000b/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118

Table: Oil Production - Long-Term Forecasts, 2015-2022 ('000b/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 119

Table: Refining Capacity - Historical Data & Forecasts, 2011-2018 ('000b/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120

Table: Refining Capacity - Long-Term Forecasts, 2015-2022 ('000b/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120

Table: Gas Production - Historical Data & Forecasts, 2011-2018 (bcm) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121



Table: Gas Production - Long-Term Forecasts, 2015-2022 (bcm) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122

Table: Gas Consumption - Historical Data & Forecasts, 2011-2018 (bcm) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123

Table: Gas Consumption - Long-Term Forecasts, 2015-2022 (bcm) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123

Table: LNG Exports - Historical Data & Forecasts, 2011-2018 (bcm) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124

Table: Net LNG Exports - Long-Term Forecasts, 2015-2022 (bcm) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125

Glossary ........................................................................................................................... 126Table: Glossary Of Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126

Methodology .................................................................................................................... 128Industry Forecast Methodology .............................................................................................................. 128

Source ............................................................................................................................................... 130

Risk/Reward Ratings Methodology .......................................................................................................... 130Table: Bmi's Oil & Gas Upstream Risk/Reward Ratings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132

Table: Weighting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 134



BMI Industry View

BMI View: Malaysia's upstream segment could see good days ahead in the short-to-medium term as the

completion of both greenfield and brownfield developments brings new volumes of oil and gas online. New

gas supplies will underpin continued expansion in the country's liquefied natural gas production based in

Sarawak. Consumption growth will limit some of the export gains to be made from growing output, though

a reduction of oil and gas subsidies would see a slowdown in the rate of this. The expansion of its

downstream capacity could be more challenging, as it would face fierce competition from neighbouring

Singapore.

The main trends and developments we highlight for Malaysia's oil and gas sector are:

■ Our expectations for growth in its oil and gas reserves are underpinned by resource upgrades stemmingfrom exploration and development activities in three areas: deepwater, marginal and stranded fields, andenhanced oil recovery (EOR) projects in mature fields.

■ Oil and gas production are set to grow, thanks to the development of large discoveries made in recentyears. For oil in particular, investment into marginal fields could support a short-term increase inproduction until larger and more complex deepwater projects come on-stream.

■ Based on projects in pipeline, we expect oil production to continue climbing upwards from an estimated625,140b/d in 2013 to a forecasted peak of 899,560b/d in 2018. However, the small scale of these fieldsmeans that their development can only sustain the country's output for a limited time. However, with thelack of large discoveries able to replace dwindling reserves from mature fields, we do not expectMalaysian oil production to reach the 1mn b/d level, with production levels starting to fall post-2018unless high and continuous development of new projects brings significant new fields online and sustainsthe country's increasing production. Over the longer term, deepwater and greenfield developments willtherefore remain necessary to maintaining oil production growth past its current expected peak in 2018.

■ A string of prolific discoveries and major projects set to come online between 2014 and 2018 would seegas production continue on an upward trend. Nearly all of these new projects are off the coast ofSarawak, East Malaysia, which will in turn support liquefied natural gas (LNG) production growth atPetronas' LNG complex.

■ We are expecting the uptrend in gas production to continue in the short-to-medium term. From anestimate of 63.6bcm in 2013, we project output to hit 75.9bcm in 2018 and continue to climb to 79.7bcmby 2020. Although we currently forecast for a slight fall from 2021 based solely on projects in thepipeline, we highlight that there is significant upside risk to the tail-end of our forecasts to 2023. Thesecome from recent discoveries made that could see a FID within 2014 to 2016. We will revise theseforecasts once more light is given on development plans for announced discoveries.

■ Consumption of both oil and gas is set to rise in the short term as demand grows in tandem to economicexpansion and facilitated by a generous subsidy regime. However, we expect growth to slow onexpectations that subsidies will be gradually reduced over time owing to fiscal necessity, therebycorrecting some of the excesses in domestic oil and gas consumption. In Q413, the government alreadycut fuel subsidies for the first time in more than two years, as part of its wider efforts at reducing itsbudget deficit. The subsidy on petrol and diesel were cut by 20 sen (6 cents) a litre each, to 63 sen a litreand 80 sen a litre respectively.



■ We expect Malaysia to remain a net oil and gas exporter throughout our forecast period. We haveupgraded our forecast for Malaysia's refining outlook, following the inclusion of Petronas' RAPIDrefinery in our forecasts from 2019. This will bring the country's total refining capacity from 564,213b/din 2013 to 864,213b/d by 2022. We do note that downside risk to this forecast could come from a furtherdelay to the RAPID project, which was originally slated to come online in 2017.

■ A more cautious view is taken on further expansion of its downstream capacity, stemming from concernsthat investment could disappoint as a result of fierce competition from Singapore.



SWOT

SWOT Analysis

Strengths ■ Malaysia is one of the world's largest producers of LNG.

■ Its oil reserves are of very high quality - light and sweet - and its benchmark Tapis

crude is one of the most expensive in the world.

Weaknesses ■ Domination of national oil company Petronas in the country's upstream and

downstream. It is the only remaining wholly state-owned enterprise in Malaysia and is

the single largest contributor of government revenues.

■ Many of its producing fields are mature and set for decline.

Opportunities ■ Deepwater potential is underexplored.

■ Marginal fields could hold undiscovered potential as technology progresses.

■ Enhanced oil recovery (EOR) opportunities for its mature fields.

Threats ■ Without curtailing oil and gas subsidies, consumption growth could eat into export

revenues.

■ Developing Pengerang as a regional oil and gas hub could face fierce competition

from Singapore.



Industry Forecast

Oil & Gas Reserves

Table: Malaysia Proven Oil & Gas Reserves And Total Petroleum Data, 2012-2017

2012 2013e 2014f 2015f 2016f 2017f

Proven Oil Reserves bblbn 4.0 4.0 4.0 4.1 4.1 4.1

Proven Oil Reserves bbl mn 4,000.0 4,000.0 4,026.2 4,069.1 4,121.8 4,142.7

Proven Oil Reserves %change y-o-y 0.0 0.0 0.7 1.1 1.3 0.5

Reserves to production ratio(RPR), years 6.2 6.2 5.5 5.3 5.1 4.6

Natural Gas ProvenReserves, tcm 2.4 2.4 2.4 2.4 2.4 2.4

Natural Gas ProvenReserves, bcm 2,350.3 2,350.3 2,365.4 2,378.6 2,368.8 2,355.8

Natural Gas ProvenReserves, % change y-o-y 0.0 0.0 0.6 0.6 -0.4 -0.5

Natural Gas Reserve toProduction Ratio, years 37.7 37.0 36.5 35.6 33.9 32.3

Hydrocarbons Production,Consumption and NetExports

Total HydrocarbonsProduction, 000boe/d 1,717.1 1,741.5 1,851.3 1,923.3 2,005.3 2,149.2

Total HydrocarbonsProduction, 000boe/d, %change y-o-y 1.6 1.4 6.3 3.9 4.3 7.2

Total HydrocarbonsProduction, US$bn 61.2 59.7 61.9 63.3 65.0 68.3

Total HydrocarbonsProduction, US$, % changey-o-y 3.5 -2.5 3.7 2.3 2.6 5.2

Total HydrocarbonsConsumption, 000boe/d 1,136.2 1,172.7 1,210.7 1,248.9 1,289.0 1,327.3

Total HydrocarbonsConsumption, 000boe/d, %change y-o-y 0.9 3.2 3.2 3.2 3.2 3.0

Total HydrocarbonsConsumption, US$bn 46.1 45.5 45.9 46.7 47.5 47.9

Total HydrocarbonsConsumption, US$, %change y-o-y 2.8 -1.4 1.0 1.8 1.6 0.9



Malaysia Proven Oil & Gas Reserves And Total Petroleum Data, 2012-2017 - Continued

2012 2013e 2014f 2015f 2016f 2017f

Total Net HydrocarbonsExports, 000boe/d 580.9 568.8 640.6 674.4 716.4 821.9

Total Net HydrocarbonsExports, 000boe/d, changey-o-y 3.0 -2.1 12.6 5.3 6.2 14.7

Total Net HydrocarbonsExports, US$bn 17.6 16.6 18.5 19.1 20.1 23.0

Total Net HydrocarbonsExports, US$, % change y-o-y 5.5 -5.7 11.1 3.6 5.1 14.7

Total Net HydrocarbonsExports, US$mn at US$50/bbl, US$bn 8.1 7.9 9.1 9.6 10.2 11.9

Total Net HydrocarbonsExports, US$mn at US$100/bbl, US$bn 16.1 15.7 18.2 19.2 20.4 23.8

e/f = BMI estimate/forecast. Source: BMI, EIA



Table: Malaysia Proven Oil & Gas Reserves and Total Petroleum Data, 2018-2023

2018f 2019f 2020f 2021f 2022f 2023f

Proven Oil Reserves bbl bn 4.2 4.2 4.2 4.2 4.1 4.0

Proven Oil Reserves bbl mn 4,152.8 4,168.3 4,190.7 4,171.3 4,110.1 4,006.7

Proven Oil Reserves % change y-o-y 0.2 0.4 0.5 -0.5 -1.5 -2.5

Reserves to production ratio (RPR), years 4.5 4.6 4.6 4.8 4.8 4.8

Natural Gas Proven Reserves, tcm 2.3 2.3 2.2 2.1 2.1 2.0

Natural Gas Proven Reserves, bcm 2,310.0 2,251.4 2,191.7 2,133.4 2,077.0 2,022.5

Natural Gas Proven Reserves, % change y-o-y -1.9 -2.5 -2.7 -2.7 -2.6 -2.6

Natural Gas Reserve to Production Ratio, years 30.4 28.7 27.5 27.2 27.2 27.2

Hydrocarbons Production, Consumption and NetExports

Total Hydrocarbons Production, 000boe/d 2,230.9 2,268.6 2,275.1 2,227.5 2,170.7 2,115.4

Total Hydrocarbons Production, 000boe/d, %change y-o-y 3.8 1.7 0.3 -2.1 -2.6 -2.5

Total Hydrocarbons Production, US$bn 69.4 70.5 71.1 69.5 67.8 32.9

Total Hydrocarbons Production, US$, % change y-o-y 1.6 1.6 0.7 -2.1 -2.6 -51.4

Total Hydrocarbons Consumption, 000boe/d 1,366.7 1,407.4 1,439.4 1,472.2 1,505.3 1,538.5

Total Hydrocarbons Consumption, 000boe/d, %change y-o-y 3.0 3.0 2.3 2.3 2.2 2.2

Total Hydrocarbons Consumption, US$bn 47.8 49.3 50.5 51.8 50.2 35.6

Total Hydrocarbons Consumption, US$, % changey-o-y -0.1 3.1 2.5 2.5 -3.2 -29.0

Total Net Hydrocarbons Exports, 000boe/d 864.2 861.2 835.7 755.3 665.4 576.9

Total Net Hydrocarbons Exports, 000boe/d, changey-o-y 5.1 -0.4 -3.0 -9.6 -11.9 -13.3

Total Net Hydrocarbons Exports, US$bn 24.1 23.9 23.3 20.5 17.6 0.3

Total Net Hydrocarbons Exports, US$, % change y-o-y 4.7 -1.0 -2.6 -11.6 -14.4 -98.1

Total Net Hydrocarbons Exports, US$mn at US$50/bbl, US$bn 12.6 12.5 12.1 10.7 9.2 na

Total Net Hydrocarbons Exports, US$mn at US$100/bbl, US$bn 25.3 24.9 24.2 21.4 18.3 na

na = not available; f = BMI forecast. Source: BMI, EIA



In early 2014, the US Energy Information Administration (EIA) reports that Malaysia has 4.0bn barrels

(bbl) of proven oil reserves, unchanged from 2012 and 2013. Proven gas reserves in early 2014 stand at

2.35trn cubic metres (tcm), unchanged from 2013.

We believe that actual reserves could be more than the EIA's estimate. National oil company (NOC)

Petronas, which has a stake in all oil and gas fields in Malaysia, reported a 172mn boe increase in proven

and probable (2P) reserves for FY2012, thanks to reserves proved up from both brownfield and greenfield

projects. Assuming that with Petronas taking an average 20% stake in Malaysian fields, total 2P reserves

growth in 2012 could be approximately 860mn boe. At a recovery rate of 50%, total proven reserves in

2012 could have risen by 430mn boe in total.

These reserves are mainly located offshore and broadly in three basins: the Malay basin in Peninsular

Malaysia - consisting of some of Malaysia's most prolific oilfields such as Tapis - and the Sarawak and

Sabah basins in East Malaysia. Most of the country's oil reserves are located in the Malay Basin and have

been noted for their light and sweet quality. Gas fields however are largely concentrated offshore Sarawak,

and provide the feedstock for Petronas' liquefied natural gas (LNG) liquefaction plant in Bintulu.

Over recent years, strong economic growth has seen oil and gas consumption in Malaysia rise dramatically,

necessitating a drive to uncover new sources of production in order to preserve lucrative export volumes.

The issue is made more pressing as production from many fields is declining ad Malaysian oil fields are

becoming mature after more than three decades of production. Several high-profile discoveries and

developments promise to support the country's oil and gas reserves. These discoveries and reserves

upgrades have come from three major sources: newly opened deepwater fields, marginal and stranded fields

previously though commercially unfeasible and which have only been recently re-looked, and from

enhanced oil recovery (EOR) and improved oil recovery (IOR) developments.

The varied sources of new additions to reserves bode well for Malaysia's oil and gas reserves outlook:

1 - Deepwater

Malaysia's deepwater acreage remains relatively underexplored. However, with declining production in

conventional shallow water fields and increasingly available deepwater technology, development of

deepwater fields is increasingly possible for companies. At present, only 3bn boe have been proven and

another 7bn boe could be waiting to be discovered, according to a report by Malaysia's Business Times.

French oilfield services giant Technip's decision to establish a plant producing high-tech flexible pipes and



umbilicals catering to deepwater development needs is an indication of optimism of the country's deepwater

potential.

2 - Marginal and stranded fields

Technological improvements, rising demand for gas and high oil prices are making marginal fields

previously thought commercially unfeasible, attractive for development. As a result, the re-exploration of

marginal and stranded fields has seen firms upgrade their resource estimates. New commercial reserves

from marginal and stranded fields - defined as fields with 30mn boe or less of resources - can be quickly

developed and could help the country keep the balance between reserve depletion and new additions.

According to Petronas, the country has about 106 marginal fields that together could hold about 580mn bbl

of oil. If proven, this would represent about 14.5% of the country's current proven oil reserves. The NOC

stated oil prices of US$55-60/bbl as the minimum breakeven cost needed for these fields to be commercial,

which looks likely given our forecast for oil prices to hover between US$104.8/bbl in 2014 and US$101.0/

bbl until 2016.US$101.5/bbl in 2014 and US$96/bbl until 2016. While the small scale of these fields means

that their resources can only sustain Malaysia's reserves for a limited time before they are depleted, they

could help maintain the country's production capacity till larger deepwater reserves - whose commerciality

will take a longer period to be determined - are proven.

The company's executive vice-president, Wee Yiaw Hin told Bernama news agency in January 2014 that

the company had identified between 25 and 27 of these fields for development by risk sharing contracts

(RSCs). Petronas has awarded four RSCs so far, for the Kapal, Banang & Merantai (KBM) Cluster, the

Berantai field and the Balai cluster.

For instance, Australia's Roc Oil and local firm Dialog Group have continuously hit oil pay at fields that

fall within the Balai Cluster RSC. The Berantai field also achieved an increase in estimated recoverable gas

resources of 15% in 2012 compared to 2011, as a result of development efforts. The most significant

discovery from a supposed 'marginal' field is Petrofac's oil find at the Cendor field. Once thought to only

hold 12mn bbl of recoverable oil, Petrofac announced in May 2013 that it has hit oil and gas-bearing

reservoirs that led it to raise recoverable estimates to about 200mn bbl, transforming a field deemed

marginal into one of the biggest oilfields in Malaysia.



3 - Enhanced oil recovery (EOR)/improved oil recovery (IOR)

Various studies estimate that the average oil recovery factor of producing fields in Malaysia to be between

33% and 37% of original oil in place. The wide-scale application of EOR could increase this by more than

5-10%.

In a September interview, Petronas' Vice President for Petroleum Management Unit, Ramlan Malek, said

that the company has identified 14 oilfields where EOR technology can be implemented in the coming

years. Five of the fields lie offshore Sabah and Sarawak, such as Baram and St Joseph. The others are

located offshore Peninsular Malaysia, such as Tapis and Dulang. Petronas' E&P Technology head of EOR

Dr. Nasir Darman said that it expected production from the 14 oil fields identified under the EOR initiative

to reach between 750mn and 1bn barrels of oil for the duration of the fields' economic producing lives, as

reported by local newspaper The Star. The company's executive vice-president, Wee Yiaw Hin told

Bernama news agency in January 2014 that about half of the country's producing fields have EOR potential.

About 10 EOR projects are currently in the pipeline, with programmes to be rolled out over the next 10

years. However, these projects are technically challenging and expensive. He estimated that total investment

of US$14bn would be required to execute them. Innovations are therefore required to lower overall costs,

improve the performance of existing technology and include the development of new technology, he said.

ExxonMobil has invested a minimum of US$2.1bn on EOR at seven mature fields that together make up

Malaysia's Tapis crude blend since 2009, which is to help recover an additional 5-10% of oil from the

fields. The Tapis oil field is the first in Malaysia to employ EOR technology and is scheduled to commence

operations in mid-2014, increasing production to between 25,000b/d and 35,000b/d by 2016-2017, from

current levels of about 4,000b/d.

Other EOR projects being carried out include one by Royal Dutch Shell for the Baram Delta gas project off

the coast of Sabah and Sarawak, which is expected to increase recovery rates from 36% to up to 50%,

making another 14% of resources commercial. Another example is an EOR project announced in October

2013, when Baker Hughes entered into a long-term Oilfield Service Agreement with Petronas to enhance

the recoverable reserves and production of hydrocarbons in the Greater D18 field offshore Malaysia,

providing further upside risk to reserves.

Petronas' rationalisation of its operations to focus more technically challenging E&P - most likely in

reference to deepwater activities - to its upstream subsidiary Petronas Carigali and to allow newly-created

Vestigo Petroleum to oversee marginal field developments is also a promising development. The

specialisation of E&P would allow the company to cover more of the country's hydrocarbon resources.



We have revised our oil reserves forecasts, based on projections that EOR efforts and greater focus on

revisiting marginal and stranded fields in particular will raise Malaysia's proven oil reserves level in the

short term. Notable oil discoveries that will likely add to the country's reserves include:

■ Petrofac's Cendor oil field;

■ Lundin Petroleum's Bertam oil field offshore Pahang, Peninsular Malaysia, which would add at least64mn bbl of oil;

■ Petronas' Wakid-1 oil discovery offshore Sabah in November 2011, which has preliminary estimates of227mn boe.

These underpin our view for oil reserves to grow from the EIA's estimate of 4.00bn bbl at the start of 2013

to 4.15bnbbl by 2018, though faster production growth than reserves addition could see reserves fall again

towards the tail end of our 10-year forecast period to 2022.

Major gas discoveries have led us to adjust our forecasts for Malaysia's gas reserves upward. Significant gas

finds in the past two years include:

■ February 2012: Gas was found in the Kasawari and NC8SW fields in Block SK-316 offshore Sarawak.Total recoverable gas resources could amount to 96.6bn cubic metres (bcm).

■ November 2012: Petronas announced two major gas discoveries offshore Sarawak in the Kuang Northand Tukau Timur fields, which together are estimated to hold about 112bcm in gas resources. Ofparticular note is the nature of the discovery at Kuang North, where gas was found in the older carbonatesection - suggesting more gas could be uncovered in the older carbonate reservoirs offshore Sarawak. TheKuang North field is estimated to hold about 64bcm in gas resources.

■ November 2012: Lundin Petroleum also discovered 30m of net gas pay at the Tembakau-1 well, in blockPM307.

■ April 2013: US independent Newfield Exploration found about 42-84bcm of gas-in-place in the B-14prospect in licence block SK-310, which Petronas has a 30% interest in. This adds to the 7.42bcm ofrecoverable resources that Newfield had earlier discovered in the nearby B-15 prospect.

■ October 2013 and January 2014: Mubadala Petroleum reported new a discovery in October offshoreSarawak via the Pegaga-1 well in Block SK320, adjacent to Shell's Block 2B. The well encountered a237m gas column. In January 2014, the company made another gas discovery through its Sintok-1 welldrilled in the same block, encountering a 292m gas column. This was the third gas find on the block,adding to the existing M5 discovery. Additional drilling is planned to appraise the extent of thesediscoveries.

Upside could also come from ongoing exploration activities. For example, GDF Suez, Petronas and JX

Nippon Oil&Gas Exploration are carrying out a three-year deepwater exploration campaign in Block 2F and

Block 3F offshore Sarawak, including the drilling of an exploration well in each block. In case of any gas

discovery, gas will be marketed either via the existing Bintulu liquefied natural gas (LNG) plant or through



a floating LNG operation. Petronas also recently awarded the Deepwater Block 3E PSC to ConocoPhillips,

with the commitment to drill three wells and reprocess 3D and 2D seismic data.

However, Petronas' ambition to raise LNG production, aided by the addition of new liquefaction capacity

from 2016, could see depletion take place at a faster rate than additions to reserves. We expect gas reserves

to decrease from 2.35bcm in 2013 to 2.32bcm in 2017. Gas reserves can be expected to fall further to

2.03bcm in 2022, though we note that large discoveries could pose upside risk to our forecast. Any upward

revision by the EIA to past estimates will see a corresponding increase in these forecasts.

We also note that additional long-term upside could also come from the upcoming Petronas Licensing

Round 2014. The round offers a total of 11 onshore and offshore blocks, of which three will be deepwater

exploration blocks in Sabah and Sarawak, providing upside risk to gas reserves. Blocks offered in Peninsula

Malaysia also offer upside risk to oil reserves.

Table: Blocks Offered In The Petronas Licensing Round 2014

Block Name Area Acreage (sq km) Type Of Contract

PM-327 Peninsula Malaysia 3990 R/C PSC

PM-331 Peninsula Malaysia 1289.93 R/C PSC



DW-T Sabah 1537 Deep Water PSC

DW-V Sabah 2895 Deep Water PSC

SB-306 Sabah 9058 R/C PSC

DW-2D Sarawak 4674 Deep Water PSC

SK-317A Sarawak 1306 R/C PSC

SK-332 Sarawak 6357 Onshore PSC

SK-335 Sarawak 2996 Onshore PSC

Source: Deloitte



Oil Supply And Demand

Table: Malaysia Oil Production & Net Exports - Historical And Forecast Data, 2012-2017

2012 2013e 2014f 2015f 2016f 2017f

Crude Oil, NGPL, and Other Liquids Production, 000b/d 622.2 625.1 712.3 750.1 779.8 868.8

Crude Oil, NGPL, and Other Liquid Production, % change y-o-y 2.8 0.5 14.0 5.3 3.9 11.4

Crude and Other Liquids Production, mn bbl/year 227.1 228.2 260.0 273.8 284.6 317.1

Crude and Other Liquids Production, US$bn 24.9 24.2 26.5 27.4 28.2 30.8

Crude and Other Liquids Production, US$bn % change y-o-y 4.6 -2.8 9.5 3.5 2.9 9.2

Crude and Other Liquids Production, US$bn at US$50/bbl 11.4 11.4 13.0 13.7 14.2 15.9



Crude and Other Liquids Net Exports, 000b/d 40.7 40.3 124.4 158.8 185.6 271.2

Crude and Other Liquids Net Exports, % change y-o-y 38.5 -1.0 208.6 27.6 16.9 46.1

Crude and Other Liquids Net Exports, US$bn 1.6 1.6 4.6 5.8 6.7 9.6

Crude and Other Liquids Net Exports, US$bn % change y-o-y 41.0 -4.3 196.6 25.4 15.7 43.1

Crude and Other Liquids Net Exports, US$bn at US$50/bbl 0.7 0.7 2.3 2.9 3.4 4.9




Table: Malaysia Oil Production & Net Exports - Long-term Forecasts, 2018-2023

2018f 2019f 2020f 2021f 2022f 2023f

Crude Oil, NGPL, and Other Liquids Production, 000b/d 899.6 886.7 865.8 840.8 816.7 793.2

Crude Oil, NGPL, and Other Liquid Production, % change y-o-y 3.5 -1.4 -2.4 -2.9 -2.9 -2.9

Crude and Other Liquids Production, mn bbl/year 328.3 323.6 316.0 306.9 298.1 289.5

Crude and Other Liquids Production, US$bn 31.5 31.1 30.3 29.5 28.6 0.0

Crude and Other Liquids Production, US$bn % change y-o-y 2.5 -1.4 -2.4 -2.9 -2.9 -100.0




Crude and Other Liquids Net Exports, 000b/d 298.5 203.6 24.6 -4.7 -33.4 -61.4

Crude and Other Liquids Net Exports, % change y-o-y 10.1 -31.8 -87.9 -119.3 604.1 83.8

Crude and Other Liquids Net Exports, US$bn 10.5 7.1 0.9 -0.2 -1.2 0.0



Malaysia Oil Production & Net Exports - Long-term Forecasts, 2018-2023 - Continued

2018f 2019f 2020f 2021f 2022f 2023f

Crude and Other Liquids Net Exports, US$bn % change y-o-y 8.9 -31.8 -87.9 -119.3 604.1 -100.0

Crude and Other Liquids Net Exports, US$bn at US$50/bbl 5.4 3.7 0.4 -0.1 -0.6 -1.1



f = BMI forecast. Source: BMI, EIA

Malaysia

Oil Production, Consumption And Imports 2000-2023


Malaysia managed to reverse its decline in oil production in 2012 to see a 2.7% year-on-year (y-o-y)

increase in total oil production to 642,660 barrels per day (b/d). We estimate that total oil production in

2013 stagnated at a level of 645,630b/d. Nonetheless, this is still considerably below its 2004 peak

production of 861,810b/d in 2004. This is mainly a result of the natural depletion of reserves of its major oil

fields, particularly of the larger fields in the waters offshore Peninsular Malaysia, while the country lacked

discoveries to replace them. Most Malaysian oilfields have an average age of around 19-30 years old.



However, the move towards deepwater, EOR and the turn to commercialise its marginal and stranded fields

will help Malaysia's oil production to durably turn around in the coming decade. Indeed, the reversal in a

downward trend in Malaysian oil production has been helped by the start-up of the deepwater Gumusat-

Kakap field. The planned EOR projects, the development of deepwater fields and once-deemed marginal

fields will help lift Malaysian oil production within our 10-year forecast period from 2013 to 2022. Major

projects contributing to this outlook fall into three categories: EOR projects, new developments, marginal

field development.

EOR projects:

■ Tapis EOR project: ExxonMobil's and Petronas' EOR work is expected to lift total output at the Tapis oilfield in the Malay basin by up to 35,000b/d, from current production of about 3,000 to 4,000b/d.Development is underway, and Petronas and ExxonMobil confirmed in September 2013 that EOR at theTapis EOR project will start-up in mid-2014, with production peaking by 2016-2017. The Tapis fieldEOR should help sustain production of the declining Tapis blend crude, whose current production,according to a Platts report could stand at about 150,000b/d at the moment.

■ Baram Delta project: Shell's EOR project for the cluster of fields in the Baram Delta, East Malaysia, hasbeen estimated to increase oil output by 90,000-100,000b/d when completed in 2016. The lower range ofthis estimate could be reached by 2019. Shell stated that this project would extend the life of these fieldsup to 2040.

Upside risk exists from other EOR projects:

■ ExxonMobil and Petronas: The Tapis field is only one of the seven mature fields offshore Malaysiawhich compose the Tapis blend crude, and that ExxonMobil and Petronas have agreed to develop as partof a 25-year PSC that was finalised in June 2010: the Seligi, Guntong, Semangkok, Irong Barat, Tebu,and Palas. In the long-term, the two companies expect to recover an additional 5-10% of resources fromthe seven fields.

■ Shell and Petronas: In 2011, Shell and Petronas agreed to invest US$12bn over 30 years in EOR projectscovering nine fields such as the Baram field and the North Sabah field offshore Sarawak and Sabah. Theprogramme is expected to boost reserves by as much as 750mn bbl, while making another 14% ofresources commercial, extending the life of the fields until after 2014. The projects will see the use of theworld's first offshore, chemical injection process of resource recovery.

Marginal fields:

■ Cendor field: Petrofac's Cendor field can be quickly brought online. While Petronas is optimistic that itcan flow first oil in 2014, we have factored in peak production level for 2015. This will bring anadditional production of 15,000b/d at peak.

■ Roc Oil's Balai Cluster and Coastal Energy's Kepal-Banang-Meranti fields will also bring an estimated20,000b/d in additional production. The KBM cluster began production in January 2014, and the BalaiCluster is likely to see first oil in 2016.



New Developments:

■ Gumusut-Kakap field: Output from Shell's deepwater field, which came online in 2012 with productionlevels of about 25,000b/d, would ramp up to its peak production level of 135,000b/d by 2016 after thefield is connected to the dedicated semisubmersible floating production system that would serve the field.It had previously been tied-back to the Murphy-operated deepwater Kikeh field to enable production as ashort-term measure.

■ Bertam field: Lundin Petroleum estimates that it can bring the recently sanctioned Bertam field,discovered offshore Pahang in 2012, online by 2014. We have taken a more conservative view, pencillingin the initial production from 2015 onwards, and the field reaching its estimated 17,500b/d output peak in2016-2017.

■ Malikai field: Shell's deepwater Malikai field is targeting 2017 for first oil. We have factored in peakoutput of 60,000b/d in the second half of our forecast period from 2018 to 2022, with a production start-date in 2017.

These plans will be supported by Petronas' ambitious capital expenditure (capex). In early 2013, it

announced that it plans to raise capex to US$59bn over the next five years, with much of the funds

earmarked to support increased exploration and production to increase domestic production.

All in all, we expect oil production to continue climbing upwards in the medium term, from an estimated

645,630b/d in 2013 to a peak of 923,320b/d in 2018. Outputs from marginal fields and EOR on producing

fields will help boost outputs in the short-term. However, the small scale of these fields means that their

development can only sustain the country's output for a limited time. Larger deepwater developments will

see an increase in output in the medium term.

However, with the lack of large discoveries able to replace dwindling reserves from mature fields, we do

not expect Malaysia oil production to reach the 1mn b/d level, with production levels starting to fall

post-2018 unless high and continuous development of new projects bring significant new fields online and

sustain the country's increasing production. Over the longer term, deepwater and greenfield developments

will therefore remain necessary to maintain oil production growth past its current expected peak in 2018. At

the moment, we see oil production falling post-2018, to reach 832,000b/d by 2023.

However, we note the following downside risks to this forecast:

■ EOR and new developments projects face delays, technical difficulties and risk disappointing recoveryrates that would limit the extent of output growth currently promised by producers.

■ An unexpected collapse in oil prices could also see a sudden cutback in projects, given that the type ofprojects supporting Malaysian production growth - EOR, marginal fields and deepwater - are costly toembark on and require high oil prices to remain economically viable.



■ Financial and political challenges facing Petronas - whose contribution to the state budget has beengrowing at the expense of reinvesting its profits - could diminish the impact of this rise in capex.

Much of the growth in Malaysia's oil consumption is a function of its economic growth. Our Country Risk

team forecasts the country's GDP growth to average at 4.1% per annum between 2013 and 2022. However,

we expect a slower rate of domestic oil consumption growth for the following reasons:

■ The shift to coal-fired power plants as the prices of oil and gas soared has reduced demand for oil fromthe power industry;

■ Another factor that is hampering growth in oil consumption is the government's steady reduction of fuelsubsidies. Although consumption is still heavily subsidised relative to countries with market pricing suchas Singapore, the decrease in subsidies would help correct some of the distortions in the market. In Q413,the government cut fuel subsidies for the first time in more than two years, as part of its wider efforts atreducing its budget deficit. The subsidy on petrol and diesel were cut by 20 sen (6 cents) a litre each, to63 sen a litre and 80 sen a litre respectively. While the waning popularity of the ruling coalition BarisanNasional (BN) would prevent it from imposing more drastic and politically unpopular cuts to fuelsubsidies, it could still choose to further roll out reductions if pressured by fiscal needs. This has beenseen in neighbouring countries in South East Asia, from Indonesia to Vietnam.

In line with these developments, we expect oil consumption to grow at a slower pace than GDP growth,

increasing at an average rate of about 3.3% per annum between 2013 and 2022. Oil demand is expected to

rise from the EIA's estimate of 598,999b/d in 2012 to 720,980b/d in 2018 and to 849,700b/d by 2023. This

means that Malaysia's net oil export capacity will rise to 202,340b/d in 2018, before slumping back down

thereafter due to falling production.



Gas Supply And Demand

Table: Malaysia Gas Production, Consumption & Net Exports, 2012-2017

2012 2013e 2014f 2015f 2016f 2017f

Dry Natural Gas Production, bcm 62.3 63.6 64.9 66.8 69.8 73.0

Dry Natural Gas Production, % change y-o-y 1.0 2.0 2.0 3.0 4.5 4.5

Dry Natural Gas Production, US$bn, % change y-o-y 2.9 -1.4 -2.0 1.2 3.5 2.4

Dry Natural Gas Production, US$bn at US$6/mn btu 13.4 13.6 13.9 14.3 15.0 15.6



Dry Natural Gas Production, % of Domestic Consumption 199.6 195.8 192.9 192.9 195.8 199.6

Dry Natural Gas Consumption, bcm 31.2 32.5 33.6 34.6 35.7 36.6

Dry Natural Gas Consumption, % change y-o-y 2.0 4.0 3.5 3.0 3.0 2.5

Dry Natural Gas Consumption, US$bn 17.0 17.1 17.0 17.2 17.6 17.6

Dry Natural Gas Consumption, US$bn % change y-o-y 3.9 0.6 -0.6 1.2 2.0 0.4

Dry Natural Gas Net Exports, bcm 31.1 31.1 31.2 32.2 34.2 36.4

Dry Natural Gas Net Exports, % change y-o-y 0.0 0.0 0.4 3.0 6.1 6.6

Dry Natural Gas Net Exports, US$bn 16.9 16.4 15.8 16.0 16.8 17.6

Dry Natural Gas Net Exports, US$bn % change y-o-y 1.9 -3.3 -3.5 1.2 5.1 4.4

Dry Natural Gas Net Exports, at US$50/bbl US$bn 7.7 7.7 7.8 8.0 8.5 9.1


o/w Pipeline Gas Net Exports, bcm 2.1 2.1 2.1 2.1 2.1 2.1

o/w Pipeline Gas Net Exports, % change y-o-y -93.2 0.0 0.0 0.0 0.0 0.0

o/w Pipeline Gas Net Exports, % of total 0.1 0.1 0.1 0.1 0.1 0.1

o/w Pipeline Gas Net Exports, US$bn 1.2 1.1 1.1 1.1 1.0 1.0

o/w Pipeline Gas Net Exports, US$bn % change y-o-y -93.1 -3.3 -3.9 -1.7 -1.0 -2.0

o/w LNG Net Exports, bcm 29.0 29.0 29.1 30.1 32.0 34.3

o/w LNG Net Exports, % change y-o-y 0.0 0.5 3.2 6.5 7.0

o/w LNG Net Exports, % of Total Gas Exports 0.9 0.9 0.9 0.9 0.9 0.9

o/w LNG Net Exports, US$bn 16.9 16.3 15.7 16.0 16.8 17.7

o/w LNG Net Exports, US$bn % change y-o-y 0.0 0.0 0.2 0.4 0.4




Table: Malaysia Gas Production, Consumption & Net Exports, 2018-2023

2018f 2019f 2020f 2021f 2022f 2023f

Dry Natural Gas Production, bcm 75.9 78.5 79.7 78.3 76.4 74.5

Dry Natural Gas Production, % change y-o-y 4.0 3.5 1.5 -1.7 -2.5 -2.5

Dry Natural Gas Production, US$bn, % change y-o-y 2.9 3.5 1.5 -1.7 -2.5 -100.0




Dry Natural Gas Production, % of Domestic Consumption 202.5 204.5 205.5 199.9 193.0 186.3

Dry Natural Gas Consumption, bcm 37.5 38.4 38.8 39.2 39.6 40.0

Dry Natural Gas Consumption, % change y-o-y 2.5 2.5 1.0 1.0 1.0 1.0

Dry Natural Gas Consumption, US$bn 17.9 18.3 18.5 18.7 18.9 0.0

Dry Natural Gas Consumption, US$bn % change y-o-y 1.4 2.5 1.0 1.0 1.0 -100.0

Dry Natural Gas Net Exports, bcm 38.4 40.1 40.9 39.2 36.8 34.5

Dry Natural Gas Net Exports, % change y-o-y 5.5 4.5 2.0 -4.3 -6.0 -6.3

Dry Natural Gas Net Exports, US$bn 18.3 19.2 19.5 18.7 17.6 0.0

Dry Natural Gas Net Exports, US$bn % change y-o-y 4.4 4.5 2.0 -4.3 -6.0 -100.0



o/w Pipeline Gas Net Exports, bcm 1.1 1.1 1.1 1.1 1.1 1.1

o/w Pipeline Gas Net Exports, % change y-o-y -50.0 0.0 0.0 0.0 0.0 0.0

o/w Pipeline Gas Net Exports, % of total 0.0 0.0 0.0 0.0 0.0 0.0

o/w Pipeline Gas Net Exports, US$bn 0.5 0.5 0.5 0.5 0.5 0.0

o/w Pipeline Gas Net Exports, US$bn % change y-o-y -50.5 0.0 0.0 0.0 0.0 -100.0

o/w LNG Net Exports, bcm 37.3 39.1 39.9 38.1 35.7 33.4

o/w LNG Net Exports, % change y-o-y 8.9 4.6 2.0 -4.4 -6.2 -6.4

o/w LNG Net Exports, % of Total Gas Exports 1.0 1.0 1.0 1.0 1.0 1.0

o/w LNG Net Exports, US$bn 2,012.0 19.9 20.3 19.4 18.2 0.0

o/w LNG Net Exports, US$bn % change y-o-y 3.3 0.1 0.1 -0.1 -0.2 -0.2

f = BMI forecast. Source: BMI, EIA



Malaysia

Gas Production, Consumption And Imports, 2000-2022


Malaysia's gas production continues on an upward trend as gas discoveries support its output. In 2011, the

EIA states that it produced 61.7bcm of gas - a 0.42% y-o-y increase. We estimate gas production rose

slightly to 62.4bcm in 2012 and 63.6bcm in 2013.

A string of prolific discoveries and major projects set to come online between 2013 and 2018 would see gas

production continue on an upward trend, as output from new gas fields help to make up for declining

production in older fields. Nearly all of these new projects are off the coasts of Sarawak, East Malaysia,

which will in turn support liquefied natural gas (LNG) production growth at Petronas' LNG complex in

Bintulu. Amongst others, these projects include:

■ Hess' North Malay Gas project: Covering blocks PM302, PM325 and PM326B offshore PeninsulaMalaysia, the first phase of the project came on stream in December 2013. The second phase, which willprovide an additional 2bcm of gas at peak is tabled to start production in 2017.

■ ConocoPhillips' Kebabangan field: This could provide Malaysia with more than 7bcm of gas per yearfollowing its targeted operation date in 2014; In its Q313 financial report, ConocoPhillips stated thatKebabangan remains on track for a start-up in 2014, with development drilling commencing in late 2013.



■ Petronas' NC3 and NC8 fields: Scheduled for a 2016 start, the two fields are expected to flow 16.8mncubic metres per day (Mcm/d) - or a peak of 6.1bcm per year - and feed the ninth train at the BintuluLNG complex;

■ Petronas' Kasawari field: Discovered early-2012, the NOC has been conducting early studies todevelop the project, estimating that it could contribute 14-21Mcm/d (5.11-7.67bcm/y) to its liquefiednatural gas (LNG) complex when online. We have factored in output from Kasawari from mid-2018.

As such, we are expecting the uptrend in gas production to continue in the short-to-medium term. From an

estimate of 63.6bcm in 2013, we project output to hit 75.9bcm in 2018 and continue to climb to 79.7bcm by

2020. Although we currently forecast for a slight fall from 2021 based solely on projects in the pipeline, we

highlight that there is significant upside risk to the tail-end of our forecasts to 2023. These come from recent

discoveries made that could see a FID within 2014 to 2016. Assuming a minimum three-year period from

FID to production, these fields could start producing after 2017, and continue the increase in total gas

output. Notable discoveries include:

■ Petronas' Tukau Timur and Kuang North discoveries, which are currently being assessed for theircommerciality. Gas-in-place estimates for these fields are 58.8bcm and 64.4bcm respectively;

■ More production from fields in Block H, including Murphy Oil's Buru discovery made in January2012;

■ Newfield Exploration's SK310, consisting of the B-14 and B-15 prospects; Newfield confirmed thecommerciality of the prospects in April 2013, with estimated gas initially in place for B-14 of 42bcm, andrecoverable resources of 8bcm in B-15.

Gas recovered from Shell's Baram Delta EOR project is currently not factored into our output for the

following reasons - most of it is eyed for reinjection as part of the EOR and there are no estimates of the

recoverable volume available. If recovered volumes are greater than EOR needs, it would also pose upside

risk to our forecast.

Gas consumption in Malaysia is set to rise in the short-term owing to a generous subsidy regime even as

demand grows in tandem to economic expansion. Due to substantial subsidies, Malaysian end-user gas

prices are the second lowest in South East Asia, behind just Brunei. However, we expect a slowdown in

consumption growth over our ten-year forecast period. Like oil subsidies, gas subsidies are looking

increasingly untenable. According to Prime Minister Najib Razak, the government incurs more than

MYR2.0bn (US$614mn) monthly as a result of the subsidies, a trend he believes is unsustainable and is

looking to end in the coming years. The government is currently looking into steadily raising prices and

plans to reach market parity by 2016. While there is limited communication on this issue, some reports

suggest that gas and electricity subsidies could be next in a round of subsidy cuts and price hikes in

2014-2015 following the fuel subsidy cut.



Economic growth of about 4% per annum will see consumption on an uptrend through our forecast period

from 2014 to 2022: we estimate that consumption rose to 32.5bcm in 2013 and is forecasted to increase to

37.5bcm in 2017, and continue to 40bcm by 2023. However, the rate of growth is clearly slowing in our

forecasts, reflecting concerns about high prices as a cap to the switch to gas.

LNG

Like other nations which span the archipelagos of the Pacific, Malaysia is seeking to develop both import

and export LNG capacity to meet the distinct energy profiles of its regions. The country currently operates

three major LNG facilities at the Petronas LNG complex in Bintulu in Sarawak, from which it provides

some 12% of world LNG exports. Total capacity at the Bintulu LNG complex is 25.7mn tonnes per annum

(tpa) - or 35.5bcm. Utilisation rate has been about 85-90% of its total capacity. Japan is its largest LNG

customer, representing 64% of exports from Malaysia in 2012, followed by South Korea, which received

18% of LNG Malaysian exports in 2012. Taiwan used to be the third largest importer of Malaysian LNG

but it is increasingly eclipsed by China.

Chinese Share Of Malaysian LNG Grows

Distribution Of Malaysia's LNG Customers, FY2011 (LHC) & FY2012 (RHC)

Source: Petronas

Malaysia LNG Group (MLNG), the LNG subsidiary of Petronas, is looking to increase its production of

LNG over the next five years. According to MLNG's chief executive officer Zakaria Kasah, the firm will



pump MYR15bn (US$4.93bn) into more than 10 capital projects in Bintulu, Sarawak, in order to meet this

target. We believe that Petronas' plan to expand its domestic LNG production capacity is indicative of a

shift towards LNG within its portfolio as it seeks to capture the opportunities afforded by expected growth

in the global LNG market.

There are two planned projects aimed at expanding its LNG production capacity: a floating LNG project

destined for the Kanowit gas field offshore Sarawak, whose construction began in June 2013 in South

Korea, and the addition of a ninth train to the Bintulu LNG complex. The projects are expected to come

online in 2015 and 2016 respectively and together add 4.80mn tpa (6.62bcm) to its LNG production

capacity.

Petronas is expected to make a final investment decision (FID) on a second FLNG export project by early

2014 - Rotan LNG. This project will tap gas from the stranded Rotan field offshore Sabah and have a

production capacity of 1.50mn tpa (2.07bcm). It would be operational by 2016 if the FID is made.

Given the high likelihood of its approval, we have included production from Rotan FLNG into our LNG

production forecasts, which assumes a 90% utilisation rate of Malaysia's total LNG production capacity.

Despite a relatively rosy outlook for gas production, we note that the availability of domestic gas supplies to

feed its LNG plants could limit the extent to which Malaysia can increase its LNG production and exports,

posing a downside risk to our forecasts.

The dramatic growth in gas consumption, owing to strong economic growth and gas subsidies, have put

pressure on gas supplies particularly in the more populated Peninsula Malaysia, which is separated by sea

from Malaysia' gas production centre in East Malaysia. To ameliorate gas shortages on the peninsula, the

country has turned to LNG imports. The first LNG regasification terminal, Melaka LNG near Sungai

Udang, came into operation in 2013 after much delay and received its first cargo in Q213. It has a capacity

of 5.24bcm.

Petronas also plans to build two more LNG import terminals: one in Pengerang, Johor and the other in

Lahad Datu, Sabah. The Johor terminal, with a capacity of 5.24bcm, would be part of a wider project to turn

Pengerang into a regional oil and gas hub, which could buy and resell LNG to meet wider regional needs.

The Sabah terminal, with a smaller capacity of 1.02bcm, will mainly support a power plant that is planned

in the eastern Malaysia state. A FID for these terminals is expected in 2014 and the NOC hopes to bring

these projects online by 2016. Together, it would raise Malaysia's total LNG import capacity to 11.5bcm.



The NOC has signed up for at least 3.5mn tpa (4.83bcm) of LNG from the Gladstone LNG export project in

Australia and Qatar's Qatargas-2 for 20 years. This would be the minimum volume of LNG imports

Malaysia will be expected to make. However, we expect the Johor terminal in particular to be underutilised

due to the fierce competition it would face from Singapore as the choice destination for LNG entrepot trade.

As such, we expect net LNG exports from Malaysia to grow from an estimate of 29bcm in 2013 to 39.9bcm

in 2019 but fall thereafter as domestic consumption continues to increase even as gas production tapers off.

Nonetheless, there is a high upside risk to the tail-end of our forecast if FID for fields that are discovered in

the period 2012-2015 are given and developed to be brought online by 2023. These additional volumes will

help support Malaysia's LNG production, presenting an upside to our forecasts.

Refining And Oil Products Trade

Table: Malaysia Refining - Production & Consumption, 2012-2017

2012 2013e 2014f 2015f 2016f 2017f

Crude Oil Refining Capacity, 000b/d 538.6 588.0 588.0 588.0 588.0 588.0

Crude Oil Refining Capacity, % change y-o-y 0.0 9.2 0.0 0.0 0.0 0.0

Crude Oil Refining Capacity, Utilisation, % 108.0 99.5 100.0 100.6 101.0 101.6

Refined Petroleum Products Production, 000b/d 581.4 584.8 587.9 591.3 594.1 597.6

Refined Petroleum Products Production, % change y-o-y 0.9 0.6 0.5 0.6 0.5 0.6

Refined Products Consumption, 000b/d* 598.0 613.0 631.3 652.2 674.3 697.3

Refined Products Consumption, % change y-o-y 0.0 2.5 3.0 3.3 3.4 3.4

Refined Products Net Exports, 000b/d -16.6 -28.1 -43.4 -60.8 -80.2 -99.7

Refined Products Net Exports, % change y-o-y -24.5 69.8 54.4 40.1 31.8 24.3

Refined Products Net Exports, US$bn -1.0 -1.3 -2.0 -2.7 -3.4 -4.1

Refined Products Net Exports, US$ % change y-o-y -12.8 38.1 49.0 35.9 27.5 20.2

Refined Products Net Exports, US$bn at US$50/bbl -0.4 -0.6 -1.0 -1.3 -1.7 -2.1



Refined Products Production (inc ethanol and non-conventional),000b/d 582.5 589.9 593.4 597.1 600.1 603.8

Refined Products Production (inc ethanol and non-conventional), %change y-o-y 0.9 1.3 0.6 0.6 0.5 0.6

Refined Products Consumption (inc ethanol and non-conventional),000b/d 598.2 613.2 631.6 652.5 674.7 697.7



Malaysia Refining - Production & Consumption, 2012-2017 - Continued

2012 2013e 2014f 2015f 2016f 2017f

Refined Products Consumption (inc ethanol and non-conventional), %change y-o-y 0.0 2.5 3.0 3.3 3.4 3.4

*Previously known in BMI's Databases as "Total Oil Consumption"; e/f = BMI estimate/forecast. Source: BMI, EIA



Table: Malaysia Refining - Production and Consumption, 2018-2023

2018f 2019f 2020f 2021f 2022f 2023f

Crude Oil Refining Capacity, 000b/d 588.0 738.0 888.0 888.0 888.0 888.0

Crude Oil Refining Capacity, % change y-o-y 0.0 25.5 20.3 0.0 0.0 0.0

Crude Oil Refining Capacity, Utilisation, % 102.2 92.6 94.7 95.2 95.7 96.2

Refined Petroleum Products Production, 000b/d 601.1 683.1 841.2 845.6 850.1 854.6

Refined Petroleum Products Production, % change y-o-y 0.6 13.6 23.1 0.5 0.5 0.5

Refined Products Consumption, 000b/d* 721.0 745.5 770.8 797.1 823.4 849.7

Refined Products Consumption, % change y-o-y 3.4 3.4 3.4 3.4 3.3 3.2

Refined Products Net Exports, 000b/d -119.9 -62.4 70.3 48.5 26.7 4.9

Refined Products Net Exports, % change y-o-y 20.3 -47.9 -212.7 -31.0 -44.9 -81.7

Refined Products Net Exports, US$bn -4.7 -2.4 2.8 2.0 1.2 0.3

Refined Products Net Exports, US$ % change y-o-y 13.2 -48.3 -217.7 -29.3 -41.5 -70.9

Refined Products Net Exports, US$bn at US$50/bbl -2.4 -1.2 1.5 1.0 0.6 na



Refined Products Production (inc ethanol and non-conventional),000b/d 607.5 689.8 848.1 852.8 857.6 862.4

Refined Products Production (inc ethanol and non-conventional), %change y-o-y 0.6 13.5 23.0 0.6 0.6 0.6

Refined Products Consumption (inc ethanol and non-conventional),000b/d 721.4 746.0 771.3 797.6 823.9 850.3

Refined Products Consumption (inc ethanol and non-conventional), %change y-o-y 3.4 3.4 3.4 3.4 3.3 3.2

na = not available. *Previously known in BMI's Databases as "Total Oil Consumption"; f = BMI forecast. Source: BMI, EIA

Malaysia has five oil refineries, which together provide the country with 584,820b/d in refining capacity in

2013. We have revised up our estimate following the completion of an expansion of Petronas' Melaka

PSR-2 refinery. Petronas owns three of these refineries, one in conjunction with Phillips66, while Shell and

Petron own the remaining two plants that are both based in Port Dickson in Negeri Sembilan.

We upgraded our forecast for Malaysia's refining outlook, following the inclusion of Petronas' Refinery

And Petrochemicals Integrated Development (RAPID) refinery which is set to come online by 2019,

according to a Petronas official in a July 2013 interview with Reuters. Based in Perengang, Johor as part of

a wider project to build the town into a regional oil and gas hub, RAPID would be Malaysia's largest



refinery at 300,000b/d. We expect the plant to come online in H219, adding 150,000b/d initially in 2019 but

300,000b/d thereafter to the country's total refining capacity and bringing the Malaysian total to 864,213b/d.

Downside risk to this forecast could come from a further delay to the RAPID project, which was originally

slated to come online in 2017. At the time of writing, a FID has yet to be made for the project though

Petronas assured that it would take place soon. In October 2013, despite the absence of a FID, Petronas has

invited tenders under packages 16A and 17 of the Refinery and Petrochemicals Integrated Development

(RAPID) project situated in Johor, Malaysia. The packages include engineering, procurement, construction

and commissioning of an effluent treatment facility and a waste management hub for the project.

The economic importance of the project to the government's plan makes it likely that Petronas will go

through with the project. However, while we believe the project will go ahead, we think that downside risk

exists to its construction, or that the project could be a scaled down version of the initially planned project.

The debate over economics of oil versus gas in petrochemical production could be a key determinant of the

project. The prospect of petrochemical growth in the US on the back of cheap gas feedstock and also in the

Middle East could be a threat to the margins that RAPID could make, particularly from 2017 onwards.

Upside risk to this forecast could come from China Petroleum Corporation (CPC)-owned Kuokuang

Petrochemical Technology Co's proposed KPTC-Malaysia Integrated Refinery and Petrochemical

Development (KPTC-MIRPD), which is also to be based in Pengerang, Johor. The 150,000b/d plant has

already received a detail environmental impact assessment (DEIA) to proceed, though it faces heavy local

opposition against its establishment on environmental grounds. If the KPTC-MIRPD project comes through,

it will bring Malaysia's total refining capacity to 1.01mn b/d by 2020, making Malaysia the largest refining

country in South East Asia.

Revenues/Imports Costs

Net oil export revenues for 2013-2017 could rise from a forecast of US$0.23bn in 2013 to US$5.78bn in

2018. Net gas export revenues are expected to increase from an estimate of US$16.39bn in 2013 to US

$18.34bn in 2018. Combined end-period crude and gas revenues are projected to amount to about US

$24.13bn in 2018.

Key Risks To BMI's Forecast Scenario

The biggest risk facing Malaysia in terms of energy revenues is the continuing strong demand growth

provoked by subsidised fuels. Unless the country changes its domestic fuel pricing policy to discourage



higher usage, the country could see demand overtaking domestic oil supply, thus creating increased demand

for imports.



Industry Risk Reward Ratings

Asia - Risk/Reward Ratings

BMI View: Asia's Oil & Gas Risk/Reward Ratings are characterised by the following: good reward scores

are concentrated in states with high below-ground potential and good demographic profiles but good risk

scores are mainly found in countries that have poor resource profiles. In the upstream category, with the

exception of Australia, several resource-rich countries underperform as a result of poorer risk scores.

Papua New Guinea has moved dramatically up the upstream table, thanks to pending liquefied natural gas

developments in the country and high resource potential. In the downstream segment, traditional giants

such as Singapore, South Korea and Japan still dominate the top spots, thanks to strong risk performances

from stable operating environments. However, we warn that emerging countries such as China are

challenging the traditional leaders and could see their overall scores improve if the domestic regulatory

environment eases up.

The main themes arising from BMI's Oil & Gas Risk/Reward Ratings (RRRs) for Asia are:

■ High level of state involvement in the sector keeps industry scores low relative to other regions, as ittakes a toll on Country Rewards scores and Industry Risk scores, both of which assess different facets ofthe level of state involvement and control over the sector.

• Unsurprisingly, countries with large below-ground potential top the Upstream RRR tables. However,there are several countries with huge exploration potential that have underperformed. Indonesia is a casein point, as increasing signs of state intervention have led to the deterioration of its operatingenvironment. This has in turn pushed down its Country Rewards and Risk scores, placing it in 11th

position in our upstream sector Risks and Rewards rankings.

■ Interestingly, with the exception of Australia, it is the markets with poor Upstream Rewards such asJapan, Hong Kong, South Korea and Singapore that show some of the highest scores in Industry Risks,which has in turn lifted their final Upstream Risk/Rewards scores. Nonetheless, poor below-groundprospects leave them at the bottom of the regional table.

■ In the long term, we see room for Upstream Rewards to grow on the back of reserves and productiongrowth as unconventional exploration looks set to pick up.

■ For Singapore, Japan and South Korea, large downstream capacities combined with strong operatingenvironments have helped them maintain their high positions in our regional Downstream RRR rankings.Nonetheless, these countries are gradually losing their advantage as they come under challenge fromemerging competitors, such as India and China, which have larger markets and newer plants. China, forexample, already ranks second in our downstream ratings table.

■ Although some of the world's fastest-growing downstream market demand is in Asia, fuel priceregulation and high energy dependency in many developing markets have pushed down scores forCountry Rewards and Risks. As a result, many countries such as Vietnam and Indonesia haveunderperformed in our downstream rankings. The continuation of high crude oil prices and fuel subsidiesposes significant downside risks to the profitability of the downstream segment in many Asiandeveloping countries.



■ Countries that top our overall RRRs perform relatively well in both upstream and downstream, though wedo highlight that Australia is at risk of losing its leading position in our ratings, as the gap with runner-upChina gradually narrows.

Table: Asia's Oil & Gas Risk/Rewards Ratings

Upstream R/R Ratings Downstream R/R Ratings Oil & Gas R/R Ratings Rank

Australia 68.6 60.0 64.3 1

China 57.2 61.6 59.4 2

Vietnam 63.5 51.7 57.6 3

India 53.8 56.7 55.3 4

Japan 48.3 61.5 54.9 5

Thailand 54.1 54.4 54.3 6

Malaysia 56.5 50.1 53.3 7

Papua New Guinea 61.8 44.7 53.2 8

Pakistan 55.7 49.7 52.7 9

Singapore 39.3 64.7 52.0 10

Philippines 52.7 50.8 51.8 11

South Korea 33.2 60.2 46.7 12

Indonesia 40.0 47.8 43.9 13

Hong Kong 35.8 52.1 43.9 14

Taiwan 16.9 36.5 26.7 15

*Higher rating = Lower risk. Source: BMI

The Upstream Leaders

Australia has the highest overall scores in the upstream ratings. Its profile is bolstered by its excellent

performance in Country Rewards, for which it leads the region by a wide margin, and a good overall

position in terms of risks. The country is an open market with a competitive environment and has relatively

well-developed links to the export market. This has more than compensated for its less impressive and

declining showing in Upstream Industry Rewards, in which it is surpassed by Vietnam, Malaysia, China,

India and Papua New Guinea. Unconventional resources and underexplored regions of Australia provide

further growth opportunities. However, high costs and growing infrastructure constraints as exploration and

production (E&P) moves beyond Western Australia is seeing the country's lead in the upstream

progressively narrow. This trend continues this quarter, with upstream Risk & Rewards ratings for

Australia's overall upstream Risk & Rewards declining from 71.2 in Q413 to 68.6 in Q114.



Imbalance Of Risks And Rewards

Asia Upstream Risk/Reward Ratings

*Higher score = lower risk; Scores out of 100. Source: BMI

Vietnam remains in a close second place in our Upstream RRR's thanks to its leading regional rewards

score arising from its good below-ground potential and its under-explored waters. Promising gas output

growth prospects arising from a number of encouraging finds to date, proven oil reserves, and a healthy

level of offshore industry activity maintain the country in a leading position in Asia for industry rewards.

Policy continuity and above regional average participation from private players in Vietnam's upstream

segment for the region also lend support. However, a poor performance on corruption and rule of law, and

E&P in the contested South China Sea, where many of these prospects lie, poses a significant downside risk

to the long-term returns of venturing deeper into Vietnamese and Philippine waters.

Unconventional exploration and investment has helped China retain fourth place in the regional upstream

table, thanks to a second-best score in the region for upstream Industry Rewards. However, at the moment,

unconventional exploration in the country has been slow and could be complicated by its difficult

geology. China has a reasonable Country Rewards rating but its score in this category is mainly dragged

down by the significant role played by the state in the oil and gas sector. State ownership of upstream assets

remains a constraint to better performance.



On the back of revisions in our production forecasts for Papua New Guinea (PNG), the country has recently

seen a steep increase in its Upstream Industry Rewards. The country's significant gas finds offshore, the

almost complete Liquefied Natural Gas (LNG) terminal, underexplored gas rich acreage and its strategic

location for exports to the Asian market have fed into its overall ratings, sending it four places higher to sit

third in our regional upstream table, slightly behind Vietnam.

Resource-Rich Countries Hit By State Involvement

State involvement in the upstream sector continues to weigh on the RRRs of some of the most resource-rich

countries. Although most oil and gas projects are licensed under the production sharing contract (PSC)

model, most of them involve high local content requirement and entitle national oil companies (NOCs) to

large shares in new projects. This regulatory framework has pulled down scores in India, Malaysia and

Indonesia in recent quarters, despite these countries' sizeable resource base.

Resource-Rich Countries Underperforming In Risk Category

Upstream Risk/Rewards For Selected Countries




For example, Malaysia performs increasingly well in terms of Upstream Industry Rewards supported by a

favourable gas reserves to production ratio. However, its overall score is dragged down by its mediocre

Industry Risk score due to a continued large presence of state ownership of upstream assets. In addition, the

country's broader Country Risk environment remains only mildly attractive, with relatively low scores for

corruption and rule of law which undermine its overall performance.

Indonesia is another case in point, with mediocre scores for country risk and rewards. A highly involved

government and contradictory policies present strong limitations to its upstream segment despite strong

below-ground potential. Creeping resource nationalism in past quarters is also a threat to Indonesia's

industry risk scores, as the increasingly intrusive government could introduce more restrictions to private

production and marketing activity and as growing domestic reservation requirement for oil and gas output

makes it less attractive than other countries in the region. Similarly, the state's low scores for corruption,

rule of law and infrastructure undermines its overall performance.

Although regulatory troubles are hindering India's short-term potential, we highlight that if they are

overcome, the country could see its Upstream RRRs scores improve. Indeed, India has gas potential, but

current production falls well short of the country's ultimate potential. In fact, the upward adjustment of

domestic gas prices to nearly double that of the previous level by April 2014 is a positive sign for the

country. Although prices of about US$8 per million British Thermal Unit (mnBTU) are still below

international levels, this will raise the incentive for investment into the country's deepwater and

unconventional resources. We therefore anticipate strong gas production growth to begin from 2016

onwards.

The country also appears to be moving ahead with a shale gas regulation. In September 2013, the Indian

government granted ONGC and Oil India the rights to explore for unconventional on the 176 existing

licences that are prospective for shale. While the new policy does not yet cover contracts for blocks

awarded to non-state explorer, another Cabinet approval should likely offer shale oil and gas blocks to non-

state explorers. This is in advance of a shale gas licensing round originally slated to be held in December

2013, but which will more likely occur in 2014, according to the Indian Oil Ministry. As a result, we could

see an improvement in India's upstream Country Rewards score next quarter, should the long-awaited

policy come through.



Table: Asia Upstream Sector Risk/Reward Ratings

UpstreamIndustryRewards

UpstreamCountryRewards

UpstreamRewards

UpstreamIndustry

Risks

UpstreamCountry

RisksUpstream

Risks

UpstreamR/R

Ratings Rank

Australia 47.5 100.0 60.6 87.5 86.2 87.0 68.6 1

Vietnam 68.8 70.0 69.1 55.0 42.6 50.6 63.5 2

Papua NewGuinea 58.8 65.0 60.3 80.0 37.6 65.2 61.8 3

China 61.3 50.0 58.4 55.0 53.0 54.3 57.2 4

Malaysia 58.8 60.0 59.1 45.0 60.6 50.5 56.5 5

Pakistan 46.3 77.5 54.1 75.0 30.6 59.5 55.7 6

Thailand 38.8 72.5 47.2 80.0 51.7 70.1 54.1 7

India 56.3 47.5 54.1 50.0 59.5 53.3 53.8 8

Philippines 45.0 65.0 50.0 65.0 48.0 59.1 52.7 9

Japan 15.0 70.0 28.8 100.0 82.1 93.7 48.3 10

Indonesia 37.5 50.0 40.6 35.0 45.5 38.7 40.0 11

Singapore 6.3 50.0 17.2 100.0 73.6 90.8 39.3 12

Hong Kong 0.0 50.0 12.5 100.0 72.0 90.2 35.8 13

SouthKorea 5.0 32.5 11.9 90.0 69.6 82.9 33.2 14

Taiwan 15.0 0.0 11.3 10.0 67.7 30.2 16.9 15

Average 37.3 57.3 42.3 68.5 58.7 65.1 49.2 -

*Higher rating = lower risk; Scores out of 100. Source: BMI

Downstream Support

Singapore maintains its position at the top of our downstream charts, largely thanks to its top-of-the table

performance in Downstream Risks and improving performance in overall Downstream Rewards. As the oil

products trading hub of the region, supported by large and sophisticated refineries, the country is well-

placed to compete in the global fuels market thanks to its good physical trade and financial infrastructure

networks.

Other top performers include the region's traditional refining giants South Korea and Japan. Like Singapore,

a mature industry coupled with a stable operating environment has boosted their Downstream Risks scores

to seal their top places in the region's downstream segment. After conceding its third place to Japan last

quarter, Australia continued its downward trend by ending in fifth position behind South Korea. Domestic



production is increasingly challenged by cheaper fuel imports from Asia and increasing crude feedstock

costs due to dwindling domestic supplies.

Traditional Giants Face Emerging Challenges

Downstream Risk*/Rewards For Selected Countries


However, we highlight that these traditional leaders are under threat. With mega-refineries emerging in

India, China and in the Middle East, they are coming under intense pressure from new players cutting into

its traditional market share. This has been exacerbated by a weak global macroeconomic environment that is

tempering global demand for oil.

In terms of Downstream Rewards, these traditional refining giants are also increasingly eclipsed by

emerging markets. Thanks to their large and still-growing domestic market for oil and gas consumption,

countries such as India and China are leading the region in this respect. Domestic fuel price regulations,

which have artificially depressed prices and are affecting refining margins are holding back downstream

risk scores for these markets, which remain average for the region. However, they have made up for this

weakness with an active effort to develop a large refining sector that can not only meet the needs of the

domestic market, but also target the export market. Chinese government policies to upgrade fuel standards



and a recent reform of its pricing mechanism - to more closely align with price changes in the global market

- have also increased opportunities for rewards.

Rising demand and limited domestic fuel supplies create opportunities in South East Asian countries.

However, state involvement in downstream pricing has hit risks and rewards in these emerging markets

such as Indonesia, Vietnam and Malaysia despite an expected increase in domestic consumption. Indonesia

is a case in point, falling one place to 13th place this quarter after a decline of three places in Q413. This fall

in its downstream Industry Rewards score comes as opportunities in the refining sector are limited by the

dominant role of the state and heavy state subsidies, despite the country's large domestic market.

Room For Downstream Progress

Downstream Risk*/Rewards For China And Regional Average


Scores for these countries also remain average because there appears to be a growing risk of overcapacity in

the region. While early investment is likely to pay off, later entrants into these markets may find themselves

struggling not only because of oversupply in the domestic market, but also from tough competition in the

wider regional market. This could improve especially with growing inclinations towards relaxing price



controls. Indonesia has made the politically difficult decision to raise fuel prices by cutting its subsidies.

Both Malaysia and Vietnam had also partially raised fuel prices in Q313.

Pricing Levels Hurt Downstream Rewards

Asia Downstream Rewards And Risk Ratings


We can see the difficulties of the downstream sector reflected in the downstream scores of the markets. The

table of our ratings below shows that the risks associated with operating in the downstream segment in

China for example are greater than the opportunities (shown by the lower score for risks than for rewards).

Similarly, Indonesia displays downstream risks which are almost equal to its low downstream rewards

ratings, which suggests a particularly high relative opportunity cost of operating in this market.



Table: Asia O&G Downstream Risk/Reward Ratings

Downstream

IndustryRewards

CountryRewards Rewards

IndustryRisks

CountryRisks Risks

R/RRatings Rank

Singapore 51.1 56 52.3 100 84.1 93.6 64.7 1

China 65.6 63 64.9 45 66.8 53.7 61.6 2

Japan 42.2 72 49.7 100 72.5 89 61.5 3

South Korea 37.8 72 46.3 100 81.4 92.6 60.2 4

Australia 41.1 66 47.3 100 73.8 89.5 60 5

India 50 70 55 65 54 60.6 56.7 6

Thailand 44.4 60 48.3 75 59.3 68.7 54.4 7

Hong Kong 32.2 52 37.2 100 67 86.8 52.1 8

Vietnam 52.2 50 51.7 45 62 51.8 51.7 9

Philippines 37.8 63 44.1 70 61.1 66.5 50.8 10

Malaysia 48.9 46 48.2 45 69 54.6 50.1 11

Pakistan 44.4 56 47.3 65 40.1 55 49.7 12

Indonesia 44.4 56 47.3 45 55 49 47.8 13

Papua New Guinea 32.2 56 38.2 75 37.3 59.9 44.7 14

Taiwan 34.4 34 34.3 20 73.9 41.6 36.5 15

Average 43.9 58.1 47.5 70 63.8 67.5 53.5 -

*Higher score, lower risk. Source: BMI



Malaysia - Risk/Reward Ratings

Malaysia Upstream Rating - Overview

Contributing to Malaysia's mediocre showing in the regional Upstream Risk/Reward Ratings (RRRs) are

low scores for oil reserves, gas production growth potential and the oil reserves/production ratio. Limited

industry privatisation attracts below-average scores, though this is slightly lifted by its healthy competitive

landscape and relatively attractive licensing terms.

Malaysia Upstream Rating - Rewards

Industry Rewards: Malaysia shines in terms of its gas reserves and gas reserves/production. However,

scores are very low for oil reserves and for oil reserves to production ratio. The country has mediocre scores

for output growth prospects.

Country Rewards: There is a mediocre Country Rewards rating. The state still shares directly in the

ownership of upstream assets, but the industry is relatively competitive, with significant international oil

company (IOC) involvement thanks to a well-developed sector and its good crude quality.

Malaysia Upstream Rating - Risks

Industry Risks: The country achieves a mid-table score here despite its reasonably transparent regulatory

and licensing environment. This is largely due a continued presence of state ownership of upstream assets.

Country Risks: Malaysia's broader Country Risk environment is only mildly attractive. The state's

relatively low scores for corruption, rule of law and physical infrastructure undermine its overall

performance. However, continuity of policy across governments reduces the operational risks for private

companies.

Malaysia Downstream Rating - Overview

Malaysia has a relatively weak position in the Downstream industry rankings, with its reasonable market

size being matched by mid-table growth prospects. State influence remains significant in the downstream

segment, with limited competition. Malaysia's downstream rating benefits from generally low-risk factors

such as short-term policy continuity, short-term economic external risk and legal framework.



Market Overview

Malaysia Energy Market Overview

State-owned energy firm Petroliam Nasional Berhad (Petronas) dominates the upstream and downstream

oil and gas industries. It is the only wholly state-owned enterprise left in Malaysia and is the single largest

contributor to government revenues. Privatisation is not on the near-term agenda.

Petronas holds exclusive ownership rights to all exploration and production (E&P) projects in Malaysia and

all foreign and private companies must operate through production sharing agreements with it. Petronas is

required to hold a 15% minimum equity in production sharing contracts (PSC) with all foreign and private

companies. ExxonMobil is the largest oil company by production volume, and there are numerous other

international oil companies operating under production sharing contracts in the country's upstream. Royal

Dutch Shell is the largest foreign investor in the country's oil sector. Petronas is a major player in the retail

and marketing segment, competing with Royal Dutch Shell and Chevron. All energy policy in Malaysia is

overseen by the Economic Planning Unit and the Implementation and Coordination Unit, which report

directly to the prime minister.

Malaysia has 4.0bn barrels (bbl) of proven oil reserves and 2.35tcm of proven gas reserves. It managed to

reverse its decline in oil production in 2012 to see a 2.75% year-on-year (y-o-y) increase in total oil

production to 642,660b/d. Malaysia's gas production continues on an upward trend as gas discoveries

support its output. In 2012, the EIA states that the country produced 62.4bcm in 2012 - a 1.00% y-o-y

increase. Malaysia's oil and gas output potential has been limited by the country's National Depletion

Policy, established in 1980, which has kept hydrocarbons production at 3% of total reserves each year.

Malaysian crude is generally of high quality and comes largely from offshore peninsular Malaysia,

dominated by the Tapis field. The Tapis crude blend has an American Petroleum Institute (API) gravity of

42.5° and is one of the most expensive benchmark crude grades in the world. There are five oil refineries in

Malaysia, providing an estimated combined capacity of around 584,820b/d in 2013. The country operates

extensive liquefied natural gas (LNG) facilities in Sarawak, East Malaysia, and provides around 13% of

world LNG exports, sold largely to Japan, South Korea, Taiwan and increasingly China. It is currently the

world's second largest LNG exporter. Small amounts of gas are sold via pipeline to Singapore. Malaysia

will remain a key supplier of gas to the Asia Pacific LNG market on the basis of long-term supply contracts,

but the growing gas needs of peninsular Malaysia will simultaneously require imports.



Overview/State Role

Petronas is responsible for the country's oil and gas supplies. The company is state-owned but has listed

subsidiaries in fuels retailing and natural gas distribution. Using PSCs, Malaysia has attracted IOCs such as

ExxonMobil, Royal Dutch Shell and ConocoPhillips. The state company has a 72% share of Malaysia's

crude oil output, 73% of its natural gas output and accounts for almost 60% of refining capacity. Subsidiary

Petronas Dagangan operates a network of over 900 service stations and has a share of just over 44% of the

domestic fuels market.

Licensing And Regulation

The Petroleum Development Act of 1974 established Petronas as a state-owned company with exclusive

rights of ownership, exploration and production. According to Malaysia's energy ministry, Petronas is

responsible for all upstream planning, investment and regulation. Companies become involved in Malaysia's

upstream sector through PSAs with Petronas.

Petronas reports directly to the Malaysian prime minister, and oil and gas come under the jurisdiction of the

Economic Planning Unit of the Prime Minister's Department. This department is also responsible for gas

pricing, while the Ministry of Domestic Trade and Consumer Affairs is responsible for the price of

petroleum products.

Downstream activities are regulated by two bodies under the Petroleum Regulations of 1974. The Ministry

of International Trade and Industry is responsible for all licences for the refining, processing, and

petrochemicals sectors, while the Ministry of Domestic Trade and Consumer Affairs is responsible for

licences for the marketing and distribution of petroleum products.

Government Policy

According to Malaysia's energy ministry, the country's energy policy goals were originally set out in the

National Petroleum Policy, formulated in 1976. The policy has three elements. The first element is to ensure

adequate supplies at reasonable prices in order to support Malaysia's economic development. By implication

this means that Malaysia's energy reserves are primarily earmarked to serve national needs. Second, the

policy aims to promote greater Malaysian involvement in oil and gas projects and to improve the investment

climate, particularly mentioning the downstream sector. Third, the policy aims to manage Malaysia's

hydrocarbon resources by controlling the rate of use of the country's reserves. This rate is supposedly

determined by social, economic and environmental factors.



This third element of the country's hydrocarbons policy was elaborated in 1980 through the National

Depletion Policy. This policy was initially aimed at oil fields containing reserves of over 400mn bbl of oil

initially in place (OIIP). In such fields, production was limited to an annual rate of 1.75% of OIIP. In 1985,

however, this rate was increased to 3%. This has meant that Malaysia's oil production is officially held

below its theoretical production level. The National Depletion Policy was subsequently also applied to gas

fields. This means that a cap of 20.67bcm/year applies to the total gas production level in peninsular

Malaysia. This cap does not apply to East Malaysia.

The National Petroleum Policy was supplemented in 2008, by an additional set of objectives published by

the energy ministry. The elements relevant to the hydrocarbons industry are to secure supply (partly through

diversification of energy sources), match supply and demand through forecasting and pricing, promote

competition and create an energy supply plan, ensure the efficient use of energy, and to monitor and

minimise negative environmental impacts.

Marginal fields and Enhanced Oil Recovery (EOR)

In late 2010, the government released details of tax incentives designed to boost investments in both EOR

and exploration and development of marginal oil fields. The income tax rate for marginal fields was

dropped from 38% to 25%, and the government cancelled export duties on total oil production from these

small fields. In addition, the government provided incentives to reduce the tax burden for companies

developing difficult or capital-intensive projects such as EOR, high-pressure, high-temperature fields and

oil infrastructure projects. For example, Malaysia provided income tax allowances of up to 100% of capital

expenditure (capex) for EOR projects.

In addition to the changes to the upstream tax structure, Najib announced the development of an upstream

and downstream services and equipment hub in Pekan, Pahang. The project, known as Tanjong Agas Oil

and Gas and Maritime Industrial Park, is being developed by Tanjong Agas Supply Base & Marine

Services and will be used to support regional oil and gas activities.



International Energy Relations

Together with Indonesia, Borneo neighbours Malaysia and Brunei have submitted competing claims for

their adjacent sections of the South China Sea under Article 47 of the UN Convention on the Law of the

Sea. Numerous border disputes in South East Asia have hindered oil exploration efforts in the region,

limiting the countries' production potential. Stagnating or falling oil and gas reserves in the majority of

South East Asian countries has prompted an upsurge in provisional bilateral agreements between the

competing claimants to boost exploration activity.

Reflecting the growing pragmatism of regional governments towards maritime border matters, Malaysia has

been seeking to fast track resource exploitation in the disputed zones by establishing 50:50 joint

administration areas with neighbouring states. Currently, Malaysia produces oil and gas in two jointly

administered zones: the Malaysia-Thailand joint development area, located in the lower part of the Gulf of

Thailand, and the commercial arrangement area with Vietnam in the South China Sea. In 2009, the dispute

between Malaysia and Brunei was resolved with the two countries signing a boundary agreement. In 2010,

Petronas and the Brunei government agreed to jointly develop two blocks offshore Borneo, and signed a 40-

year Production Sharing Agreement (PSA) for Blocks CA1 and CA2.

China, the Philippines, Malaysia, Vietnam and Taiwan have not officially resolved their dispute over the

sovereignty of the Spratly Islands in the South China Sea. It is believed that the waters around the Spratly

Islands are rich in hydrocarbons, although claims to this effect made by Chinese government bodies have

not been independently verified. Malaysia's claim has been made on the basis of the continental shelf

principle, and the country has occupied a portion of the islands. Association of Southeast Asian Nations

(ASEAN) claimants have agreed to negotiate as a single body with China on the resolution of the Spratly

Islands dispute, although China has been seeking bilateral agreements with the various claimants. Relations

between the various claimants are governed by the November 2002 Declaration on the Conduct of Parties in

the South China Sea, signed between ASEAN member-states and China.

Owing to China's growing power in its dealing with international energy companies, it has been able to

shape the Spratly Islands debate on its terms. For example, in July 2008, China pressured ExxonMobil to

end an exploration deal with Vietnam in the South China Sea, warning ExxonMobil executives that future

business interests in China would be imperilled by the furthering of the Vietnam project. Similarly, BP

suspended seismic surveys in Block 5.2 in the Vietnamese waters of the South China Sea, bordering the

Spratly Islands, in June 2007. The fact that China now possesses an unofficial veto in energy exploration

and production in the waters surrounding the Spratly Islands forces us to take the view that it is very

unlikely that Malaysia will be able to entice major IOCs with licences or concessions in the Spratly Islands,



as such firms would not be willing to sacrifice a stake in the Chinese market for as-yet unquantified

resources.

Table: Key Upstream Players

Company Oil/liquids production ('000b/d) Market share (%) Gas production (bcm) Market share (%)

Petronas* 449 61 41.1 65.5

ExxonMobil Malaysia 48 7 5.3 8.6

Shell Malaysia 40 5 8.3 13.5

Murphy Oil 76.3 10.3 0.01 na

Talisman Malaysia 32 4 0.65 1

Hess na na 0.2 0.3

*FY ended March 31 2010; na = not available/applicable. Source: BMI, Company data 2009

Table: Key Downstream Players

Company Refining capacity('000b/d)

Market share(%)

Retailoutlets

Market share(%)

Petronas/Petronas Dagangan 217* 46 925 43

Shell Malaysia 109 23 900e na

ExxonMobil Malaysia 86 18 540 na

Caltex Oil Malaysia na na 420 na

ConocoPhillips 61 13 na na

LTAT (Armed Forces Fund Board, formerly BPMalaysia) na na 240 na

*Total of 278,000b/d less Conoco's 61,000b/d share of Melaka II capacity; na = not available/applicable; e = estimate.Source: Company data 2009

Oil And Gas Infrastructure

Oil Refineries

Malaysia has five oil refineries, providing a combined capacity of about 578,000 barrels per day (b/d), and a

gas-to-liquids plant with a capacity of 14,700b/d. Three of the refineries are operated by Petronas (Melaka

I and II and Kertih), one by Shell's Malaysian unit and one by Petron. Three mega-refineries have been

proposed that could raise Malaysia's refining capacity by 800,000b/d but their progress have been stalled for

various reasons.



Table: Refineries In Malaysia

Location Name Capacity, b/d StatusOperation

Date Main Owner

Port Dickson Petron Port Dickson 88,000 Active 1963 Petron

Terengganu Kertih 49,000 Active 1982 Petronas

Malacca Melaka-II (PSR-2) 171,213 Active 1998 Petronas

Malacca Melaka-I (PSR-1) 100,000 Active 1994 Petronas

Port Dickson Port Dickson 156,000 Active 1963 Royal Dutch Shell

Sarawak (Bintulu) Bintulu GTL 14,700 Active 1993 Royal Dutch Shell

Total 578,913

Proposed Capacity

Johor KPTC-MIRPD 150,000 Proposed 2018Kuokuang

Petrochemical

Johor RAPID 300,000 Proposed 2017 Petronas

Kedah Yan 350,000 Proposed N.A.Merapoh

Resources

Total 800,000

na = not available. Source: BMI, Company data



Existing Refineries

Melaka (PSR-1): PSR-1 is based in Melaka and is owned by Petronas' subsidiary Petronas Penapisan

(Melaka) Sdn Bhd. It has a refining capacity of 100,000b/d and processes sweet crude and condensates. It

came into operation in 1994.

Melaka II (PSR-2): The Melaka II refinery, located on the same site as the Melaka I facility, is owned by

the Malaysia Refining Company, a joint venture between Petronas and Phillips66. It is operated by

Petronas Penapisan. Melaka II is currently Malaysia's largest refinery, which, following expansion works in

2010, raised the plant's capacity by 45,000b/d. It now has a capacity of 170,213b/d. PSR-2 processes

medium, high sulphur crude that is mostly sourced from the Middle East. Phillips66 is reportedly

considering the sale of its 47% stake in the refinery, though this was not confirmed at the time of writing.

Petron Port Dickson: One of two refineries in Port Dickson, Negeri Sembilan, the 88,000b/d refinery was

established in 1963. San Miguel's Petron acquired the refinery from ExxonMobil in August 2011.

The refinery processes mainly light and sweet crudes and its product slate includes gasoline, jet fuel, diesel,

liquefied petroleum gas and low-sulphur residual fuel oil.

Shell Port Dickson: Shell's Port Dickson refinery is the bigger of the two in the area with a licensed

production capacity of 156,000b/d. Most of its output is consumed within Malaysia. It was also established

in 1963. Its product slate includes gasoline, jet fuel, diesel, sulphur, liquefied petroleum gas and propylene.

In 2011, Shell announced that it would invest MYR800mn (US$247.7mn) to construct a diesel processing

plant as part of an upgrade programme. This would increase the plant's production of diesel. The diesel unit

was officially launched in June 2013, though it had begun commercial production four months earlier in

February.

Kertih: Kertih is operated by Petronas Penapisan and is based in the northern state of Terengganu. It has a

refining capacity of about 49,000b/d and mainly uses local light, sweet crude for feedstock.

The refinery is part of a wider integrated petrochemical complex in the Petronas Petroleum Industry

Complex.



Bintulu Gas-to-Liquids (GTL): Shell's Bintulu GTL plant - also known as Shell Middle Distillate

Synthesis (SMDS) plant - is its first in the world. Based in Bintulu, Sarawak, the plant is located near gas

fields and converts gas into synthetic petroleum products. The GTL plant opened in 1993 when and is

capable of converting 3.92mn cubic metres per day of gas into 14,700b/d of transport fuels and products

such as naphtha, kerosene, detergent feedstock and waxes.

Bintulu GTL is a joint venture between Shell, Mitsubishi, Petronas and the state government of Sarawak. In

2011, a company representative revealed that the plant was to expand its output to 29,400b/d - a doubling of

its original capacity of 14,700b/d.

Proposed Refineries

Yan: In July 2009, special purpose vehicle Merapoh Resources announced that it had secured investment

in a US$10bn refinery in Sungai Limau, Yan, in the state of Kedah. The refinery was to be linked to the

Trans-Peninsular Pipeline Project. The plant would be designed to process imported crude oil into refined

products for export, mainly to East Asia. The proposed facility would have a capacity of 350,000b/d and

was slated for completion in 2013-2014. Engineering, construction and maintenance contracts had

been awarded to South Korea's SK Engineering & Construction.

According to Merapoh, China National Petroleum Corporation (CNPC) was named as a strategic partner

and was to buy 200,000b/d of the refinery's output under a 20-year deal. Saudi Aramco, which would be

the main supplier of feedstock. CNPC and Merapoh signed a memorandum of understanding (MoU) on the

project in 2007, which was followed by a 20-year marketing agreement in July 2009.

Technical and financial difficulties had forced a suspension of the project. However, in June 2013 the

Kedah state government was reportedly looking to restart the development. A feasibility study was to be

conducted on it. It is part of the Kedah ruling party's plan to rejuvenate the Sungai Limau Hydrocarbon Hub

project - previously known as Yan Petroleum Industrial Zone, although local representative Datuk Paduka

Mukhriz Tun Mahathir stated that 'it is not needed for the time being' and 'the state is in no rush to restart it'.

We have not included the refinery in our forecasts.

KPTC Malaysia Integrated Refinery & Petrochemical Development (KPTC-MIRPD): Taiwan's

Kuokuang Petrochemical Technology Co - which is majority-owned by China Petroleum Corporation

(CPC) - has proposed a refinery and petrochemical complex to be based in Pengerang, Johor. The project

aims to develop southern Johor into a refining and petrochemical study and is part of Malaysia's Economic



Transformation Programme to propel the economy forward through greater private sector participation and

investment.

The proposed capacity of this refinery is 150,000b/d, which would make it one of the three largest plants in

the country assuming that Petronas' RAPID development is also brought on-stream. The Taiwanese firm is

targeting a 2018 operational date.

According to Kuokuang, the refinery will have a crude distillation unit, a naphtha cracker and an aromatics

unit. It is eyeing Saudi crude as feedstock and will produce both light oil products and petrochemicals.

Although it has obtained a detailed environmental impact assessment (DEIA), Kuokuang's refinery plans

are coming under fire from the local community, who have concerns about the effects of the refinery. A

similar project by Kuokuang was proposed for Taiwan but was put down for the same reason. We have not

included this refinery in our forecasts as the plant is still awaiting a final investment decision (FID).

In August 2013, an official from Kuokuang Petrochemical Technology Co reported that the company had

scrapped plans to set up the integrated refining and petrochemical complex in Pengerang due to poor project

economics. The official said that: 'It was meant to be using naphtha as a feedstock to produce ethylene, but

because of the rise of shale gas as an alternative, the costs will be too high [to compete with other projects]

and we won't be able to export the products' (Platts).

Refinery And Petrochemicals Integrated Development (RAPID): Petronas announced plans for a

300,000b/d plant to be based in the southern-most state of Johor in 2011. This refinery will be part of a

wider petrochemical complex in the town of Pengerang and would produce Euro-4 and Euro-5 compliant

gasoline and diesel, in addition to naphtha and liquefied petroleum gas. Naphtha produced would be fed into

petrochemical plants within the vicinity.

Several companies have been contracted to work on the refinery including Technip, which has scored a

front-end engineering and design (FEED) contract. Petronas expects to spend US$20bn on the total cost of

developing the wider RAPID petrochemical complex. In October 2013, despite the absence of a FID,

Petronas has invited tenders under packages 16A and 17 of the Refinery and Petrochemicals Integrated

Development (RAPID) project situated in Johor, Malaysia. The packages include engineering, procurement,

construction and commissioning of an effluent treatment facility and a waste management hub for the

project.

The plant is part of Malaysia's plan to make Johor a major oil and gas hub in the region, alongside

Kuokuang's KPTC-MIRPD project. Despite an original start-up target of 2016, a FID remains to be made



for the plant to go ahead. In June 2013, Petronas announced that it has pushed back its start-up date to 2017,

following local opposition to the project arising from the dislocation it has brought to local communities. In

addition, Petronas CEO Sri Datuk Shamsul Azhar Abbas also cited difficulty in securing water supply as

one of the reasons for the project's delay.

At the time of writing, a FID was yet to be made for the project, though Petronas assured that it would take

place soon. The economic importance of the project to the government's plan makes it likely that Petronas

will go through with the project and the NOC told Reuters in July 2013 that it will push back the project's

start-up date to 2018. However, while we believe the project will go ahead, we think that downside risk

exists to its construction, or that the project could be a scaled down version of the initially planned project.

The debate over economics of oil versus gas in petrochemical production could be a key determinant of the

project. The prospect of petrochemical growth in the US on the back of cheap gas feedstock and also in the

Middle East could be a threat to the margins that RAPID could make, particularly from 2017 onwards.



Oil Storage Facilities

Malaysia has a number of oil storage facilities and has been able to take advantage of the lack of expansion

space in neighbouring Singapore to increase its capacity, particularly in the south of the country. According

to the Financial Times, the government had offered a 3.0% tax rate for trading companies and zero tax for

companies - versus a 5.0% tax rate in Singapore - to incentivise the construction of storage capacity on the

peninsula in a bid to compete with its cross-strait neighbour for title of the regional oil storage hub.

Table: Oil Storage Facilities In Malaysia

Name Location Owners Capacity (bbl) Type Status

Sapangar Bay SabahSabah Ports Sdh

Bhd 220,143Refined petroleum

products Operational

Assar Oil Terminal SarawakAssar Senari Port

Sdh Bhd 3,144,900Refined petroleum

products Operational

Tysun Johor

TitanPetrochemical

Group 2,012,740 Crude Operational

Tanjung Bin Johor VTTI 5,597,931Crude and refined

petroleum products Operational

Tanjung Langsat Johor

Puma Energy,Dialog Group,MISC Berhad 2,515,900

Crude and refinedpetroleum products Operational

Port Klang SelangorZinol Universal

Lubricants 157,250 Base oil Operational

GurunHydrocarbon HubArea Kedah Pristine Oil Capital 12,580,000

Crude and refinedpetroleum products Construction

Pengerang Johor

Vopak, DialogGroup, State

Government ofJohor 8,176,800

Crude and refinedpetroleum products Construction

Tanjung Bin PhaseII Johor VTTI 5,031,800

Crude and refinedpetroleum products Planned

Pengerang Phase II Johor

Vopak, DialogGroup, State

Government ofJohor 6,289,800

Crude and refinedpetroleum products Proposed

Tanjung Piai Johor Abu Dhabi 60,000,000Crude and refined

petroleum products Proposed

Source: BMI



Tanjung Bin ATB Oil Terminal

The ATB oil terminal, located in Tanjung Bin, come online in early 2012 and welcomed its first oil tanker

in April 2012. The terminal is owned and operated by VTTI, a 50/50 venture between the Vitol Group and

Malaysia conglomerate MISC Berhad. In its first phase of construction, the facility's 41 oil storage tanks

provides for 840,000 cubic metres (cm), or 5.60mn bbl, of fuel oil, gasoline and middle distillates.

Work on the next phase has begun and development of a further 20 hectares of land will allow for an

additional 800,000cm (5.03mn bbl) of storage, which was to come online by 2014.

Langsat Terminal One

In February 2010, the Langsat Terminal One oil storage facility, in the southern Johor state, was officially

opened. The MYR500mn (US$147mn) facility is part of a tripartite venture between MISC Berhad, Dialog

Group and PUMA (a subsidiary of Trafigura). Under the first phase of development, seven 130,000cm

(817,675bbl) tanks were opened in September 2009 for the exclusive use of Trafigura (which has a 20%

stake in the project) and have since been used to store naphtha and diesel. A further 13 tanks with a total

capacity of 270,000cm (1.7mn bbl) were due to have been commissioned in mid-March 2010, bringing total

capacity to 400,000cm (2.5mn bbl).

Plans for a third 80,000cm (503,185bbl) phase for terminal one and a 176,000cm (1.1mn bbl) second

terminal (also mainly for Trafigura's use) are progressing. The Langsat terminal is only 48km from

Singapore, allowing it to take advantage of constrained spot storage capacity there.

Pengerang

In line with government plans to develop Pengerang as a regional oil and gas hub, Vopak and Dialog Group

made a FID to build and operate a storage terminal in the Johor town in June 2011. Initial storage capacity

will be 1.3mn cubic metres (Mcm) (8.18mn bbl) which is scheduled to come online in 2014, and can be

further expanded to accommodate an additional 1Mcm (6.29mn bbl) in the future. It will handle both crude

and refined petroleum products.



Tanjung Piai

Abu Dhabi expressed interest in a MYR21bn (US$6.75bn) oil storage facility in Johor in March 2013. It

signed an agreement with the state's government and envisions a capacity of 60mn bbl. Further details were

not available at the time of writing.

Oil Terminals/Ports

Malaysia has oil tanker terminals at Lumut (Perak), Port Dickson, and Kerteh, all in peninsular Malaysia.

There are also three terminals on the island of Borneo: Bintulu, Lutong and Labuan Bay.

The Labuan Crude Oil Terminal, located in Labuan Bay on Borneo, is owned by Sabah Shell Petroleum

Company Ltd. The terminal deals with all crude oil produced from Shell and Petronas platforms offshore

Sabah and exports oil via tankers that are loaded by single buoy mooring systems. The terminal is operated

by Petronas.

A project to construct a new terminal at Kimanis, Malaysia's easternmost province of Sabah, was

announced in January 2007. The Sabah Oil And Gas Terminal (SOGT), originally expected to be complete

in 2010, has been delayed to 2014. When on-stream, the terminal will have a capacity of 300,000b/d of oil

and 10bcm of gas. The SOGT will receive, process, store and export oil from nearby offshore oil fields such

as Gumusut. South Korea's Samsung Engineering was awarded a US$770mn contract by Petronas Carigali

in September 2010 to build SOGT. The contract will include engineering, procurement, construction and

commissioning services for the terminal and is expected to be completed in December 2013.

Another oil terminal project in the works is the Pengerang oil terminal in Johor as the town builds up its

status as the regional oil and gas hub. Like the storage facility, this terminal is being developed by a joint

venture between Vopak and Dialog, in conjunction with the state government of Johor. The terminal is to

come online in 2014.



Oil Pipelines

Malaysia does not have any major oil pipelines. The most notable project that has been proposed is the

Trans-Peninsular Pipeline project (TransPen), which would link the Andaman Sea and the Gulf of Thailand,

and a Thailand-Malaysia pipeline.

Trans-Peninsular Pipeline (TransPen)

The TransPen pipeline was proposed as a means to establish a new oil transport route between the Middle

East and the South China Sea, so as to avoid the chokepoint of the Malacca Straits where there is a risk of

piracy. It would be a 300km oil products pipeline through northern Malaysia that would transport refined

products produced in the proposed Yan refinery in the northern state of Kedah to the city of Bachok in

Kelantan along the north east coast of Malaysia. Bypassing the busy Malacca Strait, TransPen would cut

three days off the oil transit time between the Middle East and China. The project was estimated to cost US

$7bn.

According to Asia Port, TransPen is to be completed in two phases over a seven-year period from the start

of construction. The first phase would be capable of transporting 2mn b/d of oil, roughly 17% of the daily

volumes passing through the Malacca Strait. The pipeline's capacity would then be expanded by an as-yet

unspecified amount during the second phase. CNPC and Merapoh signed an MoU on the project in 2007,

which was followed by a 20-year marketing agreement in July 2009. The two firms also held discussions

with Bangkok over a potential pipeline link between Thailand and the TransPen project.

However, financial problems faced by Merapoh in funding the Yan refinery project had also brought the

TransPen pipeline to a standstill. An internal US document leaked by Wikileaks had suggested that this was

more a pipedream than a realistic project. The revival of the Yan refinery, as suggested in June 2013, could

perhaps revive the TransPen project though there were no updates on this at the time of writing.



LNG Liquefaction Terminals

Table: Malaysia LNG Liquefaction Terminals

Name Location Status TypeCapacity (mn

tpa)Capacity

(bcm) Owners Start-Up Date

MLNGSatu

Bintulu,Sarawak Operational Onshore 8.40 11.59

Petronas, SarawakGovernment,

Mitsubishi 1983

MLNGDua


Petronas, Shell,Mitsubishi, Sarawak

Government 1995

MLNGTiga


Petronas, JX Nippon,Diamond Gas, Shell,

SarawakGovernment 2003

PetronasFLNG

Bintulu,Sarawak Construction FLNG 1.20 1.66 Petronas 2015

MLNGTrain 9

Bintulu,Sarawak Construction Onshore 3.60 4.97 Petronas 2016

Rotan Sabah Awaiting FID FLNG 1.50 2.07 Petronas 2016

Source: BMI

Malaysia's LNG exports take place through three LNG terminals at a complex in Bintulu, Sarawak. The

complex, known as Malaysia LNG (MLNG), is the world's biggest LNG centre with an aggregated

production capacity of 25.7mn tpa (35.5bcm) spread across a total of eight trains. The three terminals

receive gas from the Central Luconia area between 125km and 275km offshore Bintulu. The terminals are

run by Malaysia's Bintulu Port Holdings, an investment holding company.

MLNG Train 9 & Petronas FLNG

As part of its plans to boost LNG production, Petronas is expanding the MLNG complex by adding a ninth

train that is expected to come online in 2016. To tap offshore gas developed in marginal and stranded fields,

the NOC is investing in a floating LNG liquefaction terminal located off the coast of Bintulu. At 1.2mn tpa

(1.66bcm), it is a relatively small facility but will help unlock reserves that were previously deemed

uneconomical to develop. It cut first steel in June 2013 in South Korea and its construction will be overseen

by Daewoo Shipbuilding & Marine Engineering (DSME) and Technip, which won the EPCI contract for

it in June 2012. It is expected to be commissioned in 2015 and would be one of the world's first FLNG

liquefaction plants.



Rotan FLNG

Petronas is looking into a second FLNG project offshore Sabah, to service gas from the Rotan field in Block

H. Front-end engineering and design (FEED) is currently being conducted for this, as the NOC aims to

bring this 1.5mn tpa (2.1bcm) plant on-stream by 2016.

A FID for Rotan FLNG is expected to be made within 2013. Two consortiums will be competing for the

EPCI contract when the FID is made: one consisting of MODEC Inc, IHI Corporation, Toyo

Engineering Corporation and CB&I, and another that comprises JGC Corp and Samsung Heavy

Industries.



LNG Import Terminals

Table: Malaysia LNG Regasification Facilities

Name Location Status Type Capacity (mn tpa) Capacity (bcm) Owners Start-Up Date

Melaka Malacca Operational Onshore 3.80 5.24 Petronas 2013

Pengerang Johor Proposed Onshore 3.80 5.24 Petronas 2016

Lahad Datu Sabah Proposed Onshore 0.74 1.02 Petronas 2016

Source: BMI

Melaka LNG

Melaka LNG (formerly known as Sungai Udang) came online in 2013, after nearly a year's delay from its

start-up date of August 2012. The facility has a receiving capacity of 3.8mn tpa, equivalent to 5.2bcm.

In June 2009, Australian gas producer Santos signed a 20-year deal to supply Petronas with 2mn tpa

(2.76bcm) of LNG from the Gladstone LNG export terminal in Queensland from 2015. Qatar's state-run

Qatargas struck a LNG sales agreement with Petronas in July 2011. The two firms signed an HoA in Doha,

under which Qatargas will export LNG cargoes to Malaysia for at least 20 years, starting in 2013, from its

Qatargas-2 plant. Qatargas has agreed to deliver 1.5mn tpa of LNG, equivalent to 2.05bcm of dry gas and

about 5% of Malaysia's annual gas demand.

New Proposed Terminals

Two other LNG import terminals, located in Pengerang (Johor) and Lahad Datu (Sabah) are expected to

come on stream in 2016. A consortium consisting of Dialog Group, the Johor government and Royal Vopak

will jointly develop an LNG storage, loading and regasification terminal as part of the wider development of

Pengerang. The terminal will import LNG for trading purposes as well as for domestic consumption. FIDs

for these regasification terminals are expected in 2014.

Gas Pipelines

The main domestic gas pipeline in Malaysia is the Peninsular Gas Utilisation (PGU), owned by Petronas

subsidiary Petronas Gas. The 35km first phase of the PGU (PGU I) was completed in 1984 and links Tok

Arun with a 2.58bcm gas processing plant in the port of Kerteh in the north east of the country. The second



phase (PGU II) extends this pipeline southwards to the town of Segamat in Johor state before it runs south

east to Pasir, where it branches into two sections - linking to Gudang and Johor Bahru - and thereafter to

Singapore across the Straits of Johor.

Another branch of the PGU II runs north west along the Malacca Straits to Serdang, just north of Kuala

Lumpur. The pipeline links three 2.58bcm gas processing plants and has a total length of 714km. PGU II

was completed in 1992. The third phase (PGU III) extends the north-western branch of PGU II to near

Kangar and includes two gas processing plants, each with a capacity of 5.16bcm, and a 5.16bcm Dew Point

Control Unit.

The three sections of the PGU pipeline are supported by two additional loops, PGU Loop 1 and PGU Loop

2, which run from Kertih to Segamat (265km) and from Segamat to Meru (227km) respectively. There is

also a multi-product pipeline, known as PGU IV, which runs from Dengkil in the north to Melaka in the

south via Port Dickson, where it is linked to PGU II.

Trans-Thailand-Malaysia Gas Pipeline System

The PGU is linked to an international pipeline known as the Trans-Thailand-Malaysia Gas Pipeline System,

which starts at the town of Changlun in Kedah state. The pipeline links offshore fields in the Malaysia-

Thailand joint development area to Malaysia, coming ashore north of Songkhla in Thailand, running south

for 86km to the Thailand-Malaysia border, and linking into Malaysia's PGU system through a 9km

interconnector in Perlis State.

In July 2013, the engineering and construction contract for the pipeline was awarded to Malaysia's largest

oilfield services firm SapuraKencana for a period of three years.

Malaysia-Singapore Gas Pipeline

The 1.55bcm Malaysia-Singapore pipeline is the southern extension of the PGU II spur to Johor Bahru and

was the first cross-border pipeline in the Association of Southeast Asian Nations.



Competitive Landscape

Competitive Landscape Summary

■ State-controlled Petronas accounts for around two-thirds of the country's oil and gas production, almost60% of the country's refining capacity and 30% of the fuels market through its Dagangan subsidiary.

■ Petronas Carigali is the principal upstream unit and works alongside a number of international oilcompanies (IOCs) and independent oil companies through production sharing contracts (PSCs) to exploitMalaysia's hydrocarbons resources. The unit is highly active internationally, taking operatorship positionsas well as junior partner roles in key exploration provinces. The Petroleum Management Unit of Petronasacts as resource owner and manager of Malaysia's domestic oil and gas assets, managing the effectiveexploitation of hydrocarbon resources.

■ Petronas has set up a subsidiary, which is to manage the firm's operations in small, marginal and maturefields. Also known as Vestigo Petroleum, its attention on marginal fields will allow the parent companyto focus on 'larger and more technically complex' field developments as the firm looks further into thecountry's underexplored deepwater potential.

■ Shell's 2012 net oil production was 41,000 barrels per day (b/d), plus 5.9bn cubic metres (bcm) of gas.The group operates a refinery at Port Dickson, as well as more than 900 retail outlets providing an almostone-third market share. Shell and Petronas have signed two new PSCs for enhanced oil recovery (EOR)projects offshore Sarawak and Sabah, Malaysia. The companies are planning to jointly spend US$12bnover a 30-year period and are targeting a near 14% increase in recovery factors.

■ At the end of 2012, US-based ExxonMobil operated 43 platforms in 17 fields in the Malaysian upstreamsegment, making it one of Malaysia's key suppliers of crude oil and natural gas. The group produced a net40,000b/d of oil/gas liquids and 3.9bcm of gas in 2012. ExxonMobil's EOR project at the Tapis field,which lies 118 miles off Terengganu in 210 feet of water, is due for completion in 2013/14. Tapis is oneof seven mature fields offshore peninsular Malaysia that ExxonMobil and Petronas have agreed todevelop as part of a 25-year PSC that was finalised in June 2010. Philippines-based downstream oil groupPetron has completed the acquisition of ExxonMobil International Holding's downstream oil business inMalaysia.

■ In October 2013, US independent Newfield Exploration agreed to sell its Malaysian interests toSapuraKencana Petroleum Bhd for US$898mn. The deal was expected to close in early 2014.Newfield is currently the fourth largest oil producer in Malaysia.

■ Chevron operates the Caltex network of around 420 fuel retail sites and has a target of opening up to 30new retail sites annually. The company also operates three terminals in Malaysia: Pulau Indah, Prai and ajoint venture in Pasir Gudang.

■ Murphy Oil's net oil production in 2012 was an average of 52,663b/d, while gas production was 2.2bcm.Murphy has majority interests in and acts as operator of six separate PSCs covering approximately 6.7mngross acres. It has an 85% interest in discoveries made in two shallow-water blocks, SK 309 and SK 311,offshore Sarawak. The company has a gas sales contract for gross volumes up to 2.58bcm per annumfrom the Sarawak area with Petronas and has prepared a multi-phase development plan for several naturalgas discoveries on these blocks.

■ Talisman Energy is a 41% stakeholder in the offshore PM-3 CAA development area between Malaysiaand Vietnam. In 2012, production in Malaysia averaged 36,800boe/d, which accounted for approximately29% of Talisman's total South East Asia production. Six development wells were drilled in Malaysia in2012, one of which was a water injector.



■ ConocoPhillips' upstream involvement in Malaysia currently comprises interests in three deep waterblocks off the eastern state of Sabah, namely Block G, Block J and the Kebabangan Cluster. These threeblocks include eight discovered fields in various stages, ranging from appraisal to developmentexecution. ConocoPhillips also has a 47% interest in the 162,000b/d Melaka II refinery, together withPetronas, from which it receives around 76,000b/d of output.

Table: Key Players - Malaysian Energy Sector

Company 2011 Sales(MYRbn)

% Share OfTotal Sales

No. OfEmployees

YearEstablished

Total Assets(MYRbn)

Ownership (%)

Petronas 222.8* 60 36,027 1974 477.6* 100% state

ExxonMobilMalaysia na 1.8 2,000 1961 na 100% ExxonMobil

Shell Malaysia na 1.9 7,000 1911 na 100% RD Shell

Caltex Oil Malaysia na 0.3 250 1937 na 100% Chevron

ConocoPhillips na 0.1 200e na na 100%ConocoPhillips

Murphy Oil 6.8 49 400 1999 na 100% Murphy Oil

Hess na na 80e 1998 na 100% Hess

Talisman Energy na na na na na 100% Talisman

*Figures reflect performance from April 1 to December 31, due to changed in financial year end; e = estimate; na = notavailable. Source: BMI, Company data



Company ProfilePetronas

SWOT Analysis

Strengths ■ Biggest domestic oil producer.

■ Unrivalled access to exploration acreage.

■ Operates national refining system.

■ Substantial share of fuels distribution segment.

■ Well-established partnerships with IOCs.

Weaknesses ■ Limited financial or operational freedom.

■ Some cost and efficiency disadvantages.

■ Medium-term decline in crude production.

■ Rising investment requirement.

Opportunities ■ Considerable untapped gas export potential.

■ Rising domestic energy consumption.

■ New marginal fields strategy.

■ Large areas of under-explored territory.

Threats ■ Long-term fall in domestic oil production.

■ Competition in regional LNG supply.

■ Changes in national energy policy.

Company Overview State-owned Petronas not only dominates the Malaysian energy sector, but has

become one of the most successful national oil companies in terms of geographical



diversification. It has fully integrated oil and gas operations, beginning with the

exploration for and development and production of crude oil and natural gas, both in

Malaysia and overseas. It is a significant player in liquefied natural

gas (LNG) processing, transport and sale, and has extensive gas pipeline interests. The

Petronas refining and marketing arm is the key player in the domestic market, with

diversification into petrochemicals.

Strategy Petronas has long been planning a major strategic review of its extensive asset portfolio

and is expected to place greater emphasis on developing domestic oil and gas

prospects. This could result in a reduction in international exploration and production

(E&P) investment and a consequent downsizing of the global upstream portfolio.

Malaysia would like to see a higher level of domestic E&P activity to boost energy self-

sufficiency. Petronas may eventually limit its global presence to large stakes in key

hydrocarbons plays.

Petronas Carigali has announced the formation of a new subsidiary, Vestigo Petroleum,

according to Oil Voice. The new unit will be charged with developing and producing its

parent's small, marginal and mature fields in Malaysia and overseas. Petronas Carigali

President Datuk Mohr Anuar Taib said Vestigo would enable the corporation to 'pursue

additional growth areas … through strategic partnerships' and establish itself through

the cultivation of technical and executional capabilities. Its attention on marginal fields

will allow parent company Petronas Carigali to focus on 'larger and more technically

complex' field developments as the firm looks further into the country's underexplored

deepwater potential.

This streamlining of operations will allow Malaysia's marginal fields to be given due

attention as high oil prices and technological advancements improve the economics of

developing these fields, which the country defines as fields with 30mn barrels of oil

equivalent (boe) or less. Petronas had previously cited oil prices of US$55-60/bbl as the

minimum breakeven cost needed to produce from these fields. According to Petronas,

there are 106 marginal oil fields in Malaysia and together they hold about 580mn bbl of

oil - more than 10% of existing oil reserves as recorded by the US Energy Information

Administration (EIA) as of the start of 2013.

Local fuels distributor Petronas Dagangan is to continue pursuing a growth strategy to

increase its market share in petroleum products and improve profitability, while also

investing in higher yielding businesses. Investment is going towards its fast-growing

and profitable retail business to build and upgrade its service stations, while the

remainder is for added investments in its commercial, LNG and lubricants businesses.

Shell and Petronas have signed two new PSCs for enhanced oil recovery (EOR) projects

offshore Sarawak and Sabah, Malaysia. The companies are planning to jointly spend US

$12bn over the next 30 years and are targeting a near 14% increase in recovery factors.

The Sarawak project includes the Bokor, Bakau, Baram, Baronia, Betty, Fairley Baram,



Siwa, Tukau and West Lutong oil fields in the Baram Delta. The North Sabah project

involves the St Joseph, South Furious, SF30 and Barton fields.

Petronas will be the operator of the Baram Delta EOR PSC with a 60% stake, working

alongside partner Shell with the remaining 40%. Meanwhile, Shell will be the operator of

the North Sabah EOR PSC with a 50% stake, working alongside partner Petronas with

the remaining 50%.

On March 5 2012, Petronas and Germany's BASF signed a heads of agreement for the

development of the refinery and petrochemical integrated development complex in

Pengerang. Petronas had been seeking an international partner for the project since it

was first proposed on May 13 2011. Under the terms of the agreement, the two

companies will form a new joint venture to develop, build and operate the plant. BASF

will be the main stakeholder with a 60% interest, leaving Petronas with the remaining

40%. The integrated petrochemicals complex will include a 300,000 barrel per day (b/d)

crude oil refinery, a naphtha cracker that will produce 3mn tpa of ethylene, C4 and C5

olefins, plus facilities for isononanol, highly reactive polyisobutylene, non-ionic

surfactants, methanesulfonic acid, as well as a gas-fired power plant to supply the site.

In July 2012, Petronas agreed to buy Canadian natural gas producer Progress Energy

Resources for CAD5.5bn, marking the latest foray into the North American energy patch

by an Asian company. Petronas also said it plans to build an LNG export terminal in

Prince Rupert, British Columbia, off Canada's western coast.

For Petronas, the deal represented its biggest foreign acquisition attempt so far,

surpassing its US$2.5bn purchase in 2008 of 40% the Gladstone LNG project in

Australia. The deal received approval from the Canadian government, which rules on big

foreign takeovers based on whether they will have a 'net benefit' for the country. The

deal gave Petronas control over Progress Energy's fields in the Montney shale-gas

basin in north-east British Columbia. Thought to be one of the richest shale-gas basins

in North America, the basin also is one of the farthest from major markets, making it

ideal for LNG.

Petronas and its PSC partners are aiming to increase their capital expenditures (capex)

to US$59bn over the next five years, as part of an effort to increase E&P in the hope of

raising output. Petronas' vice president, Datuk Wee Yiam Hin, said in October 2012 that

'capex has never been this high', adding that the company will bear 'about 70%' of this

investment and 'the bulk of it will be for [E&P]'.

Petronas in December 2012 awarded a PSC for Block SB311 offshore Sabah to a

partnership of ConocoPhillips, Sabah Gas, Shell Energy Asia and Petronas Carigali. The

block, measuring 1,046 sq km, is located in the central part of the Sabah Basin in water

depths ranging from 50 to 100 metres. The area is located within a proven hydrocarbon

fairway with key discoveries such as Kebabangan, Kinarut, and Erb West. Under the

terms of the PSC, ConocoPhillips will operate the block with a participating interest of

40%. Petronas Carigali and Shell Energy Asia will each own a 30% interest in the block.



For the SB311 PSC, the partners are committed to drill two wildcat wells, acquire 400

line km of new 2D seismic data and re-process existing 3D seismic data on the block.

Petronas aims to further develop more challenging fields in a sustainable process that

will help boost oil output in the face of dwindling reserves and growing demand, the

2012 annual report of the Economic Transformation Programme (ETP) said. It said the

company and its production sharing contractors are expecting consistent drilling and

offshore exploration over the next five years and plan to increase investment in

capability building.

The report said that Petronas will enhance investment in extensive subsea oil and gas

pipelines to enable fields in more diverse locations to be monetised. It said that while

Singapore dominates the oil storage business in Asia, Malaysia is well placed to tap into

the physical oil trade and derivatives trade that Singapore has built up. It added that this

hub could be similar to Amsterdam-Rotterdam Antwerp (ARA), complementing each

other in refining and petrochemical activities, independent storage, bunkering and

blending, as well as enjoying market access to customers in the growth markets of

China, India and South East Asia.

Petronas is planning to invest some MYR15bn in the state over the next five years to

increase the production of LNG, says Malaysia LNG Group of Companies (MLNG)

managing director and chief executive officer Zakaria Kasah. Speaking at the launching

ceremony of Biodiversity, Environment and Conservation (Beacon) project in April 2013,

he said Petronas, through its subsidiary MLNG, would implement more than 10 capital

projects in Bintulu within the next five years.

'One of the projects is the Train 9 project, which is a new LNG processing plant with a

capacity of 3.6mn tpa. This new processing train will be able to increase Petronas LNG

Complex (PLC) production capacity to 29.3mn tpa by 2016 from 25.7mn tpa

currently.' MLNG would also undertake various plant improvements and value creation

projects in the PLC to sustain and enhance its production capacity, added Zakaria.

He said with the increase in the LNG production, it would help to increase the state's

revenue as the demand of LNG, which is viewed as a more cost-effective and cleaner

source of energy, is in the rise. The 276-hectare PLC currently produces 25.7mn tpa of

LNG and contributes some 40.5% to Sarawak's gross export, 6% to Malaysia's total

export and 4.2% to the national Gross Domestic Product (GDP).

Japan-based JX Nippon Oil & Gas Exploration Corporation has signed a PSC with

Petronas for Deepwater Block 2F offshore Malaysia. Under the terms of the PSC, JX

Nippon will acquire a 40% interest in Block 2F, which covers an area of around 5,500sq

km and is located in north-west Sarawak. Subsequent to the acquisition, JX Nippon will

become the operator of the block, while Petronas will hold a 40% stake and GDF Suez

E&P Malaysia the remaining 20%.

Petronas said it is exiting one of the biggest petroleum projects in Venezuela's Orinoco

belt, after what sources close to the venture and within the firm said were

disagreements with Venezuelan authorities and state-run PdVSA. The flagship project,



called Petrocarabobo, has planned investments of about US$20bn over 25 years and

calls for building a 200,000b/d upgrader to convert heavy crude into light oil.

The company is planning to build a Canadian LNG terminal located in Prince Rupert,

British Columbia. It will process natural gas extracted by subsidiary Progress Energy

and ship it through a pipeline built by TransCanada Corporation, according to the

project's website. Petronas will invest CAD36bn to develop the LNG project. This figure

includes Petronas' cost of acquiring Progress Energy, building the terminal and the

pipeline, and completing upstream activities such as drilling wells, said Greg Kist,

president of Pacific NorthWest LNG, the Petronas-owned company that will operate the

LNG terminal. Shipments are expected to begin in 2018, he said.

Petronas in January 2014 reiterated its commitment to rejuvenate mature assets and

develop marginal fields, pledging US$14bn alone on enhanced oil recovery

projects. Petronas' executive vice president for exploration and production business,

Wee Yiaw Hin, said in an interview with local press that about US$14bn is required to

execute 10 EOR projects in the pipeline. Petronas has also set aside MYR1.1bn for its

E&P Technology Centre to develop EOR technology, according to Wee. Wee sees

potential for EOR in 50% of Malaysia's producing fields.

Market Position Owned entirely by the Government of Malaysia, Petronas not only dominates the

Malaysian energy sector, it has become one of the most successful national oil

companies in terms of geographical diversification. It has fully integrated oil and gas

operations, beginning with the exploration for and development and production of

crude oil and natural gas, both in Malaysia and overseas. It is a significant player in LNG

processing, transport and sale, and has extensive gas pipeline interests. The Petronas

refining and marketing arm is the key player in the domestic market, with diversification

into petrochemicals.

Petronas Carigali is the principal upstream unit and works alongside a number of

international oil companies and independent oil companies through production sharing

contracts (PSCs) to exploit Malaysia's not inconsiderable hydrocarbons resources. The

unit is highly active internationally, taking operatorship positions as well as junior

partner roles in key exploration provinces. Petronas' Petroleum Management Unit acts

as resource owner and manager of Malaysia's domestic oil and gas assets, managing

the effective exploitation of hydrocarbon resources.

The Petronas Gas & Power business aims to be a leading integrated gas, LNG and

power player. The unit has been restructured and streamlined into two major portfolios,

namely a Global LNG business and an Infrastructure, Utilities & Power division.

Currently, the LNG unit comprises the production and sale of LNG through domestic

operations in Bintulu, Sarawak and overseas operations in Egypt. Petronas operates

one of the world's largest LNG facilities in Bintulu, which consists of three plants,



MLNG, LNG Dua and MLNG Tiga, with a combined capacity of 24mn tonnes per annum

(tpa).

Petronas is also involved in LNG and energy trading activities through its marketing

arms in Malaysia and Europe. The group commands a sizeable LNG market share in the

Far East, having sold more than 7,000 cargoes since the establishment of its first LNG

plant in 1983.

The group's Infrastructure, Utilities & Power business focuses on ensuring long-term

security and sustainability of the gas market in Malaysia, while expanding its portfolio in

other high growth markets. Through its majority-owned subsidiary, Petronas Gas

Berhad (PGB), the croup operates the peninsular gas utilisation (PGU) system,

comprising six processing plants and approximately 2,505km of pipelines to process

and transmit gas to end-users in the power, industrial and commercial sectors in

peninsular Malaysia. Petronas also exports gas for power generation to Singapore.

The PGU system is the basis for the development of Malaysia's offshore gas fields, the

use of natural gas products for power generation and utilities, and the expansion of the

country's petrochemical industry through the use of gas derivative products, such as

ethane, propane, butane and condensates. PGB is also developing Malaysia's first LNG

re-gasification terminal in Melaka, which was completed in June 2012. This will facilitate

the import of LNG by Petronas and third parties.

Globally, Petronas has investments in pipeline operations in Argentina, Australia,

Indonesia and Thailand, as well as gas storage and LNG re-gasification facilities in

Europe.

In the downstream oil segment, Petronas attempts to add value to its upstream

production activities through refining, marketing and trading activities, as well as in the

production of petrochemicals. Petronas owns and operates three refineries in Malaysia,

two in Melaka (collectively known as the Melaka Refinery Complex) and another in

Kertih (the Kertih Refinery). The first plant in Melaka is 100% owned while the second

facility is 53% owned by the group.

Petronas also has an oil refining presence in Africa through its 80% owned subsidiary,

Engen Petroleum Limited (Engen), a leading South African refining and marketing

company that owns and operates a refinery in Durban, South Africa.

Through Petronas Dagangan Berhad (PDB), a majority-owned subsidiary, the group

markets a wide range of petroleum products, including gasoline, liquefied petroleum

gas, jet fuel, kerosene, diesel, fuel oil, asphalt and lubricants. PDB also has interest in

Malaysia's multi-product pipeline and the Klang Valley Distribution Terminal that

transports gasoline, jet fuel and diesel oil from the refineries to major demand centres in

the Klang Valley. Besides marketing activities, PDB also jointly operates a jet fuel

storage facility and hydrant line system at the Kuala Lumpur International Airport.

Outside of Malaysia, Petronas is active in the fuels segment. PT Petronas Niaga

Indonesia operates retail stations as well as markets petroleum products to industrial



and commercial customers, and manages a network of local lubricant distributors in

Indonesia. In Thailand similar activities are undertaken by Petronas Retail (Thailand) Co,

which also supplies jet fuel to the Don Muang International Airport and the

Suvarnabhumi International Airport, Bangkok. In China and India, the Group's lubricant

products are sold through Petronas Marketing China Company and Petronas Marketing

India, respectively.

In Africa, the Engen subsidiary has the largest retail network in South Africa as well as a

strong retail presence in the sub-Saharan region in countries including Botswana,

Burundi, Kenya, Lesotho, Malawi, Mauritius, Mozambique, Namibia, Réunion,

Swaziland, Tanzania, Zambia and Zimbabwe. Petronas Marketing Sudan Limited is

engaged in the marketing and retailing of petroleum products and lubricants, as well as

owning and operating retail stations. It also provides into-plane service at the Khartoum

International Airport and El-Obeid International Airport.

Petronas first ventured into the production of basic petrochemical products in the

mid-1980s and later embarked on several large scale petrochemical projects with

multinational joint venture partners. These have included Dow Chemical, BASF, BP

Chemicals, Idemitsu Petrochemical Co Ltd, Mitsubishi Corporation and Sasol Polymers

International.

The parent group has now consolidated its petrochemical business under Petronas

Chemicals Group Berhad (PCG). The leading integrated petrochemical producer in

Malaysia and one of the largest in South East Asia, PCG is the listed holding entity for

all of the group's petrochemical production, marketing and trading subsidiaries and has

a total combined production capacity of over 11mn tonnes per annum (tpa).

Malaysia has started production from its Gumusut deepwater oilfield in Block J of the

Sabah basins. Commercial production was delayed from its original start date in 2011

and was expected to reach full production of 135,000b/d by 2013-2014. The field is

operated by Shell, with ConocoPhillips, state-owned Petronas and Murphy Oil each

holding stakes. Output began at 10,000b/d in 2012 following several years of

construction-related delays.

Petronas has invited tenders under packages 16A and 17 of the Refinery and

Petrochemicals Integrated Development (RAPID) project situated in Johor, Malaysia.

The packages include engineering, procurement, construction and commissioning of an

effluent treatment facility and a waste management hub for the project. The RAPID

project involves construction of a 300,000b/d refinery that will supply feedstock to be

used for producing around 3mn tonnes a year of ethylene, propylene, C4 and C5 olefins

and several downstream units.

Petronas has awarded an engineering and construction contract for the development of

two gas fields, World Oil reports. The contract was awarded to the joint venture

between Technip and Malaysia Marine & Heavy Engineering Holdings. The gas fields



are located in Block SK316 in Sarawak State, Malaysia. Financial details have not been

disclosed.

The company is planning to postpone some of its oil and gas projects, after the

company registered lower earnings in Q213 ended June 30, reports Rigzone. Petronas'

net profit declined 0.9% to MYR15.26bn (US$4.61bn) in Q213, compared with

MYR15.40bn (US$4.65bn) in the same period of 2012. The drop has been attributed to

lower crude prices, the rising cost of infrastructure development and higher support

service rates during the quarter.

Petronas has hired French geoscience specialist CGG to carry out a 10,000 sq km 3D

seismic survey offshore Sabah and Sarawak, World Oil reports. The project, using

CGG's BroadSeis broadband marine technology, is already underway and is expected

to be completed during January 2014. CGG's Viking Vision and Geowave Voyager

vessels are being used as part of the programme.

The company has announced that its subsidiary Petronas Carigali has awarded a five-

year umbrella contract for design and engineering services for upstream projects to four

local engineering services contractors. The contract, which commenced in September

2013, was awarded to Technip Consultant, RNZ Integrated, MMC Oil & Gas Engineering

and Ranhill Worley. The contract will cover domestic upstream oil and gas engineering

services and as well as front-end engineering design (FEED) and detailed design (DD)

works.

Petronas has announced discoveries of hydrocarbon reserves offshore Malaysia and

Indonesia. The company discovered gas offshore Malaysia and oil from a new well in

the Ketapang production sharing contract (PSC), offshore East Java, Indonesia. The

2,775 metre (m) gas pay in Malaysia was discovered at the Sintok-1 well in offshore

Block SK320. Petronas said that drilling of the Bukit Tua South-2 appraisal well reached

a total depth of 2,176m and recorded an oil flow rate of 1,656b/d in early December

2013. Abu Dhabi's Mubadala Petroleum is the operator of the Malaysian block, while

Petronas Carigali Ketapang is the operator of the new well in the Ketapang PSC.

France-based GDF Suez, jointly with Petronas Carigali and JX Nippon Oil & Gas

Exploration, has secured a licence from Malaysian authorities for deepwater exploration

Block 3F, offshore Sarawak.

Petronas has announced first oil from the Kapal, Banang & Meranti cluster fields off

Malaysia. The KBM cluster is operated by Malaysian company Coastal Energy KBM and

has been developed with joint venture partners under a risk service contract (RSC).

Production started from the cluster on 16 December 2013. This is the third RSC that

has achieved oil production, after the Balai cluster and Berantai fields, according to

Petronas. According to the company, this is an eight-year development with Kapal in its

first development and production phase. The Kapal field consists of one mobile offshore

production unit, a storage tanker with a 600,000 barrel capacity, a drilling rig with an

attached well bay module and two flexible flowlines. Initial production rates from the

cluster were more than 10,000b/d, with peak production reaching around 13,000b/d. To



date, Petronas has awarded 10 fields in four clusters under the RSC arrangements, with

four fields already producing a total of more than 30,000boe/d.

Financial Data Sales

■ MYR291.0bn (FY12)■ MYR241.2bn (2011)■ MYR210.8bn (FY10)■ MYR264.2bn (FY09)■ MYR223.1bn (FY08)■ MYR184.1bn (FY07)

Net profit

■ MYR54.3bn (FY12)■ MYR68.7bn (FY11)■ MYR40.3bn (FY10)■ MYR52.5bn (FY09)■ MYR61.0bn (FY08)■ MYR46.4bn(FY07)

Operational Data Year established: 1974

■ No. of employees: 23,000■ Proven reserves: 28.3bn boe (2011)■ Oil/gas production: 2.08mn boe/d (2012)■ Oil and Condensate production: 745,000b/d (FY12)

Company Details ■ Petroliam Nasional-Bhd (Petronas)

■ PetronasTower 1Petronas Twin Towers

Kuala Lumpur City Centre

Kuala Lumpur

50088

Malaysia

■ Tel: +60 (3) 2026 5000

■ Fax: +60 (3) 2026 5050

■ ww.petronas.com.my



ExxonMobil

SWOT Analysis

Strengths ■ Strong presence in producing projects.

■ Major share of development upside.

■ Rapid near-to-medium-term output growth.

■ Involvement in gas export infrastructure.

■ Good relationship with state and Petronas.

Weaknesses ■ Substantial and rising investment requirement.







Company Overview US-based ExxonMobil is Malaysia's leading foreign oil and natural gas producer. Oil

production, however, has fallen considerably in the past five years. Gas output has

remained steady. Exxon has stakes in six production sharing contracts (PSCs) offshore

Malaysia, operates 40 offshore platforms in 17 fields in the South China Sea including

the giant Seligi field, and has plans to install three new platforms over the next few

years. In total, ExxonMobil holds an interest in 202,340 square kilometres (sq km) of net

offshore acreage.

Strategy Given the decision to sell its downstream assets in Malaysia to San Miguel in a US

$610mn deal, Exxon is now dependent on developing its upstream portfolio for growth

in the country. In January 2011 ExxonMobil said that it will team up with Petronas'



subsidiary Petronas Carigali Sdn Bhd to spend MYR10bn (US$3.3bn) on new oil and

gas properties in the country. The downstream sale was completed in January 2013,

with Exxon's refinery company fetching US$206mn and the retail units realising US

$404mn.

ExxonMobil E&P Malaysia has begun drilling for natural gas in the Telok field, offshore

Malaysia, reports World Oil. ExxonMobil has taken on the role of operator at the project,

for which it has a 50% stake in partnership with Petronas, which controls the other 50%

of the PSC. The South China Sea gas development project will help meet growing gas

demand in the country, according to ExxonMobil Development Company President Neil

W Duffin. The company has planned 14 development wells for the Telok A and B

platforms, with the Telok A platform representing the first phase of the Telok natural gas

project.

Exxon and Royal Dutch Shell have moved to the next round of bidding for Newfield

Exploration's Malaysian and Chinese oil and gas fields. The fields have been valued at

approximately US$1.2bn. Newfield is currently the fourth largest oil producer in

Malaysia.

Market Position ExxonMobil is the country's leading foreign oil and natural gas producer. Oil production,

however, has fallen considerably in the past five years. Gas output has remained

steady. ExxonMobil operates 43 platforms in 17 fields in Malaysia. Net production in

2012 averaged 40,000 barrels per day (b/d) of liquids and 3.9bn cubic metres (bcm) of

gas. During 2012, fabrication work continued on the Tapis Enhanced Oil Recovery and

Telok Gas projects. Two platforms and nine pipelines were installed. Design work on

Damar, the next planned gas development in support of meeting Malaysia's power and

industrial needs, was completed. Fabrication of associated offshore facilities is under

way. In addition, Exxon continued development planning work on the Guntong

Enhanced Oil Recovery project.

Notable projects include the Bintang gas field in the South China Sea, a 50:50 PSC

between Exxon and Petronas. It is expected to produce around 28bcm of gas, with a

peak production of 10mn cubic metres per day. Gas from Bintang's two platforms, A

and B, will flow via an 11km pipeline to Lawit A for processing and then to shore via

existing pipelines. The Bintang development will help to meet increasing natural gas

demand on the Malaysian peninsula. Project development costs are estimated at US

$80mn, excluding drilling costs.

ExxonMobil is also constructing an offshore gas compression platform as part of its

plans to build a production hub in Malaysia. The Guntong E gas compression platform

is sited some 210km off the east coast of Peninsular Malaysia. Guntong E, the first

phase of the Guntong hub development, will be followed by new drill wells, work-over of

existing wells, satellite platforms, inter-field pipelines and retrofit of existing platforms.

The Guntong hub is expected to process, over its lifetime, 113bcm of gas for sale in

Peninsular Malaysia. ExxonMobil Exploration and Production Malaysia's chairman Rob



Fisher said Guntong E would form the processing hub for a series of future gas

resources development commitments under a gas PSC with Petronas.

ExxonMobil is the operator and holds working interests of between 78% and 80% of

the Satellite Field Developments, in partnership with Petronas.

Operational Data ■ Year established: 1960■ No. of employees: 2,400

Oil/liquids production

■ 40,000b/d (2012)■ 38,000b/d (2011)■ 48,000b/d (2010)■ 52,000b/d (2009)■ 56,000b/d (2008)■ 67,000b/d (2007)■ 64,000b/d (2006)■ 82,000b/d (2005)

Gas production

■ 3.9bcm (2012)■ 4.3bcm (2011)■ 5.3bcm (2010)■ 5.4bcm (2009)■ 6.0bcm (2008)■ 6.0bcm (2007)■ 5.4bcm (2006)

Company Details ■ ExxonMobil Sdn Bhd

■ Level 29 Menara Exxon MobilKuala Lumpur City Centre

Off Jalan Kia Peng

Kuala Lumpur

50800

Malaysia

■ Fax: +60 (3) 2380 3494

■ www.exxonmobil.com



Shell

SWOT Analysis

Strengths ■ Strong presence in producing projects.

■ Major share of development upside.

■ Rapid near-term output growth.

■ Extensive fuels retail involvement.

■ Key role in gas export development.

Weaknesses ■ Substantial and rising investment requirement.







Company Overview Shell has invested around MYR75bn in the country during the last century. It entered

the country in 1910 and, as contractor to Petronas, the company produces oil and gas

located offshore at Sarawak and Sabah under numerous production sharing

contracts (PSCs), in which Shell's interests range from 30% to 80%. In Sabah, it

operates four producing offshore oil fields with interests ranging from 50% to 80% as

part of the 2011 North Sabah enhanced oil recovery (EOR) PSC and the SB1 PSC. Shell

also has additional interests ranging from 35% to 50% in PSCs for the exploration and

development of five deepwater blocks, which include the unitised Gumusut-Kakap field

(Shell interest 33%) and the Malikai field (Shell interest 35%). Both fields are currently

being developed with Shell as the operator. The group has a 21% interest in the Siakap

North/Petai field operated by Murphy Oil and a 30% interest in the Kebabangan field



operated by the Kebabangan Petroleum Operating Company. In Sarawak, Shell is the

operator of 18 gas fields, with interests ranging from 37.5% to 70%. Nearly all of the

gas produced is supplied to Malaysia LNG in Bintulu where the company has a 15%

interest in each of the Dua and Tiga LNG plants. The group also has a 40% interest in

the 2011 Baram Delta EOR PSC and a 50% interest in Block SK-307.

Strategy Having reduced its exposure to underperforming assets in its downstream portfolio,

Shell is now concentrating on its strategy of 'more upstream and profitable

downstream'. Recent upstream discoveries, including a find at offshore Sabah, will

encourage the firm to further efforts. In June 2008, Shell said it would invest US$3.1bn

in its operations in Malaysia over the following decade, mostly in exploration.

Shell's EOR schemes with Petronas may take the lion's share of medium-term

upstream expenditure, and have the potential to yield significant additional volumes.

The new deepwater exploration concessions, also with Petronas, arguably hold the key

to significant long-term reserves and production expansion.

Shell and Petronas are planning to spend jointly US$12bn over the next 30 years on the

EOR schemes and are targeting a near 14% increase in recovery factors. The Sarawak

project includes the Bokor, Bakau, Baram, Baronia, Betty, Fairley Baram, Siwa, Tukau

and West Lutong oil fields in the Baram Delta. The North Sabah project involves the St

Joseph, South Furious, SF30 and Barton fields.

Petronas will be the operator of the Baram Delta EOR PSC with a 60% stake, working

alongside partner Shell with the remaining 40%. Meanwhile, Shell will be the operator of

the North Sabah EOR PSC with a 50% stake, working alongside partner Petronas with

the remaining 50%.

In January 2011, Shell said it would invest MYR5.1bn (US$1.6bn) in building new and

expanding existing upstream, midstream and downstream energy facilities. Shell's

projects consist of development of its wax facility in Bintulu, construction of a diesel

processing unit at the Port Dickson Refinery, and expansion of the Gumusut field

offshore Sabah.

Shell Malaysia is investing MYR800mn in the construction of a diesel processing plant

at Port Dickson as part of its refinery expansion plan in Malaysia. The new plant will

enable the refinery, which is licensed to produce 156,000 barrels per day (b/d), to vary

its feedback options, increase diesel production and improve its margins.

Retail expansion is planned, even though refinery exposure has been reduced. It would

be no great surprise if Shell increased further the capacity of the GTL complex in order

to provide a low-cost source of diesel and other products.

Shell is going all out to 'rejuvenate' its GTL plant in Bintulu to ensure that the plant

continues producing innovative products. Shell Singapore vice president of Integrated

Gas Ventures East, Ate Visser said Shell has approved a US$15mn rejuvenation



investment for the 20-year old plant in Bintulu, also known as Shell Middle Distillate

Synthesis Malaysia Sdn Bhd (Shell MDS), the Borneo Post reported.

Shell and ExxonMobil have moved to the next round of bidding for Newfield

Exploration's Malaysian and Chinese oil and gas fields. The fields have been valued at

approximately US$1.2bn. Newfield is currently the fourth largest oil producer in

Malaysia.

Market Position Shell is an active participant in Malaysia's upstream and downstream sectors, having

invested around MYR75bn in the country during the last century. It entered the country

in 1910 and, as contractor to state-owned Petronas, the company produces oil and gas

located offshore at Sarawak and Sabah under 14 PSCs, in which Shell's interests range

from 30% to 80%.

In Sabah, it operates four producing offshore oil fields with interests ranging from 50%

to 80% as part of the 2011 North Sabah enhanced oil recovery (EOR) PSC and the SB1

PSC. Shell also has additional interests ranging from 35% to 50% in PSCs for the

exploration and development of five deepwater blocks, which include the unitised

Gumusut-Kakap field (Shell interest 33%) and the Malikai field (Shell interest 35%). Both

fields are currently being developed with Shell as the operator. The group has a 21%

interest in the Siakap North/Petai field operated by Murphy Oil and a 30% interest in the

Kebabangan field operated by the Kebabangan Petroleum Operating Company.

In Sarawak, Shell is the operator of 18 gas fields, with interests ranging from 37.5% to

70%. Nearly all of the gas produced is supplied to Malaysia LNG in Bintulu where the

company has a 15% interest in each of the Dua and Tiga LNG plants. The group also

has a 40% interest in the 2011 Baram Delta EOR PSC and a 50% interest in Block

SK-307.

In 2011, Shell signed a heads of agreement (HoA) with Petronas for two 30-year PSCs

for EOR projects offshore Sarawak and Sabah. These PSCs replaced the existing 2003

Baram Delta and 1996 North Sabah PSCs. The HoA specifies work activities and new

investment from Shell and its joint venture partner to increase the average recovery

factor of the fields in the PSC and extend their productive life beyond 2040.

Sarawak Shell and Petronas in April 2012 announced the signing of two new exploration

and PSCs. Shell's minimum financial commitment for activities in the two blocks will be

in the region of US$145mn over the next four years. The PSCs are for blocks 2B and

SK318, both offshore Sarawak. Under the agreements, Shell will undertake an

aggressive drilling campaign to comprehensively explore an area totalling an estimated

9,000sq km in the two blocks over the respective exploration periods. Shell is operator

and has an 85% interest in both contracts.

Deepwater Block 2B is located some 300km offshore in water depths ranging from 300

to 2,000 metres. The PSC covers 35 years with an initial four-year exploration phase.



Block SK 318 is located about 200km offshore in water depths of between 200 to 1,000

metres. The contract covers 27 years with a three-year exploration period.





holding stakes. Output will begin at 10,000b/d in 2012 following several years of


Shell operates a GTL plant (Shell interest 72%) that is located adjacent to the LNG

facilities in Bintulu. Using Shell technology, the plant converts natural gas into high

quality middle distillates and other specialty products. It has completed an expansion

programme at the facility, increasing production rates by 20%. The plant is jointly

owned by Shell, Petronas, the Sarawak state government and Japan's Mitsubishi.

The Shell group owns 51% of one of the two Port Dickson refineries (the other is held

by Petron after its purchase from ExxonMobil), with the remaining 49% publicly held.

The refinery produces a comprehensive range of petroleum products, most of which are

consumed within Malaysia. In 1999 Shell completed its MYR1.4bn investment in

Malaysia's first long residue catalytic cracking (LRCC), transforming a medium-sized

simple refinery into a modern complex plant capable of processing 125,000b/d. The

LRCC has quadrupled the refinery's LPG production and doubled its motor gasoline

output. It also enabled the refinery to manufacture propylene for the first time.

In the fourth quarter of 2011, the refinery processed 8.6mn bbl of crude oil and sold

9.2mn bbl of product. Shell's construction of the new 6,000 tonnes per day diesel

processing unit is on schedule, which will allow it to vary its feedstock options, increase

diesel production and improve refining margins.

Shell has more than 900 retail stations in the country, and plans to build a further 30 in

the immediate future. In Malaysia, Shell makes and sells more than 600 different

lubricants for the automotive sector, heavy-duty transport, food processing and power

generation. It is the lubricants market leader in Sabah and Sarawak.

Tukau Timur Deep-1 is the first completed high pressure high temperature (HPHT) well

in Sarawak and is also the deepest vertical well to be drilled by Petronas. The well was

drilled to a depth of 4,830 metres and discovered 12 gas bearing reservoirs with total

net gas sand of 183 metres. Preliminary assessments indicate the total gas-in-place for

Tukau Timur Field to be about 59bcm. Subsequent work will commence to estimate the

range of recoverable resource volumes. Tukau Timur Deep-1 is located in Block SK307

which is operated by Petronas Carigali (50%) with Sarawak Shell Berhad (50%) as

partner. The well was spudded in May 2012 and was completed in November 2012.

Sarawak Shell has awarded French engineering company Technip a contract to build

and maintain two new gas export lines in support of its Laila and D12 fields, World Oil

reports. The contract covers the design, fabrication and installation of 4.8km and 9.6km

flexible pipelines of 17.78cm and 32.5cm in diameter respectively, which will serve as



flowlines to transport gas away for processing. Technip is in charge of project

management and will also install riser clamps at both jacket platforms.

Shell has estimated that its floating production system (FPS) that serves the Gumusut-

Kakap oil field in Malaysia will be fully operational by the end of 2013. Shell has been

producing oil from the project since November 2012, but expects that the FPS's full

capacity of producing 150,000b/d of oil from 19 wells will be achieved before the end of

the current year.

Operational Data ■ Year established: 1910■ No. of employees: 7,000■ Refining capacity: 109,000b/d

Oil/liquids production

■ 41,000b/d (2012)■ 40,000b/d (2011)■ 40,000b/d (2010)■ 39,000b/d (2009)■ 38,000b/d (2008)

Gas production

■ 5.9bcm (2012)■ 7.9bcm (2011)■ 8.3bcm (2010)■ 9.1bcm (2009)■ 9.0bcm (2008)

Company Details ■ Shell Malaysia Ltd

■ Bangunan Shell MalaysiaOff Jalan Semantan, Damansara Heights

Kuala Lumpur

50490

Malaysia

■ Tel: +60 (3) 2095 9144

■ Fax: +60 (3) 2091 2957

■ www.shell.com.my



ConocoPhillips

SWOT Analysis

Strengths ■ Substantial refinery involvement.

■ Exploration upside potential.

■ Established local joint ventures.

Weaknesses ■ Limited upstream production.

■ Only modest downstream presence.

Opportunities ■ Rising domestic/regional energy consumption.

■ Large areas of unexplored territory.



Company Overview ConocoPhillips' upstream involvement in Malaysia comprises interests in three

deepwater blocks off the eastern state of Sabah, namely Block G, Block J and the

Kebabangan (KBB) Cluster. These three blocks include eight discovered fields in

various stages, ranging from appraisal to development execution. ConocoPhillips also

has a 47% interest in the 162,000 barrel per day (b/d) Melaka II refinery, together with

Petronas, from which it receives around 76,000b/d of output.

Strategy The company's downstream oil situation is hard to read, as ConocoPhillips is in the

unusual position of owning a significant share of a modern refinery, but has an

upstream-biased corporate strategy and no local retail operation to help bolster sales

and margins. On the face of it, sale of the Melaka stake seems long overdue, but there

are few immediate signs of a deal in the making. Given that ExxonMobil has quit the

country's refining sector and Shell has reduced its exposure, ConocoPhillips looks to be

out of step with its peers.

With the likes of Shell and Exxon partnering Petronas for major enhanced oil recovery

and deep water exploration schemes, it hasn't been easy for ConocoPhillips to carve

out a useful upstream niche. It is now partnering Shell, Petronas and Murphy in a



number of attractive oil and gas prospects that, over the medium term, have the

potential to deliver considerable volumes.

ConocoPhillips may have left it rather late to strengthen its modest upstream position in

the country and, without acting as operator for its key concessions, it cannot

necessarily dictate the ultimate pace of investment and activity. However, if there are

disappointing results or progress is too slow, it should be relatively easy for the

company to move the assets on to existing upstream participants. In the meantime, it

seems likely that management will be seeking other investment options in the

exploration and production sector that can deliver more immediate volumes and longer-

term upside potential.

Petronas in December 2012 awarded a production sharing contract (PSC) for Block

SB311 offshore Sabah to a partnership of ConocoPhillips Sabah Gas, Shell Energy Asia

and Petronas Carigali. The block, measuring 1,046 sq km, is located in the central part

of the Sabah Basin in water depths ranging from 50 to 100 metres. The area is located

within a proven hydrocarbon fairway with key discoveries such as Kebabangan, Kinarut,

and Erb West. Under the terms of the PSC, ConocoPhillips will operate the block with a

participating interest of 40%. Petronas Carigali and Shell Energy Asia will each own a

30% interest in the block. For the SB311 PSC, the partners are committed to drill two

wildcat wells, acquire 400 line km of new 2D seismic data and re-process existing 3D

seismic data on the block.

Market Position ConocoPhillips' upstream involvement in Malaysia began in 2000 and currently

comprises interests in three deepwater blocks off the eastern state of Sabah, namely

Block G, Block J and the Kebabangan (KBB) Cluster. These three blocks include eight

discovered fields in various stages, ranging from appraisal to development execution.

Block G (Malikai, Ubah and Pisagan) is operated by Royal Dutch Shell (35%), with

ConocoPhillips and Malaysia's state-owned Petronas holding 35% and 30%

respectively. The Malikai-1 and the Ubah-2 exploration wells were drilled in Block G in

2004 and 2005, resulting in oil discoveries. An additional oil discovery was made on the

block with the Pisagan-1A well in 2005. The Malikai discovery was appraised in 2005

and 2006, and development planning and front-end engineering are under way.

Successful appraisal wells were completed on Ubah in 2008 and 2010.





holding stakes. Output was to begin at 10,000b/d in 2012 following several years of




The Limbayong gas field on the same block is operated by Shell (40%), with

ConocoPhillips and Petronas having stakes of 40% and 20%. Appraisal of the field is

planned for 2013.

ConocoPhillips has a 21% share of Siakap North-Petai, operated by Murphy Oil (32%)

and featuring both Petronas (26%) and Shell (21%). The Petai-1 well was drilled in 2007,

resulting in an oil discovery, with additional drilling completed in 2008. Unitisation of

Petai and the Siakap North Field in Block K was completed in 2011, with ConocoPhillips

holding a 21% initial interest in the unit.

Development of Siakap North-Petai is currently under way, with first production

expected in 2013. The SNP field is located near the existing Kikeh field, northwest of

Labuan Island, in waters 3,900-4,900 feet deep.

ConocoPhillips has a 30% interest in the KBB Cluster, operated by Kebabangan

Petroleum Operating Company and featuring Petronas (40%) and Shell (30%) as the

other partners. The Kebabangan Cluster production sharing contract was signed in

2007 for appraisal and development of the Kebabangan, Kamunsu East and Kamunsu

East Upthrown Canyon gas and condensate fields. Development of the Kebabangan

Field was sanctioned in early 2011, and first production is targeted for 2014.

In August 2013, the firm said the floating production system (FPS) for the Gumusut-

Kakap deepwater field off Sabah, Malaysia had arrived on site and that hook up and

commissioning activities were in progress. Separately, development continued at

Siakap North-Petai (SNP) field, which is located in water depths of 4,429 feet off Sabah,

Malaysia. ConocoPhillips said a key production module and accommodation unit were

lifted on site at the SNP field. Both the SNP and the Gumusut-Kakap projects are

expected to start up in late 2013. Meanwhile, the Kebabangan development, located off

the northwest coast of Sabah, remains on track for start-up in 2014. The jacket was

successfully installed during the second quarter and drilling commenced in July 2013.

ConocoPhillips also has a 47% interest in the 162,000b/d Melaka II refinery, together

with Petronas, from which it receives around 76,000b/d of output. The medium, high-

sulphur crude oil processed by the refinery is sourced mostly from the Middle East and

the local area. The refinery capitalises on ConocoPhillips's proprietary coking

technology to upgrade low-cost feedstocks to higher-margin products. Some of the

refined products support ConocoPhillips's retail marketing operations in the Asia Pacific

region, with the balance of the light-oil share being sold in the regional markets. An

expansion project at Melaka was completed during 2010 to increase crude oil,

conversion and treating unit capacities to its current levels.

Operational Data ■ Refining capacity: 76,140b/d (2012)



Company Details ■ ConocoPhillips Asia Pacific Ltd

■ Suite 16.03, Wisma Goldhill67 Jalan Raja Chulan

Kuala Lumpur

50200

Malaysia

■ Tel: +60 (3) 2163 4894

■ Fax: +60 (3) 2032 5266

■ www.conocophillips.com



Murphy Oil

SWOT Analysis

Strengths ■ Biggest independent operator.

■ Large exploration and production portfolio.

■ Rapid output growth.

Weaknesses ■ Rising investment requirement.

■ No downstream presence.



Threats ■ State-imposed production limits.


Company Overview Murphy Oil has been an active participant in the Malaysian upstream sector since 1999,

and has majority interests in and acts as operator of six separate production sharing

contracts (PSCs), covering approximately 6.7mn gross acres. Murphy has an 85%

interest in discoveries made in two shallow-water blocks, SK 309 and SK 311, offshore

Sarawak. The company has a gas sales contract for gross volumes up to 2.58bn cubic

metres (bcm) from the Sarawak area with Petronas and has prepared a multi-phase

development plan for several natural gas discoveries on these blocks.

Strategy Murphy announced in July 2010 that it planned to divest its downstream assets in the

US and UK in order to focus on its more profitable exploration and production business.

As Murphy's largest and fastest growing production and reserves base, Malaysia looks

set to benefit further from the increased attention. Murphy is likely to continue its

existing strategy of organic growth by bringing new fields on stream. Natural gas

production will be a priority for the company as it seeks to continue the rapid pace of

production growth from its fields onshore Sarawak and peninsular Malaysia.

The company is aiming for upstream production of at least 260,000 barrels of oil

equivalent per day (boe/d) by 2015, of which 28% is expected to come from its



Malaysian assets. Key projects behind this target are the Patricia, Serendah, S. Acis,

Permas and Endau prospects, adding 30,000boe/d by 2014, plus Kakap and SNP

delivering 20,000boe/d in 2014/15.

The 2012/13 exploration programme includes five to seven wells in Malaysia, with four

on Block H. The Buluh-1 and Bunga Lili-1 finds are to be appraised. Murphy's estimate

of the total resource for Block H 2 is 1.5trn-2trn cubic feet, or up to 57bcm of gas.

Murphy revised its fourth-quarter 2013 production guidance. The company increased its

quarterly production expectation by roughly 3% to about 205,000boe/d from

199,000boe/d projected during the company's third quarter earnings call in 2013.

The upward revision in guidance was due to the shifting of planned downtime at the

Kikeh floating [roduction storage and offloading vessel in Murphy Oil's Siakap North/

Petai project offshore Malaysia to the end of January 2014 from early fourth quarter

2013. The company changed its plan due to climate as well as execution related delays.

One of Murphy Oil's rigs, connected to the Kikeh Spar, was late in 2013 damaged by

fire. This delayed the company's drilling activities under the Kikeh Field Development

Plan owing to the repair of the rig.

Consequently, the delay in planned downtime at the Siakap North/Petai project and rig

damage are expected to negatively impact its 2014 production by 5,000boe/d. Murphy

Oil expects 2014 production in the range of 235,000-240,000boe/d, higher than the

2013 production estimate of 203,000boe/d.

Market Position Murphy has majority interests in and acts as operator of six separate PSCs covering

approximately 6.7mn gross acres. Murphy has an 85% interest in discoveries made in

two shallow-water blocks, SK 309 and SK 311, offshore Sarawak. The company has a

gas sales contract for gross volumes up to 2.58bcm from the Sarawak area with

Petronas and has prepared a multi-phase development plan for several natural gas

discoveries on these blocks. Natural gas pricing is indexed to oil and LNG in the region.

Malaysian oil production in 2012 averaged 52,663 barrels per day (b/d). Gas volumes

were 2.2bcm for the year.

In 2002, Murphy made a major discovery at the Kikeh (80%) field in deepwater Block K,

offshore Sabah, and brought first production on line in 2007, less than five years from

initial discovery.




operated by Shell, with ConocoPhillips, Petronas and Murphy Oil each holding stakes.

Output will begin at 10,000b/d in 2012 following several years of construction-related

delays.

Several additional discoveries have been made in Block K at other areas, including the

Siakap North oil discovery in 2009. In February 2007, the company signed a Kikeh field



natural gas sales contract with Petronas that calls for gross sales volumes of up to

1.24bcm per annum. The goal is to maintain a flat production profile, net to Murphy, of

65,000-70,000boe/d from Block K through to 2015.

Murphy has 32% of Siakap North-Petai, and acts as operator. The Petai-1 well was

drilled in 2007, resulting in an oil discovery, with additional drilling completed in 2008.

Unitisation of Petai and the Siakap North Field in Block K was completed in 2011.

Development of SNP is currently under way, with first production expected in 2013.

Detailed engineering and procurement for the project are under way, and fabrication of

installation aids, etc, was expected to have begun in the third quarter of 2012.

The company also holds a 60% interest in a PSC covering Block P and an 80% interest

in deepwater Block H offshore Sabah. In early 2007, the company announced a

significant natural gas discovery at the Rotan well in Block H. In early 2008, Murphy

followed up Rotan with a discovery at Biris. In March 2008, the company renewed the

contract for Block H at a 60% interest while retaining 80% interest in the Rotan and

Biris discoveries. In 2010, another natural gas discovery was made in Block H at Dolfin.

Total gross acreage held at year-end 2010 by the company in Block H was 1.99mn

acres. In partnership with Petronas, Murphy is actively pursuing a development plan for

these Block H gas discoveries, and is optimistic that a floating liquefied natural gas

development could produce gas by 2014/15.

Murphy has a 75% interest in gas holding agreements for Kenarong and Pertang

discoveries made in Block PM 311, located offshore Peninsular Malaysia. Development

options are being studied for these discoveries.

Financial Data Sales:

■ US$28.63bn (2012)■ US$27.75bn (2011)■ US$23.35bn (2010)■ US$18.92bn (2009)■ US$27.36bn (2008)■ US$18.30bn (2007)

Net income:

■ US$0.97bn (2012)■ US$0.87bn (2011)■ US$0.79bn (2010)■ US$0.84bn (2009)■ US$1.74bn (2008)■ US$0.77bn (2007)



Operational Data ■ Year established: 2000

Oil Production:

■ 52,663b/d (2012)

■ 48,551b/d (2011)

■ 66,897b/d (2010)

■ 76,322b/d (2009)

■ 57,403b/d (2008)

Gas Production:

■ 2.2bcm (2012)

■ 2.2bcm (2011)

■ 2.2bcm (2010)

0.77bcm (2009)

Company Details ■ Murphy Sarawak OilCompany

■ Level 26, Tower 2PETRONAS Twin Towers

Kuala Lumpur City Centre

Kuala Lumpur

50088

Malaysia



Other Summaries

Chevron Chevron has no upstream oil and gas interests in Malaysia, and its focus in the country

remains as a dedicated downstream business. Chevron does business in Malaysia

through its subsidiary Chevron Malaysia Limited. It imports fuels and lubricants from its

refinery and blending facilities in Singapore and Thailand. Unleaded gasoline, diesel and

lubricants are received through three terminals that it operates in peninsular Malaysia. It

has more than 420 Caltex service stations in Peninsular Malaysia. Chevron also markets

asphalt and fuels to businesses.

Hess The Malaysia/Thailand Joint Development Area (JDA), in the northern Malay Basin was

established in 1979. In 2001, Hess acquired a 26% interest in JDA Block A-18, which

grew to a 50% stake in 2003. The block is operated by Carigali Hess, a joint venture

with Petronas Carigali.

Petronas Carigali agreed a deal with Hess on the joint development of gas reserves in

the North Malay Gas Basin. The deal will see some US$5.2bn invested in the project to

commercialise 48bn cubic metres (bcm) of gas reserves over the next five years, while

Hess acts as operator with a 50% interest. The companies expected first production in

2013.

Talisman Energy Canada's Talisman Energy holds a 41% operated interest in Block PM-3 CAA PSC

between Malaysia and Vietnam and associated production facilities. It also holds a 33%

interest in Block 46-Cai Nuoc adjacent to PM-3 CAA and a 60% interest in each of

Block PM-305 and Block PM-314. In Block PM-3 CAA, Talisman is operating facilities

referred to as the 'Southern Fields' and the 'Northern Fields'. The expiry date for the

Kekwa sub block in PM-3 CAA has been extended by nine months to April 2013.

Negotiations to further extend the Kekwa sub block as well as the balance of Block

PM-3 CAA, which expires in 2017, are ongoing.

Talisman also holds a 70% working interest in exploration licences for SB-309 and

SB-310, acreages offshore Sabah in east Malaysia. In 2012 Talisman was awarded a

60% equity interest and operatorship of the Kinabalu Oil production sharing

contract (PSC), which is a mature oilfield in the offshore Malaysian Sabah Basin.

Operatorship of this PSC became effective in December 2012 and has the potential for

significant liquids growth as well as providing tieback synergies with potential

discoveries in the existing Talisman Sabah exploration licences.

In 2012, production in Malaysia averaged 36,800 barrels of oil equivalent per day (boe/

d), which accounted for approximately 29% of Talisman's total South East Asia

production. Six development wells were drilled in Malaysia in 2012, one of which was a

water injector. Optimisation initiatives at PM-3 CAA to maximize gas production and



meet strong regional demand have resulted in an increase of 8% in gas production over

the previous year and the highest production levels since 2004.

Total French major Total's Malaysian activities are at present confined to exploration. In 2001,

it signed a farm-in agreement for a 42.5% stake in Block SKF offshore Sarawak.

Partners in the block are operator Hess, with 42.5%, and Petronas Carigali, with 15%.

The partners undertook seismic studies of the block in 2007. In May 2008, Total signed

a production sharing contract for two offshore blocks with Petronas. The contract

covers blocks P303 and PM324, which lie in water depths of 50-80m. Under the

contract, Total has committed to acquire seismic studies of the area and undertake high

pressure/high temperature exploration drilling. While the financial details of the deal

have not been released, the company is reported to gain operatorship over, and a 70%

interest in, each of the two blocks, alongside partner Petronas Carigali (30%). The

acquisition can be seen as part of Total's underlying strategy to expand its operations in

South East Asia.

Petronas and Total have signed a heads of agreement that will see the pair undertake a

collaborative assessment of the K5 sour gas field offshore Sarawak. The companies will

evaluate the field's development and production potential, with the study scheduled to

begin immediately. During the 15-month study, the companies will also look to develop

CO2 management techniques for capturing, transporting and sequestrating carbon.

Newfield Exploration US independent Newfield Exploration holds equity in five Malaysian licences. Two of

them are producing (PM318, 50%; PM322, 60%), one is in development (PM329, 70%)

and two are at the exploration stage (Block 2C, 40%; SK310, 30%).

In October 2013, Newfield agreed to sell its Malaysian interests to SapuraKencana

Petroleum Bhd for US$898mn. The deal was expected to close in early 2014.

Others Swedish oil and gas firm Lundin Petroleum announced that it had received approval for

the Bertam Field Development Plan from Petronas. The Bertam field is the first

development project operated by Lundin in Malaysia. The Bertam field is located in

Block PM307, offshore Peninsular Malaysia. Lundin Malaysia BV as operator holds a

75% working interest and Petronas Carigali holds the remaining 25% working interest.

The Bertam field will be developed using a 20 slot Wellhead Platform adjacent to a

spread moored FPSO in a water depth of 76 metres. The total gross capital investment

associated with the Bertam field development, excluding any FPSO related costs, is

estimated at approximately US$400mn.

Malaysia-based Puncak Niaga agreed to buy the remaining 60% stake in Global

Offshore Malaysia and KGL in a deal worth US$59mn. The acquisition will give Puncak

Group further exposure to the oil and gas industry. Puncak bought a 40% stake in both

the companies in May 2011.



Malaysia's Dialog Group has entered into a shareholders' agreement with Petronas and

Australian independent Roc Oil. The agreement paves the way for the formation of a

joint venture (JV) company, to be named BC Petroleum. The JV company will be the

operator of the small field risk service contract for the development of oil and gas fields

in the Balai Cluster offshore Sarawak, Malaysia. Roc will have a 48% stake in the JV,

working alongside partners Dialog with 32% and Petronas Carigali with the remaining

20%.

Dialog intends to invest up to MYR10bn (US$3.28bn) in developing an independent oil

and LNG terminal in Pengerang, Malaysia. A consortium consisting of Dialog Group, the

Johor government and Royal Vopak will jointly develop an LNG storage, loading and

regasification terminal under the proposed project. The terminal will import LNG for

trading purposes as well as for domestic consumption. It would be built in two phases,

with Phase 1 expected to be built between 2013 and 2016 and Phase 2 between 2013

and 2018, according to the company's chairman, Ngau Boon Keat.

Roc Oil has begun an extended well testing programme on the Balai-2 well of the Balai

Cluster RSC, Malaysia. The testing began on November 6 2013 and continued for

approximately 24 hours. The production is from two intervals in the upper reservoir

sands - at measured depths of 1,901m and 1,912m - and the initial average rate was in

the range of 4,000-4,200 barrels of oil a day. The programme has since recommenced

and will continue for an extended period.

BC Petroleum (BCP), a joint venture between Roc Oil, Dialog Group and Petronas, has

discovered hydrocarbons pay with its Bentara-3 pre-development well in the Balai

Cluster Risk Service Contract (RSC) offshore Eastern Malaysia. Initial assessment based

on preliminary logs indicates an estimated net hydrocarbon pay of around 91 metres

across 18 sandstone reservoir intervals. The well is being cased and completed in

preparation for extended well testing with the early production vessel (EPV) Balai

Mutiara. BCP operates the Balai Cluster RSC, whose shareholders include Roc with a

48% stake, Dialog Group with 32% and Petronas with the remaining 20%.

Coastal Energy secured a risk services contract (RSC) in July 2012 for the development

of the Kapal, Banang and Meranti oil fields offshore Peninsular Malaysia. The company

has reached a deal with Petra Energy, under which the latter will subscribe for a 30%

stake in the former's subsidiary Coastal Energy KBM. This will give Petra Energy a 30%

stake in the RSC, while Coastal will hold the remaining 70%. Coastal is planning to drill

four wells at the Benang field, three wells at the Meranti field and 10 wells at the Kapal

field. Under the RSC, the marginal fields will be developed with mobile offshore

production units and floating, storage and offloading vessels.

Japan-based JX Nippon Oil & Gas Exploration Corporation has signed a production

sharing contract (PSC) with Petronas for Deepwater Block 2F offshore Malaysia. Under

the terms of the PSC, JX Nippon will acquire a 40% interest in Block 2F, which covers

an area of around 5,500sq km and is located in north-west Sarawak. Subsequent to the



acquisition, JX Nippon will become the operator of the block, while Petronas will hold a

40% stake and GDF Suez E&P Malaysia the remaining 20%.



Regional Overview

Asia Overview

BMI View: There are four main themes that will characterise the Asian oil and gas industry over the

coming years: stronger growth in demand for gas than oil, the growing importance of liquefied natural gas

(LNG) to both producer and consumer markets, progress in shale gas exploration, and a challenging

downstream market for refiners in both regulated and free markets.

There are four main themes that will characterise the Asian oil and gas industry:

■ Gas will outperform oil in terms of both production and consumption growth.

■ Liquefied natural gas (LNG) development will remain a top priority, although we warn that growing costconcerns will likely slow the pace of LNG development.

■ Rising consumption needs will continue to drive interest in unconventional exploration, although amyriad of challenges - environmental and geological in particular - could prevent the region from quicklyreplicating the US' shale gas success.

■ There is potential for overcapacity in the downstream market, as expansion continues to take place inemerging Asia.

Gas Is Hot

Although BMI's Power team forecasts that coal will remain the dominant fuel for power generation in Asia,

some gravitation towards gas is underway as policies shift to reduce carbon emissions. Japan and South

Korea in particular will continue to be reliant on gas in their power sectors, as public aversion towards

nuclear power remains high. Meanwhile, China is seeking to increase the use of gas to 10% of its total

energy mix by 2020 (from 6% in 2012) in a bid to reduce reliance on coal, while India and Pakistan have

sufficient capacity to accommodate greater gas-fired capacity into their power grids. Other parts of South

East Asia, including the Philippines and Vietnam, are also looking to gas as feedstock for proposed power

projects.



Gas To Continue Powering North East Asia

Japan & South Korea Power Generation By Natural Gas, 2012-2022 (Twh)

Japan: Generation, Natural Gas~ TWhSouth Korea: Generation, Natural Gas~ TWh

2012

e

2013

e

2014

f

2015

f

2016

f

2017

f

2018

f

2019

f

2020

f

2021

f

2022

f

0

250

500

e/f=estimate/forecast. Source: EIA, Statistics Bureau Of Japan, FEPC, World Bank, BMI

Meanwhile, a slower rate of economic growth, as well as energy efficiency gains, will restrain growth in oil

demand. This will prove particularly true in China, where oil consumption growth is expected to slow from

about 4.8% in 2012 to 2.5% by the end of our forecast period in 2022. Downside risk to potential long-term

consumption growth exists as economic headwinds threaten to limit China's growth.



Growth Slowdown, Efficiency Gains To Cap Oil Demand Growth

China - % Year-On-Year Change In Real GDP & Oil Consumption, 2012-2022

Real GDP growth, % y-o-yOil Consumption, 000b/d~ % y-o-y

2012

2013

e

2014

f

2015

f

2016

f

2017

f

2018

f

2019

f

2020

f

2021

f

2022

f

0

5

10

e/f=estimate/forecast. Source: National Bureau Of Statistics, EIA, BMI

This will continue to see gas consumption growth outpace oil consumption growth in the region. Between

2012 and 2022, gas demand is expected to increase by 50.9%, compared to a slower (but still impressive)

rate of 24.0% over the same period for oil.



Gas To Overtake Oil Consumption Growth

Asia - % Year-on-Year Change In Oil & Gas Consumption, 2012-2022

e/f=estimate/forecast. Source: EIA, BMI

That said, we acknowledge that success in increasing the use of gas in transportation - something which

China in particular has been pushing keenly - poses upside risk to our current forecasts for regional gas

consumption growth. Solving India and Pakistan's gas import infrastructure bottlenecks could also further

boost overall gas demand in the region.

Locking Eyes On Gas Production

Meanwhile, gas will also outperform oil in terms of production growth. Between 2012 and 2017, we expect

gas production to grow steadily at an average rate of 6.2% per annum, mainly as a result of production gains

in Australia, China and Papua New Guinea (PNG). Meanwhile, oil production is projected to grow at a

slower average rate of about 1.3% per annum over the same five-year period. However, we do expect gains

in gas output to slow after 2017, particularly as the high cost of gas development in Australia puts the

brakes on massive gas projects in the region.



Gas Takes The Cake

Asia - % Year-On-Year Change In Oil & Gas Production, 2012-2022

e/f=estimate/forecast. Source: EIA, BMI

Australia's LNG Roadblocks Open Up New Opportunities Elsewhere

Asia is set to remain the largest market for LNG trade as Japanese and South Korean demand for gas

remains high. China and India are also emerging as large LNG-demand markets. For exports, Asia's status

as the region with the largest net export capacity by 2022, according to our forecasts, is buoyed by ongoing

LNG export developments in Australia that are expected to be online by 2019. Other projects contributing

to Asia's increase in LNG production are based in PNG, Malaysia and Indonesia.

However, the expansion in LNG production is likely to slow after current developments in Australia are

completed. With the future of LNG prices in flux, producers are not likely to invest in yet more large LNG

projects when returns are uncertain, especially given high development costs in Australia. Moreover,

traditional producers such as Malaysia and Indonesia may see production increases, but the beginning of

LNG imports into these countries will certainly limit the extent to which net LNG exports would rise.

Growing caution with regards to LNG developments in Australia could, however, offer new opportunities

for other countries in the region:



■ Papua New Guinea: Total's farm-in to InterOil's Elk-Antelope fields, which could contain sufficientresources to justify a LNG export project, is yet another endorsement of the country's rich potential.ExxonMobil had previously expressed more certainty in moving ahead with its PNG LNG project thanits proposed Scarborough project in Western Australia. Like Australia, PNG is located close to LNGconsumers in Asia while its small population positions it well to export gas extracted from its fields. Thenascent gas producer is likely to face less stringent regulatory requirements from the government, whichis eager to tap hydrocarbons revenues to support the country.

■ New Zealand: The country is actively seeking foreign investment to build up its hydrocarbons sector.Like PNG, its small population would also enable producers to export much of the gas developed to themore lucrative export market. New Zealand could be a longer-term play compared to PNG, however, asexploration is still in its early stages.

Producers that are still hoping to tap Australia's rich gas potential for LNG exports will most likely

increasingly look to floating LNG (FLNG) production solutions. Since Shell took the lead with its Prelude

project, at least four other proposed developments have leaned towards a floating concept - GDF Suez's

Bonaparte, PTTEP's Cash-Maple, ExxonMobil's Scarborough and Woodside's Browse project. Malaysia

has also adopted FLNG as a solution when commoditising gas from stranded fields, with two FLNG

projects scheduled to come online from 2016. The Abadi LNG project in Indonesia has also taken up a

floating solution. These projects are of a smaller scale, but the flexibility in constructing facilities will allow

firms to overcome local cost constraints to bring fields into production as early as possible.



Balance Of LNG Trade

LNG Trade Pattern By Country (bcm)

*Positive trade = net exporter; Negative trade = net importer; e/f = estimate/forecast. Source: EIA, BMI

Asia Fights Against LNG Prices

Given that Asia is a gas-deficit region, much of its demand needs will be met by imports. However, there is

a lack of pipeline connectivity within the region, unlike the relatively developed networks seen in North

America or Western Europe. Furthemore, there are no concrete plans to build up intra-regional pipelines as

currently witnessed under the massive TANAP-TAP project - being constructed to bring gas from Central

Asia into Europe. As such, Asia will remain dependent on seaborne LNG deliveries to meet most of its gas

import needs. More importantly, it will continue to engage other regions in the world to secure gas, as

regional supplies remain inadequate to meet demand.



More Than It Can Bear

Comparison Of Asia's LNG Import Requirement* With Export Capacity† (bcm)

*Countries include Japan, China, South Korea, Taiwan, India, Thailand, Singapore, Pakistan, Vietnam and Philippines. †Countries

include PNG, Indonesia, Malaysia and Australia. Source: EIA, BMI

This reliance on LNG has also made the region a central player in the current debate over LNG pricing, as it

grows increasingly restless at having to pay a premium for LNG relative to other major LNG markets in the

world.



Paying The Premium

Average Spot Prices For LNG, By Region (US$/mnBTU)

Source: Poten & Partners, Bloomberg

Japan, in particular, has taken the lead in spearheading efforts to revise the LNG pricing mechanism.

Perceiving oil-linked prices as inaccurate depictions of the global gas market, Japan has actively pushed for

the development of a spot market to price LNG deliveries. In September 2013, it announced that it would

publish the average price that its importers pay for LNG, and use this price to set the level at which LNG

futures contracts in the Tokyo Commodity Exchange will trade from 2015.

Other measures include talks of joint tenders for LNG supplies between Japan and India, which could

increase the collective bargaining power of buyers vis-a-vis sellers. Another trend we expect to see is a

pick-up in orders of LNG carriers, as Asian importers seek to address delivery bottlenecks and costs by

increasing the number of vessels available to transport LNG.

However, despite continued efforts by the region's major LNG importers to lead the global debate on LNG

pricing, we believe this will have only a limited effect with regards to lowering prices - due to tightness in

the physical LNG market. This tightness is only expected to be relieved with greater liberalisation of the US



LNG export market from 2018 - where the brownfield nature of LNG projects and low domestic gas prices

make the country's producers the most willing and able in the world to sell LNG at lower prices.

Therefore, it is our view that LNG prices in Asia will not fall below US$10 per mn British Thermal Units

(mn BTU) over our ten-year forecast period. However, a faster-than-expected increase in global LNG

supplies could push prices down and boost Asian LNG consumption beyond our current forecast levels.

Limited Downside To Prices

Forecast Of LNG Prices Based On US Henry Hub & Additional Fixed Price (US$/mnBTU)

NB: Additional fixed price includes the estimated cost of LNG production and shipping. US Henry Hub price is based on BMI's

forecast of US Henry Hub. e/f=estimate/forecast. Source: Bloomberg, BMI.

Seeking An Unconventional Rescue

Asia's growing gas needs have also made its policymakers eager to pursue their countries' unconventional

production potential. Asia's shale gas potential, in particular, could be large. China, in particular, could have

the world's largest technically recoverable resource of shale gas, according to the US EIA, at 31.2trn cubic

metres (tcm) - or nearly nine times that of its existing proven conventional gas reserves. India and Pakistan

could also possess 5.8tcm of recoverable shale gas - nearly twice the amount of proven gas reserves in both

countries, according to the same survey.



Shale Gas - A Potential Game Changer

Comparison Of Shale Gas Estimates & Proven Gas Reserves At Start-2013 (tcm)

Source: EIA

The EIA's updated study of the world's shale resource estimates also includes provisional figures for shale

oil. These new estimates suggest that shale oil could add significant upside to China and India's proven oil

reserves and long-term production potential, though this will most likely be realised only towards the tail-

end of our forecast period for China and beyond our 10-year timeframe for India.



Shale Also Promises Oil Boom

Comparison Of Technically Recoverable Shale Oil And Proven Oil Reserves, Start-2013 (bn bbl)

Source: EIA

This potential has seen a step-up in exploration efforts in China and Australia, and Indonesia has also begun

to open up to shale gas investment. Vietnam and Pakistan have also received unconventional attention from

Italian major Eni, though activities in India are being held back by a pending draft law on shale gas.

China has been most active in attracting investment into its shale potential in the region. It has officially

targeted annual shale gas production of 6.5bcm by 2015 and a further 60bcm to 100bcm by 2020 - targets

that the country may miss given the need to dramatically ramp-up production. To incentivise shale gas

developments, China has introduced subsidies and has opened up entry requirements into the country's shale

plays.

However, its complicated geology has seen companies like Shell experience difficulties translating its

potential into commercial development. Moreover, the award of shale gas blocks to non-traditional players

in its 2nd Shale Gas Round could also have slowed the rate of exploration, as the Ministry of Land and

Resources (MLR) found that some of the 16 companies awarded exploration rights to the 19 blocks offered

had barely started exploration and development works. Sinopec's recent declaration of commerciality at its



Fuling block has brought some cheer to an otherwise disappointing drilling campaign in 2013, and results

from further exploration in 2014 would give a clearer indication of the level of maturity in China's nascent

flirtation with its shale gas potential.

In general, geological challenges, water scarcity, infrastructure issues, state-regulated prices and

environmental concerns could prevent a shale revolution from sweeping through Asia in the short term, but

in the longer term momentum will continue to build. Crucially, the technology is available, and it is

constantly evolving. In time, geological understanding of shale formations and their properties in Asia are

likely to improve. Research into more efficient use of resources - water among others - in fracking could

also reduce the environmental risks of operations. The long-term demand for gas is undeniable and political

pressure could swing in favour of tapping into domestic shale resources in order to reduce energy costs.

What will differentiate the Asian shale revolution from the one in the US will be its leading actors. In the

US, it was a bottom-up effort - technology developed by the private sector was tested and deployed on

private land, spurred on by high natural gas prices determined by market forces. In Asia, with the exception

of Australia, the effort is likely to be top-down and state-led, carried out through private collaboration with

national oil companies (NOCs).

Coalbed Methane: Underrated Potential

The exploration and production (E&P) of coal-bed methane (CBM) is also ongoing in the region. Australia

leads the way, with the Gladstone LNG, Queensland Curtis LNG and Australia Pacific LNG projects

tapping gas produced from this unconventional source for feedstock for these liquefaction projects. China

and India are also tapping this resource, though production is miniscule in both countries. Indonesia has

roped in companies, notably BP, to search for gas in its coal beds. However, there have been roadblocks in

CBM developments in the region. In Australia, new regulations surrounding the use of water for coal

projects - including CBM - have made in more difficult to obtain the federal approval needed for projects to

take off. In India, an ongoing debate surrounding rights to CBM exploration by non-state companies

continue to take place. Meanwhile, ExxonMobil's exit from Indonesia's Barito Basin CBM play is also a

worrying sign, given that the supermajor had been one of the most vocal proponents of Indonesia's CBM

potential.

Refining Woes

Asia has the largest refining capacity globally, and we estimate that it accounted for 33% of global refining

capacity in 2013. Singapore, Japan and South Korea are the region's refining giants, while China and India



continue to expand their capacities to meet growing domestic demand. At least one 300,000b/d project will

be brought online in Vietnam (with another 600,000b/d refinery proposed), while Indonesia is also looking

to expand its downstream crude processing capacity by 900,000b/d.

Fuels Giant

Asia's Share Of Global Refining Capacity, 2012 & 2022

e/f = estimate/forecast. Source: EIA, BMI

Despite countries such as Indonesia and Vietnam facing a shortfall in domestic refining capacity relative to

their consumption needs, we highlight the risk of overcapacity in the region's downstream segment. Indeed,

Asian production has to compete with other products in the global market, particularly as the Middle

Eastern countries bring their large mega-refinery projects online in the next decade.

Moreover, refining margins in the region could be weak, in view of high crude feedstock prices and strong

competition in the open refined products market. This is further complicated by state-regulated pricing in

many developing countries, limiting the extent to which producers can pass costs on to consumers.



Demand Fuelling Expansion, At The Risk Of Traditional Players

Asia's Refining Capacity, 2010-2022 ('000b/d)

2010

2011

2012

2013

e

2014

f

2015

f

2016

f

2017

f

2018

f

2019

f

2020

f

2021

f

2022

f

0

10,000

20,000

30,000

40,000

e/f = estimate/forecast. Source: EIA, BMI

The region's traditional refiners, particularly those with smaller plants and high crude import dependency,

are also losing out market share as a result of growing self-sufficiency in large markets such as China and

India, even as they struggle with emergent producers in the Middle East for a slice of the remaining market.

The Asian market is also being targeted by European exports, as the US downstream renaissance has pushed

Europe's battered refiners out of their traditional markets. Australia has been hit particularly hard, with

Shell's Geelong refinery set to be the next victim of closure. Japanese refiners Cosmo and Idemitsu have

also been rationalising their operations by shuttering production capacity.

These trends mean that profits in the downstream segment will come under price pressures across the

region. It could prompt private players to continue divesting downstream assets in smaller demand markets

such as Malaysia and Philippines. The possible exit of smaller refineries opens up room for existing players

to dive into newly available markets, although these players (for example, Singapore's large refineries) will

have to ensure that their plants are sufficiently equipped and modernised to withstand competition from

emerging players such as China. NOCs are also likely to pick up the slack in highly regulated markets, to

reduce fuel import dependency. There have been plans for many of the region's NOCs to establish joint



ventures (JVs) with foreign partners to fund large refinery projects deemed to be more profitable (see

'Downstream Expansion Looms In South East Asia', January 21 2013). Whether or not these will fall

through will depend on the incentives that governments are willing to offer foreign partners.



Global Industry Overview

We err on the side of caution with our crude oil production forecasts going into 2014, as last year's outages

could re-occur or, in some cases, continue - especially taking into consideration the volatility in oil

producing regions. Iran will be the 'wild-card' in the coming year. While we do not anticipate sanctions to

be lifted to a degree that will have a powerful impact on the country's oil industry this year, nor do we

expect that - even if sanctions were lifted - the country would be able to ramp-up production overnight, we

do believe diplomatic momentum will dictate OPEC discourse, price movements and capex planning for

major producers in the region. Globally, capex seems to be exiting the cycle of growth of the past four years

as IOCs and larger independents seek to reap the rewards of their investment as a five-year project cycle

(which started with a recovery in capex in 2010) is approaching an end. We anticipate a deceleration in

capital investment growth in 2014 with companies adopting a more circumspect approach to budgetary

planning, though not a year-on-year reduction in investment - since the pricing environment remains

conducive.

OPEC Reconsiders Modus Operandi

Saudi Arabia's signal that it would step back from its traditional swing producer role highlights OPEC's

response to shifting fundamentals in the global market. Reports are emerging that Saudi Arabia has

signalled that any necessary curtailment of production by OPEC would have to come in a coordinated

move. Traditionally, while in principle the cartel has to move in coordination and cooperation to alter

supplies on the global oil markets, it has been primarily Saudi Arabia that has fluctuated its output. Given

the tensions in play, the coordinated action Riyadh is seeking will be difficult to organise but may well be

necessary. However, we note that Saudi Arabia's resolve not to go it alone would certainly be tested if

prices dropped to below US$80/bbl.

Supporting this shift in strategy, there may well be growing recognition in Riyadh that given the scale of the

potential changes underway, acting independently may not be in its best interests of OPEC itself. In our

view, the key challenges that OPEC must manage are:

■ Rising OPEC Production: Namely from Iraq, which is still outside the production quota system, but is ontrack for robust expansion of its output. This is already leading to tensions among other producers as theyincreasingly compete for market share in Asia. Other producers such as the UAE are also investingbillions in raising upstream capacity.

■ Potential Return Of Iran: As we have noted previously, the removal of sanctions on Iran's oil sectorwould be a game changer and over time could see Iran return to pre-sanctions production levelsapproaching 4mn barrels per day (b/d). With Iran claiming to have secured an agreement at the most



recent OPEC summit that would see other members 'make room' for a return of its crude shouldrestrictions be loosened, the impact on the state of the global market could be dramatic.

More Could Be On The Way

Total Monthly Estimated OPEC Production, '000s b/d

Source: Bloomberg

The latest developments pose downside risks to our production forecasts for OPEC members, but could also

put pressure on prices over the longer term should countries forgo planned upstream investment.

Outages Look Likely To Persist

Iraq, South Sudan, Libya and Kazakhstan are the main oil producers that presented a production challenge

for 2013. Timely recovery in their volumes is uncertain.

■ The Kashagan field in Kazakhstan, the largest greenfield project in the world, came online for only amatter of a few weeks before being shut down due to technical problems, therefore further risking furtherdelays to its commercial production in 2014.

■ Most of Libya's oil remains shut-in since August, with anti-government fractions including militias, clansand public workers blockading oilfields and export infrastructure. Blockaded oil ports in Eastern Libyafailed to re-open after a deadline set by the central government in Tripoli passed in mid-December andthey remain closed at time of writing.



■ The escalation of in-fighting between the military and rebel forces in South Sudan seems to have haltedthe majority of the country's production, with fighting taking place in the Unity and Upper Nile States,where the majority of oil is produced. Peace talks are ongoing though we see scope for violence toescalate further, with signs that the situation could unravel into a prolonged war of attrition between thetwo sides - posing a serious risk to the country's oil production.

■ Continued challenges in Iraq's upstream environment put the country's plans for a big increase in oilproduction growth into further doubt. While the start of major upstream projects over in the comingquarters highlights Iraq's potential, volatile production and weak gas production underscore thecountry's challenges. Although we expect strong growth in both oil and gas output over the course of ourforecast period to 2022, we expect delays and setbacks to continue, causing production to underperformthe country's raw potential. As a result, we have taken a more bearish production outlook of just under3.4mn b/d for 2014 compared to an average of 3.5mn b/d previously. Most recently, the securityenvironment has deteriorated since sectarian tension flared up in Anbar province, raising another red flagwith regards to Iraq's operating landscape.

Elsewhere, production gains in Africa, North America and Latin America will drive overall global

production growth for 2014. We forecast global crude oil production to be 88.6mn b/d in 2014, up 2% year-

on-year. US crude oil production will reach 11.5mn b/d in 2014, up nearly 5% y-o-y (though lower than the

EIA's forecast for 12.1mn b/d). We are also closely watching the Mexico energy reforms, which could also

unleash a new wave of investment in the coming years.

Americas Spearheads Production Gains

% Change y-o-y in Crude Oil Production, by Region, 2014f

f=forecast. Source: BMI



Demand will be more buoyant than in 2013. Consumption of refined fuels (our measure of oil demand)

across major emerging market is going to increase at a healthy pace, offsetting muted growth from Western

Europe and North America, both of which are seeing a structural decline as energy efficiency rises (in the

case of Western Europe it is compounded by a cyclical decline as a result of years of weak economic

growth).

Global oil consumption for 2014 will reach 88.14mn b/d up 1.7% y-o-y, of which the US will account for

17.8mn b/d, China for 11mn b/d, Japan for 4.5mn b/d, India for 3.92mn b/d and Russia for 3.3mn b/

d. BMI's global macroeconomic assumptions underpin our consumption forecast. Accordingly, BMI's

global economists forecast 3.2% real growth for 2014, up from 2.6% in 2013. Our outlook on Chinese GDP

growth is more benign than it was at this time last year, which is also reflected in our forecasts for oil

consumption growth of 4% y-o-y for the country.

Some Lift From Emerging Markets

Refined fuels consumption, '000s b/d

2014=forecast. Source: EIA, BMI

Our global oil supply and demand balance shows a surplus of 489,000 b/d for 2014, which aligns with our

expectations for lower average Brent prices over the year.



Production outages and below-expectation output have worked to sustain Brent prices at historic highs,

creating a conducive pricing environment for capex. In addition, the bounty in the United States shale

formations has attracted the industry, with several players earmarking a large proportion of their budgets for

US shale (liquids) exploration.

Benign Balance Outlook Prompts Lower Price Assumptions

Surplus/Deficit In Global Oil Market Balance ('000s b/d), Brent Basket Price, US$/bbl

2014=BMI forecast. Source: EIA, Bloomberg, BMI

Capex Growth Cycle Shifting Gears

Since 2010, when the industry recovered from the downturn of 2009, capex has been increasing at an

average of 12% y-o-y, according to data compiled by Bloomberg. However, following four years of rapid

increases in capital spending by international oil companies (IOCs) and national oil companies (NOCs), the

mood seems to be turning. Indeed, development costs have increased in tandem with spending in recent

years, as projects become more complex and skills shortages stretch the industry. According to data from

Bloomberg, exploration costs rose by an average of 20% y-o-y in 2012 and 2011, and considering the

similar growth trajectory in spending over 2013, we would expect a similar cost rise last year too.



A typical 5-year cycle in project development from exploration and appraisal (E&A) to commercial

production means that a lot of investors are now expecting companies to begin consolidating the gains from

the investment that started around 2010. We have therefore seen the industry discourse focus increasingly

on investor returns and dividends. A case in point is French company Total, which announced a reduction

in capex is in store post-2015 and that it will focus on cash flow from new developments that are due to

come online.

There are divergent expectations in the market for 2014 E&P capex. Our review of the announced 2014

capex plans from IOCs and NOCs shows that the majority of companies are looking at lower capital

spending in 2014 compared to 2013 (see table below). In a study on global E&P capex, Barclays estimates

that 2013 capex (organic) reached US$680bn and that the figure will increase in 2014 by 6% to US$723bn.

The largest oil field services companies also have given estimates that they expect capex in global E&P to

rise between 8%-10% in 2014.

Table: Announced Spending Budgets, US$bn

2013 Capex 2014 Capex

Total 28 26

Gazprom 32 21.1

Statoil 19 na

BP na 25

ConocoPhillips 16 16.7

Chevron 42 39.8

Exxon 38 na

GazpromNeft 8.2 8.5

PTT (Thailand) 12 10

Pertamina na 7.9

Source: BMI Research

A survey of analysts by Bloomberg, however, reveals that the industry is expecting capex growth to

decelerate in the coming years. For 2014, the global capex consensus forecast is US$541bn (-0.5% y-o-y),

rising to US$549bn (1.5% y-o-y) in 2015. Though the aggregate number is lower than the one quoted by the

Barclay's analysis (Bloomberg data excludes unlisted NOCs) the trend clearly indicates an expectation that

there will be a moderation in spending growth. This divergence in the outlook regarding capex plans is, in

our view, a reflection of the uncertainty regarding demand trends as well as the future pricing environment.



Capex Growth Tapering

Global E&P Capex (Organic), US$bn

e=Bloomberg consensus estimate. Source: Bloomberg

Fuelling the uncertainty in 2014 is the barrage of elections in major oil producing and consuming markets in2014 - including Brazil, Iraq, Colombia, Indonesia, India and Turkey. Energy policy is always a topic on theagenda, whether it is the upstream or the fuels market prices (and subsidies) that feature in the debate.BMI's global political risk analysts do not expect much turmoil to stem from these, though for the energymarkets, changes in energy policy could mean changes to the operating environment. Brazil, Indonesia,India and Iraq are the ones we will be watching closely as they are the most likely to have an impact on our2014 global oil market outlook.



Appendix

Asia - Regional Appendix

The data contained in these appendix tables is correct as of 1 January 2014. It represents a snapshot of our

regional forecasts at the end of our last publishing quarter. It is included for reference purposes only. Latest

data, reflecting forecasts made for the market this quarter, can be found in the Industry Forecast Scenario

section of this report. Please note, that because this table represents a snapshot of our last regional forecasts,

whereas data included in the Industry Forecast Scenario represents our latest forecasts made this quarter,

country-specific data may not match.

Table: Oil Consumption - Historical Data & Forecasts, 2011-2018 ('000b/d)

2011 2012 2013 2014 2015 2016 2017 2018

Australia 1,105 1,126 1,136 1,146 1,157 1,167 1,178 1,188

China 9,810 10,277 10,688 11,115 11,449 11,792 12,146 12,510

Hong Kong 365 290 325 353 377 398 418 437

India 3,411 3,622 3,754 3,920 4,124 4,358 4,616 4,892

Indonesia 1,384 1,384 1,370 1,356 1,363 1,374 1,385 1,399

Japan 4,608 4,910 4,699 4,534 4,479 4,461 4,452 4,451

Malaysia 598 598 616 636 657 680 703 728

Pakistan 418 440 462 481 495 505 510 531

Papua New Guinea 20 20 20 20 20 21 21 21

Philippines 316 302 317 330 337 340 343 348

Singapore 1,250 1,380 1,397 1,431 1,467 1,508 1,552 1,598

South Korea 2,258 2,301 2,313 2,325 2,334 2,348 2,360 2,367

Taiwan 1,030 1,080 1,094 1,119 1,147 1,181 1,217 1,247

Thailand 1,020 1,009 1,036 1,062 1,087 1,112 1,137 1,160

Vietnam 352 376 389 401 415 429 444 460

BMI Universe 27,944 29,115 29,616 30,228 30,908 31,676 32,483 33,339

Other Asia 963 994 1,024 1,054 1,085 1,115 1,141 1,169

Regional Total 28,907 30,109 30,641 31,283 31,992 32,790 33,624 34,507

f = forecast. Source: EIA, BMI



Table: Oil Consumption - Long-Term Forecasts, 2015-2022 ('000b/d)

2015 2016 2017 2018 2019 2020 2021 2022

Australia 1,157 1,167 1,178 1,188 1,199 1,210 1,221 1,232

China 11,449 11,792 12,146 12,510 12,823 13,144 13,472 13,809

Hong Kong 377 398 418 437 456 475 494 513

India 4,124 4,358 4,616 4,892 5,186 5,495 5,828 6,187

Indonesia 1,363 1,374 1,385 1,399 1,413 1,427 1,449 1,470

Japan 4,479 4,461 4,452 4,451 4,415 4,371 4,323 4,280

Malaysia 657 680 703 728 753 780 806 833

Pakistan 495 505 510 531 553 576 600 625

Papua New Guinea 20 21 21 21 22 22 23 23

Philippines 337 340 343 348 354 361 368 376

Singapore 1,467 1,508 1,552 1,598 1,646 1,698 1,752 1,809

South Korea 2,334 2,348 2,360 2,367 2,374 2,381 2,388 2,396

Taiwan 1,147 1,181 1,217 1,247 1,275 1,303 1,331 1,371

Thailand 1,087 1,112 1,137 1,160 1,184 1,219 1,256 1,293

Vietnam 415 429 444 460 474 488 503 518

BMI Universe 30,908 31,676 32,483 33,339 34,126 34,949 35,814 36,737

Other Asia 1,085 1,115 1,141 1,169 1,194 1,221 1,257 1,258

Regional Total 31,992 32,790 33,624 34,507 35,321 36,170 37,071 37,995


Table: Oil Production - Historical Data & Forecasts, 2011-2018 ('000b/d)

2011 2012 2013 2014 2015 2016 2017 2018

Australia 496 484 491 485 480 478 477 476

China 4,106 4,175 4,299 4,384 4,405 4,445 4,445 4,423

Hong Kong 0 0 0 0 0 0 0 0

India 904 899 923 951 977 963 949 936

Indonesia 1,003 962 920 926 932 907 885 868

Japan 19 18 17 17 17 16 16 16

Malaysia 605 622 687 708 746 828 846 912

Pakistan 63 62 63 65 66 68 68 70

Papua New Guinea 30 27 29 35 42 47 47 46



Oil Production - Historical Data & Forecasts, 2011-2018 ('000b/d) - Continued

2011 2012 2013 2014 2015 2016 2017 2018

Philippines 30 23 20 29 33 33 34 34

Singapore 1 1 1 1 1 1 1 1

South Korea 20 21 21 21 20 20 19 19

Taiwan 2 2 2 2 2 2 2 2

Thailand 397 414 413 418 433 427 419 408

Vietnam 319 359 377 402 417 426 423 418

BMI Universe 7995 8068 8262 8,442 8,571 8,661 8,631 8,629

Other Asia 336 337 344 341 338 331 322 314

Regional Total 8330 8405 8606 8783 8909 8991 8953 8943


Table: Oil Production - Long-Term Forecasts, 2015-2022 ('000b/d)

2015 2016 2017 2018 2019 2020 2021 2022

Australia 480 478 477 476 475 474 476 477

China 4,405 4,445 4,445 4,423 4,401 4,383 4,349 4,314

Hong Kong 0 0 0 0 0 0 0 0

India 977 963 949 936 923 911 899 887

Indonesia 932 907 885 868 853 838 823 808

Japan 17 16 16 16 16 15 15 15

Malaysia 746 828 846 912 969 941 914 887

Pakistan 66 68 68 70 71 72 73 75

Papua New Guinea 42 47 47 46 44 42 40 38

Philippines 33 33 34 34 33 32 31 31

Singapore 1 1 1 1 1 1 1 1

South Korea 20 20 19 19 19 18 18 18

Taiwan 2 2 2 2 2 2 2 2

Thailand 433 427 419 408 398 389 379 370

Vietnam 417 426 423 418 407 397 385 374

BMI Universe 8,571 8,661 8,631 8,629 8,612 8,516 8,404 8,296

Other Asia 338 331 322 314 306 298 292 292



Oil Production - Long-Term Forecasts, 2015-2022 ('000b/d) - Continued

2015 2016 2017 2018 2019 2020 2021 2022

Regional Total 8909 8991 8953 8943 8918 8814 8696 8588


Table: Refining Capacity - Historical Data & Forecasts, 2011-2018 ('000b/d)

2011 2012 2013 2014 2015 2016 2017 2018

Australia 757 738 668 605 543 543 543 543

China 10,185 10,385 10,826 11,086 11,434 11,634 11,919 11,919

Hong Kong 0 0 0 0 0 0 0 0

India 4,000 4,321 4,622 4,742 4,872 4,872 5,138 5,138

Indonesia 1,056 1,056 1,056 1,119 1,119 1,119 1,119 1,119

Japan 4,730 4,479 4,475 4,073 4,073 4,073 4,073 4,073

Malaysia 539 539 588 588 588 588 588 588

Pakistan 286 286 286 400 400 650 650 650

Papua New Guinea 37 37 37 37 37 37 37 37

Philippines 273 273 273 273 273 273 273 273

Singapore 1,357 1,357 1,357 1,357 1,357 1,357 1,357 1,357

South Korea 2,722 2,760 2,755 2,801 2,801 2,801 2,801 2,801

Taiwan 1,310 1,310 1,310 1,310 1,090 1,090 1,090 1,090

Thailand 1,214 1,214 1,214 1,214 1,214 1,524 1,524 1,524

Vietnam 140 140 140 140 140 190 345 451

BMI Universe 28,605 28,893 29,605 29,744 29,940 30,750 31,456 31,562

Other Asia 333 338 341 357 366 374 378 380

Regional Total 28,937 29,231 29,946 30,101 30,307 31,125 31,835 31,942


Table: Refining Capacity - Long-Term Forecasts, 2015-2022 ('000b/d)

2015 2016 2017 2018 2019 2020 2021. 2022

Australia 543 543 543 543 543 543 543 543

China 11,434 11,634 11,919 11,919 11,919 11,919 11,919 11,919



Refining Capacity - Long-Term Forecasts, 2015-2022 ('000b/d) - Continued

2015 2016 2017 2018 2019 2020 2021. 2022

Hong Kong 0 0 0 0 0 0 0 0

India 4,872 4,872 5,138 5,138 5,138 5,138 5,138 5,138

Indonesia 1,119 1,119 1,119 1,119 1,119 1,119 1,119 1,119

Japan 4,073 4,073 4,073 4,073 4,073 4,073 4,073 4,073

Malaysia 588 588 588 588 738 888 888 888

Pakistan 400 650 650 650 650 650 650 650

Papua New Guinea 37 37 37 37 37 37 37 37

Philippines 273 273 273 273 273 273 273 273

Singapore 1,357 1,357 1,357 1,357 1,357 1,357 1,357 1,357

South Korea 2,801 2,801 2,801 2,801 2,801 2,801 2,801 2,801

Taiwan 1,090 1,090 1,090 1,090 1,090 1,090 1,090 1,090

Thailand 1,214 1,524 1,524 1,524 1,524 1,524 1,524 1,524

Vietnam 140 190 345 451 501 501 501 501

BMI Universe 29,940 30,750 31,456 31,562 31,762 31,912 31,912 31,912

Other Asia 366 374 378 380 383 385 385 386

Regional Total 30,307 31,125 31,835 31,942 32,145 32,297 32,297 32,298


Table: Gas Production - Historical Data & Forecasts, 2011-2018 (bcm)

2011 2012 2013 2014 2015 2016 2017 2018

Australia 45.58 48.24 49.78 64.11 103.18 118.91 123.77 134.29

China 102.77 108.40 112.74 117.25 123.11 129.26 135.73 142.51

Hong Kong 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

India 47.62 40.38 39.17 38.76 37.61 38.24 46.70 58.39

Indonesia 76.25 71.25 72.30 75.99 76.83 76.53 77.03 75.49

Japan 4.99 3.27 3.20 3.12 3.05 2.98 2.91 2.85

Malaysia 61.73 62.35 68.27 71.68 75.99 80.16 80.97 81.98

Pakistan 39.15 38.76 39.34 39.73 40.13 39.73 39.33 38.55

Papua New Guinea 0.10 0.10 0.10 5.04 9.83 9.83 12.04 14.81

Philippines 2.90 3.79 3.77 3.96 4.08 4.12 4.14 4.14

Singapore 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

South Korea 1.01 0.44 0.42 0.41 0.40 0.39 0.38 0.36



Gas Production - Historical Data & Forecasts, 2011-2018 (bcm) - Continued

2011 2012 2013 2014 2015 2016 2017 2018

Taiwan 0.29 0.28 0.27 0.26 0.25 0.25 0.24 0.23

Thailand 36.99 36.62 36.62 36.99 37.59 38.19 38.79 39.38

Vietnam 7.71 9.30 12.04 12.25 13.08 13.44 13.04 14.06

BMI Universe 427.09 423.18 438.03 469.56 525.14 552.03 575.07 607.04

Other Asia 70.07 73.92 77.67 81.60 85.58 89.78 93.87 98.15

Regional Total 497 497 516 551 611 642 669 705


Table: Gas Production - Long-Term Forecasts, 2015-2022 (bcm)

2015 2016 2017 2018 2019 2020 2021 2022

Australia 103.18 118.91 123.77 134.29 143.63 147.04 147.73 148

China 123.11 129.26 135.73 142.51 152.49 165.45 179.52 195

Hong Kong 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0

India 37.61 38.24 46.70 58.39 62.38 60.54 58.76 57

Indonesia 76.83 76.53 77.03 75.49 76.63 77.80 76.24 77

Japan 3.05 2.98 2.91 2.85 2.78 2.72 2.65 3

Malaysia 75.99 80.16 80.97 81.98 83.62 80.69 78.27 76

Pakistan 40.13 39.73 39.33 38.55 38.16 37.40 37.02 37

Papua New Guinea 9.83 9.83 12.04 14.81 15.36 17.85 20.35 20

Philippines 4.08 4.12 4.14 4.14 4.14 4.14 4.14 4

Singapore 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0

South Korea 0.40 0.39 0.38 0.36 0.35 0.34 0.33 0

Taiwan 0.25 0.25 0.24 0.23 0.22 0.22 0.21 0

Thailand 37.59 38.19 38.79 39.38 39.96 39.56 39.16 39

Vietnam 13.08 13.44 13.04 14.06 15.85 16.40 16.25 16

BMI Universe 525.14 552.03 575.07 607.04 635.58 650.16 660.64 672.11

Other Asia 85.58 89.78 93.87 98.15 103.53 108.60 113.88 114.88

Regional Total 611 642 669 705 739 759 775 787




Table: Gas Consumption - Historical Data & Forecasts, 2011-2018 (bcm)

2011 2012 2013 2014 2015 2016 2017 2018

Australia 35.09 28.89 29.61 30.35 31.11 31.89 32.53 33.18

China 130.92 145.89 161.51 176.04 191.88 207.23 221.74 237.26

Hong Kong 3.20 3.50 3.70 3.86 4.02 4.18 4.35 4.52

India 64.01 58.77 59.01 62.42 66.40 70.80 75.54 80.57

Indonesia 37.58 39.08 40.65 42.68 44.39 46.16 48.01 49.45

Japan 111.79 122.02 120.43 120.07 120.19 122.66 124.86 124.99

Malaysia 30.62 31.23 32.48 33.78 34.79 35.84 36.73 37.65

Pakistan 39.15 38.76 39.34 39.73 40.53 41.34 42.17 43.01

Papua New Guinea 0.10 0.10 0.10 0.11 0.11 0.11 0.11 0.11

Philippines 2.90 3.64 3.75 3.99 4.21 4.27 5.13 5.65

Singapore 8.78 8.94 9.17 9.49 9.81 10.16 10.51 10.86

South Korea 45.71 49.63 53.90 55.73 57.51 56.19 54.50 52.49

Taiwan 16.21 17.00 17.34 17.69 17.87 18.05 18.41 18.78

Thailand 46.57 49.26 51.72 54.05 56.48 59.02 61.68 64.46

Vietnam 7.71 9.30 12.04 12.25 13.77 14.44 14.42 16.56

BMI Universe 580.34 606.03 634.75 662.25 693.08 722.34 750.69 779.53

Other Asia 70.07 73.92 77.67 81.60 85.58 89.78 93.87 98.15

Regional Total 650 680 712 744 779 812 845 878


Table: Gas Consumption - Long-Term Forecasts, 2015-2022 (bcm)

2015 2016 2017 2018 2019 2020 2021 2022

Australia 31.11 31.89 32.53 33.18 33.84 34.52 35.21 36

China 191.88 207.23 221.74 237.26 253.87 271.64 290.66 311

Hong Kong 4.02 4.18 4.35 4.52 4.69 4.87 5.06 5

India 66.40 70.80 75.54 80.57 85.85 91.36 97.24 104

Indonesia 44.39 46.16 48.01 49.45 50.93 52.46 54.03 56

Japan 120.19 122.66 124.86 124.99 124.74 124.74 123.49 122

Malaysia 34.79 35.84 36.73 37.65 38.59 38.98 39.37 40

Pakistan 40.53 41.34 42.17 43.01 43.87 44.75 45.64 47

Papua New Guinea 0.11 0.11 0.11 0.11 0.12 0.12 0.12 0

Philippines 4.21 4.27 5.13 5.65 6.28 6.40 6.85 7



Gas Consumption - Long-Term Forecasts, 2015-2022 (bcm) - Continued

2015 2016 2017 2018 2019 2020 2021 2022

Singapore 9.81 10.16 10.51 10.86 11.23 11.62 12.02 12

South Korea 57.51 56.19 54.50 52.49 50.39 49.38 50.57 52

Taiwan 17.87 18.05 18.41 18.78 19.34 19.92 20.72 22

Thailand 56.48 59.02 61.68 64.46 67.36 70.39 73.56 77

Vietnam 13.77 14.44 14.42 16.56 18.85 20.58 21.52 21

BMI Universe 693.08 722.34 750.69 779.53 809.95 841.72 876.05 911.30

Other Asia 85.58 89.78 93.87 98.15 103.53 108.60 113.88 114.88

Regional Total 779 812 845 878 913 950 990 1,026


Table: LNG Exports - Historical Data & Forecasts, 2011-2018 (bcm)

2011 2012 2013 2014 2015 2016 2017 2018

Australia 10.49 19.35 20.16 33.75 72.07 87.02 91.24 101.11

China (16.90) (20.27) (23.50) (26.80) (33.79) (35.86) (40.00) (42.40)

Hong Kong 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

India (16.39) (18.39) (19.84) (23.67) (28.79) (32.57) (28.86) (22.18)

Indonesia 29.10 28.43 21.60 26.16 25.30 23.21 21.87 18.89

Japan (106.80) (118.75) (117.24) (116.95) (117.14) (119.67) (121.95) (122.14)

Malaysia 0.00 29.00 33.67 35.78 39.07 42.21 42.11 43.27

Pakistan 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Papua New Guinea 0.00 0.00 0.00 4.93 9.72 9.72 11.93 14.70

Philippines 0.00 0.00 0.00 (0.03) (0.13) (0.13) (1.05) (1.51)

Singapore 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

South Korea (44.70) (49.19) (53.47) (55.32) (57.11) (55.80) (54.13) (52.12)

Taiwan 0.00 (16.72) (17.07) (17.43) (17.61) (17.80) (18.17) (18.54)

Thailand 0.00 0.00 (2.15) (3.00) (5.00) (7.00) (9.00) (11.00)

Vietnam 0.00 0.00 0.00 0.00 (0.69) (1.00) (1.38) (2.50)

BMI Universe (145.20) (146.55) (157.83) (142.57) (114.11) (107.68) (107.37) (94.44)

Other Asia (8.40) (20.71) (24.62) (35.71) (44.27) (51.61) (62.95) (78.80)

Regional Total (153.60) (167.26) (182.45) (178.29) (158.38) (159.29) (170.32) (173.23)




Table: Net LNG Exports - Long-Term Forecasts, 2015-2022 (bcm)

2015 2016 2017 2018 2019 2020 2021 2022

Australia 72.07 87.02 91.24 101.11 109.79 112.52 112.52 112.52

China (33.79) (35.86) (40.00) (42.40) (44.00) (46.34) (48.83) (49.65)

Hong Kong 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

India (28.79) (32.57) (28.86) (22.18) (23.48) (30.82) (38.49) (46.52)

Indonesia 25.30 23.21 21.87 18.89 18.55 18.19 15.06 13.85

Japan (117.14) (119.67) (121.95) (122.14) (121.96) (122.02) (120.84) (119.66)

Malaysia 39.07 42.21 42.11 43.27 43.96 40.65 37.84 35.49

Pakistan 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Papua New Guinea 9.72 9.72 11.93 14.70 15.25 17.74 20.23 20.22

Philippines (0.13) (0.13) (1.05) (1.51) (2.13) (2.26) (2.70) (2.87)

Singapore 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

South Korea (57.11) (55.80) (54.13) (52.12) (50.03) (49.04) (50.23) (51.66)

Taiwan (17.61) (17.80) (18.17) (18.54) (19.11) (19.70) (20.50) (21.34)

Thailand (5.00) (7.00) (9.00) (11.00) (13.00) (16.00) (20.00) (24.00)

Vietnam (0.69) (1.00) (1.38) (2.50) (3.00) (4.18) (5.27) (5.52)

BMI Universe (114.11) (107.68) (107.37) (94.44) (89.17) (101.27) (121.21) (139.15)

Other Asia (44.27) (51.61) (62.95) (78.80) (93.90) (108.61) (136.65) (135.65)

Regional Total (158.38) (159.29) (170.32) (173.23) (183.06) (209.89) (257.86) (274.80)




Glossary

Table: Glossary Of Terms

AOR Additional oil recovery KCTS Kazakh Caspian Transport System

APA Awards for predefined areas km kilometres

API American Petroleum Institute LAB linear alkyl benzene

bbl barrel LDPE low density polypropylene

bcm billion cubic metres LNG liquefied natural gas

b/d barrels per day LPG liquefied petroleum gas

bn billion m metres

boe barrels of oil equivalent mcm thousand cubic metres

BTC Baku-Tbilisi-Ceyhan Pipeline Mcm mn cubic metres

BTU British thermal unit MEA Middle East and Africa

Capex capital expenditure mn million

CBM coal bed methane MoU memorandum of understanding

CEE Central and Eastern Europe mt metric tonne

CPC Caspian Pipeline Consortium MW megawatts

CSG coal seam gas na not available/ applicable

DoE US Department of Energy NGL natural gas liquids

EBRD European Bank for Reconstruction &Development NOC national oil company

EEZ exclusive economic zone OECD Organisation for Economic Cooperation & Development

e/f estimate/forecast OPEC Organization of the Petroleum Exporting Countries

EIA US Energy Information Administration PE polyethylene

EM emerging markets PP polypropylene

EOR enhanced oil recovery PSA production sharing agreement

E&P exploration and production PSC production sharing contract

EPSA exploration and production sharingagreement q-o-q quarter-on-quarter

FID final investment decision R&D research and development

FDI foreign direct investment R/P reserves/production

FEED front end engineering and design RPR reserves to production ratio

FPSO floating production, storage and offloading SGI strategic gas initiative

FTA free trade agreement SoI statement of intent

FTZ free trade zone SPA sale and purchase agreement

GDP gross domestic product SPR strategic petroleum reserve



Glossary Of Terms - Continued

AOR Additional oil recovery KCTS Kazakh Caspian Transport System

G&G geological and geophysical t/d tonnes per day

GoM Gulf of Mexico tcm trillion cubic metres

GS geological survey toe tonnes of oil equivalent

GTL gas-to-liquids conversion tpa tonnes per annum

GW gigawatts TRIPS Trade-Related Aspects of IntellectualProperty Rights

GWh gigawatt hours trn trillion

HDPE high density polyethylene T&T Trinidad and Tobago

HoA heads of agreement TTPC Trans-Tunisian Pipeline Company

IEA International Energy Agency TWh terawatt hours

IGCC integrated gasification combined cycle UAE United Arab Emirates

IOC international oil company USGS US Geological Survey

IPI Iran-Pakistan-India Pipeline WAGP West African Gas Pipeline

IPO initial public offering WIPO World Intellectual Property Organization

JOC joint operating company WTI West Texas Intermediate

JPDA joint petroleum development area WTO World Trade Organization

Source: BMI



Methodology

Industry Forecast Methodology

BMI's industry forecasts are generated using the best-practice techniques of time-series modelling and

causal/econometric modelling. The precise form of model we use varies from industry to industry, in each

case being determined, as per standard practice, by the prevailing features of the industry data being

examined.

Common to our analysis of every industry is the use of vector autoregressions. Vector autoregressions allow

us to forecast a variable using more than the variable's own history as explanatory information. For

example, when forecasting oil prices, we can include information about oil consumption, supply and

capacity.

When forecasting for some of our industry sub-component variables, however, using a variable's own

history is often the most desirable method of analysis. Such single-variable analysis is called univariate

modelling. We use the most common and versatile form of univariate models: the autoregressive moving

average model (ARMA).

In some cases, ARMA techniques are inappropriate because there is insufficient historic data or data quality

is poor. In such cases, we use either traditional decomposition methods or smoothing methods as a basis for

analysis and forecasting.

BMI mainly uses OLS estimators and in order to avoid relying on subjective views and encourage the use

of objective views, BMI uses a 'general-to-specific' method. BMI mainly mainly uses a linear model, but

simple non-linear models, such as the log-linear model, are used when necessary. During periods of

'industry shock', for example poor weather conditions impeding agricultural output, dummy variables are

used to determine the level of impact.

Effective forecasting depends on appropriately selected regression models. BMI selects the best model

according to various different criteria and tests, including but not exclusive to:

■ R2 tests explanatory power; adjusted R2 takes degree of freedom into account;

■ Testing the directional movement and magnitude of coefficients;

■ Hypothesis testing to ensure coefficients are significant (normally t-test and/or P-value);

■ All results are assessed to alleviate issues related to auto-correlation and multi-collinearity.



BMI uses the selected best model to perform forecasting.

Human intervention plays a necessary and desirable role in all of BMI's industry forecasting. Experience,

expertise and knowledge of industry data and trends ensure that analysts spot structural breaks, anomalous

data, turning points and seasonal features where a purely mechanical forecasting process would not.

Sector-Specific Methodology

There are a number of principal criteria that drive our forecasts for each energy indicator.

Energy Supply

This covers the supply of crude oil, natural gas, refined oil products and electrical power, which is

determined largely by investment levels, available capacity, plant utilisation rates and national policy. We

therefore examine:

■ National energy policy, stated output goals and investment levels;

■ Company-specific capacity data, output targets and capital expenditures, using national, regional andmultinational company sources;

■ International quotas, guidelines and projections from organisations such as OPEC, IEA, and EIA.

Energy Consumption

A mixture of methods is used to generate demand forecasts, applied as appropriate to each individual

country:

■ Underlying economic (GDP) growth for individual countries/regions, sourced from BMI publishedestimates;

■ Historic relationships between GDP growth and energy demand growth at an individual country areanalysed and used as the basis for predicting levels of consumption;

■ Government projections for oil, gas and electricity demand;

■ Third-party agency projections for regional demand, from organisations such as the IEA, EIA, OPEC;

Extrapolation of capacity expansion forecasts based on company- or state-specific investment levels.



Cross Checks

Whenever possible, we compare government and/or third-party agency projections with the declared

spending and capacity expansion plans of the companies operating in each individual country. Where there

are discrepancies, we use company-specific data as physical spending patterns to determine capacity and

supply capability. Similarly, we compare capacity expansion plans and demand projections to check the

energy balance of each country. Where the data suggest imports or exports, we check that necessary

capacity exists or that the required investment in infrastructure is taking place.

Source

Sources include those international bodies mentioned above, such as OPEC, IEA, and EIA, as well as local

energy ministries, official company information, and international and national news, plus international and

national news agencies.

Risk/Reward Ratings Methodology

BMI's Risk/Reward Ratings (RRR) provide a comparative regional ranking system evaluating the ease of

doing business and the industry-specific opportunities and limitations for potential investors in a given

market. The RRR system divides into two distinct areas:

Rewards: Evaluation of sector's size and growth potential in each state, and also broader industry/state

characteristics that may inhibit its development. This is further broken down into two sub categories:

■ Industry Rewards (this is an industry-specific category taking into account current industry size andgrowth forecasts, the openness of market to new entrants and foreign investors, to provide an overallscore for potential returns for investors);

• Country Rewards (this is a country-specific category, and the score factors in favourable political andeconomic conditions for the industry).

Risks: Evaluation of industry-specific dangers and those emanating from the state's political/economic

profile which call into question the likelihood of anticipated returns being realised over the assessed time

period. This is further broken down into two sub categories:

■ Industry Risks (this is an industry-specific category whose score covers potential operational risks toinvestors, regulatory issues inhibiting the industry, and the relative maturity of a market);

• Country Risks (this is a country-specific category in which political and economic instability,unfavourable legislation and a poor overall business environment are evaluated to provide an overallscore).



We take a weighted average, combining market and country risks, or industry and country rewards. These

two results in turn provide an overall Risk/Reward Rating, which is used to create our regional ranking

system for the risks and rewards of involvement in a specific industry in a particular country.

For each category and sub-category, each state is scored out of 100 (with 100 the best), with the overall

Risk/Reward Rating a weighted average of the total score. Importantly, as most of the countries and

territories evaluated are considered by BMI to be 'emerging markets', our rating is revised on a quarterly

basis. This ensures that the rating draws on the latest information and data across our broad range of

sources, and the expertise of our analysts.

BMI's approach in assessing the risk/reward balance for infrastructure industry investors globally is

fourfold:

■ First, we identify factors (in terms of current industry/country trends and forecast industry/countrygrowth) that represent opportunities to would-be investors;

■ Second, we identify country and industry-specific traits that pose or could pose operational risks towould-be investors;

■ Third, we attempt, where possible, to identify objective indicators that may serve as proxies for issues/trends to avoid subjectivity;

■ Finally, we use BMI's proprietary Country Risk Ratings (CRR) in a nuanced manner to ensure that onlythe aspects most relevant to the infrastructure industry are incorporated. Overall, the system offers anindustry-leading, comparative insight into the opportunities/risks for companies across the globe.

Sector-Specific Methodology

BMI's approach in assessing the risk/reward balance for oil and gas industry investors is threefold:

■ First, we have disaggregated the upstream (oil and gas E&P) and downstream (oil refining and marketing,gas processing and distribution), enabling us to take a more nuanced approach to analysing the potentialin each segment, and identifying the different risks along the value chain.

■ Second, we have identified objective indicators that may serve as proxies for issues and trends that werepreviously evaluated on a subjective basis.

■ Finally, we have used BMI's proprietary Country Risk Ratings in a more refined manner in order toensure that only those risks most relevant to the industry have been included.

Conceptually, the ratings system is organised in a manner that enables us clearly to present the comparative

strengths and weaknesses of each state. The headline oil and gas rating is the principal rating. However, the

differentiation of upstream and downstream and the articulation of the elements that comprise each segment



enable more sophisticated conclusions to be drawn, and also facilitate the use of the ratings by clients who

have varying levels of exposure and risk appetite.

Our sector-specific industry ratings include:

■ Oil & Gas Risk/Reward Rating: This is the overall rating, which comprises 50% upstream and 50%downstream;

■ Upstream Oil & Gas Risk/Reward Rating: This is the overall upstream rating, which is composed ofrewards/risks (see below);

■ Downstream Oil & Gas Risk/Reward Rating: This is the overall downstream rating, which comprisesrewards/risks (see below).

The following indicators have been used. Overall, the rating uses three subjectively measured indicators and

41 separate indicators/datasets.

Table: Bmi's Oil & Gas Upstream Risk/Reward Ratings

Indicator Rationale

Upstream RRR: rewards

Industry rewards

Resource base

- Proven oil reserves, mn bbl Indicators used to denote total market potential. High values givenbetter scores.

- Proven gas reserves, bcm

Growth outlook

- Oil production growth, 2009-2014 Indicators used as proxies for BMI's market assumptions, with stronggrowth accorded higher scores.

- Gas production growth, 2009-2014

Market maturity

- Oil reserves/production Indicator used to denote whether industries are frontier/emerging/developed or mature markets. Low existing exploitation in relation topotential is accorded higher scores.

- Gas reserves and production

- Current oil production versus peak

- Current gas production versus peak

Country rewards

State ownership of assets, % Indicator used to denote opportunity for foreign NOCs/IOCs/independents. Low state ownership scores higher.

Number of non-state companies Indicator used to denote market competitiveness. Presence (and largenumber) of non-state companies scores higher.

Upstream RRR: risks



Bmi's Oil & Gas Upstream Risk/Reward Ratings - Continued

Indicator Rationale

Industry risks

Licensing terms Subjective evaluation of government policy towards sector againstBMI-defined criteria. Protectionist states are marked down.

Privatisation trend Subjective evaluation of government industry orientation. Protectioniststates are marked down.

Country risks

Physical infrastructure Rating from BMI's CRR. It evaluates the constraints imposed bypower, transport and communications infrastructure.

Long-term policy continuity risk From CRR. It evaluates the risk of a sharp change in the broaddirection of government policy.

Rule of law From CRR. It evaluates government's ability to enforce its will withinthe state.

Corruption From CRR, to denote risk of additional legal costs and possibility ofopacity in tendering or business operations affecting companies'ability to compete.

Source: BMI

Weighting

Given the number of indicators/datasets used, it would be inappropriate to give all sub-components equal

weight. Consequently, the following weighting has been adopted:



Table: Weighting

Component Weighting (%)

Upstream RRR 50, of which

Rewards 70 of Upstream RRR, of which

- Industry rewards 75

- Country rewards 25

Risks 30 of Upstream RRR, of which

- Industry risks 65

- Country risks 35

Downstream RRR 50 of Oil & Gas RRR, of which

Rewards 70 ,of which

- Industry rewards 75

- Country rewards 25

Risks 30, of which

- Industry risks 60

- Country risks 40

Source: BMI



malaysia - ump libraryumplibrary.ump.edu.my/images/manual/serial_report/bmi_malaysia_… · oil...

Documents