JPMorgan Global LNG Feb 2012

www.morganmarkets.com

Global Equity Research13 January 2012

Global LNGFull steam ahead, but cross-basin arbitrageurs beware Henry Hub price diffusion

European Oil & Gas

Fred Lucas AC

(44-20) 7155 [email protected]

J.P. Morgan Securities Ltd.

Nitin Sharma AC

(44-20) 7155 [email protected]


Australian Oil & Gas

Benjamin Wilson AC

(61-2) [email protected]

J.P. Morgan Securities Australia Limited

Asian Oil & Gas

Brynjar Eirik Bustnes, CFA AC

(852) [email protected]

J.P. Morgan Securities (Asia Pacific) Limited

Indian Oil & Gas

Pradeep Mirchandani, CFA AC


J.P. Morgan India Private Limited

Russian Oil & Gas

Nadia Kazakova, CFA AC



North American Oil & Gas

Joseph Allman, CFA


J.P. Morgan Securities LLC

Katherine Lucas Minyard, CFA AC


J.P. Morgan Securities LLC

Global Commodity Research

Colin P. Fenton


JPMorgan Chase Bank NA

See page 245 for analyst certification and important disclosures, including non-US analyst disclosures.J.P. Morgan does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision.

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Fred Lucas(44-20) 7155 [email protected]

J.P. Morgan’s Global Oil & Gas Research Network

UK IntegratedsFred Lucas

(44-20) 7155 6131

[email protected]

UK & European Oil Services & EquipmentAndrew Dobbing

(44-20) 7155 6134

[email protected]

James Thompson

(44-20) 7325 9460

[email protected]

European IntegratedsNitin Sharma

(44-20) 7155 6133

[email protected]

UK Exploration & ProductionJessica Tadj-Saadat, CFA

(44-20) 7155 6636

[email protected]

Emerging Oils – RussiaNadia Kazakova, CFA

(7-495) 937 7329

[email protected]

Andrey Gromadin, CFA

(7-495) 967 1037

[email protected]

Emerging Oils – AsiaBrynjar Bustnes

(852) 2800 8578

[email protected]

Sophie Tan

(852) 2800 8578

[email protected]

Sukit Chawalitakul

(66-2) 684 2679

[email protected]

Australian OilsBenjamin Wilson

(61-2) 9220 1384

[email protected]

Daniel Butcher

(61-2) 9220 1405

[email protected]

Indian OilsPradeep Mirchandani, CFA

(91-22) 6157 3591

[email protected]

For Specialist Sales advice, please contact:Hamish Clegg

(44-20) 7325 0878

[email protected]

Americas Exploration and ProductionJoseph Allman, CFA

(1-212) 622-4864

[email protected]

Jeanine Wai

(1-212) 622-6489

[email protected]

Jessica Lee

(1-212) 622-9812

[email protected]

Americas Oil Services & EquipmentJ. David Anderson, PE, CFA

(1-212) 622-6684

[email protected]

Samantha Hoh, CFA

(1-212) 622-5248

[email protected]

William S Thompson

(1-212) 622-9978

[email protected]

Americas Integrated OilsKatherine Lucas Minyard, CFA

(1-212) 622-6402

[email protected]

Igor Grinman

(1-212) 622-6596

[email protected]

Emerging Oils – LatAmCaio Carvalhal

(55-11) 3048-3946

[email protected]

Felipe Dos Santos

(55-11) 4950-3796

[email protected]

South African OilsAlex Comer

(44-20) 7325 1964

[email protected]

Head of Global Commodity ResearchColin Fenton

(1-212) 834-5648

[email protected]

Energy Strategy – OilLawrence Eagles

(1-212) 834-8107

[email protected]

David G Martin

(44-20) 7777-0211

[email protected]

Energy Strategy – GasScott Speaker

(1-212) 834-3878

[email protected]

mailto:[email protected]








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J.P. Morgan Global Oil & Gas Equity Coverage

UK Integrateds - Fred Lucas

BG Group, BP, RD Shell A & B

UK & European Oil Services & Equipment - Andrew Dobbing

Aker Solutions, Amec, CGG Veritas, Petrofac, Saipem, Subsea 7, TGS Nopec, Technip, Tecnicas Reunidas

James Thompson - Cape, Hunting, Lamprell, PGS

European Integrateds - Nitin Sharma

ENI, Essar Energy, Galp Energia, OMV, Repsol YPF, Statoil, TOTAL

UK E & P - Jessica Tadj-Saadat, CFA

Afren, Cairn Energy, Enquest, Genel Energy, Heritage Oil, Ophir Energy, Serica Energy, Soco, Tullow Oil

Emerging Oils – Russia - Nadia Kazakova, CFA

C.A.T Oil, Eurasia Drilling Company, Gazprom, Gazprom Neft, HMS Group, MOL, Novatek, PKN Orlen, Rosneft, Surgutneftegaz, Surgutneftegaz Prefs

Andrey Gromadin, CFA

Alliance Oil Company, Bashneft, Bashneft (pref), Integra, Lotos, Lukoil, Tatneft, Tatneft Prefs, Tupras

Emerging Oils – Asia - Brynjar Bustnes

CNOOC, China Oilfield Services Limited, Inpex Corporation, MIE Holdings, PetroChina, S-OIL Crop, SK Energy, Sinopec

Emerging Oils – Thailand – Sukit Chawalitakul

PTT, PTTEP, Thai Oil

Australian Oils - Benjamin Wilson, Daniel Butcher

AWE Limited, Beach Energy, Oil Search, ROC Oil, Santos, Woodside Petroleum

Indian Oils - Pradeep Mirchandani, CFA

BPCL, Cairn India Ltd., Essar Oil, GAIL, Gujarat Gas Gujarat State Petronet Ltd., HPCL, Indian Oil, Indrapastha Gas, Oil India Ltd., ONGC, Petronet LNG Ltd., Reliance Industries Ltd.

USA Exploration & Production - Joseph Allman, CFA

ATP Oil & Gas, Anadarko Petroleum, Apache Corp., Approach Resources, Atlas Energy, Berry Petroleum, Brigham Exploration, Cabot Oil & Gas, Carrizo Oil & Gas, Chesapeake Energy, Cobalt International Energy, Concho Resources, Continental Resources, Denbury Resources, Devon Energy, EOG Resources, EQT Corp., EXCO Resources, El Paso Corp., Goodrich Petroleum, McMoran Exploration, Newfield Exploration, Noble Energy, PDC Energy, Penn Virginia Corp., PetroQuest Energy, Pioneer Natural Resources, Plains E&P, QEP Resources, Quicksilver Resources, Range Resources Corp., SM Energy, SandRidge Energy, Southwestern Energy, Swift Energy, Ultra Petroleum, Venoco Inc., Whiting Petroleum Corp., Williams Companies

USA Oil Services & Equipment - J.David Anderson, PE, CFA

Baker Hughes, Cameron Int’l, C&J Energy Services, Diamond Offshore, Dresser-Rand, Dril-Quip, Ensco, Exterran Holdings, FMC Technologies, Halliburton, National Oilwell Varco, Noble Corp, Rowan Companies, Schlumberger, Transocean, Weatherford Inernational

Integrateds - Katherine Lucas Minyard, CFA

USA - Chevron, ConocoPhillips, Exxon Mobil, Hess, Marathon Oil, Murphy Oil, Occidental Petroleum

Canada – Baytex Energy, Canadian NaturalResources, Cenovus Energy, Husky Energy, MEG Energy, Nexen, Suncor Energy, Talisman Energy, Lone Pine Resources, Penn West Exploration

Emerging Oils – LatAm – Caio Carvalhal

Ecopetrol. Gran Tierra Energy, HRT, Lupatech, OGX, Petrobras, Pacific Rubiales, Tenaris

South African Oils - Alex Comer

Sasol

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Table of ContentsOne-minute, one-page synopsis .............................................6

Introduction – global thematic research ................................7Executive Summary .................................................................9

Global theme – LNG demand growth....................................15LNG market .............................................................................17

North American LNG export potential ..................................27LNG pricing – the Henry Hub threat......................................30

Global LNG supply & demand scenarios .............................37Origin of LNG competitive advantages ................................50

Competitive ranking of LNG players.....................................55Alternative strategies to play LNG theme ............................60

Company Profiles ...................................................................63BG Group ................................................................................64

BP ............................................................................................80RD Shell...................................................................................87

ENI ...........................................................................................96Repsol YPF ...........................................................................100

Statoil ....................................................................................105TOTAL ...................................................................................108

Chevron.................................................................................113Exxon Mobil ..........................................................................117

Gazprom................................................................................121Novatek .................................................................................130

Oil Search..............................................................................132Santos ...................................................................................136

Woodside ..............................................................................141Origin Energy........................................................................149

Inpex ......................................................................................151Overview China LNG ............................................................158

CNOOC..................................................................................165PetroChina ............................................................................167

Sinopec .................................................................................168Overview India LNG..............................................................169

Petronet LNG ........................................................................171

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AppendicesAppendix I: LNG exporting countries .................................173

Appendix II: LNG export projects........................................175

Appendix III: LNG importing countries...............................178

Appendix IV: LNG shipping .................................................182

Appendix V: Floating LNG ...................................................187

Appendix VI: A brief history of LNG ...................................189

Appendix VII: Glossary of terms in LNG ............................190

Appendix VIII: Company financials.....................................208

Equity Ratings and Price Targets

Mkt Cap Price Rating Price TargetCompany Symbol ($ mn) CCY Price Cur Prev Cur PrevBG Group BG.L 75,875.38 GBp 1,448 OW n/c 1,900 1,800BP BP.L 139,011.70 GBp 475 OW n/c 575 n/cRoyal Dutch Shell B RDSb.L 234,869.60 GBp 2,414 N n/c 2,400 n/cENI ENI.MI 76,015.01 EUR 16.50 OW n/c 21.00 n/cRepsol YPF REP.MC 34,465.86 EUR 22.20 N n/c 25.00 n/cStatoil STL.OL 80,427.16 NOK 152.40 UW n/c 145.00 n/cTOTAL TOTF.PA 113,747.60 EUR 39.88 OW N 49.00 47.00Chevron Corp CVX 215,397.00 USD 107.77 UW n/c 120.00 n/cExxon Mobil Corp XOM 412,042.40 USD 85.08 UW n/c 92.00 n/cGazprom GAZP.RTS 129,013.20 USD 5.63 N n/c 6.94 n/cNovatek NVTKq.L 40,959.77 USD 134.90 UW n/c 82.90 n/cOil Search OSH.AX 8,904.85 AUD 6.57 N n/c 8.01 n/cSantos Limited STO.AX 12,316.17 AUD 12.75 OW n/c 18.59 n/cWoodside Petroleum WPL.AX 26,674.44 AUD 32.37 UW n/c 44.64 n/cInpex Corporation 1605.T 24,262.33 JPY 510,000 OW n/c 750,000 n/cCNOOC 0883.HK 86,370.72 HKD 15.02 UW n/c 12.50 n/cSinopec Corp - H 0386.HK 19,191.29 HKD 8.88 OW n/c 9.40 n/cPetroChina 0857.HK 29,286.29 HKD 10.78 UW n/c 8.50 n/cPetronet LNG Ltd. PLNG.BO 2,298.83 INR 161.60 N n/c 190.00 n/cOrigin Energy ORG.AX 14,986.55 AUD 13.49 OW n/c 18.95 n/cSource: Company data, Bloomberg, J.P.Morgan estimates. n/c = no change. All prices as of 11 Jan 12 except for OSH.AX [12 Jan 12] STO.AX [12 Jan 12] WPL.AX [12 Jan 12] 1605.T [12 Jan 12] 0883.HK [12 Jan 12] 0386.HK [12 Jan 12] 0857.HK [12 Jan 12] ORG.AX [12 Jan 12].

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One-minute, one-page synopsis

The Arab Spring and the Fukushima tragedy have only emboldened the script in favor of global LNG. Notwithstanding its relatively high cost, we believe that the case for LNG is underpinned by five very durable, investable and politically charged themes: (i) national energy supply security (ii) national energy supply flexibility (iii) national energy infrastructure renewal to improve system resilience to supply-demand shocks, stimulate investment and reduce unemployment (iv) the de-carbonization of economic growth as a social imperative, so continuing the displacement of coal by natural gas (v) given rising popular opposition, a further slow down in nuclear power generation. These factors will continue to drive long term LNG contract agreements close enough to oil price parity to warrant the very large upfront capital investment that LNG export chains mandate.

We acknowledge that the LNG market dynamics are complex and a clear understanding of the global supply-demand balance is very difficult given limited public disclosure on contract pricing and off-take flexibility. With this caveat, we believe that the global LNG market will remain tight for the next 2-3 years given a notable slow down in liquefaction capacity additions (2011-13E +27 MT pa, +9% versus 2008-10 +82 MT pa, +40%), high risks of further project delays and very resilient demand patterns, most notably in Asia Pacific, but also supported by an increasing number of new LNG importers in Europe, the Middle East and elsewhere. We estimate that the number of countries with LNG import capabilities will rise from 25 (90 import terminals) at end 2011 to 48 (160 terminals) by end 2015.

Given the aforementioned themes and project delay risk, we have a bias to our BULL case set of assumptions - global demand reaches 368 MT by 2018E (2011E 249 MT), a 2011-18 CAGR of 6% (versus 2000-10 CAGR +8%). In the absence of meaningful domestic gas shale supplies, Chinese LNG demand surpasses 30 MT in 2016 (2011E 12 MT); Indian demand reaches 20 MT by 2015 (2011E 10 MT). On this basis, the LNG market will continue to tighten 2012 to 2014 and will be supply constrained from 2015 to 2017. Near term this is supportive of oil-indexed LNG contract pricing and supports meaningful regional price differentials 2012-14 which will provide suppliers with portfolio flexibility with profitable cargo diversion opportunities.

However, a new pricing paradigm is emerging in the shape of Henry Hub indexed supply contracts for US gas sourced LNG exports. Given this and a meaningful deepening LNG market liquidity post-2014, this will likely elevate depressed US gas prices and lead to tighter regional gas price dispersion. This will mitigate cross-basin arbitrage opportunities thus reducing the strategic value of portfolio supply flexibility and re-promoting the importance of water-tight long term contracts.

We continue to encourage investors to maintain / build exposure to names that are exposed to the global LNG theme. We review the LNG strategies, asset spreads and competitive positioning of 20 companies. From this, our top global IOC picks with Overweight recommendations are BG Group (PT 1900p - upside 31%), Inpex (PT Y750,000 – upside 47%), Santos (PT A$18.6 – upside 46%) and TOTAL (PT €49 –upside 22%). Our note also lists alternative plays in Equipment & Services (given the potential for $1 trillion of capital investment 2012-18E), E&Ps (small companies do not easily survive long cycle LNG projects) and Shipping (we anticipate robust rates through to 2013 and play this through the ship builders and the ship owners).

Five big themes underwrite LNG-–energy security, energy

flexibility, energy infrastructure

renewal, de-carbonization of GDP growth and a continued

transition away from nuclear

power

LNG markets will stay tight 2012-14 as capacity growth slows,

projects start late and new

demand centers grow

Our BULL scenario is supportive of oil priced indexation for long

term contracts and continued

regional price arbitrage 2012-14

New Henry Hub priced & sourced exports in 2015+ and

deeper market liquidity will then

tighten regional price dispersion

We favor four IOCs - BG Group, Inpex, Santos and TOTAL and

also cite alternatives in OFS,

E&P and Shipping sectors to play LNG theme

7



Introduction – global thematic research

This is the third of JPM’s globally themed oil & gas research pieces. In these global notes we tackle important industry themes by linking a comprehensive top down (macro) view of specific parts of the industry value chain with a detailed bottom-up (company) analysis and cross-border competitive analysis.

Figure 1: Holistic approach to analyzing the global oil & gas sector

Source: J.P. Morgan.

As per the schematic above, by combining cross-border company comparison with a top-down industry value chain analysis, we aim to provide more detailed and holistic insights and a different perspective to conventional silo-bound company specific research. In our view, this provides investors with superior industry insights and stock selection advice.

1. Global Upstream – Upstream, the shape of things to come, (23 September 2010). In that note, we examined the IOC portfolio transition to the upstream via downstream divestments / upstream acquisitions and rising upstream capital reinvestment. We also set out various long term metrics that enable upstream performance to be more clearly understood by investors and companies to be ranked accordingly.

2. Global Downstream – Refining – a long and painful sunset for many, (8 September 2011). In that note, we examined the global capacity outlook in refining and drew some very bearish conclusions about refining margins and returns over the near and medium term. We also analyzed various metrics that enable downstream performance to be measured and more clearly understood by

Gas (LNG) market

Refining industry

Growth potential

Capital stewardship

Restructuring potential

Portfolio risk

COMPANY SPECIFIC - Alpha

Oil market

MACRO – Alpha skew

BG

Gro

up

TO

TA

L

Wo

od

sid

e

BP

EN

I

Sta

toil

Ch

evro

n

Execution risk

San

tos

Valuation anomaly

xx

x

Industry is redeploying capital

upstream and raising exploration intensity

Refining is, and will remain, a

bad industry for many years

8



investors. We then ranked the developed market and emerging market IOCs and NOCs accordingly. We defined multiple ways to play this negative theme, via (long) positions in capacity enablers (EPC providers, software and hardware manufacturers) and (short) positions in the most challenged European refiners.

3. Global LNG – Full steam ahead, but cross-basin arbitrageurs beware the Henry Hub S-curve, (13 January 2012). In this note, we examine the demand drivers, capacity growth outlook and pricing dynamics of global LNG. We discuss the hallmarks of a good LNG business and perform a competitive ranking of the world's leading, listed players in LNG. We review the exposures of key names and assess their competitive positioning in the global LNG hierarchy. We conclude that LNG is no longer a ‘transition' fuel that reduces global carbon intensity, it is the ‘destination’ fuel of choice that ensures this happens whilst facilitating multi-lateral energy relationships to develop. We anticipate that robust global demand for LNG will keep the market tight 2012-14. Thereafter, the onset of new LNG supplies from North America directly linked to a Henry Hub price index and overall deeper market liquidity (as the number and scale of LNG supply points increase – we estimate potential for 118 MT pa of incremental capacity 2012-16 which is 42% of YE 2011 global capacity) will likely reduce regional price dispersion and volatility. This will ultimately constrain cross-basin arbitrage opportunities, most likely from 2015 onwards, although project delays may extend the arbitrage window.

LNG demand trends are very

firm, long term pricing is robust,

but cross-basin price arbitrage

9



Executive Summary

LNG infrastructure projects (liquefaction and re-gasification) rely on private sector investment and they create local employment. From an importer’s perspective, they diversify a country’s energy supplies / augment energy security whilst also ultimatelyreducing its carbon footprint. Furthermore, LNG re-gasification terminals (the import- enabling asset) may be built in 18-24 months; a cross-border gas pipeline may take over a decade to sanction and build. From the perspective of government, especially those fighting against high unemployment, large fiscal deficits, the threat of energy supply dislocations and rising environmental awareness, LNGinfrastructure projects have many of the key desirable attributes. The Fukushima tragedy has just added impetus for governments to steer energy dependency away from nuclear. We believe that the after effects of Fukushima on global energy markets will be felt for years to come. Following the Arab Spring, we also see a world where energy flows will become more, not less, politicized and energy diversification will be ever more important. The Durban UN Climate Change Conference has helpfully defined the road map for negotiations on a comprehensive climate change agreement and lent clear support for investment in the low-carbon economy. The script for rapid growth in LNG has, in many respects, been written.

In 2011, we estimate that there was approximately 291 MT of liquefaction capacitylocated in 18 countries and 27 plants (LNG export) and 565 MT of re-gasification (LNG import) capacity located in 25 countries and 90 terminals. Levels of re-gasification capacity will continue to exceed export capacity. We estimate that global aggregate re-gasification capacity will rise from 565 MT pa at end 2011 to 778 MT pa by end 2015 located in 48 countries and 160 terminals. This represents a capacity CAGR of 8%. Over the same period, we estimate that the aggregate liquefaction capacity will rise from 291 MT to 350 MT pa in 35 plants, a capacity CAGR of 5%. As such, we do not expect import capacity to be a constraint on LNG demand per say. However, the market may well remain supply constrained which enforces an element of demand latency not seen at other point in the hydrocarbon value chain.

We model two simple BEAR and BULL global LNG supply/demand scenarios. Our BULL case assumes liquefaction projects due on stream 2013 onwards are delayed by 12-months and operate at 75% capacity in their first year whilst existing capacity operates at 95%. We also assume that gas shale does not meaningfully displace potential Chinese demand. Under this set of assumptions, global demand reaches 368MT by 2018, a 2011-18 CAGR of 6%. Chinese demand surpasses 30 MT in 2016. The LNG market will continue to tighten 2012 to 2014 and will be supply constrained from 2015 to 2017. This is supportive of oil-indexed LNG contract pricing and should support meaningful regional price differentials which, in turn, will provide those LNG suppliers with portfolio flexibility with profitable cargo diversion opportunities.

Given the aforementioned structural LNG demand drivers, we feel that this outcome will be closer to reality than our BEAR case which assumes that all new capacity is commissioned on schedule and operates at 85% in its first year whilst existing capacity operates at 100%. We assume that gas shale does displace LNG demand in China and Europe is in a deep recession in 2012 and only gradually emerges from there in 2013-14. Under this scenario, global demand only reaches 291 MT by 2018 (24% below our BULL case demand estimate) and Chinese demand only reaches 19

LNG infrastructure build out dovetails in to a number of

global themes – multi-lateral

energy security, private sector investment and lower carbon

economic growth

LNG demand will not be constrained by import capacity

BULL case sees market tightening further in 2012 and

demand constrained by supplies

2014-17

BEAR case will see liquefaction projects deferred 2014 onwards

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MT in 2016. Levels of spare liquefaction capacity do not really change 2012-15 versus prior years but will rise substantially thereafter. However, if the world looks like it is heading in to this scenario, liquefaction projects which have not yet been sanctioned with an expected on stream date 2016-18 will almost certainly be deferred.

Refining is an industry that is prone to cyclical capacity imbalances, most often surpluses, for a variety of reasons. Refining is dogged by a large, fragmentedpopulation of players (many hundreds) that includes many non-commercial NOCs. As our global note on refining cautioned, unwanted refining capacity growth across such a broad population of players is very likely to occur – indeed, we estimate that two thirds of new refining capacity 2011-16 has a NOC sponsor behind it. Furthermore, new refineries are built without contracted off-take and thus must oftenmarginalize higher cost / less efficient existing refineries to secure their place in the market.

In contrast, LNG is blessed by a very small population of very rational IOCs (around 50-60) and a tiny population of disciplined NOCs (e.g. QPC- Qatar, Sonatrach -Algeria, Petronas - Malaysia and ADNOC – Abu Dhabi). Indeed, we estimate that in the seven year period 2012 to 2018, less than 5% (c.12 MT) of identified global capacity growth is NOC sponsored (in Algeria, Libya and potentially Iran). We believe that the risk of a maverick NOC pursuing a major LNG export project without firm long term off-take contracts has now passed – the upfront capital and market risks are simply too high. LNG is, and will remain, a relative niche business given a number of entry barriers - high capital intensity, long project lead times and the need to discover and certify very substantial (at least 3-4 TCF) gas resources. Demand concentration in LNG is also quite unique, e.g. we estimate that Japan consumed 36% of global LNG (89 MT of 249 MT) in 2011. Country specific demand shocks, as occurred in Japan in 2011 as a result of Fukushima which drove Japan’s 30% Y-o-Y LNG demand growth, can transform the global supply-demand situation over night. Such a high impact, single demand shock could simply not occur in refining. Similarly, LNG supply shocks pose a more severe ‘tail risk’ to market equilibrium. LNG capacity is very highly concentrated when compared to refining. For example, the world’s largest supplier, Qatar, has 77 MT of capacity which is approximately 27% of global capacity. All of Qatari LNG output transits via the Straits of Hormuz. Any blockade of this choke point, albeit temporary, would have a major impact on the global LNG market and cargo clearing prices in Europe and Asia Pacific.

Capacity displacement does not occur in LNG – new plants are typically built given firm demand for their incremental output. Provided equity project sponsors are price-sensitive, which we believe they are given rising capital costs and high levels of equity financing following the withdrawal of project finance capacity, new projects will only proceed with robust long-term pricing agreements and output that is largely bound up to long term firm buyers. The long term (20 years or more) contracting convention in LNG, completely absent from refining, is another support for sustained market equilibrium. We continue to monitor progress on no less than twelve green field LNG projects in Australia (Pluto, Gorgon, QC LNG, AP LNG, GLNG, Prelude, Wheatstone, Ichthys, Browse, Curtis LNG, Sunrise and Bonaparte) for evidence of robust long term demand at pricing close to oil price parity. So far, we estimate that over 60% of the aggregate capacity of these twelve projects (118 MT pa) already has firm contracts - we are confident that more long term contracts will follow at close to

The dynamics of LNG are

completely different to refining

LNG has fewer and more

disciplined players

New LNG capacity is often

contracted before it is built

11



oil price parity. Sponsoring much of this incremental demand is, of course, China’s continued integration in to global energy markets and its desire to develop multi-lateral energy relationships rather than become too dependent on any particular source e.g. piped gas which may be used as a geo-political influence. As a reminder, LNG offers a choice of multiple sources and added procurement flexibility that a conventional pipeline off-take agreement cannot provide.

At the start of 2012, we therefore continue to encourage investors to raise their equity portfolio exposure to listed names with a meaningful position in the LNG segment. Amongst the integrated names, our top global picks to play the LNG theme are BG Group, Inpex, Santos and TOTAL. Our note also provides an extensive range of alternative LNG plays in the E&P, Equipment & Services and Shipping sectors around the world.

12



Stock specific summary

For seven European names featured in this note, we highlight the key qualities and exposures to the LNG value chain (Tables 1 and 2).

Table 1: Stock summary – LNG SWOT summary + segment profile / valuation of UK companies

Key Strengths / Opportunities Key Weaknesses Key Threats Capacity, Earnings & ValuationBG GroupInnovated contractual concept of flexible destination LNG cargoes and differentiated by taking on multiple supply purchase agreements to build a portfolio of low cost supply options.

Retains leased rights to excessive (idle) volume of US re-gasification (LNG import) capacity.

Advent of US LNG exports will almost certainly reduce regional price arbitrage 2015 onwards.

CapacityLiquefaction: 7.2 MT pa operational, 7.9 MT pa under developmentRe-gasification: 23.7 MT pa (91% leased)

Operator of project that is front of queue of CBM to LNG projects in Australia –successfully contracted output from first two trains at close to oil price parity; likely to add a third train at QC LNG.

Late to realize the importance of a resource and liquefaction position in Asia Pacific – had to buy its way in to the play (QGC and Pure Energy).

Other large players are replicating BG Group’s portfolio strategy of buying its own LNG and using an array of supply contracts to optimize sales to different markets.

Earnings - LNG represents around 30% of BG Group’s 2011E earnings.

Subject to results of drilling campaign over next 6-months, potential to lead East Africa's first green field LNG project in Tanzania.

Given pre-salt capital commitments and finite capabilities, will struggle to pursue another major LNG project in parallelwith QC LNG Trains 1-2.

Cost inflation, magnified by AUD/USD appreciation at QC LNG project could further trim NPV following adverse fiscal changes.

Valuation - We value BG Group's LNG business at around $22bn or 409 pence per share (but this figure depends on the apportionment of value for QC LNG). Ranks 4th in our 11 company competitor ranking.

BPAcquired a strong position in Atlantic LNG (Trinidad) via Amoco which was expanded very cost effectively.

Following years of purposefully avoiding large infrastructure projects, left without any identifiable, firm growth options post-Angola LNG (on stream H1 2012).

Upstream portfolio lacks any clearly identifiable green field LNG growth option – BP may look to remedy this via acquisition / alliance in order to establish more long-lived assets.

CapacityLiquefaction: 12.2 MT pa operational, 0.7 MT pa under development.Re-gasification: 6.8 MT pa (71% leased)

Reasonable exposure to re-gasification capacity (57% of net liquefaction capacity).

Tangguh LNG contracted on a very low price to CNOOC (2.6 MT pa, $3.35 per mmbtu, capped at oil price equivalent of $38/bbl). Plant expansions in Indonesia have also proven problematichistorically.

Angola LNG may be obliged to sell in to the low priced US market.

Earnings - LNG represents around 10% of BP’s 2011E earnings.

Opportunity to supply Bontang LNG facility in Indonesia with coal bed methane – could be a world first.

No upstream supply position in Abu Dhabi to ADGAS.

Valuation - We value BP’s LNG business at $10bn or 33 pence per share. Given its upstream heritage and pedigree, BP is a bit of an ‘also ran’ in global LNG - it ranks 8th in our 11 company competitor ranking.

RD ShellInvolved in LNG since industry conception in early 1960s, now has world's number one position with c. 20 MT pa net operational capacity of which over 50% is located in Asia Pacific.

Failed to really see and grasp the regional price arbitrage opportunity –90% of LNG volumes still sold under long term contract with limited destination flexibility (although most long term contract are set on robust oil-price indexed terms).

Rights to MLNG Dua (1.2 MT pa) and Tiga (1.0 MT pa) set to expire in 2015 and 2023 respectively.

CapacityLiquefaction: – 19.9 MT pa operational, 8.9 MT pa under development.Re-gasification: 14.9 MT pa (85% leased)

Global position with very strong development pipeline with potential to more than double liquefaction capacity by 2020.

No upstream supply position to two LNG plants in Oman or any real chance of securing upstream supplies (not involved in tight gas exploration in Oman).

At $3,000 to $3,500 per ton (before any cost escalation to budget), floating LNG is not low cost and may need more than one application to generate a robust return.

Earnings - LNG represents around 10% of RD Shell’s 2011E earnings.

Pioneering development of world's first floating LNG project (Prelude FLNG) –numerous potential applications of this on other stranded gas deposits.

Certain project interests (Sunrise 33%, Browse 50% and Pluto LNG 90%) are held through 24.3% stake in Woodside which RD Shell is looking to exit.

GLNG is last in queue of 4 competing coal bed methane to LNG projects in Queensland, Australia – at greatest risk of delays and cost inflation, in our view.

Valuation - we value RD Shell's LNG business at $50bn or just over 500pence per share. Just pipped by Exxon Mobil, RD Shell ranks 2nd in our 11 company competitor ranking.


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Table 2: Stock summary – LNG SWOT summary + segment profile / valuation of European companies

Key Strengths / Opportunities Key Weaknesses Key Threats Capacity, Earnings & ValuationENIStrong presence in all the phases of LNG business - liquefaction, shipping, regas and marketing. ENI's first liquefaction plant was commissioned in 1977.

Portfolio is largely ex-growth with only one green field project (Angola LNG) on the company's near term agenda

LNG gas supplies are mostly routed into Italy/Europe – weakening demand will likely have a negative impact on segmental earnings.

CapacityLiquefaction: 5.7 MT pa operational, 0.7MT pa under development Re-gasification: 11.5MT (90% leased)

Given the size of recent discovery in West Africa (Mozambique), ENI may lead a multi train (3+) LNG facility in the country.

Lacks ambition of expanding into the higher margin gas arbitrage business. LNG strategy is focused on just the development of the company's equity gas resources via long term contracted off-take agreements.

ENI has a history of reliance on acquisitions to fuel its upstream growth ambitions

Earnings - LNG represents around 7% of ENI’s 2011E earnings.

Acquisition of Distrigas helped ENI diversify its LNG supply portfolio.

Limited liquefaction position in the higher demand growth Asia-pacific basin.

Valuation - We value ENI’s LNG business at €5bn. ENI ranks 9th in our 11 company competitor ranking.

Repsol YPFRepsol YPF's LNG business is focused on higher margin LNG marketing and trading. Repsol YPF has committed limited capex to this business stream.

LNG business has slipped in the company's list of strategic priorities.

New leadership in Peru (led by President Humala) could impose higher taxes/adverse contractual changes on Peru LNG.

CapacityLiquefaction: 5.1 MT pa operational, no projects under developmentRe-gasification: 10 MT pa

Stream JV with Gas Nat adds to the company's capacity for contract portfolio arbitrage and optimization.

Both of the recent growth projects (Peru LNG and Canaport) are tied to very weak LNG demand in North America.

Capex needs for the various upstream developments in Repsol YPF's portfolio means that it is unlikely LNG will re-emerge as an axis of growth for this name.

Earnings - LNG represents around 15% of Repsol YPF’s 2011E earnings.

Valuation - We value Repsol YPF’s LNG business at €2.5bn. It ranks 10th in our 11 company competitor ranking.

StatoilRecent discoveries in Barents sea could likely activate Statoil's plans for expansion of its liquefaction capacity in Norway.

Statoil 's LNG assets have an Atlantic basin bias – a common weakness amongst the euro names.

Snohvit LNG has faced numerous technical issues since its commissioning which have caused undesirable, prolonged plant outages.

CapacityLiquefaction: 1.4MT pa operational, no projects under development.Re-gasification: 7.7MT pa

Statoil is responsible for marketing the Norwegian state's share of Snohvit output - adding to its LNG volume flexibility.

Statoil's gas strategy remains focused on piped gas – it therefore has a limited focus on the LNG business.

Utilization rates for the Cove Point re-gas terminal are likely to remain very low over the next few years.

Earnings - LNG represents around 2% of Statoil’s 2011E earnings.

LNG business is largely based in OECD – very low risk of contractual changesor supply disruption.

Valuation - We value Statoil’s LNG business at NOK9.6bn or just NOK3 per share. Statoil ranks 11th in our 11 company competitor ranking.

TOTALLong history in the LNG business – was involved the first liquefaction plant in the world and now has c.19MT pa liquefaction capacity

Growth pipeline is exposed to many capital intensive and technically challenging projects e.g. Yamal LNGand Shtokman LNG.

On-going political instability in Yemen is a potential threat for Yemen LNGoperations.

CapacityLiquefaction: 18.9MT pa operational, 2.7MT pa projects under development.Re-gasification: 16.8MT pa (59% leased).

Global position with strong development pipeline with potential to deliver significant growth in liquefaction capacity through to 2020.

TOTAL has a small equity stake (24%) in Ichthys but is forced to commit a high number of engineering staff to the project given the in-experience of the operator, Inpex.

TOTAL is not averse to relying on its balance sheet to gain access to resources and projects.

Earnings - LNG represents around 22% of TOTAL’s 2011E earnings.

Well regarded for its technical and project execution strength in LNG business.

Valuation - We value TOTAL’s LNG business at €18bn. TOTAL scores quitewell and ranks 5th= in our 11 company competitor ranking, alongside Woodside.


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As per Figure 2, we have scored the LNG portfolios and strategies of 11 of the 20 companies featured in this note using 11 key parameters. On this basis, Exxon Mobil and RD Shell are the outright global leaders with Chevron and BG Group not far behind.

Figure 2: Competitive ranking of top listed LNG players


3. Capacity location

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Global theme – LNG demand growth

Connectivity between the world’s regional natural gas markets continues to increase, partly as a result of more large capacity pipeline interconnectors. However, cross-border gas transmission networks face increasing political opposition given the ever greater importance of energy security and the geopolitical risks that pipeline import dependency can generate. The new ‘big gas links’ that join North America, Europe and Asia Pacific are being formed via the synchronized development of LNG re-gasification (import) terminals and liquefaction (export) facilities. These infrastructure nodes, connected by LNG transportation vessels, are fast becoming the new global gas ‘super highways’ of choice of the 21st century.

Figure 3: Location, schedule and scale (MT pa) of new liquefaction capacity


Approaching its 50th anniversary, we estimate that between 2012 and 2018 up to 287MT of liquefaction capacity may be built – this represents growth of almost 100% (given YE 2011 estimated capacity 291 MT pa) and a 7 year CAGR of 10%. Since the first liquefaction plant was commissioned in Algeria in 1964, this magnitude of growth is completely unprecedented in the history of the LNG industry (Figure 4).This period will see a number of world firsts - floating LNG (Australia), coal seam gas to LNG (Australia) and tight gas / gas shale to LNG (likely in Canada and theUSA). This mirrors the changes in the upstream industry – to non-conventional oil & gas and to the offshore (deeper waters, more complex sub-surface).

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Figure 4: Global LNG export capacity additions by year (MT)


As the physical interconnection between regions deepens, in our view, it is inevitable, that regional spot gas prices will start to converge – with the lowest (currently North America) rising and the highest (Asian LNG) falling, assuming (as we do) that North America will export increasing volumes of LNG from 2015 onwards. Presently, Henry Hub 1-month trades at just $3 per mmbtu, an oil price equivalent of less than $20 per barrel whilst LNG cargoes are being sold in Tokyo for $18 per mmbtu, an oil price equivalent of almost $110 per barrel. This extreme price difference will not survive when molecules of low cost gas from North America eventually reach Asian markets, most likely in 2015-16 and as the global market liquidity deepens (given the potential for 42% or 118 MT pa of incremental capacity 2012-16).

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Unprecedented decade long growth in LNG capacity driven by:1. Environment - society's preference for lower carbon fuels e.g. gas2. Economics - carbon costing is spreading from OECD to non-OECD3. Energy security - desire to diversify supply sources i.e. avoid pipelines4. Geopolitics - some countries will not pipe gas to their neighbours5. Gas costs - creation of new low cost supply sources e.g. CBM, gas shale6. Nuclear risks - heightened popular opposition post-Fukushima

------> 7 year 2012-18 +287 MT pa could require $1 trillion investment

Regional price dispersion will tighten

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LNG market

Regional gas markets

We must first put the global LNG market in to clear context – identifying its size and relative importance in today’s global gas industry. Figure x shows the sizes of the regional gas markets in 2010 and, within each region, the percentage of consumption that was satisfied by LNG. Given a lack of inter-connecting pipelines, the world is essentially split in to three gas markets – North America, Europe and Asia Pacific. North America (98%) and Europe (92%) rely primarily on regional gas production / piped gas. The more fragmented economies of Asia Pacific are much more dependent (31%) on LNG for their gas.

In 2010, the world consumed 307 bcfpd of natural gas with a CAGR of 2.8% 2000-10. Of this figure, LNG consumption was approximately 29 bcfpd which was a 9% global market share; 91% of global gas is therefore either piped (21%) or consumed within the country of its production (70%). As per the insert chart in Figure 5, LNG’sglobal gas market share has actually been relatively slow to rise – it was 6% in 2000. Behind this average of 9% in 2010, the regional penetration of LNG is clearly very different – just 2% of North America versus 31% of Asia Pacific which, alongside the Middle East, has experienced the highest rate of gas demand growth 2000-10 of 7%.

Figure 5: Global gas consumption 2010 - regional splits and LNG dependency

Source: J.P. Morgan., BP Statistical Review of World Energy 2011

82 bcfpd27% of world

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LNG demand profile

As per Figure 6, global LNG consumption has grown at a compound rate of 8% 2001-10 which is over 3x the rate of global gas consumption growth. Of note, even when global economic growth collapsed in 2008, global LNG consumption was flat, highlighting the comparatively resilient nature of LNG demand. We expect global LNG growth to have averaged approximately 15% in 2011, driven by acceleratingJapanese consumption post-Fukushima and continued growth in Chinese LNG imports.

Figure 6: Global LNG consumption - MT pa

Source: BP 2011 Statistical Review of World Energy, J.P. Morgan.

Figure 7: Global LNG consumption - by region & country

Source: BP 2011 Statistical Review of World Energy, J.P. Morgan.

As per Figure 8, in 2010 Japanese consumption of LNG represented 31% of total global consumption. As a reminder of the concentration of LNG demand, the ten largest consumers of LNG represented 87% of global demand in 2010. We note that China was the seventh largest consumer of LNG, just eclipsing US demand in 2010.

Figure 8: Global LNG consumption by country - 2010 (MT)


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China’s increasing integration to global energy markets will continue to impact regional and global supply-demand dynamics. We note that China is actually already the fourth largest consumer of gas in the world (Figure 9). The Chinese government now regards gas as cornerstone of its primary energy mix over the next decade given its availability (both domestically and via piped and LNG imports) and clean burning qualities when compared to coal. Presently, China imports approximately 15% of its gas requirement (2010 total gas consumption c.109 bcm). We believe that Chinese gas consumption is supply-constrained due to a lack of import infrastructure, either major import pipelines or re-gasification terminal capacity.

Figure 9: World's 10 largest gas consumers (2010 - bcm pa)

Source: BP 2011 Statistical Review of World Energy

Based on 2010 primary energy consumption, if the penetration of gas in China’s primary energy diet increases by just 1% (from 4% to 5%), it will require an extra 27 bcm pa which is equivalent to 20 MT pa of LNG (Figure 10). On the same basis, if gas penetration of the primary energy diet of Brazil, India, South Korea and Japan rises by 1% in aggregate, that is equivalent to just 13 MT pa of LNG. So, China's appetite for gas, and more importantly imported LNG, is a key variable in the global LNG market. We believe that China will continue to nurture multi-lateral energy relationships rather than develop a dependency on any particular source country.

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Figure 10: Global energy markets - gas penetration & rate of growth of gas demand (blob sizes correspond to size of country’s primary energy)


LNG demand growth drivers

Our database on global LNG export projects enables us to present a 55+ year overview of LNG plant construction. As per Figure 4, the world’s first large scale liquefaction plant was commissioned in 1964 in Algeria. Global additions were infrequent and small until 1978-79, 1989 and 1999. There was then a nine year period (2002-10) of sustained capacity growth.

Looking ahead, we forecast a decade of uninterrupted annual capacity growth. The pace and uninterrupted intensity of capacity growth is completely unprecedented in the 50 year history of the global LNG industry. We cite several key demand-related factors that underpin this capacity growth outlook. It is very important to note that LNG export capacity is not built on the basis of speculative demand. High capital intensity necessitates that capacity is built with water-tight off-take agreements that typically run for 20 or more years. So capacity is therefore locked up before it is built. This is in stark contrast to capacity additions in oil and refining where output is more typically sold in to a global spot market which thus risks free-flowing (un-contracted) product-on-product competition

Environmental issues shaping regulatory & policy change

Society is fast becoming more conscious of its environmental footprint and isaccepting fuller responsibility for its consequences e.g. undesirable climate change and attendant human health issues. This is spurring the substitution of higher carbon

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fuels, e.g. coal by lower carbon fuels such as natural gas. This trend is spreading from G20 countries to developing economies where CO2 emissions are escalating with industrialization. Table x shows the absolute and relative CO2 intensity of energy derived from oil, coal (carbon) and gas (LNG). LNG’s CO2 footprint is 45% lower than coal's.

Table 3: The comparative emissions footprint of oil, coal and LNG

Oil Coal LNGCarbon produced to generate 1 GJ energy (T) 0.0187 0.0247 0.0135Molecular weight of Carbon Dioxide 44Atomic weight of Carbon 12CO2 produced to generate 1 GJ energy (T) 0.0686 0.0906 0.0495Ratio if coal = 100 76 100 55


As per Figure 11, in 2007 (the last available accurate data for all countries featured) PR China’s CO2 emissions (6.7 billion tons) over took the emissions from the USA, although the latter still bears the highest per capita emission rate (19.3 tons per person in that year). China’s per capita emission rate was roughly half that of Japan in 2007, but four times that of India. Between 1997 and 2007, the aggregate CO2

emissions of the world’s top ten emitting countries increased 26%, a CAGR of 2.4% - a clear reminder that global economic (GDP) growth drives emissions. The two key action points from the recent Durban UN Climate Change Conference were to continue the Kyoto Protocol and to negotiate (the Durban Platform) a comprehensive climate change agreement that will be legally binding. This continues to support investment in the low-carbon economy.

Figure 11: Carbon dioxide emissions (billion MT)

Source: World Resources Institute

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The environmental threat from CO2 emissions continues to bias government policy towards natural gas substitution.

1. US power and vehicles - A current example of regulation that is set to bolster demand for gas is the Cross State Air Pollution Rule (CSAPR), issued by the US Environmental Protection Agency (EPA). The CSAPR is forcing US utilities to convert from coal-fired power generation to gas-fired. Staying in the US, we also note the revival earlier in 2011 of the New Alternative Transportation to Give Americans Solutions Act (NAT GAS Act). This Act would provide federal incentives for the use of natural gas as a vehicle fuel, the purchase of natural gas fueled vehicles and the installation of natural gas vehicle refueling infrastructure. Presently, the US public can only buy one car powered by natural gas - the Honda Civic Natural Gas.

2. Marine fuel –The UN-backed global shipping regulator, the International Maritime Organization (IMO), is pushing for LNG to replace marine fuel oil. The 1% sulfur content limit in the North Sea, Baltic Sea and the English Channel will be cut to 0.1% from January 2015. The cost of low-sulfur bunker oil is now on a par with LNG. A total retrofit of a vessel to LNG propulsion is estimated to cost around €15m. In certain countries e.g. Norway, the conversion enables the vessel owner to qualify for lower NOX emission taxes. The combustion of LNG leads to lower carbon emissions and virtually no SO or particle emissions.

Substitution of coal by gas in the electricity sector

We share a fairly common view – gas will continue to substitute for coal as more governments impose policies that place a direct cost on carbon emissions (via taxes, caps and subsidies for alternatives). When used for electricity, gas emits up to 45% less CO2 than coal. In its recent review (The Outlook for Energy – A view to 2040),Exxon Mobil forecast that global electricity demand would be 80% higher in 2040 versus 2010. It expects the share of electricity generation from natural gas to rise from 20% to 30%. So, in effect, demand for gas for electricity generation is expected to rise by 170%. Exxon Mobil expects overall demand for natural gas to rise by more than 60% through to 2040 – this is the highest rate of growth for any major energy source. In the absence of game-changing new technology, we suspect that the much higher cost of renewable alternatives (Figure 13) will keep these at the fringes of the global energy diet. Indeed, Exxon Mobil estimates that wind, solar and bio-fuels will represent just 4% of the world energy in 2040 (Figure 12).

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Figure 12: Global primary energy mix outlook

Source: Exxon Mobil (The Outlook for Energy – A view to 2040)

Figure 13: Average cost of US electricity in 2030 (2011 cents)

Source: Exxon Mobil (The Outlook for Energy – A view to 2040)

Of course, the switch from coal to gas is not only driven by the cost of carbon. Gas-fired stations may be permitted and built in less than 2 years versus 4-5 years for a coal-fired plant. Gas-fired power generation is also 50% more energy efficient than its coal equivalent. A new turbine powered by coal is 40% efficient – so for every 100 units of primary energy that go in to the plant, only 40 units are converted in to usable electricity. Gas-fired turbines have a 60% efficiency rate. Finally, given a far smaller emissions footprint, gas-fired plants may also be located closer to demand centers. This reduces transmission line losses which may average 10% in OECD and as much as 15% in non-OECD.

Energy security

For most governments of countries that carry energy deficits (i.e. must import energy in the form of oil, gas, coal etc), maximizing the security of supply at a reasonable price is more important than trying to minimize prices at the expense of increased supply risk. The nightmare of every government (and indeed the event that can trigger social unrest and changes to government) is when a country's energy supply systems fail and, quite literally 'the lights go out.' Following the Libyan oil & gas supply outages in 2011 and the Fukushima gas demand shock, we sense that governments want to develop more redundancy and flexibility in to their energy infrastructure systems. This is manifesting in an unprecedented pace of construction of new LNG re-gasification (import) terminals with their attendant choice of suppliers. Planning permission processes are also being accelerated e.g. in Italy, given the local employment benefits of these infrastructure projects. We believe that burgeoning population growth (7 billion now, to reach 9 billion by 2050 according to the UN), the accelerated growth in a global Middle Class and the shifting identity of the world’s energy creditors / debtors render energy security as one of the key and enduring investment themes of the 21st Century. Furthermore, we believe that LNG will play a key role in the global energy equation.

Geopolitics

It is clear to us that governments do not want to build a greater dependency on pipedgas imports, especially when the source supplier(s) has proven itself unreliable. At the opening ceremony for the Nord Stream pipeline (8 November 2011), Europe’s Energy Commissioner (Gunther Oettinger) referred to Europe’s diversification strategy and its efforts to secure natural gas supplies from countries other than

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Russia. The 1,224 km Nord Stream gas pipeline from Russia to Germany is a dual pipeline project capable of supplying 27 bcm of natural gas but this could increase to 55 bcm in September 2012 when the second line becomes operational. We also note that in 2008, the US government (via the US Trade and Development Agency) funded an $826,000 study in to a possible LNG import terminal in Lithuania; the USTDA funded a similar study in to a Romanian LNG terminal. Our view is that inso doing, the US is seeking to limit Russia's ability to use piped gas supplies as a source of geopolitical leverage and influence. The growth in US gas shale production has displaced the need for US LNG imports which has, in turn, provided other LNG buyers with greater choice. Indirectly, this has rendered it more difficult for countries such as Iran and Venezuela to promote their first green field LNG export projects, thus constraining their ability to use energy supplies as a geopolitical tool of influence.

Nuclear substitution by gas

The Fukushima disaster (11 March 2011) led to a total of 14 nuclear reactors in Japan (6) and Germany (8) being closed. Following this and due to safety inspections, only 11 of Japan’s 54 nuclear reactors are currently operating (20% of 49.9 GW installed capacity). The Japanese government has recently published a report indicating that it will take 30 years or more to decommission the Fukushima Daiichi plant. In July, the Japanese government announced that all nuclear reactors will be required to submit to a “stress test” leading to further delays before reactors are allowed to reopen (reactors are typically shutdown for routine maintenance every 13 months). In addition, Fukushima triggered a review many countries which has already led some to initiate a phased withdrawal from nuclear.

1. Specifically, Germany and Switzerland decided to phase out nuclear power generation. Germany decided to close the country’s 17 nuclear power stations by 2022 rather than 2036. Mexico has put all new nuclear plant projects on hold and Thailand has cancelled its nuclear development program altogether. In its place, the Electricity Generating Authority of Thailand (EGAT) is planning to build a series of combined-cycle gas-fired power plants. The country’s 2010 power development plan was to build 2-5 1 GW nuclear stations with the first two operational by 2020.

2. Taiwan, which generates 19% of its electricity from nuclear, has also decided not to extend the 40-year life-spans of its three existing plants. The 1,272 MW Jingshan facility is due for closure 2018-19; the 1,970 MW Guosheng plant by 2021-23 and the 1,903 MW Maanshan facility in 2024-25. A fourth facility will, however, be commissioned in 2016 (2,700 MW Lungmen). As a direct result, Taiwan’s Bureau of Energy estimates that the country’s LNG import needs could rise from 12 to 20 MT pa, which will require the construction of a third re-gasification terminal.

3. In the US, the Nuclear Regulatory Commission (NRC) is also imposing additional regulations over the next five years - this has already led to a longer than normal spring maintenance season in 2011.

4. In France, elections are now only four months away. The opposition Socialists may well push nuclear as a campaigning issue. Their position - scaling back the country’s nuclear portfolio to around 50 percent by 2025 - differs markedly from President Sarkozy, who supports an unabated nuclear program. The outcome could have major implications for the future of nuclear power in Europe as a whole.

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However, we note that PR China continues with its program to build twenty-seven new reactors. Brazil’s Electronuclear (owned by Electrobras) nascent nuclear program, driven to diversify the country’s fuel mix, also has tentative plans to add eight reactors to its base of two. So, it is fair to say that the growth in nuclear power capacity has not cancelled outright.

Figure 14: Nuclear power – global consumption growth - 'three strikes and you are out'

Source: J.P. Morgan, BP 2011 Statistical Review of World Energy.

Fukushima was the world's third, very high profile nuclear incident. As per Figure 14, global growth in nuclear energy consumption peaked in 1985. Since the Chernobyl accident, nuclear energy consumption has been on a clear downward pathway. Although Chernobyl did not deter the USA, Canada, Japan, France and the UK from nuclear power, some countries did respond to popular concerns e.g. Austria, Australia, Denmark, Italy, New Zealand, Norway and Sweden. We feel that Fukushima will accelerate the switch away from nuclear.

The energy market after-shocks of Fukushima have reduced demand for Uranium – this has had a dramatic impact on the price of Uranium. The price of Uranium has fallen from $70 per pound to just over $50/pound (Figure 15). The share price of Cameco Corp, one of the world’s largest producers of Uranium has also more than halved (Figure 16).

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(TW

h)

Middle East S. & Cent. America Africa Asia Pacific North America Europe & Eurasia Aggregate growth/(decline)

Chernobyl26 Apr 1986

Three Mile Island28 Mar 1979

Fukushima11 Mar 2011

26



Figure 15: Uranium price - $ per pound


Figure 16: Cameco share price (C$)


40

45

50

55

60

65

70

2010 2011

15

20

25

30

35

40

45

2010 2011

27



North American LNG export potential

North America LNG exports – nothing new

The United States has exported LNG from Kenai, Alaska, to Japan for 42 years, since 1969. The exports, which have averaged 1.1 MT pa (0.1 to 0.2 bcfpd) in recent years, appeared that they would stop in 2011 because the plant was no longer commercially competitive. Indeed, the plant was put in ‘preservation mode’ in November. However, the operator ConocoPhillips recently reversed its decision to mothball the plant after signing new supply contracts with producers from Alaska’s Cook Inlet Basin, and it plans to resume exports of around 1.9 MT pa in mid-2012. Apart from the existing Kenai terminal, it looks like North America (including the USA and Canada) is on the verge of exporting LNG from other plants, and in more substantial quantities, within the next five years.

In North America, most of the announced liquefaction projects are facilities on the same site as existing or planned re-gasification terminals. Operators conceived of or constructed the re-gasification terminals at a time when it seemed that the USA would need increasing LNG imports. However, the shale gas revolution literally changed the gas market “overnight.” Bucking an earlier trend of annual natural gas production declines, US natural gas production grew from 49.5 bcfpd in 2005 to 59.1 bcfpd in 2010, and LNG imports decreased from 1.7 bcfpd to 1.2 bcfpd over the same period.

Proposed export facilities in Canada and US

In western Canada, a site previously planned for an LNG re-gasification terminallikely will be the site of the country’s first LNG liquefaction plant. The Kitimat facility, owned by Apache (40%), EOG (30%) and EnCana (30%), could begin operations as early as 2015 with Asia-Pacific as the target market. The owners expect completion of the FEED in early 2012 and an FID sometime in 2012. Planned capacity for Phase 1 is 5 MT pa (or close to 700 mmcfpd). Korea Gas Corp and Gas Natural SDG SA (Spain) have signed 20-year preliminary agreements to buy 40% and 30% of the exports, respectively.

This plant offers a relatively short route to Asia (estimated 11 shipping days). Another benefit of this plant versus some other plants around the world is the connection to the North America natural gas grid. Whereas many stranded gas projects include an individual field or collection of discoveries, the owners of Kitimat are sizeable companies that have significant tested and producing natural gas resources in western Canada (primarily Horn River Basin shale) and massive additional back-up gas supplies throughout North America. Thus, there may be greater reliability and sustainability of supply with this project compared to others. Among other possible projects in western Canada, this project appears to have a first-mover advantage.

As for the US, Sabine Pass (Cameron Parish, Louisiana) has made progress towards potentially exporting LNG. The four trains at Sabine would export 4.5 MT pa each for a total of 18 MT pa. The Department of Energy (DOE) has approved 16 MT pa of exports from Sabine Pass. Cheniere Energy has signed three long-term Sale and Purchase Agreements (SPAs) with BG Group, Gas Natural Fenosa (Spain, Latin America), and GAIL (India). Each contract is for 3.5 MT pa (or around 500 mmcfpd).

Joseph Allman, CFA

(1-212) 622-4864

[email protected]

US has exported LNG from Alaska since 1969

Gas shale has transformed the potential for LNG exports

Kitimat LNG is advantaged by location on west coast

Sabine Pass is shaping up nicely

28



Table 4: Sabine Pass LNG contracts

Source: Company website

Sabine Pass still requires FERC approval for its operation and construction, which Cheniere hopes to start in early 2012. The three SPAs are contingent upon, among other things, regulatory approval, Cheniere receiving financing, and the project’s FID. If Cheniere is unable to satisfy these contingencies by the end of 2012 (BGGroup, Gas Natural Fenosa) or mid-2013 (GAIL), either party could terminate the contracts. The $3.9bn, first two-train contract with the EPC contractor, Bechtel, also requires that Cheniere secure financing by March 31, 2012. Cheniere has significant debt obligations, so financing appears to be a real risk to the success of the Sabine Pass project.

We are not aware of any contracts with customers to send their gas to Sabine Pass for export. If, for some reason, upstream suppliers are not comfortable with Cheniere’s credit or with signing long-term contracts for gas sales at 115% of Henry Hub, it could cause LNG exports to be lower than the planned liquefaction capacity. If gas producers can receive a premium to Henry Hub for an extended time, as long as they are comfortable with the size of their resources, they likely will take it. Thus, it probably is just a matter of time before we hear about supply agreements into Sabine Pass. However, given the depth and liquidity of the US gas market, the Sabine Pass liquefaction terminal may be unique if it does not require explicit resource dedication / reserve certification.

Cheniere also announced that it plans to build a liquefaction plant on another site that it previously had planned for a re-gasification terminal. The Corpus Christi (TX) site could add an addition 13.5 MT pa of liquefaction capacity, with the Eagle Ford Shale as the primary source of the natural gas. We assume that, if this plant ever begins operations, it would not begin exporting LNG until the latter part of this decade at the earliest.

Other plants are seeking approval for LNG exports, but those plants are at earlier stages than Sabine Pass. In Table 5 we show those plants and the ones mentioned previously.

Company Train Volumes Period Planned Fixed Sales Charge % of Henry Hub (NYMEX)

(Mtpa) Start Up (per MMBtu)

BG 1 3.5 20 years 2015 $2.25 115%

10 year extension option

Gas Natural Fenosa 2 3.5 20 years 2016 $2.49 115%


GAIL 4 3.5 20 years 2017 $3.00 115%


Wait to see who will supply Sabine Pass

Other plants are at earlier stages

29



Table 5: Proposed LNG export plants in North America

Source: FERC, Company websites

Key review underway

The DOE recently indicated that it would not issue any additional unrestricted export licenses before it completes a review of the impact of liquefaction projects on US markets. The review includes two studies that are in progress with expected completion in 1Q 2012. The main concern driving these studies appears to be the potential increase in domestic natural gas prices due to LNG exports, as LNG exporters can tap importing markets which typically pay a much higher gas price compared to the US. The first study is an analysis by the EIA on the effect of LNG exports on domestic natural gas prices. The second study by an external agency will evaluate the impact of LNG exports on the overall economy.

Currently, most of the plants that we mentioned above have a license to export to countries that have a free trade agreement (FTA) with the US. However, this license is of limited practical use as the current FTA list includes only 15 countries and none is a major LNG importer. Of the planned US projects, only Sabine Pass has secured an unrestricted export license. Comments from a DOE official indicate the department’s desire to honor the sanctity of the Sabine Pass contract. However, the law appears to allow the DOE to change any contract if, for example, it deems the arrangement a threat to energy security or if it finds a higher-priority use for the natural gas.

Proposed Terminal Export capacity Export license status1 Developer Expected Start-up(Mtpa)

U.S

Sabine Pass, Louisiana 18.0 Secured unrestricted DOE, awaiting FERC Cheniere Energy 2015

Freeport, Texas 13.5 Secured DOE (FTA2 only), awaiting FERC Conoco & multiple partners NA

Lake Charles, Louisiana 15.0 Secured DOE (FTA2 only) Southern Union & BG NA

Cove Point, Maryland 7.5 Secured DOE (FTA2 only) Dominion NA

Coos Bay, Oregon 9.0 Secured DOE (FTA2 only) Fort Chicago & Energy Projects Development NA

Corpus Christi, Texas 13.5 Pre-filing stage Cheniere Energy NA

Cameron, Louisiana 12.7 Filed with DOE (FTA2 only) Sempra Energy NA

Canada

Kitimat, Br. Columbia (BC) 5.2 Secured NEB Apache, EOG, Encana 2015Douglas Island, BC 1.9 Filed with NEB BC LNG Export Cooperative NAPrince Rupert Islands, BC 7.5 NA Shell NA

Notes: 1. Securing a DOE permit is the first step, next step is securing FERC approval for building infrastructure (in the U.S). 2. Countries with a Free Trade Agreement with the U.S are not significant importers and therefore an Unrestricted DOE license is important.

Outcome of DOE review, expected Q1 2012, is key

30



LNG pricing – the Henry Hub threat

LNG Pricing Phase Shift Ahead?

Global shale gas revolution challenges the oil-linked price mechanism for LNG

In 2011, the United States and Canada each granted permits for the commercial export of LNG—the first of their kind in North America. The granting of these licenses, plus several more permit applications in queue, gives renewed urgency to the longstanding questions of:

how long can the cumbersome Asian oil-linked pricing formulas endure?

what will replace them if pricing formulae change?

These are critical risks for the gas industry, as well as for fuel makers in the petroleum, coal, and alternative energy sectors. Asia buys over 60% of global LNG and almost every proposed project targets these high value oil linked markets.

The potential rewards for success (and costs for failure) are enormous: the shale gas boom has opened a greater than $10 per mmbtu gap between 5-year forward Henry Hub prices and the price implied by recently agreed oil-linked LNG price formulas. The recent approval of an export license for Cheniere’s Sabine Pass terminal in Louisiana (with whom JP Morgan has a commercial arrangement), followed closely by three major supply purchasing agreements, including a large Asian buyer, has only underscored the latent appetite for this cheap resource.

The prospect of a major new low-cost LNG supplier entering the market has emboldened some buyers and is worrying to potential suppliers at the high end of the cost curve—notably some of the Australian green field and expansion projects. On top of all of this, unseasonably warm winter in North America has significantly cut into US gas heating demand, forcing spot NYM natural gas below $3.00 per mmbtu (less than $20 per boe) to price levels that cannot be ignored by consumers paying the equivalent of $100, or more, per boe.

Figure 17: Henry Hub Forward Price versus Asian LNG Price Implied by Crude Forward Curve


2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

18.0

Feb-12 Dec-12 Oct-13 Aug-14 Jun-15 Apr-16

$/MMBtu

Asian LNG Price

US Natural Gas Futures

Global Commodities Research

Colin Fenton

(1-212) 834-5648

[email protected]

Jeff Brown

(65) 6882 2215

[email protected]

Any changes to Asian pricing

are crucial

Massive regional price spread

sends a signal to Asian buyers

mailto:[email protected];

31



Spot LNG is already closely linked to international gas prices

Asian LNG is already linked to international gas markets in the spot market. Because Asia is typically short LNG, Atlantic Basin spot cargoes bound for Asia generally trade at the highest Atlantic Basin alternative (generally either the UK National Balancing Point, NBP, or a continental price) plus transport cost. If, as seen recently, the tanker market is very tight or Asia pulls all the available cargoes, Asian spot LNG prices can rise to oil prices on a heating equivalent basis. Because gas tends to be more efficient than oil in power generation, LNG prices can spike above oil prices, but these are typically short-lived. When LNG is tight, oil can be pulled into heating and power, displacing gas and effectively placing a ceiling on LNG prices. Going forward, a key challenge will be trying to anticipate what portion of the LNG trade migrates from long-term contracts to short-term contracts and opportunistic cash market transactions. For reference, DOE data show that upwards of 94% of Canadian gas pipeline flow into the US is in the “spot market”, or scheduled to be delivered within 12 months.

As discussed elsewhere in this collaborative study, the trend toward greater international trade volumes in LNG, directed toward Asia, will likely prove durable, though we also believe the US and Canada may find themselves competing with other new suppliers far sooner than they might expect. Spot LNG will likely act to equalize gas prices across regions, just as movements in crude oil keep price spreads relatively narrow. Spot LNG trade already has an impact on liquid markets, like the UK, which have a well developed infrastructure for receiving LNG imports. Spot volumes are pushed to or pulled from the UK depending on NBP pricing relative to competing markets. But spot LNG trade accounts for only a small percentage of total global LNG trade (i.e., including contracts), and total global international trade in LNG supplies only about 10% of global gas consumption. So there are limits today on the extent to which spot LNG can balance global gas markets, particularly during seasonal spikes, which explains how the wide spreads between Henry Hub and Asian oil-linked LNG have been able to persist to date. Also, on a heating equivalent basis LNG is well over three times as expensive as oil to transport, and the LNG tanker market is relatively small and often tied to long-term contracts.

Figure 18: Asian LNG spot price versus Henry Hub, NBP, and oil price equivalent


0.0

5.0

10.0

15.0

20.0

25.0

30.0

2001 2003 2005 2007 2009 2011

$/MMBtu Representative Asian LNG Price

US Natural Gas (HH)

UK NBP

Crude Oil Equivalent

Regional prices are already linked

Spot LNG is the liquidity skin that may reduce price dispersion

32



Long-term contracts are still oil linked but pricing formulas vary widely with cost trends

Asian long-term LNG contracts for deliveries over periods of up to 25 years, but typically for 15-to-20 years have historically been linked to crude oil prices. Generally, the pricing formula has a small fixed component plus a coefficient multiplied by crude price (by convention, usually the Japanese Customs Cleared Crude (JCC) price even for non-Japanese Asian buyers).

Heretofore, the major structural shifts in the LNG market—and associated impacts on domestic gas markets—have been transmitted through changes to long-term contract pricing and terms. As buyers’/sellers’ market expectations evolve, long-term contract terms typically change quickly, as witnessed several times over the past decade. Because long-term contracts underpin the viability and thus approval (or scuttling) of new gas projects and encourage buyers to build out receiving infrastructure and downstream industry—all of which require a 3-to-5 year lead—even small changes to market expectations can have a major impact on capex planning and thus future LNG business growth.

Figure 19: Basic LNG pricing formulaPLNG = A x PCrude Oil + Bwhere:PLNG is the price of LNG in US$/MMBtuA is the “slope” indicating the crude linkage. Before 2003 the slope was typically .1485PCrude Oil is the price of Japan Customs Cleared (JCC) crude oil in US$/barrelB is the “constant” which was often representative of transport cost, typically about US$0.60-0.90*Note that there are numerous variations on the basic formula, such as “S-curves," floors/ceilings, etc., but they are generally thought to follow the construct outlined above.


Prior to 2003, when Japanese and Korean buyers dominated the global LNG market, LNG was typically priced at about 85% of the benchmark international oil price. There were some variations, such as the introduction of “S-curves” that softened the oil linkage at high and low oil prices, but pricing terms were similar across contracts. Over the past decade, as competition among buyers and sellers has intensified and their relative negotiating power has ebbed and flowed, wider ranges in agreed-upon coefficients and other variations in pricing formulas have emerged.

Most interestingly, although the contracts remain oil linked, the agreed pricing terms are generally set in the market by the full development costs of the marginal seller. This spot in the market has long been held by Australia, because: (1) it is a relatively high-cost construction venue, and (2) it has had numerous projects at various stages of development by international oil companies for decades.

The long-standing 85% oil price linkage norm changed around 2002-to-2003 when projects in Trinidad demonstrated that LNG construction costs could be pushed to very low levels (about $200 per T) and major new projects in Qatar, Indonesia and Australia decided to look past slower-growing established markets in Japan and Korea and altered their pricing strategies to push into China and India, where they believed they had to compete with coal use. Oil linkages quickly dropped to about 30%, and some price ceilings fixed below $4 per mmbtu for 20-year contracts. The contracts prices were centered at around $22-to-$25/bbl crude. This price range may seem incredible today, but because the full development and delivery cost for Australian LNG projects was less than $3 per mmbtu at the time, the market was offered down to these levels through a tender process initiated by a major Chinese buyer. The example is a terrific illustration of the strategic position conferred by a prudent and forward-looking consumer hedging strategy.

Historic pricing convention links LNG price to oil price

Australian LNG projects have long set marginal cost

EPC cost nadir and new target markets shifted pricing models

33



The LNG market subsequently shifted again when oil prices began to ratchet upwards starting in late 2003, as China’s inexorable energy appetite became apparent. The combination of demand pull and several unplanned outages (Hurricanes Katrina, Rita) eventually lifted US Henry Hub gas prices to a cyclical high above $15 per mmbtu and NBP prices briefly above the equivalent of $22 per mmbtu. In response to these prices, dozens of LNG receiving terminals were planned on both coasts in the US, Canada, and Mexico. Many market observers, including the US Energy Information Administration, projected that the US would quickly become one of the world’s largest LNG importers and eventually pass Japan to become the largest importer. Asian buyers were understandably concerned that North America would pull away Asian LNG and there was talk of LNG sellers possibly demanding Henry Hub based pricing from Asian buyers (demonstrating just how quickly the LNG market can change with shifts to large domestic gas markets, in this case the US). Meanwhile construction costs rose quickly as both upstream and downstream service providers were stretched. Over the 2005-2006 interval, linkage ratios with oil began to move higher even as oil prices rose, with new contracts surpassing the 50% threshold against higher mid-points for oil prices.

In 2008, Chinese state oil companies moved aggressively to sign new LNG long term contracts just as an unprecedented wall of new Qatari supply was poised to surge into the market. Critically, Qatar was the only major incremental source of supply, and it held the line on pricing. Originally, much of the Qatari LNG was targeted at the Atlantic Basin, but by 2008 the rapid growth of shale gas in the US had altered market dynamics and Asia was a much tighter market, willing to pay high prices to fuel its strong growth. The Qatari LNG projects demanded, and signed, several contracts with roughly a 100% crude oil linkage. The LNG market was so tight and nervous about the prospects of China taking in all of the available LNG that long-term contract prices were bid up to oil parity.

Since the Great Recession crude linkages have fallen back as numerous Australian LNG projects have raced to secure buyers and get to Final Investment Decision (FID). The Tohoku earthquake slowed the pullback from a tight crude linkage on the prospects for much higher Japanese LNG demand, but recently some long-term contracts are said to have a 80% crude linkage. Analysts and investors, in our view, have rightly questioned whether adequate returns in Australian LNG projects can be achieved at this level, introducing a new threat in the value proposition.

Will new supplies undercut pricing and threaten Australian LNG?

Australian LNG projects are clearly at the high end of the cost curve and may be thought of as “marginal” supply. So long as the perceived long-term demand for LNG exceeds the perceived long-term supply at an 80% crude oil linkage, currently planned but un-contracted Australian LNG still stands a high probability of eventually finding buyers and moving ahead. But if substantial volumes of lower cost LNG begin to push into Asia, the Australian projects at the high end of the cost curve are especially vulnerable.

In this context, it is important to remember that several proposed US LNG export projects have a unique cost advantage, in that they have already built out berthingand storage facilities in anticipation of LNG imports which never materialized. The United Sates has some 13.35 MT pa of LNG import capacity but only imported 9.2

History shows that pricing

models can change quite quickly

Qatari pricing discipline remains

key

Recently oil price discounts of

15%+ have been taken

US exports have a large, in-built cost advantage

34



MT pa of LNG in 2010. Currently, there are four proposed projects for 6.6 bcfpd paof liquefaction, one of which has already received required approvals and has signed gas sales agreements. Of course, these facilities require some modifications and gas liquefaction must be added, but reportedly these costs amount to some US$500-800 per T versus over US$3,000 per T in Australia. This wide cost differential easily overcomes the higher cost of shipping LNG from the USGC to Asia.

It must also be noted that Qatar, the world’s largest LNG producer, poses a potential threat in that it sends over 30 MT pa of LNG into the Atlantic Basin which could be redirected into high priced sales in Asia. In the past, Qatar has chosen to push for high price coefficients and keeping the Asian market “tight”. Qatar now appears to be relaxing its pricing terms in acknowledgement of the new, if still evolving, realities.

Overall, it appears that a hard push by North American projects, several of which involve Asian buyers, has already altered industry’s long-term views on the availability of supply. This has, in turn, spurred Australian sellers to offer somewhat better terms to secure supply agreements before this threat escalates further.

Clearly, the rise of alternative LNG suppliers is a significant challenge for Australian LNG operators, particularly as their costs continue to escalate. But it must be clarified that if some, or even all of the Australian projects, were to be displaced it would not necessarily mean that LNG prices would decline sharply because the next marginal seller is also high cost. For example, the full cost of LNG from Western Canada to Asia is very similar to Australia. Grassroots USGC projects are similarly high cost if transport costs are included.

The simple fact is LNG itself is expensive and at the high end of the natural gas cost curve. As such the biggest threat to all LNG projects, one which can dramatically alter the long-term LNG price outlook, is a sudden shift in the domestic gas supply outlook among major buyers. Based on the experience with US shale gas, the most obvious candidate to radically alter long-term supply expectations would be an acceleration of shale gas development in China and other major buyers. There is no question that China has substantial shale resources. In fact, the US Energy Information Agency estimates China has the largest shale reserves in the world, at 36.1 trillion cubic meters (tcm) of technically-recoverable reserves, or about 50% more than the US. Chinese industry pegs its shale gas reserves somewhat lower (26 tcm), but this figure is still larger than the US resource.

The challenge for China is that while the US is generally developing shallow, broad marine basins, China has a mix of different structures, spread over a range of smaller basins, which are often deeper, presenting unique challenges and potentially higher cost. Because of below and above ground challenges, in the early stages costs are likely to exceed the US, although these can fall rapidly as infrastructure expands. China’s ability to follow in the footsteps of US developments and technology is a major advantage in quickly closing the cost gap.

Doubts about China’s ability to get large-scale projects done quickly have repeatedly been proven wrong: overseas upstream acquisitions, LNG re-gasification/importterminals, and domestic pipeline expansions all lagged before China surprised observers with swift shifts in priorities and quickly ramped up development in these areas. Numerous drivers contributed to the changes, but three keys were: (1) a strong political push; (2) competition among the state majors; and (3) early foreign involvement.

US threat has pushed sellers to

accept lower contract pricing

All eyes on China gas shale….

China gas shale faces many challenges….

…but China’s ability to execute large projects is not in doubt

35



Developments over the past few months further show political support aligning for shale gas. In August, the head of the National Energy Administration said China’s powerful State Council was urging faster shale development. At a recent Shale Conference in Shanghai, a government official tasked with designing new plans for shale gas development said that China hopes to produce 60 to 80 billion cubic meters (bcm) per annum by 2020, following on an estimated 6 bcm by 2015. These are aggressive targets, given that they exceed announced company plans, but the official also discussed new subsidies for shale gas, wider participation by domestic and foreign companies and strong pressure on companies that win future tenders to aggressively explore and develop new plays.

The key area to watch is Sichuan, where China’s first horizontal shale gas well was completed. The region has among the most promising reserves, and perhaps more importantly, ample water which is necessary for fracking. The other major promising region, the Tarim Basin, is arid so water access presents challenges. Sichuan is also a major conventional gas-producing region, so necessary infrastructure is already in place. Early development efforts of the state majors and foreign companies are focused on the region, with Petrochina saying that 1 bcm of its targeted 1.5 bcm of shale gas output in 2015 will come from the region. Among the main challenges we see for Sichuan is the structural complexity, which we understand has presented some difficulties in the early stages of development.

Conclusion - prospects for gas-based pricing for Asian LNG

Given the rapid growth and increasing liquidity of the global LNG market, as well as the coming amplification of the shale gas phenomenon to global proportions, we think it is likely that gas-linked pricing will take-off in Asia. The market already sees several Asia spot LNG price quotes, including a Japan, Korea, Taiwan price marker from pricing agency Platts. Singapore aspires to become a regional LNG trading hub with the opening of a re-gasification terminal in 2013, which is also already slated for expansion. Singapore is already the regional pricing hub for oil products, so adding LNG to the fold makes sense, though Shanghai is also a major regional contender.

Historically, Asian utilities were reluctant to link LNG prices to Henry Hub in the US or the UK National Balancing Point due to basis risk. Oil price linkages were more familiar and easier to explain to utility customers, particularly in Japan where oil still plays a substantial role in power generation during periods of peak demand. With that said, Asian utilities do eye each other closely. If one utility jumps to a new pricing system others are likely to try it, lest their competitive position becomes eroded. The state utilities also need to demonstrate that they are securing the best deals available in the market. We have seen several examples of this “follow the leader” behavior, including the widespread adoption of “S-curves”, as described above.

In late 2010, the consensus among North American gas producers predicted that spot gas, trapped in the North American market, would trade in a $4.50 to $6.50 per mmbtu range (Henry Hub basis) through 2011 and 2012 before beginning to find support in 2013. We have disagreed with this price view, arguing that both the floor and ceiling of this range would likely be violated between 2011 and 2015, as novel pathways for clearing supply and demand emerged and as volatility picked up

Chinese government has

ambitious shale output

aspirations

Watch for news from the

Sichuan and Tarim basins

We expect gas-linked pricing to penetrate Asia

Utilities behavior can be herd-like….when one moves…..

Simple arithmetic of US LNG exports reaching Asia are

compelling

36



sharply for fundamental reasons. Cheniere estimates transportation costs from the US Gulf Coast to Asia are about $2.80 per mmbtu. Given that China and Japan are already paying $12 to $16 per mmbtu for LNG on a delivered basis, if the Sabine Pass option were available today, spot Henry Hub physical gas could be $6.13 to $9.61 per mmbtu today and still be competitively priced with oil-linked molecules in North Asia. The midpoint of the imputed range implies $7.87 per mmbtu. This is more than 2X the current spot price. The imputed range is also generally above the price level that many in industry believe will be the ceiling for the spot price for many years.

But violation of that supposed ceiling at $6.50 is an outcome consistent with the economics of marginal cost and the wide dispersion in fuel prices (more than $80 per boe) waiting to be arbitraged. There is a ready analogue in the rail and truck investments that have been pursued in 2011 to narrow the Brent-WTI spread after its historic blow-out over $20 per bbl (historic norm is about $1.50 per bbl WTI above Brent). Rail shipments of petroleum and petroleum products in the US Midcontinent surged in 2011, according to the Association of American Railroads, as Bakken barrels moved toward the NYM delivery hub at Cushing, OK and onward to the Gulf Coast.

Similarly, the potential for North American gas prices to reflect the marginal molecule in Asia consumption, rather than local production costs in a US basis, is reminiscent of the marginal cost economics that became so obvious in oil in 2008. That year, an oil sands producer in Canada or a deep water producer in the Western Gulf of Mexico or offshore Angola, who might have carried production costs somewhere between $50 and $65 per bbl, still received upwards of $140 per bbl on every barrel for a short period of time because at that instant the marginal molecule of global oil demand (driven by Asia) called upon the marginal molecule of supply (biofuels in Romania and the US) and every barrel in the world cleared off that marginal price.

Henry Hub can price to Asian

import costs, well above

marginal cost of US marginal cost of production

37



Global LNG supply & demand scenarios

We use our global database on LNG projects to forecast operational capacity as far out as 2020 (please see Appendix II). We run two simple global LNG supply-demand scenarios (a BULL and a BEAR case) and examine the potential supply deficit / surplus under each.

In both scenarios, we are subject to the key boundary condition that LNG imports cannot exceed a country’s expected re-gasification capacity based on existing and planned import terminals. For many countries that will import LNG for the first time, we assume a modest build up in re-gasification terminal utilization i.e. LNG imports will remain a tactical, but secondary source of gas to existing piped gas imports and domestic supplies for most countries e.g. in Europe. However, we do assume that these import terminals will be built and partly used. For example, in Europe we assume 2015E-17E LNG demand of 4-9-14 MT pa respectively from countries that do not currently import LNG (a combination of Albania, Croatia, Cyprus, Estonia, Germany, Lithuania, Poland, Slovenia, Sweden and the Ukraine). In truth, this represents a very small fraction of their aggregate gas demand, currently sourced via import pipelines.

We also assume that certain countries that currently import LNG, but which look set to export LNG (e.g. Canada and the USA) experience an accelerating decline in LNG imports as exports commence in 2015-16.

Under both scenarios we assume that Japanese LNG consumption will remain unusually high 2011 and 2012, only then reducing in 2013 given the return of much of its nuclear generation capacity. We note that J.P. Morgan’s forecast for Japan’s 2011 demand (source - Tomohiro Jikihara, Japanese utility analyst) of 89 MT represents 30% Y-o-Y growth and an increment of 21 MT. To put this in to context, this is more than half of the global growth in LNG in 2010 (+40 MT).

Under both scenarios, we also assume a loss of operating capacity of 2 MT pa 2011-2014 and 1 MT pa 2015-16 arising from the exhaustion of upstream gas supplies e.g. to Arun LNG (Indonesia – original capacity 12.5 MT pa – we note that BPMigas has recently confirmed that Indonesia will likely only export around 300 LNG cargoes in 2012 versus 367 in 2011 and 427 in 2010), Kenai LNG (USA – original capacity 1.5 MT pa) and MLNG Tiga (Malaysia – original capacity 7.4 MT pa).

We acknowledge that such a long range demand forecast will be error prone given LNG demand can be dislocated by numerous variables other than the economy: (i) weather – either very cold in the Northern Hemisphere or very hot in the Middle East (ii) the availability of hydro-electricity - we really cannot forecast local rainfall (iii) unexpected supply disruptions – perhaps arising from domestic or import pipeline shut downs (iv) government policy changes - for example, the Spanish government passed a decree in Spring 2011 to incentivize the burning of coal; this has contributed to a likely 20% Y-o-Y decline in Spanish LNG imports.

We note that during the seven year period 2005 to 2011, the global LNG system operated with almost 20% of theoretical spare capacity (based on 100% nameplate capacity of existing plants).

Re-gasification capacity sets a country’s limit to import LNG

Fukushima really was a ‘bomb in the LNG pond’

Some capacity retirement expected

38



LNG SUPPLY-DEMAND BULL CASE

Table 6: LNG demand outlook (MT pa)

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

Europe 35 42 39 40 50 64 68 67 68 72 78 86 94 99Middle East / Africa 0 0 0 0 1 2 3 4 4 5 7 9 9 10China 0 1 3 3 6 9 11 15 18 23 27 31 34 37India 4 6 7 8 9 9 9 12 16 18 20 22 24 27Japan 56 60 65 67 63 68 89 89 75 78 80 82 83 84Rest of Asia 29 32 33 35 34 43 48 51 56 63 70 75 78 81Latin America 1 1 1 1 2 7 9 11 13 14 18 20 22 23North America 13 13 18 10 13 15 12 12 11 10 9 8 7 7

138 154 165 165 177 217 249 260 262 283 308 331 352 368Market shareEurope 25% 27% 24% 24% 28% 29% 27% 26% 26% 25% 25% 26% 27% 27%Middle East / Africa 0% 0% 0% 0% 0% 1% 1% 1% 2% 2% 2% 3% 3% 3%China 0% 0% 2% 2% 3% 4% 5% 6% 7% 8% 9% 9% 10% 10%India 3% 4% 4% 5% 5% 4% 4% 5% 6% 6% 6% 7% 7% 7%Japan 40% 39% 39% 41% 35% 31% 36% 34% 29% 27% 26% 25% 24% 23%Rest of Asia 21% 21% 20% 21% 19% 20% 19% 20% 21% 22% 23% 23% 22% 22%Latin America 0% 0% 0% 1% 1% 3% 3% 4% 5% 5% 6% 6% 6% 6%North America 9% 8% 11% 6% 7% 7% 5% 5% 4% 4% 3% 2% 2% 2%

100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%YoY growthEurope 21% -7% 4% 25% 27% 6% -3% 3% 6% 8% 10% 10% 5%Middle East / Africa NM NM NM NM 230% 40% 27% 12% 16% 47% 17% 9% 3%China NM 287% 15% 72% 68% 20% 30% 25% 25% 18% 15% 10% 10%India 32% 25% 8% 17% -4% 7% 31% 31% 11% 11% 11% 10% 10%Japan 7% 9% 4% -7% 9% 30% 0% -15% 3% 3% 2% 2% 1%Rest of Asia 11% 2% 7% -5% 29% 11% 7% 9% 13% 10% 8% 4% 4%Latin America 5% 13% 54% 94% 181% 27% 32% 16% 11% 21% 12% 10% 7%North America -2% 37% -44% 28% 15% -18% -1% -5% -11% -13% -11% -7% -4%

12% 7% 0% 7% 23% 15% 5% 1% 8% 9% 8% 6% 4%Effective supply capacity 170 182 190 198 221 254 273 280 280 285 295 318 367 426Spare capacity 24% 18% 15% 20% 25% 17% 10% 7% 7% 1% -4% -4% 4% 16%2005-2011 average 18%


Supply - We assume the start ups of all new liquefaction plants in 2013 and onwards are 12-months late and new plants only operate at 75% capacity in their first year of operation. We assume that all plants then run at 95% of capacity(which would vary through the year according to seasonal demand).

Demand – We assume (i) a European recession in 2012, but recovery in 2013 onwards (ii) domestic shale gas fails to materially displace LNG demand in China(as occurred in the US).

39



Figure 20: BULL CASE - LNG effective supply / demand outlook (MT pa)


As per Table 6, under this scenario global demand rises from just under 250 MT pa in 2011E and almost reaches 370 MT pa by 2018E, a potential demand CAGR of 6%.

2012E global demand grows 5% to 260 MT.

Japanese demand holds at 89 MT pa in 2011 and 2012, declining to 75 MT in 2013 (2010 68 MT) as nuclear plants are re-commissioned.

Chinese demand surpasses 30 MT pa in 2016 (2010 9 MT and 2011E 11 MT) and reaches 37 MT pa in 2018 (2010 9 MT and 2011E 11 MT). The Chinese government has estimated total Chinese gas demand of 300 bcm pa by 2020. If we assume 8% pa LNG demand growth 2019-2020, this would imply that 20% of China’s gas needs could be supplied by LNG by 2020. This seems reasonable under a scenario where gas shale supplies are not the game-changer they were in the US gas market.

The global supply / demand balance tightens 2012-17. There is a risk of zero spare capacity by 2014-15. As a result, global LNG demand may be supply constrained from 2015 to 2017. If we extrapolate 2018 demand at 4% pa for two years, we infer 2020 LNG demand at just over 400 MT.

We suspect that this scenario (or something like it) may explain why China remains keen to contract long term supplies that are scheduled to commence in 2014-15, accepting oil price indexation for long term contract pricing..

Under this scenario, we expect regional gas price differentials to remain high for the next 2-3 years (until US LNG exports with a Henry Hub cost profile commence), offering low cost LNG suppliers with portfolio flexibility profitableopportunities to divert cargoes to an oil price indexed Asia Pacific market.

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450

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

Europe Middle East / Africa China

India Japan Rest of Asia

Latin America North America Effective operating capacity

Market cover runs down 2011-16

18%15% 20%

25%

17%

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24%

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40



LNG SUPPLY-DEMAND BEAR CASE

Table 7: LNG demand outlook (MT pa)

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

Europe 35 42 39 40 50 64 68 61 60 62 66 72 78 81Middle East / Africa 0 0 0 0 1 2 3 4 4 5 7 8 9 9China 0 1 3 3 6 9 11 13 15 17 18 19 20 21India 4 6 7 8 9 9 9 11 13 13 14 15 15 16Japan 56 60 65 67 63 68 89 80 68 69 70 71 71 72Rest of Asia 29 32 33 35 34 43 48 49 52 59 64 68 70 71Latin America 1 1 1 1 2 7 9 10 11 12 14 16 17 18North America 13 13 18 10 13 15 12 11 10 8 6 5 4 4

138 154 165 165 177 217 249 239 233 245 259 273 285 291Market shareEurope 25% 27% 24% 24% 28% 29% 27% 25% 26% 25% 25% 26% 28% 28%Middle East / Africa 0% 0% 0% 0% 0% 1% 1% 1% 2% 2% 3% 3% 3% 3%China 0% 0% 2% 2% 3% 4% 5% 6% 7% 7% 7% 7% 7% 7%India 3% 4% 4% 5% 5% 4% 4% 5% 5% 5% 5% 5% 5% 5%Japan 40% 39% 39% 41% 35% 31% 36% 33% 29% 28% 27% 26% 25% 25%Rest of Asia 21% 21% 20% 21% 19% 20% 19% 21% 22% 24% 25% 25% 24% 25%Latin America 0% 0% 0% 1% 1% 3% 3% 4% 5% 5% 6% 6% 6% 6%North America 9% 8% 11% 6% 7% 7% 5% 5% 4% 3% 2% 2% 2% 1%

100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%YoY growthEurope 21% -7% 4% 25% 27% 6% -11% -2% 3% 6% 9% 9% 3%Middle East / Africa NM NM NM NM 230% 40% 17% 13% 18% 50% 18% 9% 3%China NM 287% 15% 72% 68% 20% 20% 15% 10% 5% 5% 5% 5%India 32% 25% 8% 17% -4% 7% 15% 15% 5% 5% 5% 5% 5%Japan 7% 9% 4% -7% 9% 30% -10% -15% 1% 1% 1% 1% 0%Rest of Asia 11% 2% 7% -5% 29% 11% 2% 7% 12% 9% 6% 2% 3%Latin America 5% 13% 54% 94% 181% 27% 19% 8% 9% 20% 10% 7% 4%North America -2% 37% -44% 28% 15% -18% -8% -9% -16% -27% -18% -10% -4%

12% 7% 0% 7% 23% 15% -4% -2% 5% 6% 5% 4% 2%Effective supply capacity 170 182 190 198 221 254 288 295 302 313 337 390 452 552Spare capacity 24% 18% 15% 20% 25% 17% 16% 24% 30% 28% 30% 43% 59% 89%2005-2011 average 19%


Supply - We assume all new liquefaction plants are commissioned on schedule and then operate at 85% capacity in their first year of operation. We assume existing plants run at 100% of capacity (this varies through the year according to seasonal demand).

Demand – We assume (i) a European recession in 2012 and a slow-paced recovery in 2013-14 (ii) reflecting a faster return of nuclear capacity, a 10% decline in Japan’s LNG consumption in 2012 from the record high of 89 MT in 2011, followed by a 15% decline in 2013 (iii) the onset of shale gas production starts to displace material volumes of potential LNG demand in China from 2013 onwards.

41



Figure 21: BEAR CASE - LNG supply / demand outlook (MT pa)


As per Table 7, under this scenario, global demand rises from around 250 MT in 2011E and only reaches around 291 MT by 2018, a potential demand CAGR of just 2%.

2012E global demand declines 4% to 239 MT.

Chinese demand only reaches 19 MT pa in 2016 (2010 9 MT pa and 2011E 11 MT and our Bull Case estimate of 30 MT).

The market’s spare supply capacity averages over 20% (higher than the average ‘spare’ capacity 2005-2011 of around 19%) through to 2015 before rising substantially 2016-18.

If the world looks like it is heading in to this scenario, projects which have not yet contracted off-take / been sanctioned with an on stream date 2016-18 will almost certainly be deferred as sponsors will struggle to contract off-take based on an acceptable long term pricing structure as LNG-on-LNG competition escalates.

If we extrapolate 2018 demand at 2% pa for two years, we infer 2020 LNG demand at around 320 MT. This is more 24% below the implied demand figure under our BULL scenario in 2020 of just over 400 MT.

Under this scenario, we would expect regional gas price dispersion to narrow as more LNG supply points emerge with material spare capacity. This scenario would thus be characterized by more limited opportunities for regional price arbitrage; the value of supply flexibility would thus be reduced.

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

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Market cover rises to 25-30%

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42



Why we might (well) be wrong

We have been researching the global energy sector for long enough to acknowledgethat long term energy supply-demand forecasts are very often wrong for unexpected reasons - the unseen unknowns usually unhinge the most complicated spreadsheets.So, we do not apologize for presenting two extreme scenarios that show two very different market environments. To present a narrower bandwidth for the future would be too presumptuous, in our view.

LNG sits within a complex energy matrix. As a result, demand for LNG can be disrupted, both positively and negatively, by very many factors other than the weather and the state of the global economy. Although the underlying drivers to the global LNG demand trends, that are in turn driving the liquefaction capacity growth, look to be very secure, we must consider potential dislocations that could jeopardize the tremendous pace of capital investment, especially as it relates to a number of pre-FID projects scheduled to be on stream 2016 onwards. We consider eight specificfactors that could slow down either the pace of capacity growth or LNG demand.

Capacity growth risks

Project delays and cancellations - As per Figure 24, J.P. Morgan’s analysis of LNG projects 2000-2010 shows that 34% were delivered behind schedule (versus 66% on or ahead of schedule) and 38% are over budget (63% on or under budget). So, one might say the odds of late project completion is one in three. As per Figure 22, we note that looking beyond 2015, virtually all projects that are tentatively scheduled to be on stream 2016 to 2020 have yet to be sanctioned. Indeed, of the 710 MT pa that could be on stream by 2020, almost half (c.45% or 320 MT pa of capacity) has yet to be sanctioned. We have also witnessed very significant capital cost escalation for LNG projects (Figure 23) - from a low of $200 per ton, the current rate is typically over $3,000 per ton, a 15-fold increase. It is conceivable that project capital costs continue to escalate to a level where, even given a direct oil price to LNG price linkage, the economics of a project are so severely damaged that the project is cancelled.

Long term forecasts are usually

wrong for unexpected reasons

As Warren Buffet wrote

‘forecasts tell you little about the

future, but a lot about the forecaster’

Mega-infrastructure projects

often fall behind schedule….and

sometimes just never happen

43



Figure 22: LNG capacity at risk (MT pa)


Price revocation / contamination as Henry Hub diffuses in to global LNG price structures – Most, if not all, long term LNG sales and purchase agreements include windows for contract price re-openers. This can lead to modest changes to the long term price agreement. It is, as yet, unprecedented for a buyer to demand and secure a complete price renegotiation - but this could happen. The key risk, as we see have discussed in the section on LNG price risks, is global contract price contamination once Henry Hub based export price agreements proliferate. Indeed, we have already seen three such contracts signed by BG Group, Gas Natural and GAIL with Cheniere. Equally, buyers negotiating a contract for a green field project might insist

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2010 2011 2012E 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

Operating capacity Projects under development Projects with defined FID timeline Projects without clear FID timeline

Projects that are likely to slip

Projects that are likely to slip or may not happen

Projects that may slip

320 MT pa or 45% 2020E capacity yet to be sanctioned

Figure 23: LNG project capital (EPC) costs - $ per ton of capacity


Figure 24: Global LNG project execution efficiency 2000-10


Henry Hub S-curve could

contaminate regional pricing

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44



on a ’fusion’ of oil and US gas price linkage – this could undermine the project economics and lead to a deferral / cancellation. At the very least, we expect lower priced Henry Hub based S-curves to reduce regional price dispersion and thus erode returns from regional LNG arbitrage trading. Another form of this risk can occur if a government revises the terms (sales price formula) of an LNG export sales contract. This has already occurred with BG Group in Egypt LNG.

Politics – The decision by a government to approve an LNG export scheme can be a very controversial one. Although the project will create employment, inward investment and ultimately taxes, it can also lead to higher domestic gas prices. This can threaten the efficiency of local industry e.g. steel, autos, fertilizers and petrochemicals which can in turn threaten employment, inward investment and tax receipts. So, governments must strike a balance between the two.

1. USA - It is conceivable that the US government, lobbied by some powerful domestic industry groups, will delay the development of an LNG export hub along the Gulf Coast. We note that four LNG export projects on the US Gulf Coast (Sabine Pass, Freeport, Lake Charles and Jordan Cove) could together export over 8 bcfpd - this is a meaningful 12% of total US gas consumption in 2010 (66 bcfpd). The US Department of Energy (DoE) is now conducting two studies (one via the US Energy Information Administration and the other via private consultancy) on the potential gas price impacts of these exports on the domestic natural gas market and on public interest in general. The conclusions of these two studies will likely determine whether any or all of the remaining four applications for export projects which total 55 MT pa (Freeport LNG - Texas, Lake Charles –Lousiana, Cove Point LNG – Maryland and Jordan Cove - Oregon), will be approved. Until these studies are concluded, no new LNG export licenses will be granted by the DoE.

2. Trinidad & Tobago / Egypt—Both countries have stalled brown field expansion of existing LNG facilities (Egypt - ELNG Train 3, Damietta LNG Train 2 and Trinidad - ALNG Train X) in order to slow the depletion of gas resources and to prioritize domestic consumption. It seems very unlikely that populist policies post-Mubarak will see any LNG expansion in Egypt even if more gas is discovered (which is required to support a third train at ELNG)

3. Qatar – Qatar has a moratorium on any further development of its super giant North field in order to preserve its resources for future generations. This moratorium is to be reviewed in 2014.

Project finance withdrawal – Given the extreme capital intensity of liquefaction projects, participants have historically depended on project finance in order to limit the more expensive equity finance component. Such project finance has historically been secured through special purpose vehicles once upstream reserves have been fully certified and a long term LNG off-take agreement has been signed. The conventional sources of project finance loans have been the large commercial banks and government owned multi-lateral lenders (e.g. JBIC). Basle III (to apply from 2015) imposes a Net Stable Funding Requirement (NSFR). This will force banks to hold 10x more capital reserves and the capital reserves must cover the undrawn portion of the project finance facility. Sovereign downgrades have also made it more expensive for such banks to lend. This may lead to an increase in LNG related bond issuance. At present, we are only aware of the RasGas I and RasGas II-III bonds ($2.23bn face value rated A3 by Moody’s). However, such bonds do not permit a staged drawdown and also require bi-annual interest payments before a project has started.

LNG projects can create and

threaten local employment

Bond market may have to

replace project finance

45



Failure to prove up sufficient gas resources – Woodside has had to delay Pluto Train 2 (WDS 90%) following disappointing drilling results (the Cadwallon-1 well, WA-434-P, only intersected a 27m column of hydrocarbons and was deemed sub-commercial). Woodside plans another five wells to mid-2012 to prove up sufficient gas to progress a second train. There are numerous green field projects which have yet to clear the commercial gas reserve threshold (around 5 TCF for one train), e.g. Tanzania LNG (BG Group, Ophir Energy) and Kribi LNG (GDF Suez, Cameroon).

In Table 8, we list the liquefaction export projects that are at above average risk of delay or failure because of government depletion controls, potential reserve threshold risks, economic sanctions, politics and vulnerable (sub-scale) sponsors. All have tentative start up years 2017-2020. The total capacity at risk is almost 187 MT pa (84% green field) which is spread across 43 trains (39 green field projects).

46



Table 8: LNG projects at risk

Country ProjectCapacity

(MT pa) Trains Project type FIDPotential

On stream

Gas depletion controls, domestic market prioritisationEgypt Damietta LNG T2 4.8 1 Brownfield No 2018Trinidad ALNG Train X 5.0 1 Brownfield No 2018Potential reserve threshold riskCameroon Kribi LNG 3.5 1 Greenfield No (2013E) 2018Tanzania Tanzania LNG T1 6.6 1 Greenfield No 2018Economic sanction riskIran Pars LNG 10.0 2 Greenfield No 2018

Iran LNG 10.0 2 Greenfield No 2019Persian LNG 16.2 3 Greenfield No 2020

Political riskAustralia / East Timor Sunrise FLNG 3.6 1 Greenfield No 2018Brazil Santos FLNG 2.7 1 Greenfield No (2012E) 2018Canada Progress LNG 7.4 2 Greenfield No 2017-18

Prince Rupert 8.0 2 Greenfield No 2017Georgia Azerbaijan LNG 5.0 1 Greenfield No TBCIndonesia Tangguh LNG T3 3.8 1 Brownfield No (2014E) 2018Nigeria Brass LNG 10.0 2 Greenfield No (2012) 2018

OK LNG 12.6 4 Greenfield No 2020NLNG T8 8.5 1 Brownfield No 2019

USA Lake Charles LNG 15.0 3 Greenfield No 2017Cove Point LNG 7.8 2 Greenfield No 2020Cameron LNG 12.0 3 Greenfield No 2020Jordan Cove LNG 9.0 2 Greenfield No 2020

Russia Yamal LNG 15.0 3 Greenfield Yes 2019Pechora LNG 2.6 1 Greenfield No 2020

Venezuela Gran Mariscal de Ayacucho 4.7 1 Greenfield No 2019Vulnerable sponsor riskAustralia South Australia LNG 1.0 1 Greenfield Yes 2017PNG Gulf LNG (PNG FLNG) 2.0 1 Greenfield No (2012) 2017

TOTAL CAPACITY AT RISK 186.8 43


LNG demand growth risks

Gas shale revolution in the US repeats elsewhere – No one (as best we know) in the oil & gas industry fully anticipated the rapid pace of gas shale supply growth in the USA which now accounts for one third of total US gas production (close to zero in 2000 versus over 10 bcfpd in 2010). This unexpected source of low cost gas supply has left most of the country’s LNG import terminals running at very low utilization rates and has enforced the deferral / cancellation of all new import terminals / terminal expansions. Figure x shows the volume weighted (based on technically recoverable resources) average and range of estimated break even gas prices for the various US gas shale plays. We note that technology continues to evolve in the US gas shale, so the cost curve remains a dynamic one e.g. Schlumberger’s HiWAY fracking technique can yield up to twice daily production versus standard slick water fracs. Further developments that could reduce costs include top-side water recycling, the use of Nitrogen or LPGs to fracture shale and the use of briny water from deep-source aquifer.

Gas shale revolution could recur in China, Poland, Argentina….

47



Figure 25: Break even price of various US gas shale sources

Source: James A. Baker III Institute for Public Policy - Shale Gas and U.S. National Security

(July 2011)

Figure 26: Break even price of potential non-US sources of gas shale

Source: James A. Baker III Institute for Public Policy - Shale Gas and U.S. National Security

(July 2011)

Although we feel it will be at least 1-2 years before its potential is known, it is conceivable that China could rapidly unlock its gas shale potential which could quickly displace its need for incremental LNG imports. As per Figure x, the EIA estimates that China may hold 1,275 TCF of technically recoverable gas shale resources – this is 19% of the EIA's estimated global gas shale resource and compares to 862 TCF in the USA (Figure 27). China has set a target to grow gas shale production to 15-30 bcm by 2020. In our view, the key challenges for the commercialization of China’s gas shale resource include:

a. Location - Unlike the US, we note that China's gas shale resource is spread across 150 basins, many of which are located a long way from demand centers.Some of these basins are located close to existing gas infrastructure, but face capacity bottlenecks. Other basins are remote from any infrastructure that would have to be installed.

b. Drilling costs – It is still very early days, but drilling costs (per the PetroChina / RD Shell alliance in the Fushun-Yongchuan block in Chengdu) are presently much higher than the US. This reflects both difficult terrain and deeper shale horizons.Some of China’s potential gas shale is also thought to be clay rich which is typically associated with much lower well production rates.

c. Water availability / environmental footprint – Access to water is a problem given well fracturing needs. We also understand that a number of the shale plays contain high levels of inert gases that would have to be stripped out and contained.

d. Regulated gas pricing – Domestic gas prices are regulated at levels that are below the free market price of imported LNG. Prices may need to rise to incent risk-taking in gas shale. Figure x shows the range of estimated break even gas prices for gas shale from four basins (basin complexes) - Sichuan / Jianghan, Ordos, Tarim / Junggar / Tuja and Songliao - the volume weighted break even price is close to $7 per mmbtu.

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48



e. No community of risk-taking independents – The successful development of US gas shale relied, in many key respects, on the pioneering efforts of risk / reward seeking independent explorers that worked the play and encouraged effective technological changes in horizontal drilling and fracturing. China lacks an equivalent community of suitably incentivized risk-takers and is more obviously dependent on a few, much larger companies to mature its gas shale potential. At the very least, this could slow down the pace of the play’sevolution.

Figure 27: Estimated technically recoverable gas shale resources (TCF)

Source: EIA (March 2011). The EIA’s estimates for China and the USA are much higher than those from the James A. Baker III Institute for Public Policy - Shale Gas and U.S. National Security

(July 2011). Amongst other things, this reflects different views on most likely recovery factors.

LNG on piped gas competition – This is not a new phenomenon. Since 2006, China and Russia have been negotiating the supply of 68 GM3 over 30 years via twoproposed pipelines from Russia to China - one bringing gas from western Siberia to the existing West-East pipeline; the other to be supplied from East Siberia. Gazprom has not been prepared to yield on price and has seen some of its market taken by LNG imports and piped gas from Central Asia e.g. Turkmenistan. We note the recent agreement between Beijing and Ashgabat (Turkmenistan) to increase gas exports to China from 40 to 65 bcm pa (the original 30-year supply deal for 30 bcm pa was signed in 2006 and was increased to 40 bcm pa in 2008 with supplies commencing in 2009). If Gazprom yields on price to protect its market share, this could quickly displace some of China's potential need for imported LNG. As per the recent news confirming Gazprom’s willingness to refund certain buyers, we sense that Gazprom remains very keen to protect its export markets.

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Technically Recoverable Shale gas resources (TCF) * Romania, Hungary, Bulgaria

Gazprom could ‘blink’, piped gas price concessions could

follow….

49



Diminution or an end to unsustainable domestic gas price subsidies – Many countries still use a government owned central buyer of LNG to aggregate LNG imports. This entity then sells the gas on to industrial and commercial users at much lower prices, thus burdening the government with an effective subsidy bill for the imported LNG. A depreciating local currency magnifies the cost of this subsidy since imported LNG is US dollar denominated.

1. In India, state owned producers of domestic gas sell gas at a regulated gas price of $4 2 per mmbtu.

2. In Egypt, industrial end users pay as little as $1.25 per mmbtu. In the fiscal year 2011-12, natural gas subsidies cost the Egyptian government approximately $1.6bn, 10% of the country's total energy subsidy bill.

3. In Argentina, YPF pays ENARSA (the country’s state owned buyer of gas) $3.5 per mmbtu for re-gasified volumes from its two LNG import terminals (Bahia Blanca and Escobar).

4. In Taiwan, government owned CPC sells gas to Taipower at a government adjusted price of $13 per mmbtu whilst it pays as much as $18 per mmbtu for LNG imports. Taiwan’s budget deficit continues to undermine its currency which amplifies the scale of the gas subsidy since LNG imports are US dollar denominated.

5. In May 2010, the Chinese government raised regulated domestic gas prices by 25%. Although provincial governments are allowed to adjust gas prices within a 10% range from the centrally mandated priced, in 2011 cargoes of LNG were purchased and imported via Fujian at double the price at which the gas was subsequently sold to end users.

6. In June 2011, the Malaysian government raised gas prices from $3.55 to $4.55 per mmbtu for electricity generation and from $4.98 to $5.34 per mmbtu for industrial users. The government plans to increase gas prices by $1 per mmbtu every 6-months until December 2015.In the meantime, Petronas pays market rates for Malaysia’s imported gas.

7. Earlier this month, parts of Bangkok (Thailand) were paralyzed as truckers and taxi drivers blocked off streets near to PTT HQ to protest the government’s plan to steadily raise NGV (natural gas for vehicles) prices by Bt6/kg (from Bt8.5/kg), beginning 16th January. Despite these protests, the government insiststhat NGV prices must rise as overly cheap prices are distorting the entire energy market in Thailand, leading to excessive consumption and waste.

50



Origin of LNG competitive advantages

As per Figure 28, we believe that it is possible for the ‘best in class’ players to derive very attractive returns from the LNG suite of businesses across multiple cycles provided they possess and sustain all the key competitive advantages that we cite for each of the four key streams (liquefaction, shipping, re-gasification and sales contracts – see Appendix VII for a full glossary of terms).

Figure 28: Sources of competitive advantage on the LNG value chain


Plant scale Terminal scale Vessel scale & design

- > 5MT pa mega trains - > 3MT pa - Q-Max and Q-Flex, on board reliquefaction

- potential for hub

Location Terminal design Vessel age

- close to source gas - multiple unloading berths for Q-Max - new, low boil off (0.15% per day)

Location Location LNG fuel usage

- close to key demand centres - unconstrained shipping access - captures LNG boil off, reduced emissions

Location Location Ownership

- politically stable environment - close to inland demand centres - leased rather than owned directly

- few environmental / land owner issues

Location Pipeline connectivity Financing

- low cost, accessible onshore setting - access to premium priced markets - optimum levels of vessel finance

Plant design Storage capacity Capacity coverage

- multiple loading berths for Q-Max - maximise operational flexibility - ideally built in to bottom of downcycle

Construction timing Output capacity profile

- in to cycle bottom - high baseload + peaking capability

Ownership Operating costs Low cost, reliable sources

- simple, aligned to upstream suppliers - low fixed & variable costs - ideally 20 year contracts

- participation of customers

Financing Construction timing Long term offtake contract

- optimum levels of project finance - in to cycle bottom - at or close to oil price 6:1 parity

- limited price re-openers

Fiscal regime Ownership - limited daily quantity tolerance range

- low rate ring fence - ideally leased via LT tolling agreement

Destination flexibility

Asset integrity / reliability Leasing agreement - to enable exploitation of price differentials

- maximize availability - low fixed cost component - supported by strong trading function

Storage capacity Reloading capability Diversion rights

- maximise operational flexibility - permissioned for export option - rights to high % price upside

Source gas Terminal efficiency- low cost, reliable, long-lived resource - NGL extraction, air vaporisation system

Floating storage, regasification unit

- cheaper and faster to build, movable

------> HIGH RETURN, HIGH FREE CASH FLOW BUSINESS <-------

------> GLOBAL CAPABILITY & POSITIONING <-------

<-------------------------------------------------------- Portfolio optimization ------------------------------------------------------->

SALES CONTRACTS

ORIGINS OF LNG COMPETITIVE ADVANTAGEKEY VALUE DRIVERS

LIQUEFACTION PLANT REGASIFICATION TERMINAL SHIPPING

- co-ordinate utilization of all assets across demand cycle

<--------------------------------------------------------- Best people -------------------------------------------------------->

- correctly incentivised for operational & HSE excellence

<------------------------------------------------------ Best contractors ----------------------------------------------------->

- incentivised for operational excellence, adequately supervised with clear policies & procedures

LNG has relatively high entry barriers

Companies that create gas chains and position on the best

links in those chains generate

very good returns

51



Just as storage facilities and pipelines help to maximize the value of gas, so too does liquefaction by giving gas the reach to higher priced markets. However, we believe that the highest returns may be derived from players with appropriate levels of control / ownership of all key infrastructure i.e. export capacity, shipping capacity and import capacity since this infrastructure cluster enables and supports the development of a very high return trading function, especially given a portfolio of flexible LNG supply contracts. Companies that have evolved a presence and skills across the entire value chain are ideally placed to create new gas chains and extract maximum value there from.

Figure 29: Activity links on the LNG value chain - financial returns and capital intensity


In Figure 31, we depict the capital intensity and return volatility of the four key activities on the LNG value chain. LNG’s relatively high levels of capital intensity have helped to limit the population of players, which is thus fortunately characterized by a comparatively small number of very rational and return-seeking players. This has certainly helped to protect the returns extracted from the LNG value chain. Liquefaction is by far the most capital intensive link on the value chain - a two train green field LNG project may now cost more than $20bn including the upstream supply and pipeline infrastructure. This typically limits participation therein to the larger IOCs and NOCs which have the balance sheet capacity for such large, long lead infrastructure projects.

The returns from LNG liquefaction infrastructure (when acting as an isolated tolling facility) are typically reasonable, but not excessive (c.10%) and stable provided the plant is efficiently operated and maintains consistently good utilization rates (> 90%). With respect to liquefaction, adequate and reliable supplies of source gas, coupled to plant efficiency can make a very material difference to plant economics. As per Figure 30, a well run plant can reach close to 100% of nameplate operating capacity in a year without maintenance (which usually occurs every 2-3 years). However, a less well run plant suffering from unreliable, declining gas supplies may only achieve 30-40% utilization. The makes a very material difference to plant economics.

Natural Gas production

LiquefactionShipping & Marketing

Re-gasification terminals

Delivery and Marketing

High

Low

Returns

High

Low

Capital intensity

Integrated presence can secure

the highest returns

Liquefaction participation

requires a big balance sheet and

a long time horizon

Liquefaction plants must have

good uptime

52



Figure 30: 2010 liquefaction plant utilization rates by country (%) *

Source: J.P. Morgan. * Utilization is defined as LNG exports divided by nameplate operating capacity

The world's average train capacity has almost trebled from the first trains (1 MT pa) to almost 3 MT pa. The largest LNG train now in operation is in Qatar (7.8 MT pa –Qatargas II Trains IV and V and Ras Gas 3 Trains VI and VII). Until recently it was Train 4 of Atlantic LNG in Trinidad and Tobago with a production capacity of 5.2 MT pa.

The capital cost of re-gasification terminals are substantially lower, often less than $1bn. Returns to the terminal owner may be more volatile. If the owner simply tolls for usage (i.e. does not take any price or spread risk), returns may be reasonable depending on utilization (see Appendix III).

LNG vessels are relatively expensive to build ($200m to $300m) and returns there from will depend on the duration and terms of charter. Vessels left exposed to the spot market will typically generate volatile returns (see Appendix IV).

LNG trading is not capital intensive per say, although it requires ancillary, enabling infrastructure. The nature of most LNG trade - typically hedged back to back –means that the volatility of returns is quite low.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Production issues

Declining gas supplies

Ramping up

Ramping up

Operatingat capacity

Ramping up

Scale of liquefaction train also

matters

http://en.wikipedia.org/wiki/Trinidad_and_Tobago

http://en.wikipedia.org/wiki/Atlantic_LNG

53



Figure 31: LNG value chain - capital intensity versus volatility of returns


As we depict in Figure 32, it is quite difficult, albeit never impossible, to lose a lot of money in LNG. In theory, an LNG vessel could run aground or be sabotaged, thus causing its cargo to leak. However, unlike a tanker oil spill, the LNG would quickly vaporize and (barring exceptional atmospheric conditions which have only once occurred in the USA – see Appendix VI) disperse in to the atmosphere. So, the economic loss would be limited to the value of the cargo and vessel.

Similarly, an LNG plant could experience a catastrophic explosion if the gas entering the plant and being processed prior to liquefaction encountered an ignition point. In the 50+ year history of liquefaction, this has only occurred once (in Algeria in 2004 –see Appendix VI). The largest risk to LNG liquefaction returns is capital cost over-runs and project delays - a combination of both can rapidly reduce project returns to an economic break-even. This is a very legitimate investor concern given already high unit capital costs (EPC > $3,000 per ton of annual capacity are more than 10x the cycle low just ten years ago) and the unprecedented scale of capacity growth over the next decade, especially in Australia where there are numerous projects competing for the same underlying resources (skilled and craft labor, steel, capacity for modules from a limited number of yards etc).

SHIPPING

VO

LA

TIL

ITY

OF

RE

TU

RN

S

CAPITAL INTENSITY

LIQUEFACTION

TRADING

Low Medium High

Lo

wM

ed

ium

Hig

h

Least desirable exposure

Most desirable exposure

Charter

Tolling model

Regional arbitrage

REGASIFICATIONLease

Train phasing

Hard to lose money in LNG

54



Figure 32: LNG value chain - entry barriers versus potential for large losses


The entry barriers to LNG trading are surprisingly high – new entrants require more than just experienced traders and trading systems. They must have access to cargoes, but the market's liquidity is typically held captive by the LNG liquefaction owners / upstream suppliers who are understandably very reluctant to release volumes for traders to trade with. Traders must also have access to shipping, either via owned vessels or the charter market. Furthermore, certain ships can unload at certain terminals (e.g. many import terminals cannot accommodate Q-Max vessels). This can make it even more difficult to efficiently connect volumes to buyers.

From an LNG buyer’s perspective, the trader must ideally have a track record of reliable delivery – the buyer will not risk delivery failure. Since most LNG trading is arranged with back-to-back supply agreements, the trading party does not bear volume or price risk on execution – the spread is locked in. So, we believe that the stock market ought to assign a higher than normal multiple (value) to LNG trading versus other lower quality trading functions in the oil & gas industry. However, companies with a material exposure to LNG trading need to better inform the market about this business.

The entry barriers to re-gasification are lower given much lower capital intensity than export facilities and capital barriers may be side-stepped via long term capacity rental agreements. Given low fixed operating costs, even if left largely idle, an LNG terminal will not generate large losses.

REGASIFICATION

PO

TE

NT

IAL

FO

R L

AR

GE

LO

SS

ES

ENTRY BARRIERS

SHIPPING

TRADING

LIQUEFACTION

Low Medium High

Lo

wM

ed

ium

Hig

h

Least desirable exposure

Most desirable exposure

Risk of major industrial accident

LNG spill bears low environmental risk

Bilateral OTC trading

Terminals have low fixed costs

Participation in all four areas can reduce risk and enhance overall returns

LNG trading is a very difficult market to penetrate

55



Competitive ranking of LNG players

Identity of listed players

As we have already noted, compared to upstream (thousands of players) and refining(many hundreds of players), there are comparatively few players in LNG – it is an industry that has typically attracted some of the IOCs and some of the NOCs. This reflects relatively high entry barriers (high capital intensity, long lead times etc) and the need to discover very substantial gas resources (not a natural exploration priority for most small E&P companies). Consolidation also plays a role - smaller E&P companies that find themselves part of an LNG development are very often acquired before project sanction. This results in a relatively small number of players - Figure 33 highlights just over 50 of the key players including both IOCs and NOCs. This helps to induce robust capital discipline across the cycle which is further reinforced by the need to contract off-take before project sanction – little or no LNG export capacity is therefore built on a speculative basis.

There are many ways to categorize the listed players in the global LNG market. In Figure x, we split them according to market status and ambition and whether they are integrated (present in liquefaction, shipping and re-gasification) or not. This research note takes a detailed look at the LNG strategies, assets and global positioning of 20of the 34 listed companies identified below. Unsurprisingly, perhaps, two of the world’s largest and oldest listed oil companies (Exxon Mobil and RD Shell) show clear dominance of the space – LNG requires a large balance sheet and a long strategic wavelength, but ultimately rewards both very well.

Figure 33: Nature of key players in the LNG space

Source: J.P. Morgan. * HQCEC – China Huanqiu Contracting & Engineering Corporation – a subsidiary of CNPC.

DOMINANT INCUMBENTS

RD ShellExxon Mobil

AGGRESSIVE GROWTH

BG GroupChevron

ConocoPhillipsTOTAL

Woodside

NICHEPROJECTS

GazpromNovatek

GALPMarathon Oil

Oil SearchOrigin EnergyPetronet LNG

NEWENTRANTS

CNOOCPetroChina

SinopecPTTEP

AnadarkoApache

BHP BillitonEncana

Talisman

BITPLAYERS

BPGDF SUEZ

ENIE.ON

Gas NaturalKansai Electric

KOGASMitsubishi

MitsuiRepsol YPF

RWEStatoilTEPCO

Inpex Santos

INTEGRATED

UPSTREAM or DOWNSTREAM

ONLY

QPCNNPC

SonatrachPetronas

Brunei NOCCIC

Oman NOC

ADNOCLNOC

PetoroPertamina

UnlistedNOCs

Listed IOCs, NOCs, E&PS, Utilities

HQCECSonangol

Population of players in LNG much smaller than refining or

E&P

Exxon Mobil and RD Shell stand out leaders

56



Amongst the unlisted National Oil Companies, those with the largest LNG presence are QPC (Qatar), NNPC (Nigeria), Sonatrach (Algeria) and Petronas (Malaysia). Of these names, Petronas is the only NOC to have positioned itself in LNG projects in and outside its home country. However, this internationalization strategy is now being replicated by the three listed Chinese NOCs – CNOOC, PetroChina and Sinopec. In many respects, they are replicating the entry strategy pursued by the Japanese utilities which contract for some of the LNG off-take and also take an equity position in the project. We expect to see more international alliances between NOCs and NOCs and IOCs, as per PetroChina with RD Shell in Australia, to enable new entrants to accelerate their growth in LNG. We note that ONGC of India has confirmed it is in discussions with Gazprom of Russia.

The world’s largest NOC, Saudi Aramco, does not have any presence in LNG. Notwithstanding Saudi's need for more gas to supply burgeoning domestic industrial growth (e.g. plastics, cement and water desalination), we doubt Saudi Aramco will develop a presence in LNG (as a potential importer) given its ability to burn crude oil for power if required to do so.

Competitive positioning

It is difficult to perform a detailed competitive ranking of the companies featured in this note given limited disclosures by many of these companies on their LNG businesses. We note that only two companies (BG Group and Repsol YPF) actually report LNG as a separate segment, although RD Shell provides some additional disclosure on its Gas & Power business which largely comprises LNG (Gas & Power is reported as part of its upstream segment).

Other oil & gas companies include LNG earnings in their reported upstream results and the non-upstream earnings may only be seen (and often not explicitly) with their once annual FAS 69 Supplementary Oil & Gas disclosures. So, the analyzable metrics are limited - we cannot measure margins or returns on capital and, for most companies, we have limited information on LNG purchase and supply contracts.

We see little point in assessing the competitive positioning of new and niche playersalongside the more established, larger players since by definition it will be weak. So, in order to give an idea of competitive standing of the better established players, we have scored eleven of the twenty companies that we feature in this note on the elevenmetrics detailed below. Since each company can score a maximum of four on each metric, this gives a maximum score of forty-four.

1. Liquefaction scale – We position the companies in to four simple categories based on their net liquefaction capacity: < 5 MT pa, 5-10 MT pa, 10-15 MT pa and >15 MT pa. As per Figure 34, the top three players (RD Shell, Exxon Mobil and TOTAL) look set to remain the top three by 2015. Of note, BP’s looks set to slip to fifth place as it will be over-taken by BG Group. Chevron and Woodside jump up the ranking by 2015, moving in to sixth and seventh position respectively. So, a new set of leaders emerges later this decade.

A few NOCs also have a very big

presence in LNG

World’s largest NOC, Saudi

Aramco, is unlikely to move in to

LNG

Limited disclosure constrains

peer group analysis

11 key parameters to think about

when looking at an LNG portfolio

57



Figure 34: Net liquefaction capacity (MT pa)


2. Liquefaction plant vintage – Given the very high level of cost inflation since the LNG cost curve bottomed out in 2003 to 2006, plants that were built around this time have the advantage of a lower unit capital cost. Conversely, plants built in the period 2006 and beyond have experienced material cost inflation. So, we favor companies with a concentration of portfolio capacity built at or around the bottom of the EPC cost cycle specific to liquefaction. We also favor companies with older facilities – even though they will likely have smaller train sizes, they will have exited project finance debt repayments and will thus be generating regular dividends to their owners (typically prevented if not constrained whilst project related debt repayments are underway). We are concerned that companies with a high growth dependency on CBM to LNG projects in Queensland (Australia) will experience both cost over-runs and project schedule delays.

3. Liquefaction capacity location – Given much stronger demand trends in Asia Pacific, we favor companies with a liquefaction location bias to Asia Pacific since they ought to be able to reach the key demand centers at lower cost. As second best, we favor North Africa (including the Middle East) as a location over the Atlantic Basin. We score companies based on the likely evolution of their capacity dispersion based on identified liquefaction developments. For a company to score above average, it must have more than half of its net capacity in Asia Pacific.

4. Average train size – Liquefaction facilities have fixed costs. Furthermore, there are scale economies to the construction of liquefaction trains. So, we favor companies which have above average unit train size (> 3 MT pa). As per Appendix II, the global average train size will continue to grow through this decade – we estimate it will rise from 3.1 MT pa to 3.7 MT pa.

0

5

10

15

20

25

30

35

RDS XOM TOT BP BG ENI REP CVX WDS STL STOS OS

2011 2015E

58



5. Brownfield expansion potential – As we have discussed, brown field plant expansion can typically be achieved at attractive unit costs given existing facilities that do not have to be duplicated e.g. plant utilities, loading facilities and marine jetty. For example, BG Group estimates that the unit capital costs of a third train on QC LNG will be 40% lower than for Trains 1 and 2. So, we favor companies which have an embedded expansion option in their existing liquefaction plants given upstream resource cover, local government support and available land.

6. Green field growth potential – We favor companies with clearly identified liquefaction growth projects that will add materially to the operating base and LNG earnings base. So, we favor companies that have a high level of intrinsic organic growth potential when looking out to 2015. However, we restrain our score if we feel the growth projects are particularly challenging e.g. in the Russian Arctic.

7. Plant operatorship – We favor companies that have a senior position, as a result of a large if not dominant working interest, in the operating company of an LNG plant as opposed to small, minority working interests.

8. Integrated chain presence – As we have argued, we believe that the best returns from the LNG value chain may be achieved when a company has a full chain presence from upstream through liquefaction, shipping and re-gasification. However, we favor companies with an upstream / liquefaction bias as opposed to a re-gasification bias, especially if the outlook for latter is to be left largely idle.

9. LNG trading capability – Given very substantial regional natural gas (LNG) price differences, we favor companies with supply flexibility and ownership of / access to the enabling assets (access to shipping and a trading capability) that allows them to exploit cross-basis LNG price arbitrage as fully as possible with a proven track record of supplying LNG in to many (or all) of the world’s 25 importing countries. The ideal LNG portfolio has multiple customers and multiple supply points with in-built flexibility to supply from the optimum source.

10. Relevance of LNG to company - We position the companies in to four simple categories: < 5% 2012E group earnings from LNG sub-segment, 5-10%, 10-15% and >15%. This earnings exposure is typically positively correlated to LNG segment value exposure.

11. Quality of LNG segment disclosures – Good levels of public disclosure are vital in order to permit an accurate analysis and valuation of the LNG exposure of a company. As we have cautioned, many companies simply fail to disclose enough about their LNG business to ensure a full and fair valuation of their LNG position. We favor companies that provide an explicit quarterly disclosure on LNG earnings (turnover, EBIT or post tax earnings), volumes and capital investment. Some companies e.g. BG Group provide very good and explicit disclosure on their LNG business. Other companies, such as BP provide far too little information on the performance of its LNG business, in our view. We cannot see any reason for BP not to improve its disclosure standards on this important segment.

59



Figure 35 shows how we score and rank eleven of the twenty companies that are featured in this note that have a well developed presence in the LNG space. Our chosen categorization defines a leadership group comprising 5-6 companies. Exxon Mobil ranks first (33 of 44 points), out-scoring RD Shell (32 points) by just one point which in turn out-scores Chevron by one point (31 points). BG Group (29 points) ranks fourth and TOTAL (26 points) ranks a joint fifth with Woodside. This top tier is followed by a second tier of companies with smaller exposures to LNG – this includes Santos, BP and the remaining European names.

Figure 35: Competitive ranking of top LNG players


3. Capacity location

4. LNG train size

8. Integrated chain presence

9. Trading capability

10. Relevance of LNG to company

11. Quality of LNG disclosures

7. Plant operatorship

5. Brownfield expansion potential

2. Plant vintage

1. Liquefaction scale

BG

Gro

up

Exxo

nM

ob

il

RD

Sh

ell

Rep

so

l Y

PF

TO

TA

L

Wo

od

sid

e

BP

EN

I

29 32 26 x21 17 33 16OVERALL SCORE (Max 44)

Sta

toil

15

Ch

evro

n

31

6. Greenfield growth potential

San

tos

x

4th 2nd 5th= 5th=8th 9th 1st 10thOVERALL RANK (1-11) 11th3rd 7th

23 26

60



Alternative strategies to play LNG theme

With the backdrop of our positive secular demand growth (as expressed in our bias to believe our BULL supply / demand scenario, as opposed to our BEAR scenario) and pricing outlook on LNG, there are many ways for stock market investors to take exposure to the global LNG market. Investors are not limited to an exposure to the equity owners of LNG export infrastructure. Investors can therefore choose where to play the economic value concentration – upstream via project commercialization and subsequent LNG linked price realizations, downstream on the LNG chain or across the entire LNG value chain. As per Figure 36, we highlight four broad alternative investment categories, as clarified below.

1) ADVANTAGED PROJECT PORTFOLIO OWNERS - Focus on equity owners of LNG export projects.

This is perhaps the most conventional route for LNG market exposure. The only problem with the majority of this specific set of companies is that LNG (earnings, project development news) is only a modest share price driver. Of the companies that we cite, we believe that the most leveraged to LNG are BG Group, RD Shell and Santos. TOTAL also has an above average exposure to LNG, although we are concerned that the news flow relating to its LNG development projects (GLNG –Australia, Ichthys LNG – Indonesia, Shtokman LNG and Yamal LNG – Russia) may be challenging.

2) NICHE PROJECT EXPOSURE – Invest in smaller names with a niche exposure to LNG project commercialization.

Within this category, we highlight three names: (i) Inpex – this company has a 74.8% exposure to the Ichthys LNG project (Australia) and a 60% exposure to the Abadi Floating LNG project (Indonesia) (ii) Ophir Energy – an early stage exploration company with exposure to two potential LNG projects, one in Tanzania (Greenfield) and the second in Equatorial Guinea (brown-field) (iii) Cove Energy—another relatively early stage exploration company which an 8.5% working interest in the prolific Offshore Area 1 (Rovuma Basin), Mozambique. According to Anadarko, the operator of the block, discoveries thereon have already proved up over 10 TCF of prospective resources which is enough to support a two train LNG project.We very much doubt that the two smaller names (Ophir Energy and Cove Energy) will participate in their respective LNG developments. More likely, in our view, is that both companies will monetize their stakes or be taken over. Indeed, we note that the board of Cove Energy has recently put the company up for sale (5 January 2012 –Company Formal Sale Process).

3) OILFIELD SERVICE & EQUIPMENT PROVIDERS – Invest in the companies that help to design and build LNG export and import infrastructure.

This strategy mirrors the one that we have recommended to play the build out in global refining capacity. In the case of LNG, there is actually far greater choice given a larger population of players with a more diversified set of segment exposures. As per Figure 36, we cite fifteen listed names (5 in each region) that have a material top line and profit exposure to the LNG construction wave. As we have already highlighted, over the seven year period 2012-18, there may be over 40 LNG export projects built. The aggregate new capacity totals 287 MT pa which is more than the

Four broad ways to play the positive LNG theme

Invest in large cap, LNG project portfolio owners

Invest in smaller cap names exposed to niche project

developments

Invest in the capacity enablers

61



global operational capacity at end 2010. If we simply assume an average EPC cost of $3,000-$3,500 per ton, this may require capital investment between $850billion and $1 trillion. In addition, as many as 80 new re-gasification terminals will be built. Given an average cost of $750m, this may require another $60bn of capital investment. So, LNG is a key driver of the industry's capital expenditure cycle that most equipment and service providers depend on. In Table 9, we list some of the key service names with a meaningful exposure to LNG capital investment.

Table 9: LNG value chain service & equipment providers

Facility layout & design Engineering

ProjectManagement Liquefaction Procurement & Construction

Facility start up

Import pipelines Support services

Amec Bechtel BechtelAir Products & Chemicals Bechtel Clough Allseas

Cape (access, insulation)

Chiyoda CB&I CB&IChart Industries (cooling stacks)

CB&I (+ civil engineering, processing plants) Foster Wheeler Saipem

Kentz (electrical, hook-up)

Clough Chiyoda Chiyoda LindeClough (+ civils, import structures)

Technip (Global Industries)

Foster Wheeler Clough JGC Chiyoda

KBRFoster Wheeler KBR Daewoo (modules)

Maire Technimont JGC Kellog Samsung (modules)

Saipem KBRFoster Wheeler GE (turbines)

Technip Kellog Saipem FluorWorley Parsons Technip Technip Foster Wheeler

Worley Parsons

Worley Parsons Hyundai (modules)

KBR (+ Storage, civils, marine facilities)Leighton Worley Parsons (+ storage and loading)Saipem (+ import terminals)Siemens (turbines, compressors)Technip (+ import terminals, marine transfer)


4) LNG SHIPPING – We sub-divide this category in to the LNG ship owners and the LNG ship builders.

We estimate that the global LNG fleet is currently around 360 vessels. Some of the world’s largest LNG ship owners are private companies and thus out of conventional institutional reach. However, there are a few relatively small listed entities that own LNG ships. We name five in Europe – Awilco LNG, Exmar NV, Golar LNG, Hoegh LNG and Wartsila OYJ (propulsion conversions). These names are a good way to play very robust and rising charter rates as the volume of traffic increases and the average distance rises between LNG sources and LNG demand centers. We expect LNG vessel day rates to remain firm through 2012 and in to 2013 (see Appendix IV). In addition, we name five listed Asian ship builders that are directly involved in the construction of new LNG vessels with yards in either South Korea or Singapore. The conditions and outlook for LNG shippers is a complete contrast to the situation facing oil tanker owners where freight rates have fallen below vessel operating costs. In mid-November, General Maritime (USA) filed for Chapter 11 bankruptcy protection, Frontline (Norway) announced a financial restructuring and Torm (Denmark) increased the size of its rights issue from $100m to $300m.

Invest in the ‘floating pipeline’ owners and builders

62



Figure 36: Different ways to play the global LNG market via listed equities


EuropeCape [CIU LN]Linde [LIN GR]Saipem [SPM IM]SBM Offshore [SBMO NA]Technip SA [TEC FP]

NICHE PROJECT EXPOSUREEuropeCove Energy [COV LN]Flex LNG [FLNG NO]Ophir Energy [OPHR LN]North AmericaCheniereEnergy [LNG US]InterOil [IOC US]LNG Energy [LNG CN]AsiaEnergy World Corp [EWC AU]Inpex [1605 JP]Liquefied Natural Gas Ltd [LNG AU]Medco Energi Internasional [MEDC IJ]Noble Group [NOBL SP]Oil Search [OSH AU]PetronetLNG [PLNG IN]

(2) NICHE PROJECT Strategy

(3) INDIRECT PLAY Strategy

SHIP / FSRU OWNERS / CONVERTERSEuropeAwilco LNG [ALNG NO]Exmar NV [EXM BB]Golar LNG [GOL NO]Hoegh LNG [HLNG NO]Wartsila OYJ [WRT1V FH]Asia

STX Pan Ocean [028670 KS]

(4) INIDRECT PLAYStrategy

(1) REGIONAL WINNERS Strategy

ADVANTAGED INTEGRATED PLAYERSUSAChevron [CVX US]Exxon Mobil [XOM US]EuropeBG Group [BG/ LN]RD Shell [RDSB LN]TOTAL [FP FP]AsiaSantos [STO AU]Woodside Petroleum [WPL AU]

AsiaChiyoda Corp [6366 JP]Daelim Industrial Co. Ltd [000210 KS]GS E&C [006360 KS]JGC Corp [1963 JT]Worley Parsons Ltd [WOR AU]

EPC PROVIDERSNorth AmericaChicago Bridge & Iron [CBI US]FMC Technologies [FTI US]Fluor Corp [FLR US]Foster Wheeler [FWLT US]KBR [KBR US]

SHIP BUILDERSAsiaDaewoo Shipbuilding & Marine [042660 KS]Hyundai Heavy Industries [009540 KS]Samsung Heavy Industries [010140 KS]Sembcorp Marine [SMM SP]STX Offshore & Shipbuilding [067250 KS]

GLOBAL INVESTMENT THEME LNG demand growth

63



Company Profiles

Co

mp

an

y P

rofi

les

64



BG Group

Figure 37: BG Group - Location of LNG assets

Source: J.P. Morgan. * BG Group owns 40% of GLNQ which owns and operates the 2.5 MT pa LNG import terminal in Quintero Bay, Chile – it has a 21-year supply commitment of 1.7 MT pa to its

three partners (ENAP, ENDESA and Metrogas S.A.). ** Effective average interest in Atlantic LNG Trains 1-4. *** Effective average interest in ELNG Trains 1-2.

LNG strategy assessment

Notwithstanding BG Group’s prolific success in the oil biased pre-salt play , offshore Brazil, finding gas and creating gas value chains remain at the very heart of BG Group's very successful strategy (Figure 38).

BG Group's strategy is thus differentiated from the oil majors - it has a focus on both ends of the gas value chain and positions itself on the most desirable links. This has run as far downstream so as to include helping to develop a country's downstream market for gas e.g. in Brazil (ComGAS, Sao Paolo) and India (Gujarat and Mahanagar gas supply franchises). BG Group has long had a distinctive production bias to gas (Figure 51). This has led to an upstream portfolio with below average unit costs, but below average unit realizations. So, connecting low cost gas to high value markets has been and remains at the epicenter of BG Group’s strategy. Via LNG, BG Group connects multiple markets (demand centers) to upstream gas resources and multiple sources of gas to markets.

Operational Liquefaction capacity (MT pa)

Liquefaction capacity under development (MT pa)

Operational Re-gasif ication capacity (MT pa)

Re-gasif ication capacity under development (MT pa)

15.1

8.5

(Trinidad & Tobago, 29.9% **)

7.2

17.3

4.4

6.0(Brindisi LNG, Italy, 80%)

(Dragon LNG, UK, 50%)

(Lake Charles, 100%)

(Egypt, 36.75% ***)

(QC LNG, 93.8%)2.5

(Quintero LNG, Chile, 0%) *

4.2

(Elba Island, 100%)

6.0

(Jurong Island, 0%)

Fred Lucas

(44-20) 7155 6131

[email protected]

Integrated gas chains at the

heart of BG Group's strategy….this is differentiated

to other IOCs

65



Figure 38: BG Group's strategy – distinctive, but non-exclusive focus on gas


If we exclude the experience of legacy British Gas which actually imported the first cargo of LNG in to the UK from Algeria in 1964 (the British Gas Council – see Appendix VI), BG Group was actually a relatively late arrival to the LNG industry, participating in the construction of its first LNG project (Atlantic LNG) in the mid-1990s. Hitherto, its gas exposure had been focused on upstream assets and piped gas. Fortunately, the period of its entry coincided with the bottom of the liquefaction cost curve. Indeed, BG Group's plants in Trinidad & Tobago (Atlantic LNG) and Egypt (Egypt LNG) registered the lowest unit capital costs of any liquefaction facility(Figure 39).

Figure 39: Liquefaction projects - unit capital costs ($ per Ton)


Figure 40: Pace of LNG project commercialization (Years)


BG Group has also proven itself able to commercialize LNG projects faster than any other rival (Figure x). For example, QC LNG remains on track for first LNG within six years of BG Group's first move in to Australian coal bed methane in 2008 via an alliance with Queensland Gas Company (QGC). Given the typical long lead times for LNG projects, shortening (elongating) lead times really unlocks (erodes) project value. Its ability to compress LNG project cycle times has been helped by its ability to contract for off-take itself (so reducing often lengthy marketing timelines), as well as careful choice of service contractors.

Connect gas to high-value markets

• Build & access markets• Serve customers

Secure competitively priced resources

• Equity reserves• Contracted resources

Global Gas Major

Skills to succeed across the gas chain

0

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PRODUCING

UNDER DEVELOPMENT

FID PENDING

BG projects

0

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Egypt LNG Atlantic LNG QC LNG RasGas Qatargas Nigeria

LNG project to EPC contract EPC award to f irst LNG

BG Group has proven itself to be

the strategic innovator in global LNG….

Relatively late arrival to LNG, but moved aggressively and

efficiently

66



As with many things that it does, BG Group moved both decisively and very aggressively in to the LNG business, seeing its presence and capabilities therein as a plank of its global integrated gas strategy. Martin Houston spear-headed this particular growth axis within BG Group soon after it was separated from legacy British gas. He was recently appointed COO and is widely regarded by investors to be a leading contender to be BG Group’s next CEO in 2013 when the incumbent, Sir Frank Chapman, has indicated he intends to retire from the board.

Understanding the dynamic nature of gas value chains, BG Group went on to very purposefully establish an exposure to every part of the LNG value chain – starting with low cost upstream gas supplies, multiple LNG liquefaction facilities (owned), multiple LNG import terminals (leased), LNG ships (owned and chartered)and long / short term supply and off-take contracts (Figure 41).

Figure 41: BG Group - capturing value along the entire LNG value chain


Gas market foresight led BG Group to make some well timed contractual innovations which leveraged what is otherwise a relatively low return business. The LNG industry had a well established modus operandi – in effect, a rule book as to how upstream producers and liquefaction owners were supposed to contract off-take. In many respects, the LNG industry was trapped by historic convention and conservatism - it was ripe for some innovative thinking. BG Group didn’t tear up this rule book, but rather using its experience in gas marketing it inserted a ‘few new pages’. Indeed, BG Group has driven industry change in the LNG world and must be regarded as a strategic innovator in what was relatively static industry. In our view, BG Group may be fairly described as the ‘Agent Provocateur’ of the LNG business.

Strategic firsts

Specifically, BG Group innovated in the following commercial areas:

1. First to secure large and long term secure access to US import capacity - This move was originally intended to secure access for LNG exports from other countries to reach the US market, the world’s deepest and most liquid gas market, and thus secure then high US gas prices (when Henry Hub spot gas was $8+ per mmbtu). However, as the US gas price weakened, those same import rights gave BG Group assured market access for its contracted supplies which it could then divert to higher priced markets. So, BG Group used its re-gasification capacity rights as secure market access to anchor flexible destination third party supply contracts.

LNG VALUE PROPOSITIONPRODUCTION LIQUEFACTION SHIPPING REGASIFICATION MARKETS

Swap & Arbitrage

Portfolio Optimisation & Leverage

Midstream marginLow Cost Supply

Downstream Margins

BG Group did not follow the

entire LNG ‘rule book’…it

appended some new rules

BG Group’s many firsts…

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2. First to purchase large volumes of LNG with diversionary rights – The LNG industry was set up under a simple commercial model which was invariant for decades - fixed destination contracts. The seller of LNG was obliged (by contract) to supply that cargo to a pre-agreed import terminal over 20+ years. Dedicated LNG vessels ran these so-called ‘milk runs’ with no ability to divert. Changes in either price or volumes were restricted and limited to informalnegotiation between buyer and seller. Asian buyers of LNG prized the certainty of price and volume provided by these long term contracts. In many respects, BG Group used its experience of gas marketing (Figure 42) to pioneer the concept whereby the buyer of LNG negotiated the right to divert LNG cargoes to multiple markets at its discretion – converting the historic concept of batch LNG supplies to something much more valuable. This choice allowed BG Group to divert cargo flows to the highest priced markets around the world. BG Group negotiated different price upside rent sharing agreements with each supplier. BG Group used its insights in to gas markets and its US re-gasification capacity rights (that ensured access to a deep market to place the LNG if it had to) to procure large volumes of LNG which it could then divert to the highest margin markets. Most of its competitors (owners of upstream resource and liquefaction capacity) continued to look to monetize their upstream resources via third party buyers under fixed destination contracts.

Figure 42: LNG supply and portfolio optimization


3. First to invoke the concept of ‘portfolio supply’ – BG Group also pioneered the concept of a portfolio sales agreement wherein a buyer agreed to purchase a defined volume of LNG over a defined period – as per a conventional LNG sales and purchase contract. The key difference is that BG Group committed to supply the LNG volumes from its portfolio of supply sources rather than a specific facility or contract (see Table 11 – contracts with GSPC of India and Tokyo Gas). This enabled BG Group to retain overall supply flexibility and thus optimize its portfolio’s diversionary capabilities.

4. First to use coal bed methane as a source for an LNG export project – BG Group was the first of many non-Australian companies to move to aggregate upstream real estate rights in Australia – specifically with coal bend methane to LNG supply potential. Although its somewhat ambitious attempt to acquire Origin Energy failed, it successfully acquired two other listed companies - QGC and Pure Energy. Of the four best defined projects that will liquefy and export gas from coal seams, BG Group’s QC LNG project is now clearly in front of queue. Three competing projects in Queensland that are led by Santos,

Marketing- Term sales- Customer interface- Projects- Business development

Logistics- Gas scheduling- Volume balancing- Transportation mgt- Deal capture

Optimisation- Daily sales- Customer fulfillment- Market/volume risk mgt- Location/time arbitrage

EVOLVING THE CONCEPT OF LNG (GAS) MARKETING

…first to recognize the value of

supply flexibility…

….and the value of a portfolio of

supply points

Likely to be first to supply and

convert non-conventional gas to

LNG

68



ConocoPhillips and RD Shell follow in its wake. We believe that being first will give BG Group a cost and execution advantage over competing projects, although we expect all projects to run over budget (not least due to AUD/USD appreciation) and behind schedule (as most LNG projects do).

5. First to sign a long term purchase contract for LNG exports from the East Coast of the USA – BG Group recently signed a 20 year supply agreement with Cheniere Energy Partners, L.P. (Cheniere) for 3.5 MT pa from the Sabine Pass facility in western Cameron Parish, Louisiana. BG Group will pay Cheniere a fixed take-or-pay fee of $2.25 per mmbtu to cover procurement, liquefaction and loading costs in Year 1. Thereafter 15% of this fee ($0.34 per mmbtu) escalates with inflation. A second flexible component will see BG Group pay 115% of the Henry Hub price. BG Group is responsible for shipping costs (spot rates currently around $1 per mmbtu to Europe and $3 per mmbtu to Asia although BG Group will have its own shipping capacity at below current spot rates) to source volumes from the US pipeline system. This gives BG Group another low cost source of LNG which is not yet dedicated to any particular market without exposing itself to the capital requirements of a liquefaction facility. As below, we note that Cheniere has since entered in to two further sale and purchase agreements. Sabine Liquefaction is developing a liquefaction project at the Sabine Pass LNG terminal that would include up to four liquefaction trains capable of producing 18 MT pa - it is targeting selling c.14 MT pa of the capacity under long-term SPAs.

a. Gas Natural Aprovisionamientos, a subsidiary of Gas Natural Fenosa(GNF). Under the agreement, Gas Natural Fenosa (GNF) will purchase close to 500 MMcf/d of LNG from the Sabine Pass liquefaction facility for a period of 20 years, with an extension available for another 10 years. GNF will pay a take-or-pay tolling fee of $2.48 per mmbtu and the same flexible component as BG Group (115% Henry Hub).

b. GAIL (India) Limited, a subsidiary of the Gas Authority of India. GAIL has agreed to purchase c.3.5 MT pa of LNG from train four. The SPA has a term of twenty years and an extension option up to ten years. Prior to the commencement of T4 operations (expected 2017), GAIL will purchase bridge volumes of 0.2 MT pa upon the commencement of T2 (expected 2016). GAIL will purchase LNG on an FOB basis for a purchase price indexed to the monthly Henry Hub price plus a fixed component of $3.00 per mmbtu. This is 33% higher than BG Group’s equivalent deal which clearly benefited, once again, from its ‘first mover’ status.

Sabine Liquefaction is advancing towards making a final investment decision for the construction of first two trains (Phase 1). This means that 78% (7 MT pa) of the 9 MT pa capacity of Phase 1 has been contracted. Cheniere was granted an export license from the US DOE on 20 May 2011 for up to 15 MT pa without constraints on where the LNG is exported to.

Strategic errors

However, BG Group’s pioneering and aggressive growth strategy in LNG has also included some strategic errors, as we highlight below. Fortunately, none have had very severe consequences for the profitability of its LNG franchise or the group. Furthermore, we believe that the risks that BG Group ultimately assumed were well worth taking, even with hindsight.

Rapid innovation also surfaced a

number of strategic errors

69



Entry to Asia Pacific LNG market could have been much sooner – Although BG Group attempted to enter Asia Pacific based LNG projects e.g. PNG LNG, it failed do so and thus failed to establish a resource / liquefaction presence in Asia Pacific. Instead, it focused on what it believed would be a higher growth LNG demand opportunity in the Atlantic Basin. In 2003 (BG’s LNG Business – 13 November 2003), BG Group’s management described Asia Pacific as a ‘mature region with a supply over-hang’ – it expected Atlantic Basin LNG demand to triple by 2010 causing market tightness and real price tension. Reflecting this view, BG Group actually sold out its position in Tangguh LNG, Indonesia and promoted such projects as Pacific LNG to take gas from Bolivia through to an export terminal in Chile (which now imports LNG) and OK LNG (in September 2006, management indicated an FID for this four train 22 MT pa Nigerian green field project would occur in early 2007). As the LNG demand growth outlook in the Atlantic Basin slowed, primarily as a result of the advent of US gas shale which reduced that country’s need for LNG (see below) and as China entered the Asia Pacific demand picture, this strategy looked increasingly 'second best' to one that positioned BG Group on the ground in Asia Pacific. BG Group’s LNG pricing thesis in the last decade was that Henry Hub would over-take oil price indexation in Asia – it believed that Asia would cease to be the premium market for LNG and Henry Hub pricing would actually exceed oil indexed pricing. This bold LNG price outlook has essentially done a ‘back-flip’ with BG Group now very keen to see its equity LNG off-take sold on an oil price link. To be fair, we must acknowledge that BG Group effectively 'globalized' its LNG business without investing in several capital intensive liquefaction centers via multiple customers and supply propositions. By 2011, it had sold to 22 of 23 LNG importing countries and purchased cargoes from 12 of 18 LNG exporting countries.

US re-gasification capacity rights could have been much smaller, it joined (if not led) the industry ‘gold rush’ - BG Group’s decision to take on very significant US re-gasification capacity was based on a view that the US would have a rising need for imported LNG – this proved totally incorrect following the surge in US gas shale production. In 2003, management showed US LNG demand forecasts ranging from over 40 to over 60 MT by 2010. In 2010, the US actually imported less than 9 MT of LNG. This has seen BG Group’s leased capacity rights largely unused in 2011. Figure 45 shows the diminishing number of cargoes that BG Group has sold in to the US market as the US gas price has weakened. Fortunately, the fixed cost lease payments which BG Group must make to keep these facilities largely idle are small. We acknowledge, however, that secure access to the deep US gas market via these import terminals enabled BG Group to develop a very flexible portfolio which, in turn, has generated very strong earnings through cargo diversions.

Italian re-gasification project has stalled – BG Group initiated a new re-gasification terminal in Italy (the country’s first since 1971), with a view to import third party LNG from Damietta LNG in Egypt and to divert cargoes from Egypt LNG Train 2 directly to the Italian market. At the time, this was seen as a potentially attractive arbitrage play with the US market. In November 2003, BG Group management indicated that its Brindisi re-gasification terminal would be operational by mid-2007 with a capacity of 6 MT pa (BG Group to have 80% of the terminal’s capacity while the remainder will be subject to regulated third party access). In September 2006, BG pushed the start date back to 2009.

Strategic focus on Atlantic Basin

rather than Asia Pacific was a

mistake

Over-exposed to US re-

gasification capacity which is now largely redundant

Italian re-gas project has been

delayed 7-8 years

70



However, construction activities have been suspended since February 2007. The timing of first deliveries to the Brindisi terminal is dependent on how soon access to the site can be restored and resolution of the various outstanding legal matters.We note that the full Environmental Impact Assessment (EIA) which was completed in 2003 is still valid.

Like many others, BG Group was also late to spot the US gas shale opportunity - BG Group missed the US gas shale opportunity (as did almost every other non-US independent) and thus arrived late to the play via a joint venture with EXCO Resources in 2009, albeit as did most of its competitors. Although it was one of the first large players to move in to the Australian coal seam gas to LNG opportunity, arguably it could have done so sooner with an increased organic bias. Moving when it did necessitated acquisitions to ‘muscle’ in to the play – an earlier organic build up might have been done at lower cost.That said, the companies and assets that BG Group purchased have seen total 3P resources rise from c.5 TCF to over 20 TCF, so its acquired resources have since grown very materially.

Locked in LNG sales volumes and prices in 2009 for 2010-12 - In order to protect a very important earning stream and to reassure the market about its sustainability in what (pre-Fukushima) looked like a potentially over-supplied LNG market when viewed back in 2009, BG Group locked in 80% of its LNG off-take at fixed or ‘semi-fixed’ prices 2010-12. It thus left only 20% of its volumes with source, destination and pricing flexibility. Sales volumes were thus left substantially un-hedged in 2013 onwards based on their assessment that the market would tighten in 2013. Global demand strengthened dramatically during 2010 as the global economy recovered, rising by 23%. Fukushima then triggered a further acceleration in global demand growth in 2011 - we estimate to over 15%. So, management reduced its portfolio flexibility just when its value could have been maximized following the market dislocation caused by Fukushima. We must acknowledge, however, that BG Group has raised its 2011 LNG segment EBIT guidance three times (i) from $1.8bn to $2.0bn to $1.9bn to $2.2bn (ii) from the latter to ‘the high end of the range of $1.9bn to $2.2bn’ (iii) from the latter to $2.4bn with its Q3 2011 results (announced 25 October 2011). We note that the EBIT upgrade from $1.9bn (mid-point of first guidance range) to $2.4bn is $0.5bn. If this increase is exclusively tied to superior margins on the 20% floating component of its portfolio only, this might imply that un-hedged, EBIT guidance could have reached over $4bn. As such, we believe that BG Group has given up very meaningful upside by its prior period hedging strategy – this is apparent from Figure 46 which shows a notable decline in estimated EBIT per LNG cargo in 2010-11. With hindsight, management should have retained greater flexibility in order to exploit market dislocations. Fortunately, the hedging levels reduce in 2012 and, according to management BG Group will be substantially un-hedged in 2013. We expect BG Group management to refresh its LNG EBIT guidance for 2012 and 2013 at its Annual Strategy Update on 7 February 2012.

Late to US gas shale party….as

were most other non-US

companies

Strategy always recognized

potential for market dislocations, yet locked in high percentage of

prices and volumes to certain

buyers 2010-12

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Liquefaction assets

As per Table 10, BG Group has interests in six operational LNG trains - four in Trinidad & Tobago (Atlantic LNG) and two in Egypt (Egypt LNG) with a total net capacity at end 2010 of 7.18 MT pa. This capacity is split 63% Atlantic Basin and 37% North Africa. The average capacity of BG Group’s six operational trains is 3.7 MT pa. All of BG Group’s liquefaction trains have operated very safely and reliably since their commissioning.

Realistically, given robust government gas depletion controls and the prioritization of domestic gas uses (power, fertilizers and residential), we believe that it is presently unlikely that either Atlantic LNG or Egypt LNG will be able to add a fifth / third train respectively. We note that BG Group was discussing the concept of a fifth train (third train) with the government of Trinidad (Egypt) back in 2002. BG Group has contracted gas that could either be used to support a fifth train or backfill existing trains in Trinidad. However, it needs to discover more gas in Egypt to warrant a third train. So, BG Group’s existing portfolio of liquefaction assets bears limited expansion options.

With the exception of BG Group’s first train (Train 1, Atlantic LNG) which operates as a merchant facility (i.e. it buys gas which BG Group does not produce and sells the LNG directly), BG Group supplies equity upstream gas to all of its liquefaction trains which act as tolling facilities. Also, with the exception of Train 1, Atlantic LNG, all of BG Group’s LNG train interests operate under a tolling model i.e. charge the users a liquefaction tolling fee. This secures the invested capital therein with a reasonable rate of return.

Table 10: Liquefaction interests

PlantStart date

Gas Supply

mmcfpdBG Group

equity supplyCapacity

MT paBG Group

equity %

Net capacity

MT pa Plant type Off-take agreementsTrinidad & TobagoTrain 1 1999 520 No 3.1 26.0 0.8 Merchant GdF Suez 60%, Gas Natural 40%Train 2 2002 560 Yes 3.4 32.5 1.1 Tolling BG Group 50%, BP 50%Train 3 2003 560 Yes 3.4 32.5 1.1 Tolling BG Group 25%, BP 75%Train 4 2005 800 Yes 5.2 28.9 1.5 Tolling BG Group 28.89%, Others train

4.5 partners 71.11%EgyptTrain 1 2005 565 Yes (50%) 3.6 35.5 1.3 Tolling GDF Suez (100%)Train 2 2005 565 Yes (50%) 3.6 38.0 1.4 Tolling BG Group (100%)

2.6Total operational capacity 7.2Firm development projectsAustraliaQC LNGTrain 1 2014 700 Yes (95%) 4.25 90.0 3.8 Tolling Qunitero LNG, Singapore LNGTrain 2 2015 700 Yes (98.75%) 4.25 97.5 4.1 Tolling Tokyo Gas, CNOOC for both trainsTotal development capacity 7.9Source: J.P. Morgan.

Ideally, BG Group would have added additional green field capacity sooner (in order to optimize contractor engagement and deployment of in-house project capabilities), but its participation in potential projects was either cancelled e.g. Bolivia (Pacific LNG) and Iran (Pars LNG) or experienced open-ended delays e.g. Olakola LNG (Nigeria). BG Group thus turned its strategic focus to coal seam gas in Australia given clearer political support and an ‘easier’ business environment. Via a series of corporate acquisitions (QGC and Pure Energy, both in 2009) and subsequent asset acquisitions, BG Group took the leading position in the world’s emerging hub for coal seam gas to LNG projects in Queensland.

Legacy operating assets were

built at very low cost at the

bottom of the liquefaction EPC cost curve

No real expansion options given

government policies in Egypt

and Trinidad

Conventional projects delayed,

BG Group turned its strategic focus to coal bed methane in

Australia

72



BG Group now has two trains under construction in Queensland, Australia (QC LNG), with the first of these due to be commissioned in 2014 and the second in 2015. These two trains will raise the average capacity of its suite of trains from 3.7 to 3.9 MT pa and will be BG Group’s 7th and 8th trains in just 12 years. Notwithstanding flooding in Queensland, which disrupted BG Group’s land drilling campaign, BG Group remains confident that Train 1 will be commissioned in 2014. For now, this remains credible – we note BG Group’s differentiated track record of LNG project delivery. QC LNG is a great opportunity for BG Group to demonstrate that its track record reflected its core competencies rather than a benefit of the easier construction cycle / easier project types.

A third train at QC LNG in Australia is also looking very likely, in our view, given the scale of estimated resources (last estimated by BG Group to be 3P resources of 21 TCF – February 2011) and the progress that BG Group is making contracting the off-take from a third train. BG Group would like to sanction a third train within 18-months of taking FID on the project’s first phase. The CEO has indicated that a third train is unlikely to be sanctioned before H2 2012, but the ideal time is before the end of Q3 2012 to maximize project efficiency. We note that the site in Queensland has space for up to 5 trains with a total capacity of 20 MT pa. In order to sanction a third or fourth train, BG Group must convert more of its equity owned 3P resource to 2P and 1P. Alternatively, if not in addition, there is potential for acreage swaps with other companies and supply collaboration given other companies may have incentive to supply sooner to a third party export project. Indeed, BG Group (Walloons CSG) recently agreed such a gas supply agreement with Toyota Tsushu Corporation to take gas from ATP 651P for twenty years.

So, in addition to the 7.97 MT pa under development, we also see potential for a third 4.25 MT pa train with BG Group owning 100%, which could be operational by 2016-7. QC LNG will be BG Group’s first liquefaction position in Asia Pacific and to be located in an OECD country. It also looks very likely to be the world’s first liquefaction plant to be supplied from non-conventional coal seam gas (CSG); at least three other competing CSG to LNG projects will follow it.

Subject to the outcome of its multi-well offshore drilling program (first well spud late December 2011 with results likely in Q1 2012), BG Group may also ultimately lead a green field LNG project in Tanzania. This could see BG Group’s net liquefaction capacity exceed 20 MT pa by 2018. The average (gross) size of BG Group’s operational liquefaction trains is 3.7 MT pa. If we include three trains at QC LNG (each 4.25 MT pa) and one train at Tanzania LNG (6.6 MT pa), its average train size increases to 4.2 MT pa.

For now, at least, a 3 MT pa floating LNG solution in the Santos Basin (Brazil) looks unlikely in the near term with the gas more likely destined for the domestic market via pipeline. BG Group has indicated that the FLNG will be held in reserve as an additional flexibility to be deployed later. We believe that Petrobras must first define a master plan for Brazilian gas supplies which more clearly defines the role of domestic supplies and piped/LNG imports. This, in turn, will define the scope for regular LNG exports via an FLNG scheme in the Santos Basin.

BG Group is pursuing one further potential liquefaction project. In July 2011, BG Group and Southern Union received US DoE approval to export up to 15 MT pa over a 25-year period to countries that have free trade agreements with the USA. Central to BG Group’s strategy is the ability to source low cost gas (ideally at a small premium to Henry Hub) and sell it as LNG in Asia Pacific on an oil price index.

Front of project queue in CSG to

LNG, Queensland

Train 3 QC LNG continues to

look very likely

Tanzania could be its next green field project

Santos FLNG looking less likely

One more option for US LNG exports

73



Finally, we note that BG Group retains title (90% to be reduced to 60% if the Consolidated Contractors Company and the Palestine Investment Fund exercise their participation options at development sanction) to, and is operator of, the offshore Gaza Marine license. Two discoveries were made in 2000 (Gaza Marine-1 and Gaza Marine-2) with contingent resources estimated to be 1 TCF. In 2007, BG Group ended gas sales negotiations with the Israeli government and, in 2008 it closed its office in Israel.

LNG supply sources & contractual commitments to supply

In essence, BG Group was the first company to recognize that a set of LNG purchase agreements and another set of LNG sales agreements created a portfolio optimization business opportunity with a very different set of value drivers to a conventional LNG business. The enabling hardware required (or firm access thereto) was low cost shipping capacity and low cost import capacity. The enabling ‘software’ was a very good understanding of the pricing dynamics in multiple markets and very strong relationships with many high quality downstream customers.

As per Table 11, BG Group has a diversified set of long term supply sources, some from third parties (i.e. sourced from projects in which BG Group does not participate) and others from BG Group equity LNG projects (e.g. in Egypt and Trinidad). Including the recently announced agreement to purchase 3.5 MT pa from Sabine Pass (USA) with Cheniere Energy and assuming that Nigeria LNG Train 7 is eventually sanctioned, the aggregate supply sources may reach 27 MT (24.7 MT pa excluding NLNG Train 7). In addition to these volumes, BG Group may pick up short-lived supplies in the market – it buys and sells spot LNG cargoes on an ad hoc basis. As such, BG Group’s LNG supplies are not overly dependent on the performance any specific asset / source.

Table 11: BG Group - sources of contracted LNG and contractual supply obligations

Long term sources of LNG supply (purchase contracts) Firm supply (MT pa) S&P agreement start up Years Shipping

BG in LNG export project

Atlantic LNG Trains 2-3 2.1 Q4 2005 20 FOB YesEgypt LNG Train 2 3.5 Q1 2006 20 FOB YesEquatorial Guinea 3.3 Q4 2006 17 FOB NoAtlantic LNG Train 4 1.5 Q2 2007 20 FOB YesNigeria LNG Trains 4-5 2.3 Q3 2007 20 CIF NoQueensland Curtis LNG Trains 1-2 8.5 2014 - - YesSabine Pass LNG * 3.5 TBC 20 TBC NoNigeria LNG Train 7 2.3 TBC 20 CIF No

27.0Long term LNG supply commitments (sales contracts) Supply (MT pa) Start up Years Source

BG in LNG import project

Quintero LNG, Chile * Up to 1.7 2009 21 QC LNG YesSingapore Up to 3.0 2013 20 LNG portfolio YesGSPC, India Up to 2.5 2014 20 LNG portfolio NoCNOOC, China 3.6 2014 20 QC LNG NoChubu Electric Power Inc. Up to 0.4 2014 21 LNG portfolio No

Tokyo Gas Co., Ltd 1.2 2015 20QC LNG + LNG

portfolio NoUp to 12.4

Source: J.P. Morgan. * BG Group’s supply contract in to Chile is on a US Henry Hub index (the higher of Henry Hub or Brent until end 2013 and then a pure Henry Hub link) which provides BG

Group with an internal hedge if the Henry Hub price rises very significantly thus raising the cost of its LNG via its supply deal with Cheniere (Sabine Pass). Their agreement includes an option to

extend by up to 10 years.

1 TCF offshore Gaza could feed

Noble’s LNG export scheme

BG saw the value in portfolio

optimization

BG Group remains long LNG

supplies

74



We have not included QC LNG Train 3 volumes (4.3 MT pa) which are currently being marketed, but may be purchased in part or outright by BG Group. According to BG Group’s management its firm supply volumes could reach 32 MT by 2017-18 and it sees a ‘blue sky’ upside supply scenario with over 50 MT pa of supplies by the end of this decade.

BG Group also has six contracts to supply LNG that total up to 12.4 MT pa – four of these are specifically sourced from QC LNG, the other two may be supplied from anywhere within BG Group’s supply portfolio. According to BG Group’s management (February 2011 Strategy Update), 75% of its LNG sales contracts will be oil priced linked by 2015 (70% of total sales will be oil / oil price indexed versus 50% in 2010).

As per Figure 49, BG Group’s LNG portfolio remains long supply sources versus contracted supply obligations. This excludes potential new sources of supply, e.g. from Tanzania LNG that could start up 2018-19.

BG Group was the first LNG player to recognize and exploit the value of supply flexibility. Its supply configuration leaves BG Group effectively ‘long LNG supplies’ that are not contracted to any specific destination. This is a key competitive advantage that leaves BG Group in a very strong position to continue to divert LNG cargoes to the highest priced markets given its ability to send cargoes to the US East Coast as the lowest priced market of last resort.

BG Group, in common with all of its competitors, does not disclose details on its supply agreements - either to buy or sell LNG. However, we understand that all of its sales contracts to third parties are set close to oil price parity, whilst its LNG purchase contracts (with itself and third parties) are set closer to parity with a Henry Hub gas price index.

LNG re-gasification capacity

As per Table x, BG Group has 21.5 MT pa of LNG re-gasification capacity on the East Coast of the USA via its capacity rights to the Lake Charles and Elba Island LNG import facilities. Access via both these terminals (neither owned by BG Group) is an absolutely vital piece of enabling infrastructure access that has allowed BG Group to take on long term LNG supply sources which has, in turn, left it very well positioned to exploit regional price arbitrage by re-directing cargoes to premium priced markets.

In 2008, the Energy Market Authority (EMA) of Singapore appointed BG Group as the aggregator of LNG demand for the Singapore market, hitherto a piped gas market only. BG Group is responsible for supplying up to 3 MT pa of LNG for up to 20 years with initial deliveries in 2013. As per Table 12, BG Group has agreed to supply up to 3 MT pa from its global portfolio of LNG sources. BG has also signed 15 gas sales contracts with various customers (primarily local utilities) in Singapore totaling 2.6 MT pa. BG Group will also look to aggregate and offer customers spot volumes.

Supply portfolio leaves ample

flexibility to reach highest priced

markets

75



Table 12: BG Group - re-gasification terminal capacity rights

Terminal Start dateRe-gasification capacity MT pa

BG Group capacity rights / equity %

Net Capacity MT pa Contract

Lake Charles, USA Phase 1 Jan 2004 13.4 100 13.4 LeasedPhase 2 July 2006 LeasedPhase 3 Mar 2010 3.9 100 3.9 Leased

Elba Island, USA * Jan 2004 - May 2007 4.2 100 4.2 LeasedDragon LNG, UK ** July 2009 4.4 50 2.2 OwnedQuintero LNG, Chile *** Jan 2011 2.5 0 0.0 Option to accessTotal operational capacity 23.7Expansions / developmentsBrindisi LNG, Italy TBC 6.0 80 4.8 OwnedJurong Island, Singapore 2013 6.0 0 0.0 Aggregator roleTotal new capacity 4.8

Source: J.P. Morgan. * Of which 1.2 MT pa may be supplied by Marathon. Capacity reflects facility’s second expansion. ** Petronas owns the other 50% *** BG Group currently holds no capacity in

the terminal but has the option to acquire capacity if needed to support BG Group’s downstream market development. It is committed to supply 1.7 MT pa to its three partners – ENAP, ENDESA

and Metrogas.

LNG shipping assets

BG Group has a long history in LNG shipping having been involved in the development of both the prototype and the world’s first working LNG carriers. Its shipping activities are today directed towards meeting the needs of the group’s LNG and crude oil trading. In essence, BG Group’s LNG shipping strategy is designed to optimize the trade-off between operational flexibility and the after-tax cost of supplying LNG.

BG Group originally built out its shipping capacity via chartering when the LNG shipping market was short. Such secure access to shipping capacity filled an important ‘infrastructure link’ that enabled BG Group to take on re-gasification capacity rights, to lock in long term supplies of LNG and to build a downstream customer base.

BG Group has a core fleet of 13 LNG vessels. It owns four of these ships and, via a sale and leaseback arrangement, charters the remaining nine vessels (two under time charter and seven under bare boat charter contracts). BG Group also has a number of smaller and slightly older LNG vessels (2005-10) which it charters. At any time, BG Group has firm access to around twenty vessels – four via direct ownership, nine under long term charter agreements and the balance via shorter term charter agreements subject to its needs and the market conditions. Management believes that as an LNG principle (i.e. a company with firm supply and off-take contracts), BG Group would have advantaged rights to yard capacity in Asia should it want to build more vessels.

The average size of its core fleet of thirteen boats is 152,170 cubic meters or around 108,000 DWT - this is 38% larger than the global average vessel size (estimated to be around 78,500 DWT). BG Group does not own any of the much larger Q-Max or Q-Flex vessels and, having taken delivery of four vessels in 2010 it does not have any vessels under construction although it is finalizing a JV structure with CNOOC for the design and construction of two LNG vessels.

LNG portfolio valuation

BG Group is one of the very few companies to present an LNG EBIT and associated operational and financial information. Indeed, BG Group discloses more on its LNG business than any other company that is featured in this note. So, we cannot criticize

Rights to shipping were a key enabling asset for BG’s LNG

strategy

BG Group has done 9 sale and leasebacks – it only owns four

vessels

Superior disclosure enables more rigorous analysis and

valuation

76



its disclosure policies as we do for some other companies – we can only commend BG Group for its disclosure leadership. Consequently, we are able to perform more meaningful analysis on BG Group’s LNG business compared to all other companies featured in this note.

BG Group is one of the few companies where it is possible (given differentiated disclosure policies on this business) and it makes sense to value its LNG business separately and, indeed, it is very important to do so, in our view. We can estimate a notional free cash flow from its LNG business (Table 13). However, we must make the following caveats about this analysis: (i) although we understand that LNG profits are channeled through relatively low tax rate jurisdictions, we do not know the effective tax rate on this stream (ii) we exclude working capital movements and interest payments (iii) actual cash flows from liquefaction projects are typically constrained until project finance debt has been repaid; until then there are dividend constraints (iv) BG Group does not give specific capital expenditure guidance for LNG – it only guides for group capital expenditure (Feb 2011 guided to $21bn in 2011-12 with $10bn in 2011 assuming reference conditions which include USD/£ 1.50 and USD/AUD 1.20). It does, however, report LNG capex when spent each quarter.

With these caveats, this analysis underlines that a business which has recently (2007 to 2010) generated positive free cash flow will (2011 to 2013) quite likely generatenegative free cash flow given BG Group’s move back in to more capital intensive liquefaction in Australia. This shift has knock-on consequences for BG Group's free cash flow, which we also expect to be negative 2011 to 2014 given heavy capex commitments elsewhere in its upstream portfolio (e.g. the Brazilian pre-salt). We forecast that BG Group's gearing ratio will rise (Q3 2011 27%), which we expect will peak in 2013-14 at around 35% (ND/ND+E). In order to safeguard its single-A credit rating – a stated priority of management - we expect BG Group will divest more non-strategic assets.

Table 13: BG Group - LNG segment notional free cash flow (£m)

£m 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011E 2012E 2013E 2014E 2015E

EBIT $m 42 12 126 182 329 643 1,047 2,983 2,405 2,449 2,460 2,674 3,342 3,830 4,974EBIT 29 8 77 99 181 352 521 1,585 1,551 1,583 1,525 1,743 2,178 2,496 3,242Tax rate 25% 25% 25% 25% 25% 25% 25% 25% 25% 25% 25% 25% 25% 30% 35%Notional Tax (7) (2) (19) (25) (45) (88) (130) (396) (388) (396) (381) (436) (545) (749) (973)Capex 104 117 301 417 422 496 194 273 653 1,200 1,518 2,000 2,000 1,750 1,750Depreciation 2 4 5 13 24 38 45 56 49 95 107 112 117 267 417Cash flow (80) (107) (238) (330) (262) (194) 242 972 559 83 (267) (581) (250) 264 936


We assign a relatively low value to BG Group’s liquefaction assets in Egypt and Trinidad which, as we have discussed, act as tolling plants (with the exception of Train 1, Atlantic LNG). It is not yet clear how much of the value of QC LNG will be concentrated within the LNG factory gate versus Upstream and/or in Shipping & Marketing. We have, somewhat arbitrarily, assigned 55% of our total value for QC LNG to the LNG segment. At some point, we expect BG Group to clarify how the rent from this project may be apportioned.

We assign a much higher value to BG Group’s Shipping & Marketing stream. In our view, this stream is enabled by a shipping fleet, re-gasification terminal access rights and an advantaged LNG trading function. Rather than value each of these

LNG negative free cash flow

2011 to 2015

Around $20bn, £13bn or 375 pence per share

77



components separately, it is easier (and arguably more sensible) to value the Shipping & Marketing stream as a whole, recognizing that these underlying tangible and intangible assets support it. However, putting a definitive value on a flexible set of supply agreements is difficult.

Table 14: Valuation of BG Group's LNG franchise

Infrastructure / capability

Net capacity

MT pa

Implied EV/EBITDA

2012E £mPence

per shareAtlantic LNG Trains I-IV 4.5 606 87Egyptian LNG Trains I-II 2.6 3.5 457 13Queensland Curtis LNG I-III 8.0 3,057 90Shipping & Marketing + enabling assets & capabilities * 6.0 9,831 288

15.1 7.5 13,951 409

Source: J.P. Morgan. * enabled by capacity rights at LNG import terminals, ships (owned and chartered) + long term supply and sales contracts

As per Table 14, we value BG Group’s LNG franchise at around £14bn or almost $21.4bn - this equates to around 409 pence per share, approximately 19% of our sum-of–the-parts of around £19.6 per share. This compares to cumulative sunk investment (un-depreciated) by end 2011 of around £5.7bn. According to the company (December 2011), the sell-side range for the value of this stream runs from 200 pence to 760 pence with a mean around 400 pence. However, as above, analyst estimates vary depending how much of QC LNG’s value is allocated to the upstream segment versus the LNG segment.

The stream represents around 33% of our group EBIT forecast for 2012. This segment valuation equates to a 2012E segment EV/EBITDA multiple of 7.5x which we feel is conservative given the (i) durability of the stream (ii) the very low risk nature of price arbitrage trading profits (iii) its high free cash conversion characteristic given low taxes (the profit is realized in low tax rate jurisdictions e.g. the UK) and low capital requirements (with the exception of QC LNG, much of the necessary infrastructure has already been either built or leased) (iv) 2012E EBITDA is still suppressed by some out-of-the-money fixed price hedges relative to spot pricing (v) such a distinctive array of assets, skills and customer relationships. If we assume a 25% segment tax rate, the implied 2012E PER is around 10x. Again, we feel that this is relatively low, but putting an accurate boundary around the profits and cash flows of BG Group’s LNG business is trickier given the ‘blurred’ value boundaries around QC LNG.

Clearly, the most valuable piece of the franchise is the capability to buy large volumes of reliable and low cost LNG (ideally priced off Henry Hub) and to sell it close to oil price parity. Figure 47 shows how BG Group's LNG realizations have achieved consistently large premiums over and above Henry Hub average quarterly prices. This profit is recorded in the LNG Shipping & Marketing sub-segment reported by BG Group. As above, it is enabled by BG Group’s contractual architecture, its shipping capacity and re-gasification access rights and a very experienced trading function. Our valuation of this arbitrage profit stream assumes a compression in the margin over Henry Hub past-2015 when we assume North American LNG exports will grow and thus reduce regional LNG price dispersion.

We value the LNG franchise at

£7.7bn or 225 pence per share

Value is dominated by portfolio

of low cost supply contracts

which can reach highest priced markets

78



Figure 43: Liquefaction capacity - net (MT pa)


Figure 44: Sources of LNG and LT supply commitments (MT pa)


Figure 45: LNG cargoes sold by quarter


Figure 46: EBIT per LNG cargo by quarter (estimated, £m)


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79



Figure 47: LNG price realization by quarter ($/mmbtu)


Figure 48: LNG EBIT composition by quarter (£m)


Figure 49: LNG portfolio balance


Figure 50: BG Group - SOTP and share price premium / (discount)


Figure 51: BG Group - oil versus gas production mix (%)


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2001 292002 82003 772004 992005 1812006 3522007 5212008 1,5852009 1,5512010 1,5832011e 1,515

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Oil Gas

80



BP

Figure 52: BP - Location of key LNG assets

Source: J.P. Morgan. * Effective average working interest in Atlantic LNG Trains 1-4. ** BP has certain rights to supply gas in to Damietta LNG, but does not have any ownership of the facility.


According to BP, the creation of gas value chains is one of the three core drivers of upstream growth:

1. Deep water

2. Giant fields

3. Gas value chains

BP has created some important, long-lived and high value gas value chains. Most recently as operator, BP has connected gas offshore Azerbaijan (Shah Deniz field) to downstream markets in Georgia, Turkey and eventually parts of Europe via the South Caucasus Pipeline (SCP). However, we feel that BP has somewhat neglected its LNG business and turned away from LNG related growth opportunities for too long. This occurred under the leadership of Sir John Browne who steered BP away from too many long lead, very capital projects, focusing more on higher return, quicker payback upstream projects, specifically oil related. Browne wanted to build one of the lowest cost and highest return upstream portfolios and LNG did not easily fit within that strategy. We are not critical of BP’s reluctance to invest in liquefaction, per say - that is a low return tolling business. Rather, we regard as a weakness BP’s inability to develop more, very profitable and long-lived integrated gas chains. As per Figure 53, RD Shell's first liquefaction position was operational five years before BP, but since the 1970s RD Shell has grown its LNG far more aggressively and now

15.1

(Atlantic LNG, Trinidad & Tobago, 39%*)

5.9

3.3(Isle of Grain, UK, 50%)

16.3

(NW Shelf, 16.7%)

7.1

(ADGAS, Abu Dhabi, 10%)

7.6(Tangguh LNG, Indonesia, 37.2%)

5.2

(Angola LNG, 13.6%)

7.46.7

(Rovigo, Italy, 13%)(Cove Point, USA, 33%)

(Dapeng, China, 30%)




5.1

(Damietta Train 1, 0% **)

Fred Lucas

(44-20) 7155 6131

[email protected]

BP has neglected LNG for too long and may have to play catch

up

81



sits with a much fuller LNG growth pipeline than BP. We feel that this is a portfolio issue that BP’s current CEO (Bob Dudley) may look to remedy through acquisitionor strategic alliance.

Figure 53: BP versus RD Shell - net liquefaction capacity (MT pa)


BP does not have a head of Global LNG - LNG projects are managed by the upstream performance units in which they reside. However, there is a head of BP’s LNG merchant trading business who sits within BP’s global trading operation.

We see the potential formation of two new gas (LNG) chains within BP’s grasp, one in India and another one in Indonesia.

India – Via its upstream / downstream alliance with Reliance Industries Limited, BP is looking beyond its recently acquired upstream position, anchored in the Krishna Godavari Basin, in to a full presence across the entire Indian gas value chain. Realistically, this is a long term opportunity, but one where we expect the alliance to move downstream in to LNG re-gasification / imports, potentially supplied by BP’s LNG portfolio. RIL already imports LNG cargoes via Petronet LNG and has been forced to import LNG via the Hazira terminal due to the unexpected decline in gas production from the KG-D6 gas complex. We note that BP and RIL have recently set up India Gas Solutions (IGS), a 50:50 JV to source gas globally, including LNG, and market it in India. We understand that OGS will be responsible for securing and marketing LNG to RIL’s existing customers, but RIL will continue to acquire LNG for its own requirements for the time being.

0

5

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72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15

BP RD Shell

Looking to form two new potential gas (LNG) chains

82



Indonesia – In the past two years, BP has been very obviously building its acreage position in Indonesia with a eye to supply gas to the Bontang LNG facility. On 30 November 2009, BP (via VICO, a 50:50 joint venture with ENI)signed a PSC to develop the Sanga-Sanga coal bed methane project in East Kalimantan. The PSC overlays the same acreage as the conventional PSC (BP 37.8%, ENI 37.8%) which supplies gas in to the Bontang LNG plant. Preliminary studies on the block suggest it has a CBM resource potential of 4 TCF (ENI now estimates 13 TCF). This ought to be a near term opportunity - given existing gas production infrastructure, development ought to be rapid. As such, BP may supply coal bed methane to an LNG plant before BG Group does so in Australia.In 2009, BP also acquired a 32% interest in the West Papua I and III PSCs from Chevron. In November 2010, BP was awarded 100% in the North Arafura PSD -seismic operations are to start in 2012. In April 2011, BP was awarded another four CBM PSCs in Central Kalimantan - the Tanjung IV PSC is operated by Pertamina with 56% and BP 44%. The Kapuas I, II and III PSCs are operated by BP with 45%; Sugico owns 55%. On 21 November 2011, BP was awarded 100% of two offshore PSCs, West Aru I and II, in the Arafura Sea, Indonesia.

As per Figure 54, it appears that BP has really only taken on a new LNG project once per decade since the 1970s. Actually, it is less than that since it acquired its LNG position in Trinidad via its merger with Amoco (1998) and its supply position toBontang LNG in Indonesia via its acquisition of ARCO (1999, VICO – 50%).

BP has only actively pursued one green field LNG project as operator in its entire 102 year history - Tangguh LNG (Indonesia). BP is a minority partner in Angola LNG which is due on stream in 2012 and is operated by Chevron. As we have mentioned, BP’s current management has a more pragmatic stance towards LNG and may look to raise BP’s exposure to LNG. We believe that the quality of BP's portfolio would be enhanced with the addition of one or two more long-lived legacy LNG assets.

Having pulled the plug on its $35bn Denali pipeline project with ConocoPhillips (to bring 4.5 bcfpd gas from the North Slope to Alberta – launched 2008) in 2011, we wait to see if BP and others can create an alternative LNG export scheme using the same source gas. In theory, gas (North Slope holds at least 35 TCF) could be piped 800 miles from the North Slope to a liquefaction plant at Valdez. Realistically, this would not be on stream much before 2020. Alternatively, a pipeline could be built to supply ConocoPhillips' Kenai LNG plant which is likely to be mothballed otherwise.

Tangguh is BP’s only operated

LNG project

Will Valdez LNG ever happen?

83



Liquefaction assets

As per Table 15, BP has interests in fourteen operational LNG trains - four in Trinidad & Tobago (Atlantic LNG, as per BG Group – operated by the JV), five in Australia (NW Shelf – operated by Woodside), three in Abu Dhabi (ADGAS – Das Island – operated by the JV) and two in Indonesia (Tangguh LNG, Bintuni Bay of Papua Barat – operated by BP) with a total net capacity at end 2010 of 12.2 MT pa. Of this, 5.5 MT pa (45%) is located in Asia Pacific with the balance in the Atlantic Basin (48%) and the Middle East (7%). So, BP only operates one facility - Tangguh LNG.

Table 15: BP - liquefaction interests

Plant Start dateNet gas supply

(mmcfpd)BP equity gas

supplyCapacity

MT paBP equity

%Net capacity

MT paPlant type Markets served

Trinidad & Tobago (Atlantic LNG)Train 1 1999 - Yes (34.0%) 3.1 34.0 1.1 Merchant US, SpainTrain 2 2002 - Yes (42.5%) 3.4 42.5 1.4 Tolling US, SpainTrain 3 2003 - Yes (42.5%) 3.4 42.5 1.4 Tolling US, SpainTrain 4 2006 - Yes (37.8%) 5.2 37.8 2.0 Tolling US, Dominican Republic

1,649 5.9Australia (NW Shelf) *Train 1 1989 - Yes (16.7%) 2.5 16.7 0.4 Tolling Japan, China, KoreaTrain 2 1989 - Yes (16.7%) 2.5 16.7 0.4 TollingTrain 3 1992 - Yes (16.7%) 2.5 16.7 0.4 TollingTrain 4 2004 - Yes (16.7%) 4.4 16.7 0.7 TollingTrain 5 2008 - Yes (16.7%) 4.4 16.7 0.7 Tolling

371 2.7Abu Dhabi (ADGAS)Train 1 1977 No 2.3 10.0 0.2 Tolling JapanTrain 2 1977 No 2.3 10.0 0.2 TollingTrain 3 1994 No 2.5 10.0 0.3 Tolling

0.7Indonesia (Tangguh LNG)Train 1 2009 - Yes (37.2%) 3.8 37.2 1.4 Tolling Mexico, China, Korea,Train 2 2010 - Yes (37.2%) 3.8 37.2 1.4 Tolling Japan ***

413 2.8

Egypt (Damietta)Train 1 2005 63 Yes 5.1 0.0 0.0Total operating capacity 2,496 **3.2 12.2Development projectsAngola LNG 2012 Yes (13.6%) 5.2 13.6 0.7Total development capacity 0.7Source: J.P. Morgan. * Train capacity is shown as it is today following upgrades ** Average capacity. *** Long term supply contracts with CNOOC (2.6 MT pa for 25 years) Posco (0.55 MT pa for 20 years), K-Power (0.6 MT pa for 20 years), Tohoku Electric (0.125 MT pa for 15 years) and Sempra (3.7 MT pa for 20 years).

The average capacity of BP’s liquefaction trains is around 3.2 MT pa. With the exception of ADGAS (Abu Dhabi), BP supplies equity gas to all its equity owned liquefaction facilities. BP also has an equity supply agreement with Damietta LNG, but does not own any equity in the liquefaction plant (which is effectively owned 40% ENI, 40% Gas Natural and 20% EGAS). Similarly, BP has a supply contract to Bontang LNG, Indonesia.

BP does not yet have any exposure to LNG projects to be supplied from non-conventional gas, although as we have noted, coal bed methane from the Sanga Sanga CBM PSC could potentially be used as a supply source in Indonesia (to the Bontang LNG facility). We note that 2.5 bcfpd of BP equity gas was processed through a liquefaction plant in 2010 – this represents almost 30% of its total gas output in 2010 (8,401 mmcfpd) and 11% of its total production in 2010 (3,822 kboepd).

BP has interests in fourteen

trains in four facilities

No presence in CBM to

LNG….but watch this space

84



We see limited potential for the addition of further trains at any of its facilities given government gas depletion controls and priority given to domestic needs (Egypt and Trinidad), declining domestic gas reserves (Indonesia) and competing projects (Australia). BP only has one firm development project – Angola LNG – which is nearing completion and due on stream in early 2012. There is potential for a fourth train at ADGAS, but this has yet to be sanctioned by the operator, ADNOC.

BP has also yet to confirm that the Tangguh LNG project has sufficient proven reserves to support a third train – this requires an additional 5 TCF over the existing P1 reserve base of 14 TCF. Government officials have indicated that FID may be taken in 2013 with first production from a 3.8 MT pa train in 2018.

This ex-growth feature of its LNG portfolio is clearly not a particular strong position. We believe that this reflects a long term historic strategic aversion to liquefaction projects and, more generally, LNG. We sense that BP may look to remedy this situation, perhaps by buying in to an LNG development or acquiring a company with rights therein.


As per Table 16, BP retains capacity rights to a total of 6.8 MT pa (around 905 mmcfpd) of LNG re-gasification capacity via four operational terminals in China (owned), Italy (leased), UK (leased, a 20-year contract is in place with BP/Sonatrach for this first phase of capacity to enable them to import LNG into the UK from other countries) and USA (leased). BP is the only foreign company to own a piece of a Chinese re-gasification terminal (30% Dapeng) – this is its only part-owned facility.

Table 16: BP - re-gasification terminal rights

Re-gasification terminals Start date Gross capacity MT pa BP equity Net capacity MT pa ContractChinaDapeng 2006 6.7 30% 2.0 OwnedItalyRovigo 2009 5.9 13% 0.7 LeasedUKIsle of Grain Phase 1 2005 3.3 50% 1.7 LeasedUSACove Point 1976 7.4 33% 2.4 LeasedTotal operational capacity 6.8


BP is not involved in any new re-gasification projects. BP thus retains access to 6.8 MT pa of re-gasification capacity which equates to just 57% of its net operational liquefaction capacity.

BP’s LNG portfolio is going ex-

growth

BP's re-gasification capacity is

57% of its liquefaction capacity

85



LNG shipping assets

As per Table 17, BP has direct access to 8 modern LNG vessels (the oldest was delivered in Q4 2002) - 7 via operating leases and 1 via a time charter. The average size of these 8 vessels is 146,813 M3 or around 104,200 DWT - this is 33% larger than the global average vessel size (estimated to be around 78,500 DWT). In addition, some of BP’s LNG joint ventures have their own dedicated LNG shipping fleets. The North West Shelf project has 7 dedicated ships with a combined capacity of c.900,000 M3. The ADGAS joint venture also has 7 dedicated ships with a combined capacity of around 960,000 M3. Tangguh LNG sells on an FOB basis to CNOOC (i.e. CNOOC provides its own ships). Tangguh LNG charters ships forother contracts that are on a delivered basis. Atlantic LNG also sells on an FOB basis. Angola LNG charters shipping capacity. BP does not own or have direct access to any of the much larger Q-Max or Q-Flex vessels.

Table 17: BP - LNG vessel portfolio

LNG vessels Delivery date Capacity M3 Capacity T ContractBritish Trader Q4 2002 138,000 97.9 LeasedBritish Innovator Q1 2003 138,000 97.9 LeasedBritish Merchant Q3 2003 138,000 97.9 LeasedBritish Emerald Q3 2007 155,000 110.0 LeasedBritish Ruby Q3 2008 155,000 110.0 LeasedBritish Sapphire Q3 2008 155,000 110.0 LeasedBritish Diamond Q3 2008 155,000 110.0 LeasedGolar Arctic Q1 2011 140,500 99.7 Time charterTotal operational capacity 1,174,500 833.5Average capacity per vessel 146,813 104.2



BP does not explicitly disclose the financial performance of its LNG business – it is included in its upstream segment without incremental disclosure; nor does it discloselevels of invested capital or capital investment. In our view, this is not a very constructive disclosure stance and could be improved without compromising BP’s competitive position in any way. However, it might draw attention to the fact that, alongside the LNG businesses of RD Shell and BG Group, BP's LNG business is significantly less profitable.

However, we can estimate the earnings contribution from its LNG portfolio using BP’s once annual supplementary information on oil and natural gas. This discloses the contribution from Midstream activities which includes LNG processing facilities and transportation. As per Table 18, we have assumed that given the size of BP's interests in liquefaction facilities that all LNG profits feature within associates (which are reported post-interest, tax and minorities). This would imply 2009-10 average earnings of around $776m. We anticipate higher earnings in 2012 once Angola LNG is commissioned and given the more favorable market environment more generally. If we assign a PER of 10x, this would imply an NPV of around $9.7bn or around 33 pence per share. This represents just 4% of our sum-of-the-parts of BP. This underlines BP’s under-exposure to the LNG industry which, given the strategic importance assigned to integrated gas chains, is an issue that BP’s management may seek to address.

BP does not own any of its LNG

vessels

Around $8bn or just 26 pence

per share

86



Table 18: BP - LNG portfolio valuation

2010 ($m)Subsidiaries pre-

tax earningsAssociates post-

tax earnings 2009 ($m)Subsidiaries

pre-tax earningsAssociates post-

tax earnings

UK 23 0 UK 925 0Rest of Europe 42 4 Rest of Europe 17 5US -347 27 US 719 29Rest of North America 3 238 Rest of North America 833 134South America 49 199 South America 17 214Africa -26 63 Africa -27 56Russia 4 255 Russia -37 -113Rest of Asia -23 518 Rest of Asia 518 611Australasia -13 0 Australasia -315 0

-288 1,304 2,650 936Gains 0 0 LukArco divestment gain 976 0Underlying -288 1,304 Underlying 1,674 936Implied LNG 0 721 Implied LNG 0 830Tax 0 Tax 0Total post tax 0 721 Total post tax 0 830Total estimated LNG earnings 721 Total estimated LNG earnings 8302010-09 average earnings 7762012E earnings potential 9692012E PER (x) 10Implied LNG valuation ($m) 9,694Pence per BP share 33% of BP SOTP 4%

Source: J.P. Morgan. BP 2010 Report & Accounts – supplementary information on oil and natural gas

Figure 54: BP - liquefaction capacity (MT pa)


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87



RD Shell

Summary of key LNG assets

Figure 55: RD Shell - Location of key LNG assets

Source: J.P. Morgan. * Pluto LNG Train 1 (4.3 MT pa, 21.9%), Gorgon LNG train 1-3 (15 MT pa, 25%), Prelude FLNG (3.6 MT pa, 100%), Wheatstone LNG Trains 1-3 (8.9 MT pa, 6.4%). ** With

the exception of the Hazira re-gasification terminal (74% owned), RD Shell has import capacity rights via terminals in the US, Spain and Mexico that it does not own – these capacity rights are

shown.


RD Shell has a clearly defined upstream growth strategy with three central planks:

Build resources

Accelerate resource to value conversion

Differentiation through integrated gas leadership, technology and partnerships.

As per BP and BG Group, integrated gas chains are central to RD Shell’s upstream strategy. However, unlike BG Group, RD Shell has a more limited interest and presence in the downstream supply of gas to end users.

As a result of its gas chain capabilities, RD Shell has long had a relatively high exposure to natural gas production. Indeed, as per Figure 59, 2010 was the first year when gas (51%) was more than half of group output. By 2015, we expect gas willrepresent 57% of group output.

Within RD Shell, global LNG now falls under the International Upstream segment –Malcolm Brinded has executive responsibility for this business. So, in common with BP, RD Shell does not have a dedicated individual who is responsible for global LNG.

16.3

2.2

(Elba Island and Cove Point)

(Costa Azul, Mexico)

(NW Shelf, Australia, 20.7%)

7.5

(Brunei LNG, 25%)

14.6(Dua and Tiga, Malaysia, 15%)

21.6

(Bonny LNG, Nigeria, 21.6%)

7.2

(Oman LNG, 30%)

9.6

(Sakhalin LNG, 27.5%)

7.8

(Qatargas, Qatar, 30%)

31.8

(Hazira, India, 74%)

2.7

8.8

1.2

(Huelva and Barcelona, Spain)

(Pluto, Gorgon, Prelude, Wheatstone *)

3.7

(Qalhat LNG, 11%)




Fred Lucas

(44-20) 7155 6131

[email protected]

Integrated gas chains are central

to RD Shell's upstream strategy

88



RD Shell actually provided the technology for the world’s first liquefaction plant at Arzew, Algeria. As per Figure x, RD Shell’s position in global LNG is world leading which is clearly contrasted to BP's much smaller position. RD Shell has liquefaction capacity in the Atlantic Basin (Nigeria), the Middle East (Oman and Qatar), Russia (Sakhalin) and Asia Pacific (Australia, Brunei and Malaysia). Interestingly, both BP and RD Shell took their first respective exposures to LNG in the early-mid 1970s –RD Shell in Brunei and BP in Abu Dhabi. Yet we estimate that by end 2011, RD Shell had net liquefaction capacity of almost 20 MT pa, 61% larger than BP's net capacity (12.2 MT pa). RD Shell also has the potential to more than double its net liquefaction capacity by 2020 (+8.9 MT pa projects underway and a further +19.2 MT pa potential projects). BP’s LNG growth options are much more limited with only one development to add 0.7 MT pa or 6% net capacity in 2012 (Angola LNG).

Strategic errors & unanswered questions

It is quite tricky to fault RD Shell’s global LNG position – it is the world’s number one with a distinctive global presence, first class reputation and proven project delivery capabilities.

We feel that RD Shell is somewhat over-exposed to the capital intensive, lower return end of the LNG value chain – liquefaction. It is similarly over-exposed to refining. In our view, RD Shell has a tendency to want to build and own exposure to capital intensive processing assets and a reluctance to reduce that exposure when perhaps it could/should. Given the size of its balance sheet and its unrivalled experience in all aspects of the LNG industry, RD Shell could have penetrated the market for LNG arbitrage more aggressively had it taken on more equity / third party LNG flows directly, as BG Group did. Perhaps because it was unwilling to risk changing its reputation in the LNG industry or perhaps because it simply failed to see the opportunity, RD Shell missed this contractual innovation.

Unlike BP and Exxon Mobil, RD Shell also has developed a distinctive strategic alternative for gas monetization - gas-to-liquids (GTL). GTL effectively competes with pipelines and LNG as a route to get stranded gas to market. LNG has historically been the preferred choice to GTL given LNG’s lower capital intensity, simpler and more proven technology and robust LNG pricing – gas resource owners have been able to contract for 20+ years at or very close to oil price parity. RD Shell has two operational GTL facilities – both 100% owned (Bintulu, Malaysia, output capacity 14.7 kbpd and Pearl GTL, Qatar, output capacity 140 kbpd). Pearl GTL has cost over $18bn (more than three times its original budget of $5bn to $6bn) and taken several years to develop. Pearl’s first train was successfully commissioned in 2011(originally scheduled for 2009) and its second train is currently being commissioned. It is debatable whether the source gas for Pearl GTL (1.6 bcfpd) might have been more wisely dedicated to another, lower cost LNG train in Qatar. From the perspective of a shareholder in RD Shell, the answer will depend on the premium prices realized for the GTL products and the operating performance of Pearl GTL. In the meantime, the Qataris continue to realize robust prices for their LNG exports, at or close to oil price parity.

Like so many others, RD Shell was also caught out by the view that the US was set to become a major LNG importer. In 2003, it believed that Asian demand for LNG would slow, whilst North American demand would accelerate. Consequently, it took re-gasification capacity rights at Cove Point and Elba Island (Table 20). In 2003, it also planned an offshore re-gasification terminal in the Gulf of Mexico with a

RD Shell is the global LNG

‘supremo’

RD Shell could have taken on more LNG supplies itself

RD Shell must prove that GTL is a valid / superior alternative to

LNG

Joined the US re-gasification ‘gold rush’

89



capacity of 7 MT pa. This facility was scheduled to start up in 2007, but was never built. RD Shell also took re-gasification capacity rights in Mexico via the Baja and Altamira terminals to supply both Mexico and the US – it has recently sold its position in Altamira.

Many IOCs including BG Group moved in to power as a means to monetize gas and then exited when they realized that the return uplift to their business was negative. RD Shell bulked up in power more than others, via InterGen, and was then slow to exit the business having taken major write-downs. InterGen’s power assets were targeted users of RD Shell’s gas (LNG) e.g. the La Rosita (1 GW) plant in Mexico via the Baja re-gasification terminal with LNG from Sakhalin-2.

RD Shell was operator and the dominant owner (55%) of Sakhalin-2. This was RD Shell’s sixth and largest LNG project. In late December 2006, Gazprom announced that it would purchase 50% plus 1 share in Sakhalin Energy Investment Company (SEIC) for $7.45bn cash. This transaction closed in April 2007. At the time, we estimated that this stake had a market value in excess of $10bn (around $5 per boe for partly developed resources). This move evenly diluted the three western owners of SEIC (RD Shell 55%, Mitsui 25%, Mitsubishi 20%) by half, thus diluting RD Shell’s ownership to 27.5%. RD Shell’s project status was also changed to Technical Advisor. The move followed much negative publicity in Russia which focused on the project’s environmental track record and cost over-runs. The original budget of around $10bn (defined March 2003) effectively doubled to $20bn which delayed tax payments to the Russian government since Sakhalin-2 was a Production Sharing Agreement (PSA). The PSA was signed in the 1990s under President Yeltsin and was one of just three PSAs signed by the Russian authorities with western companies. The project’s start up was also delayed from 2007 to 2009. Clearly, it was controversial for Gazprom not to have been involved at all in Russia’s first and only LNG project. However, the original solution to address this issue (first announced July 2005 and originally expected to complete early 2006) was a swap of a 25% stake in Sakhalin for a 50% stake in the Zapolyarnoye Neocomian field in the Arctic. This would have helped to maintain RD Shell’s overall resource position in Russia and diversified its portfolio therein. Instead, RD Shell paid a price for this LNG project’s delays and cost over-runs via material dilution at a price well below market value, in our view. However, in exchange, the Russian government approved the project's higher budget and cost recovery items and the PSA remained intact.Furthermore, since Gazprom took ownership in the project, Sakhalin LNG has run very efficiently. In our view, it is perhaps a shame that RD Shell’s 'alliance’ with Gazprom which was initiated in 1997 seems to have generated such little benefit or advantage to RD Shell. However, we are quite hopeful that a third train at Sakhalin will be sanctioned, perhaps in 2012-13.

Sakhalain-2 was RD Shell’s first and only operated LNG project to experience major cost over-runs and delays. Between 1999 and 2003, it was partner in a total of 8 new LNG trains (Oman LNG T1-2, Nigeria LNG T1-3, Malaysia Tiga T1-2 and NWS T4). All of these trains were actually delivered under budget and/or ahead of schedule. RD Shell is now fourth in the queue of CBM-to-LNG projects in Queensland, Australia. Ahead of it are BG Group's QC LNG (T1-2 8.5 MT pa), Santos’s Gladstone LNG (T1-2 7.8 MT pa) and ConocoPhillips’s APLNG (T1-2, 9.0 MT pa). Given the number of competing LNG projects in Australia, we are concerned that RD Shell’s 50:50 project with PetroChina (Curtis Island LNG) will suffer from an over-heating of the Australian skilled and semi-skilled labor market

Regrettable move in to gas-fired

power

RD Shell was heavily diluted in

Sakhalin LNG

Could APLNG be RD Shell’s next

Sakhalin-2?

90



and contract hardware at the top of an EPC cost cycle. RD Shell has yet to disclose a capital budget for this project, with sanction not expected before end 2013 and a start up in 2018, at the earliest. One of RD Shell's problems was that it arrived late to the CBM-to-LNG play. In common with other IOCs (BG Group, ConocoPhillips and TOTAL), RD Shell was obliged to buy in to the play, jointly acquiring Arrow Energy and, more recently, Bow Energy via an alliance with PetroChina.

With the exception of Sakhalin-2, RD Shell has a very good track record of defining an LNG growth opportunity and delivering the project efficiently. There are not too many historic examples of identified leads that failed to be commercialized. We would only cite Iran LNG (and Iran GTL Assaluyeh), Venezuela LNG and Olakola LNG (Nigeria). In contrast, there are not too many examples of green field opportunities that RD Shell has missed. As highlighted, it was a late arrival to the Australian CBM-to-LNG play. RD Shell may, however, have missed the opportunity to take ‘a seat of influence’ at the East African LNG table - perhaps acquisitions could change that.

Following the 10% placing in 2010, RD Shell has made it clear that it intends to exit its 24.3% position in Woodside (although it has not clarified the method of exit e.g. another market placing for cash or an asset swap with Woodside). Ideally in our view, RD Shell would have acquired Woodside to consolidate its position in Australian LNG. By exiting, it loses an indirect exposure to a number of LNG projects e.g. Pluto T1-2 (Woodside 90%), Sunrise LNG (Woodside 33.4%, a potential candidate to apply RD Shell’s Floating LNG technology), Browse LNG T1-3 (Woodside 50%) and the NW Shelf T1-5 (Woodside 16.7%). This will dilute RD Shell’s upstream project pipeline and will clearly reduce its overall exposure to LNG – neither particularly desirable, in our view.

Liquefaction assets

RD Shell’s first liquefaction asset was commissioned in Brunei in 1972. Since then, it has developed an extremely impressive portfolio of liquefaction assets. RD Shell now has a total net operating capacity of approximately 19.7 MT pa which is spread across a total of seven countries (Australia, Brunei, Malaysia, Nigeria, Oman, Russia and Qatar), nine LNG plants (including two in Malaysia and two in Oman) and twenty-seven trains with an average capacity of 3.2 MT pa. This ranks RD Shell as the largest owner of liquefaction capacity of all the IOCs. RD Shell’s net liquefaction capacity is spread 51% in Asia Pacific, 24% Middle East and 25% in the Atlantic Basin. Its interests in the North West Shelf (Australia) are held directly (16.67%) and via its 24.3% stake in Woodside (which also owns 16.67%). Of note, RD Shell does not operate any one of these liquefaction plants or trains.

Between 2012 and 2017, we count another four green field projects involving eight trains, including the world’s first floating LNG facility (Prelude FLNG) that are now underway which will add another 8.9 MT pa of net capacity.

Over a decade since RD Shell first proposed FLNG to develop the Kudu gas field, offshore Namibia (a field that is still undeveloped and since its discovery in 1974 has seen seven operators – RD Shell, Texaco, Chevron, Energy Africa, Petronas, Tullow and Gazprom), in July 2009, RD Shell awarded Samsung Heavy Industries and Technip the contract to design, build and install multiple FLNG facilities over a period up to 15 years. In May 2011, Shell announced the go ahead for the world’s

Not too many ‘dead leads’, but

might have missed the East

African LNG opportunity….

Farewell to Woodside….and its

LNG exposure

Almost 20 MT pa operating

capacity spread across seven

countries

Four green field developments

underway to add almost 9 MT pa

91



first floating LNG (FLNG) facility. The vessel will process gas initially from seven subsea wells in the Prelude field in the Browse Basin and, in a second phase, from the Concerto field. Later in the project life, gas is also expected to come from the Crux field. Prelude FLNG will be the world’s first floating LNG facility and it will be RD Shell’s first 100% owned and operated liquefaction facility. A floating solution remains the preferred option for the Greater Sunrise LNG project that is located in the joint development area of the Timor Sea, but the government of EastTimor wants an onshore liquefaction facility to be located in their country. RD Shell is also looking at floating LNG applications in Iraq and Indonesia (following its 30% acquisition in to the Abadi project – the Masela field in the Arufura Sea - from Inpex).

RD Shell has also expressed some interest in joining the Gulf LNG project, led by InterOil in Papua New Guinea. The acting petroleum secretary of PNG (Rendle Rimua) has said that RD Shell is the state’s preferred LNG operator.

Looking beyond these projects, we see potential to add another 20 MT pa via sixgreen field projects (Australia x3, Indonesia, Iraq and Nigeria) and five brown field projects (Australia, Nigeria and Russia) with a total of 16 trains. The addition of a third LNG train on Sakhalin Island is also looking more likely – please refer to the section on Gazprom. By 2020, RD Shell could have more than 48.5 MT pa in a total of 56 liquefaction trains. This represents potential growth of +146% versus YE 2011 operational capacity and a potential capacity CAGR 2011-20 of 11%. In our view, this really underlines RD Shell’s potential to continue, if not extend its global leadership in global liquefaction. No other company has this scale, global footprint or density of identifiable growth opportunities.

Development options include

another 20 MT pa

92



Table 19: RD Shell - liquefaction assets

Liquefaction plant Start date RDS equity supply Gross capacity MT pa RDS equity Net capacity MT paAustralia (NW Shelf) *Train 1 1989 Yes 2.5 20.7% 0.5Train 2 1989 Yes 2.5 20.7% 0.5Train 3 1992 Yes 2.5 20.7% 0.5Train 4 2004 Yes 4.4 20.7% 0.9Train 5 2008 Yes 4.4 20.7% 0.9Brunei (Brunei LNG) 3.4Train 1 1972 Yes 1.5 25.0% 0.4Train 2 1972 Yes 1.5 25.0% 0.4Train 3 1973 Yes 1.5 25.0% 0.4Train 4 1974 Yes 1.5 25.0% 0.4Train 5 1974 Yes 1.5 25.0% 0.4Malaysia 1.9DuaTrain 1 1995 Yes 2.6 15.0% 0.4Train 2 1995 Yes 2.6 15.0% 0.4Train 3 1995 Yes 2.6 15.0% 0.4TigaTrain 1 2003 Yes 3.4 15.0% 0.5Train 2 2003 Yes 3.4 15.0% 0.5Nigeria (Bonny LNG) 2.2Train 1 1999 Yes 3.2 21.6% 0.7Train 2 1999 Yes 3.2 21.6% 0.7Train 3 2002 Yes 3.2 21.6% 0.7Train 4 2005 Yes 4.0 21.6% 0.9Train 5 2006 Yes 4.0 21.6% 0.9Train 6 2007 Yes 4.0 21.6% 0.9Oman 4.7Oman LNGTrain 1 2003 No 3.6 30.0% 1.1Train 2 2004 No 3.6 30.0% 1.1Qalhat LNGTrain 1 2006 No 3.7 11.0% 0.4

2.5Sakhalin (Sakhalin LNG)Train 1 2009 Yes 4.8 27.5% 1.3Train 2 2009 Yes 4.8 27.5% 1.3

2.6Qatar (Qatargas 4)Train 7 2011 Yes 7.8 30.0% 2.3Total operational capacity 3.2 19.7Development projects underwayAustraliaPluto LNG Train 1 * 2012 No 4.3 21.9% 0.9Gorgon LNG Trains 1-3 2016 Yes 15.0 25.0% 3.8Prelude FLNG 2016 Yes 3.6 100.0% 3.6Wheatstone LNG Trains 1-3 2017 Yes 8.9 6.4% 0.6Total development capacity 8.9Potential developmentsAustraliaPluto LNG Train 2 * 2015 No 4.3 21.9% 0.9Curtis Island LNG Trains 1-2 2018 Yes 8.0 50.0% 4.0Browse LNG Trains 1-3 * 2017-18 Yes 12.0 20.6% 2.5Sunrise FLNG * 2018 Yes 3.6 34.7% 1.2Gorgon LNG Train 4 2017 Yes 5.0 25.0% 1.3Indonesia – Abadi FLNG 2019 Yes 2.5 30.0% 0.8Iraq - Khawr al-Amaya FLNG 2017 Yes 2.0 100.0% 2.0NigeriaTrain 7 2019 Yes 5.0 25.6% 1.3Train 8 2020 Yes 8.5 25.6% 2.2Olakola LNG 2020 Yes 12.6 19.5% 2.5Russia - Sakhalin Train 3 2016 Yes 5.0 27.5% 1.4Total development potential 22.5

Source: J.P. Morgan. * Includes stakes held directly and via 24.3% stake in Woodside Petroleum.

93




As per Table 20, RD Shell has re-gasification capacity rights to total of 14.9 MT pa (c.2 bcfpd) via seven operational terminals in India (partly owned), Spain (leased), USA and Mexico (leased). This represents 76% of RD Shell’s net liquefaction capacity (19.7 MT pa at end 2011). Just 15% of its capacity is owned, the balance is leased under long term (20 year or more) lease agreements.

Table 20: RD Shell – re-gasification capacity

Terminal name Location Start upCapacity right

periodRD Shell capacity

rights (MT pa)RD Shell

Ownership

Hazira Gujarat, India 2005 Owned 2.2 74%Altamira * Altamira, Mexico 2006 - - -Huelva Huelva, Spain 1988 2010-34 0.3 LeasedBarcelona Barcelona, Spain 1969 2010-34 0.9 LeasedCove Point Lusbu, Maryland, USA 2003 2003-23 1.8 LeasedCosta Azul Baja, California, Mexico 2008 2008-28 2.7 LeasedElba Island Elba Island, Georgia, USA 2006 2006-36 2.8 LeasedElba Island expansion Elba Island, Georgia, USA 2010 2010-35 4.2 LeasedTotal re-gasification capacity 14.9

Source: J.P. Morgan. * In 2011, RD Shell (50%), TOTAL (25%) and Mitsui (25%) sold their ownership of Altamira to a 60:40 JV of Vopak and Enagas.

LNG shipping assets

Shell actually started corporate life as a shipping company, bringing exotic sea shells and kerosene from the East to Europe in the late 1800s (in 1833 Marcus Samuel expanded from selling antiques to oriental shells). Today, the Shell Shipping organization (Shell International Trading & Shipping Company Limited) is based in London, with operations in Houston, the Hague, Singapore, Perth and Tokyo.

Through joint ventures and direct ownership, RD Shell has interests in around a quarter of the world’s LNG vessels in operation. It currently manages more than 60LNG carriers (Table 21). This includes around 30 vessels managed via its partnership with Nakilat Shipping (Qatar) Limited (a wholly owned subsidiary of Qatar Gas Transport Company Ltd or Nakilat) following an agreement at the end of 2006. The intention of this agreement is to develop Nakilat’s shipping expertise, so that operational management of the ships can be transferred to Nakilat 8-12 years after delivery of their last vessel.

Table 21: RD Shell - LNG vessel portfolio

LNG vessel classNumber of

vesselsAverage vessel

capacity (cm)Average vessel capacity (Tons)

Total capacity (Tons) Routes

B - Class 8 75,000 53.2 426 Brunei to Japan, S.KoreaG - Class 7 130,000 92.3 646 GeneralNLNG - Class 12 135,000 95.8 1150 Nigeria to NW EuropeNWS - Class 5 130,000 92.3 461 NW Shelf to AsiaNakilat Q-Max & Q-Flex * 30 - - - Managed on behalf of Nakilat (Qatar)

Source: J.P. Morgan. * Nakilat owns another 20 Q-category vessels via JVs.

RD Shell’s re-gasification

capacity is 92% of its

liquefaction capacity

RD Shell has interests in or

manages around one quarter of

the world’s LNG fleet

94




LNG is a very important component of RD Shell’s overall value and will remain a very important enabler for higher margin gas production growth. In our view, it is especially important for investors to appreciate the significant value of RD Shell’s LNG portfolio.

RD Shell no longer explicitly discloses the performance of its global LNG business which is now included in its Upstream International segment. Some years ago, it used to provide an annual disclosure (in its annual strategy presentation) via a graph that broke out LNG earnings explicitly. However, one better than BP, RD Shell does disclose the performance of its Integrated Gas business each quarter - this incorporates LNG (including LNG marketing and trading) and Gas-to-Liquids operations. In addition, the associated upstream oil and gas production activities from projects where there are integrated fiscal and ownership structures across the value chain are also included in Integrated Gas. These include the Sakhalin II (Sakhalin LNG – an integrated PSA) and North West Shelf projects that are on stream, Pearl GTL (Train 1 shipped its first cargo in June 2011 and Train 2 was commissioned in November 2011), Qatargas 4 (commissioned), Gorgon and Pluto (both under development) projects. Power generation and coal gasification activities are also included in Integrated Gas results.

As per Figure 56, the percentage of group earnings sourced from Integrated Gas has increased from around 10% closer to 20% as RD Shell has increased its operational LNG capacity and LNG pricing has risen on a lagged relationship with the higher oil price. From Q4 2011 onwards, we also expect a fuller contribution from Pearl GTL as Train 1 completes a full quarter of revenue / profit generation and Train 2 is then fully commissioned during H1 2012.

In the first 9-months of 2011, RD Shell reported post-tax earnings of $4.6bn from Integrated Gas. Our FY 2011E estimate is $6.6bn – if we take 85% of the total (assuming 15% of this figure might be generated by non-LNG related activities), we measure an underlying post-tax contribution from LNG in 2011 of approximately $5.6bn. If we apply a multiple of 9x to this stream (90% of RD Shell’s LNG is sold under long term contracts with 80% oil price indexed on a 3-6 month lag – so 2011 earnings are reflecting an oil price > $100 per barrel), we infer a potential equity valuation of just over $50bn. This represents just over £5 per share and just under 20% of our sum-of-the-parts value of around £26. This value captures some of the value of RD Shell’s stake in Woodside (current market value around $7bn) as well as some of the upstream reserve value of gas supplies in to liquefaction facilities (as above, Sakhalin LNG, North West Shelf and Qatargas 4).

We note that in almost 6 years from 2006 to 2011, RD Shell’s cumulative capital expenditure in Integrated Gas & Power was $25.3bn, although much of this (c.$19bn) would have been dedicated to Pearl GTL (RD Shell 100%).

Tricky to value given limited

financial disclosures on LNG

business

We value LNG franchise at

around $50bn or £5 per share

95



Figure 56: RD Shell - Integrated Gas earnings ($m, % of group)


Figure 57: RD Shell - LNG sales by quarter (MT)


Figure 58: RD Shell - Net liquefaction capacity and sales (MT pa)


Figure 59: RD Shell - production mix - oil versus gas


0%

5%

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2500

2004 2005 2006 2007 2008 2009 2010 2011

Integrated Gas earnings % of group earnings

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2006 2007 2008 2009 2010 2011

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72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 19 20

Brunei Australia Malaysia + Indonesia Nigeria Oman Russia Qatar Iraq LNG sales

0%

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2000 01 02 03 04 05 06 07 08 09 2010 11e 12e 13e 14e 15e

Oil Gas

Notable shift to gas

96



ENI


Figure 60: ENI - Location of key LNG assets

Source: J.P. Morgan

ENI's strategy for its LNG business has been driven by two objectives – optimum monetization of its equity gas (especially in Africa) and meeting the gas requirements of Italy given ENI’s 'nation' status. We do not believe that ENI has an ambitious growth outlook for this business or intends to be a serious player in the LNG arbitrage market. This partly reflects ENI’s origins as a pipeline company and its ownership of utility assets. ENI's LNG business resides within two business segments – Upstream (Liquefaction assets) and Gas & Power (Re-gasification terminals and LNG vessels).

Given the size of ENI's discoveries/gas resource base in Mozambique and Indonesia (CBM) – the company's liquefaction capacity is likely to see significant growth over the medium term as the company looks to monetize these equity gas resources. However, we also concede that these potential developments are still many years off. We also believe that ENI's execution portfolio carries risk of delays – both Nigeria LNG and Brass LNG have already been pushed back and we remain cautious on the delivery schedules of both these projects.

Operational Liquefaction capacity (Mt/y)

Liquefaction capacity under construction(Mt/y)

Operational Re-gasif ication capacity (Bcm/y)

(Nigeria LNG T1-T6, 10.4%)

22

LNG project (FEED or under study) (Mt/y)

3.7

(Qalhat LNG, 3.5%)

5.2

(Angola LNG, 13.6%)

10

(Brass LNG (FEED), 17%)

8.8

(Sagunto, 21.25%)

2.5 (Panigaglia, 50%)

3.6

(El Ferrol, 9.5%)

5.1

22.2

(Bontang, 4%)

(Egypt, 40%)

3.2

(Darwin plant, 11%)

8.5

(Nigeria LNG T7-T8 (FEED), 10.4%)

15.5

(Cameron, 40%)

3.2

(Zeebrugge, 56%)

11.2

(Pascagoula, capacity rights)

Re-gasification under development (Bcm/y)

Nitin Sharma

(44-20) 7155 6133

[email protected]

Strategy focused on

development of the company’s

equity gas resources

Recent discoveries should drive

LNG growth

97



We believe that the weaker outlook for Italian gas demand means that ENI needs to increasingly focus on international markets to deliver growth in its gas marketing business - a process that was started by ENI's acquisition of Distrigaz in 2009 but needs to progress at a faster pace. We also believe that ENI needs to define a clearer growth strategy for its LNG arbitrage business. In our view, this is an obvious growth segment as the company looks to finalize its plans (likely divestment) for the non-core regulated businesses in Italy (SRG).

Liquefaction assets

ENI's first liquefaction plant (Bontang LNG, Indonesia) was commissioned in 1977 –so the company has been active in this business for more than three decades. But the relative growth in the company's LNG liquefaction portfolio has been limited in recent years – no new projects have been commissioned in the last 5 years. In our view, this is a reflection of the company's reliance on piped gas imports from North Africa and Russia to supply its Gas Marketing business that is largely Europe focused. ENI now has a total net operating capacity of approximately 5.7 MT pa which is spread across five countries (Egypt, Indonesia, Nigeria, Oman and Australia). As per Table 22, these interests are (with the exception of Damietta LNG) typically small, minority interests.

ENI's pipeline of liquefaction projects is not very strong - there is only one firm LNG development project in ENI's portfolio (Angola LNG). The project is nearing its completion and is expected on-stream in early 2012. The LNG output from the project was originally planned to go to the US East Coast (ENI has back up re-gasification capacity) but given a collapse in US LNG import needs, Angolan cargoes may well be shifted to Europe/Asia.

ENI has potential developments of 3.1MT pa net in Nigeria – Brass LNG and two additional trains in NLNG. Both of these projects are yet to be sanctioned. Given the history of delays in these projects, we believe that there is a risk of further slippages in both these projects.

Mamba South, Area 4 block is the biggest operated discovery to date by ENI which is already looking at a multi-train (> 3) LNG green field project. We expect this giant gas discovery to provide a much needed boost to ENI's LNG business. Furthermore, the presence of KOGAS (one of the biggest LNG buyers in the world) as a partner in the block is an obvious plus for the marketing aspect of this potential LNG development.

Greater international focus and

ambition in LNG arbitrage

business needed to deliver growth

ENI has interest in 10 trains in 5

countries

Only one green field

development on agenda

Mozambique holds early

promise

98



Table 22: ENI - liquefaction interests

Liquefaction plant Start dateENI equity

supplyGross capacity

MT pa ENI equity Net capacity

MT pa Plant typeENI off-take (MT

pa)

EgyptDamietta (Train 1) 2005 Yes (20%) 5.1 40.00% 2.0 Tolling 2.0IndonesiaBontang (A-H) 1977 Yes (8.4%) 22.2 4.00% 0.9 Merchant 2.2Nigeria (Bonny LNG)Train 1 1999 Yes (7%) 3.2 10.40% 0.3 Merchant 2.2Train 2 1999 Yes (7%) 3.2 10.40% 0.3 MerchantTrain 3 2002 Yes (10%) 3.2 10.40% 0.3 MerchantTrain 4 2005 Yes (7%) 4 10.40% 0.4 MerchantTrain 5 2006 Yes (7%) 4 10.40% 0.4 MerchantTrain 6 2007 Yes (7%) 4 10.40% 0.4 MerchantOmanQalhat LNG (Train 1) 2006 No 3.7 3.50% 0.1 Merchant 0.1AustraliaDarwin LNG 2006 Yes (11%) 3.2 11.00% 0.4 Merchant 0.4Total operational capacity 5.7Development projects underwayAngolaAngola LNG 2012 Yes (13.6%) 5.2 13.60% 0.7 0.7Total development capacity 0.7Potential developmentsNigeriaNigeria LNG (Train 7) 2019 Yes 5.0 10.40% 0.5Nigeria LNG (Train 8) 2020 Yes 8.5 10.40% 0.9Brass LNG 2018 Yes 10.0 17.00% 1.7Total development potential 3.1

Source: J.P. Morgan


As per Table 23, ENI has re-gasification capacity rights to a total of 11.5 bcm pa (8.5 MT pa) via five operational terminals in four countries (Italy, Spain, Belgium and USA) across two continents. This represents 149% of ENI’s net liquefaction capacity (5.7 MT pa at end 2011). Just 10% of its re-gasification capacity is owned, the balance is leased under long term agreements. It is also clear that the majority of ENI's re-gas capacity is owned indirectly by the company via its stakes in Snam Rete Gas (SRG) and Union Fenosa Gas (UFG).

Table 23: ENI – re-gasification terminal rights

Terminal name Location Start upCapacity right

period

Gross Capacity (Bcm pa)

ENI equity

interest

ENI capacity rights

(Bcm pa) Ownership

Cameron Louisiana, USA 2009 20y 15.5 40% 6.2 Through UFGEl Ferrol Spain 2007 10y 3.6 9.5% 0.3Sagunto Spain 2006 10y 8.8 21.3% 1.9 Through UFG

Panigaglia Italy 1971Owned, no

expiry 2.5 50.0% 1.25 Indirect ownership via SRGZeebrugge Belgium 1987 till 2027 3.2 56% 1.8Total re-gasification capacity 11.5Expansions/developmentsPascagoula USA 2012 30y 11.2 0% 5.7Total new capacity 5.7

Source: J.P. Morgan

LNG shipping assets

ENI manages its LNG shipping assets via a 100% subsidiary – LNG Shipping. ENIowns four LNG carriers: LNG Portovenere and LNG Lerici, with a capacity of

ENI's re-gasification capacity is

significantly above its


ENI's owns a fleet of 4 LNG

vessels

99



65,000 M3 each and LNG Palmaria and LNG Elba, with a capacity of 40,000 M3

each. These LNG carriers operate in the Mediterranean region; their LNG cargoesare usually loaded in Algeria and unloaded in Italy, Spain, and France.


As highlighted before, ENI's gas value chain sits within different segments thus providing us with almost zero disclosure on the earnings contribution of its LNG business. Further, a number of its LNG liquefaction / re-gasification assets are owned via subsidiaries and associates – making it even more complicated to assess the performance of this business.

We estimate that ENI's LNG business generates approximately €500m of net income of which c.€300m is the contribution of NLNG and Union Fenosa Gas (associate/subsidiary contributing the bulk of ENI's LNG earnings) with the remainder generated by LNG volume arbitrage/trade and a regulated return on re-gas assets in Italy (owned by SRG). If we apply a multiple of 10x to this stream (higher multiple given that our earnings estimate does not capture all of ENI’s LNG exposure due to lack of disclosure), we infer a potential equity valuation of c. €5bn. This represents c. €1.4 per share and just under 5% of our sum-of-the-parts value of around €28.

Figure 61: ENI - Net Liquefaction capacity and sales (MT pa)

Source: J.P. Morgan

Figure 62: ENI - LNG sales by plants (MT pa)

Source: J.P. Morgan

0

0.5

1

1.5

2

2.5

3

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

LNG

sal

es

(Mtp

a)

Liq

ue

fact

ion

ca

pac

ity

(M

tpa)

Egypt Indonesia Nigeria Oman Australia Angola LNG sales

Under Construction

Possible

0

2

4

6

8

10

12

14

16

2006 2007 2008 2009 2010

Italy Rest of Europe Extra European markets Bontang (Indonesia) PoinFortin (Trinidad & Tobago) Bonny (Nigeria) Darwin (Australia)

Almost no disclosure on the

performance of ENI’s LNG

business


around €5bn or €1.4 per share

100



Repsol YPF


Figure 63: Repsol YPF - Location of key LNG assets


Repsol YPF created an LNG division in its re-organization in 2007 – a clear indication of its sharpened focus on this business stream as an important growth driver. Repsol YPF’s strategy was to focus on its marketing strength whilst committing limited capital to the LNG business. Peru LNG is a case in point - Repsol YPF holds a 20% equity stake in the project, but is entitled to 100% of the plant off take.

However, the company's ambitions for the LNG segment have since been scaled back for two key reasons: (i) a significant exposure to the Atlantic Basin meant that weakening LNG demand in North America has been a constraint on the company's original growth plans (ii) a strategy of capex avoidance for the LNG business has resulted in a portfolio that has effectively zero growth optionality in near/medium term.

The profitability of and returns from both of its most recent growth projects in LNG (Peru LNG – pricing of majority of long term supply volumes linked to Henry Hub and Canaport regas terminal – suffers from low utilization) were directly linked to robust LNG demand in North America. Unsurprisingly, the prolific rise of US gas shale supplies and the negative consequence for US gas prices have been negative for the business. Repsol YPF does not have any foothold in the growing Asia Pacific LNG market.





4.4

(Peru LNG, 20%)

6.7

(Sagunto, 6.5%)**

2.7

(Bilbao, 25%)

15.2

(Atlantic LNG T1-T4, Effective Interest 23%*)

* Repsol has 20%, 25%, 25% and 22.5% respectively in Atlantic T1, T2, T3, & T4

5

(Atlantic LNG T5, 22.5%)

0.7

(EcoElectrica, 15%)**

10

(Canaport, 75%)

3.7

(Qalhat LNG, 1.14%)**

5.1

(Egypt, 12%)**

* * Indirect stake through Gas Natural (Repsol owns 30.8% in Gas Natural which owns 50% of UFG)

4

(Escobar, 29%)**

3.6

(Reganosa, 2.8%)**

8 (Trieste, 30.8%)**

8 (Taranto, 30.8%)**


Nitin Sharma

(44-20) 7155 6133

[email protected]

Focus on LNG business as a growth driver…

…but ambition since has been

scaled back

Over-reliance on North American LNG demand was a strategic

mistake

101



Liquefaction assets

As per Figure 63Figure 63, Repsol YPF has direct interests in five liquefaction trains and an in-direct interest (via Gas Natural) in two further trains with four trains in Trinidad and Tobago and one each in Peru, Oman and Egypt. The capacity is split 17% Peru, 70% Trinidad and Tobago, 12% Egypt and 1% Oman. The start up of Peru LNG has been an obvious plus for the operating performance of the division (Figure 66 and Figure 67).

Repsol YPF does not have any new green field LNG projects in view. Persian LNG (Iran) - a green field project previously on its agenda has now fallen off the radar altogether. Repsol YPF has development potential of 1.1MT pa based on a fifth train at Atlantic LNG. However, the status of this project is 'still unconfirmed' and given the prevailing weak LNG demand in North America, the outlook for this project is looking challenged.

Table 24: Repsol YPF - Liquefaction interests

Liquefaction plant Start dateRepsol equity


MT pa Repsol equity Net capacity MT

pa Plant type

PeruPeru LNG 2010 Yes 4.4 20.00% 0.9 MerchantTrinidad & TobagoAtlantic LNGTrain 1 1999 Yes 3 20.00% 0.6 MerchantTrain 2 2002 Yes 3.5 25.00% 0.9 MerchantTrain 3 2003 Yes 3.5 25.00% 0.9 MerchantTrain 4 2005 Yes 5.2 22.20% 1.2 MerchantEgypt (through Gas Natural) 3.5Damietta (Train 1) 2005 No 5.1 12.32% 0.6 TollingOman (through Gas Natural)Qalhat LNG (Train 1) 2006 No 3.7 1.14% 0.0 MerchantTotal operational capacity 5.1Potential developmentsTrinidad & TobagoAtlantic LNG Train 5 2017 Yes 5 22.50% 1.1 MerchantTotal development potential 1.1

Source: J.P. Morgan

Repsol YPF legacy assets

concentrated in Atlantic basin

No new green field

developments on agenda

102




As per its liquefaction capacity, Repsol YPF's re-gasification capacity is also concentrated in the Atlantic Basin. Its re-gas capacity represents 126% of its net liquefaction capacity (5.1 MT pa at end 2011).

Table 25: Repsol YPF – re-gasification terminal rights

Terminal name Location Start upFull Capacity

(Bcm pa)Repsol equity

interestRepsol capacity rights (Bcm pa) Ownership

Bilbao port Spain 2003 2.7 25% 0.7 Equity interestCanaport Canada 2009 10 75% 7.5 Equity interestEcoElectrica Puerto Rico 2000 0.7 15% 0.1 Through Gas NaturalSagunto Spain 2006 6.7 6.5% 0.4 Through Gas NaturalEscobar Argentina 2011 4.0 29.1% 1.2 Through YPFReganosa Spain 2007 3.6 2.8% 0.1 Through Gas NaturalTotal re-gasification capacity 10.0Expansions/developmentsTrieste Italy 2014+ 8.0 30.8% 2.5 Through Gas NaturalTaranto Italy 2014+ 8.0 30.8% 2.5 Through Gas NaturalTotal new capacity 4.9

Source: J.P. Morgan

LNG shipping assets

Repsol YPF's LNG shipping assets are managed via Stream, a 50/50 JV with Gas Natural. This JV manages c.17bcm pa of LNG volumes (around 296 cargoes pa) and has a fleet of 20 LNG vessels (2,719,000 M3) with vessel sizes ranging from 35,000 M3 to 173,800 M3 (Table 26). The LNG cargoes are sourced from Trinidad & Tobago, Qatar, Nigeria and Libya and delivered to Spain, France, USA, Mexico, Brazil, Argentina and Japan (Figure 64).

Figure 64: Repsol YPF – LNG supply and delivery points

Source: Stream

Repsol YPF's re-gas capacity is

126% of its liquefaction capacity

Repsol YPF's LNG shipping assets managed via JV with

GasNat.

103



Table 26: Repsol YPF - LNG vessel portfolio

LNG vessel name Vessel capacity (m3) Comments

Anabella 35,000 Gas Natural charteredSCF Arctic 71,500 Gas Natural charteredSCF Polar 71,500 Gas Natural charteredNorman Lady 87,500 Gas Natural charteredCatalunya Spirit 138,000 Gas Natural charteredMadrid Spirit 138,000 Repsol CharteredBilbao Knutsen 138,000 Repsol CharteredC.Villalba 138,000 Gas Natural charteredSestao Knutsen 138,000 Repsol CharteredIberica Knutsen 138,000 Repsol CharteredHispania Spirit 140,500 Repsol CharteredBarcelona Knutsen 173,000 Repsol CharteredSevilla Knutsen 173,000 Repsol CharteredValencia Knutsen 173,000 Repsol CharteredRibera del Duero Knutsen 173,400 Repsol CharteredCastillo de Santisteban 173,800 Repsol CharteredSTX Frontier 153,400 Repsol CharteredMaersk Methane 165,500 Repsol Chartered - short termTrinity Arrow 154,900 Repsol Chartered - short termGolar Grand 145,000 Repsol Chartered - short term

Total capacity 2,719,000

Source: J.P. Morgan, Stream


Repsol YPF's creation of a stand alone LNG division in its re-organization in 2007 ensures that we have explicit disclosure on the financial performance of this business. This improvement in disclosure was a very positive step in our view – and we believe it would be beneficial if the company went further to report the segmental tax and adjusted net earnings for LNG also.

We estimate that LNG will contribute c. €350m of operating income in 2012 (€250m operating earnings of Repsol YPF's LNG segment and c.€100m contributed by LNG business of Gas Nat - net share of Repsol YPF). If we apply a multiple of 7x to this stream (low multiple given the above average exposure of the company's portfolio to the depressed North American market – 75% of the Peru LNG volumes priced off Henry Hub), we infer a potential equity valuation of c. €2.5bn. This represents close to € 2 per share and just under 7% of our sum-of-the-parts value of around €28.


around €2.5bn or €2 per share

104



Figure 65: Repsol YPF - Liquefaction capacity and sales (Net MTpa)


Figure 66: Repsol YPF - LNG sales by quarter (MT)

Source: J.P.Morgan

Figure 67: Repsol YPF - Adjusted operating income by quarter (M€)

Source: J.P.Morgan

Figure 68: Repsol YPF - LNG cargoes sold and LNG volume(Tbtu)

Source: Company presentation, J.P.Morgan

0

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7

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1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

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sal

es

(Mtp

a)

Liq

ue

fact

ion

ca

pac

ity

(M

tpa)

Angola Trinidad & Tobago Egypt (through G N) Oman (through G N) LNG sales (TBtu)

Possible

0

0.5

1

1.5

2

2.5

3

2007 2008 2009 2010 2011

LNG sales by quarter (Mt)

0

20

40

60

80

100

120

140

2007 2008 2009 2010 2011

Adjusted operating income (M€)

150

200

250

300

350

400

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2008 2009 2010 2011E

Re

pso

l LN

G V

olu

me

s (T

btu

)

# o

f ca

rgo

es

# of cargoes Repsol LNG Volumes (Tbtu)

105



Statoil


Figure 69: Statoil - Location of key LNG assets

Source: J.P. Morgan

Developing a world class LNG business has not been at the forefront of Statoil's corporate strategy given that a very high percentage of its upstream gas volumes are sold via pipeline in to Europe. The company's exposure to LNG business is limited to one liquefaction plant (Snohvit) located in Hammerfest, Norway and its capacity rights to the Cove point re-gasification terminal in the US. Statoil's LNG business sits within its Manufacturing, Processing and Renewable Energy segment.

Given its historic roots in piped gas and the dominant position that the company enjoys within Europe's gas markets, it is very unlikely that there will be any major shift in the company's approach towards LNG. It has, and will retain, a niche presence in LNG. However, it is clear that the focus of the company's small LNG business is shifting away from the US. In 2010, Statoil diverted 14 cargoes away from the US into Europe and Asia. Furthermore, Statoil has also significantly reduced its commitments relating to re-gas capacity at the Cove point terminal.



Operational Re-gasification capacity (Bcm/y)


10.9*

(Cove Point*, 0%)

4.2

(Snohvit LNG, 33.53%)

* Statoil have a long term contract with the operator of Cove point with capacity rights of 10.9bcm/yr. Statoil does not have equity interest in the regasification terminal

7.5

(Shtokman (FEED), 24%)

Nitin Sharma

(44-20) 7155 6133

[email protected]

Piped gas will remain the

'backbone' of Statoil...no major shift towards LNG is expected

106



Liquefaction assets

Snohvit LNG was commissioned in 1997 - it is the first and only LNG liquefaction plant in Europe. The project has experienced considerable technical issues since its commissioning. Numerous outages at this plant were related to leakages in the sea water heat exchangers.

We believe that Snohvit could play a vital role in the company's plan to develop gas discoveries in the remote Barent sea. Statoil is currently evaluating an expansion plan for this project with natural gas feed stock from the Goliat field. Statoil is also responsible for marketing the Norwegian state's share of Snohvit output, therefore the company markets c.64% (net Statoil is 34%) of the total output from the project -primarily to the USA (Cove Point) and Spain (sold to Iberdrola). Whilst we believe that Snohvit is a world class project, we also highlight its history of delays and operational issues. In our view, the reliability of this asset is still not beyond doubtalthough management is now confident on the reliability of the plant.

Statoil does not have any green field projects on its near/medium term agenda (Table 27). The Shtokman gas and condensate field was discovered in 1988. This project has been on the drawing board for over 10 years. Shtokman is still pre-FID (Statoilstake 24%, TOTAL 25% and Gazprom 51%). Statoil acknowledges that the timelineof this project remains uncertain and final fiscal terms for the project are yet to be agreed. Recent press reports suggest that Statoil (and TOTAL) want significant fiscal support for the Shtokman project. Either way, it is clear that the end 2011 FID timeline has now slipped in to 2012, if not beyond. In our view, both international participants require 'water tight' and supportive fiscal arrangements (including tax concessions) before agreeing to sanction this project.

Table 27: Statoil - Liquefaction interests

Liquefaction plant Start dateStatoil equity


MT pa Statoil equity Net capacity MT

pa Plant type

NorwaySnohvit 2007 Yes 4.2 33.53% 1.4 MerchantTotal operational capacity 1.4Potential developmentsRussiaShtokman LNG 2018 No 7.5 24.00% 1.8 MerchantTotal development potential 1.8

Source: J.P. Morgan


Statoil has two long-term capacity contracts (with Dominion Resources) for capacity rights at the Cove Point LNG re-gasification terminal in Maryland, USA. The first is for c.3.2 bcm pa (or one third of Cove Point’s capacity) and the second is for 100% of the Cove Point Expansion (CPX) capacity of approximately 7.7 bcm pa –total re-gasification capacity of 10.9 bcm pa. This long-term capacity agreement was renegotiated in December 2010 – we understand that the Cove Point expansion capacity contract term has been reduced from 18 to 10 years. We also believe that the utilization level of this terminal is particularly low as Statoil is diverting cargoes from Snohvit to Asia and Europe.

Snohvit – Europe's first and only

liquefaction plant

No green field developments on

the agenda

Negotiated significant reduction in the Cove point regas capacity

107



LNG shipping assets

Statoil charters a fleet of four LNG vessels of which three are on long term charters (Arctic Discoverer, Arctic Princess and Arctic Voyager) and one is on a short term charter. We estimate that 65-70 cargoes of LNG per year are shipped from the Snohvit liquefaction plant.


Given the very small size of Statoil's LNG business, the company does not report this business as a separate segment - it resides within Statoil's Manufacturing, Processing and Renewable Energy segment. This means that assessing the financial performance of the company's LNG business is not straightforward due to lack of adequate disclosure.

Our FY 2012E estimate for the LNG business operating income is Nkr1.2bn – weexpect more cargoes to be diverted to Europe/Asia and capacity at Cove point to remain under-utilized. If we apply a multiple of 8x to this stream, we infer a potential equity valuation of c.Nkr9.6bn. This represents just over Nkr 3 per share and just under 2% of our sum-of-the-parts value of around Nkr185.

Statoil charters a fleet of 4 LNG

vessels

LNG business resides within the

MMR segment


around Nkr9.6bn or Nkr3 per

share

108



TOTAL


Figure 70: TOTAL - Location of key LNG assets

Source: J.P. Morgan


TOTAL's strategy for its LNG business is driven primarily by the company's bullish outlook for global gas demand. TOTAL has aggressive investment plans for this sub-segment and is looking to deliver 50% growth in its LNG volumes by end 2020. TOTAL plans to have a balanced exposure across the LNG value chain. TOTAL’s LNG business sits within its upstream business segment – its disclosure on LNG on a standalone basis is limited.

TOTAL has a long history in the LNG business – it was the joint operator of the Arzew plant (Algeria), the first liquefaction plant in the world. A notable acceleration in TOTAL's LNG investment took place in 2000s, in particular in the second half of this decade. As per Figure 70Figure 70, TOTAL now has a very strong position on the global LNG stage - it has a well diversified presence. We estimate that by end 2011, TOTAL has net liquefaction capacity of almost 18.9 MT pa, growth of 47% relative to its 2005 base. TOTAL also has the potential to increase its net liquefaction capacity by more than 50% by 2020 based on 2.7 MT pa projects underway and a further 7.6 MT pa of potential projects.



Operational Re-gasification capacity (Bcm/y)

40

(Snohvit LNG, 18.4%)

(Nigeria LNG T1-T6, 15%)

4.2

21.9


6.7

(Yemen LNG, 39.62%)

8.5

(Nigeria LNG T7

(FEED), 15%)

3.7

(Qalhat LNG, 2.04%)

7.2

(Oman LNG, 5.54%)

22.2

(Bontang, 41.5%)

5.6

(Adgas, 5%)

9.9

(Qatargas 1, 10%)

7.8

(Qatargas 2, Train 5

- 16.7%)

5.2

(Angola LNG, 13.6%)

7.2

(GLNG, 27.5%)

10

(Brass LNG (FEED), 17%)

8.4

(Ichthys LNG (FEED), 24%)

7.5 (Shtokman (FEED), 25%)

(Sabine Pass, Capacity

subscribed by Total - 10Bcm/y)

6.7

(Altamira, , 25%)

5

(Hazira, 26%)

8.25

(Fos Cavaou, 28.03%)

21 (South Hook, 8.35%)

10 (Dunkirk, Capacity rights)


15

(Yamal LNG, 20%)

10

(Adria, 27.36%)

Nitin Sharma

(44-20) 7155 6133

[email protected]

LNG is a key plank in TOTAL's

growth strategy

TOTAL aims to be 'world leader

in LNG' by 2030

109



TOTAL's growth pipeline has many capital intensive and challenging LNG projects, bearing high political and technical risks e.g, Yamal LNG, Shtokman LNG and Ichthys LNG. It is clear that TOTAL has emerged as a key LNG player on the global scene but we sense that the next leg of its growth will be more challenging – with pressure on both timelines and costs –risks that are all too common within the IOC landscape. We also believe that TOTAL has plans to expand its LNG arbitrage capture. Competing with BG Group in that space will be challenging, in our view.

Liquefaction assets

TOTAL has an impressive portfolio of operational liquefaction assets – its footprint expanded in Asia following the start up of the Qatar LNG 2 and Yemen LNG in 2010 (Table 28). The company has a net liquefaction operating capacity of 18.9MT spread across seven countries in three continents – so bears a diversified geographical footprint which is likely to grow as projects in Australia (Ichthys LNG) and Russia (Shtokman LNG) come on-stream. Indeed, TOTAL ranks 3rd in the global ranking of the IOC liquefaction capacity. TOTAL’s net liquefaction capacity is located 49% in Asia Pacific (Indonesia), 30% Middle East (Abu Dhabi, Yemen, Qatar, Oman), 17% in Africa (Nigeria) and 4% in the Europe (Norway).

We estimate that 2012-16, TOTAL will add 2.7mt of net capacity to its portfolio of LNG projects - from 2 projects under development (Angola LNG and GLNG, Australia). In particular, these include TOTAL's first LNG project (GLNG) using unconventional source gas (coal seam gas). In 2010, TOTAL acquired a 20% integrated position in this project (the upstream resources and the LNG project). TOTAL also committed to an off take contract of 1.5 MT pa from GLNG. Overall both projects show good momentum with Angola LNG very close to its scheduled start up in early 2012.

Beyond 2016, we see potential to add another 7.6 MT pa via 3 green field projects (Australia, Nigeria, Russia) and 1 brown field project in (Nigeria). As such, by 2020, TOTAL could have a total of 29.2 MT pa in 12 liquefaction plants. This represents potential growth of +54% versus YE 2011 operational capacity and a capacity CAGR 2011-20 of almost 5%. TOTAL is obviously making good progress on its LNG growth agenda – but we feel that delivery on budget and on time will remain the key challenges especially on the projects in the 'potential development' category (Table 28).

Project pipeline contains many

capital intensive and technically

challenging projects

Almost 19 MT pa of net

operating capacity spread

across seven countries

2 green field developments

underway increase the capacity

by 14%

Development options include

another 7.6 MT pa

110



Table 28: TOTAL- liquefaction interests

Liquefaction plant Start date TOTAL equity supply Gross capacity MT pa TOTAL equity Net capacity MT pa Plant type

YemenYemen LNG 2009 No 6.7 39.62% 2.7 MerchantIndonesiaBontang T1-T9 1977 Yes 22.2 41.50% 9.2 MerchantAbu Dhabi (ADGAS)ADGAS 1977 No 5.6 5.00% 0.3 MerchantNigeria (Bonny LNG)Train 1 1999 Yes 3.2 15.00% 0.5 MerchantTrain 2 1999 Yes 3.2 15.00% 0.5 MerchantTrain 3 2002 Yes 3.2 15.00% 0.5 MerchantTrain 4 2005 Yes 4 15.00% 0.6 MerchantTrain 5 2006 Yes 4 15.00% 0.6 MerchantTrain 6 2007 Yes 4 15.00% 0.6 MerchantOman 3.2Oman LNGTrain 1 2003 No 3.6 5.54% 0.2 TollingTrain 2 2004 No 3.6 5.54% 0.2 TollingQalhat LNGTrain 1 2006 No 3.7 2.04% 0.1 TollingQatar 0.5Qatargas 1 1999 Yes 9.9 10.00% 1.0 MerchantQatargas 2 (T5) 2010 7.8 16.70% 1.3 MerchantNorway 2.3Snohvit 2007 Yes 4.2 18.40% 0.8 MerchantTotal operational capacity 18.9Development projects underwayAngolaAngola LNG 2012 Yes 5.2 13.60% 0.7 MerchantAustraliaGLNG 2015 Yes 7.2 27.50% 2.0 MerchantTotal development capacity 2.7Potential developmentsAustraliaIchthys LNG 2016-2017 Yes 8.4 24.00% 2.0 MerchantNigeriaNigeria LNG (Train 7) 2019 Yes 5 15.00% 0.8 MerchantNigeria LNG (Train 8) 2020 Yes 8.5 15.00% 1.3 MerchantBrass LNG 2018 Yes 10 17.00% 1.7RussiaShtokman LNG 2018 No 7.5 25.00% 1.9 MerchantYamal LNG 2019 No 15 20.00% 3.0 MerchantTotal development potential 10.6

Source: J.P. Morgan


As per Table 29, TOTAL has re-gasification capacity rights to a total of 17 bcm(12.6 MT) pa via five operational terminals in five countries across three continents. This represents 66% of TOTAL’s net liquefaction capacity (18.9 MT pa at end 2011). Just 41% of its capacity is owned with the balance leased under long term (20 year or more) lease agreements. It is clear that TOTAL's portfolio will become increasingly long liquefaction as new liquefaction assets come on-stream and givenlimited growth in re-gas capacity. This may position the company well to capture more LNG arbitrage opportunities.

TOTAL's portfolio will become

long LNG supplies given limited growth in re-gas capacity

111



Table 29: TOTAL – re-gasification terminal rights

Terminal name Location Start upFull Capacity (Bcm

pa)TOTAL equity

interestTOTAL capacity rights

(Bcm pa)

Hazira Gujarat, India 2005 4 26% 1.04Altamira * Altamira, Mexico 2006 6.7 0% 1.7Fos Cavaou France 2009 8.3 28% 2.3South Hook United Kingdom 2009 21 8.4% 1.8Sabine Pass U.S.A 2008 (Phase 1) and 2009 (Phase 2) 40 10.0Total re-gasification capacity 16.8Expansions/developmentsDunkerque LNG France 2014 10-13 0 2Adria LNG Croatia 2017 10 27.36% 2.7Total new capacity 4.7

Source: J.P. Morgan


TOTAL does not explicitly disclose the performance of its global LNG business which is included in its upstream segment. However, in recent years the company has indicated the approximate contribution of this business to the overall upstream segment. We believe that management is increasingly aware of the need to demonstrate the value of its LNG business and is therefore looking to increase the disclosure on this sub-segment. We encourage any such move.

In 2010 TOTAL indicated that the LNG business accounted for 20% of adjusted net earnings of its upstream segment or around €1.8bn. Our FY 2011E estimate for the upstream segment net income is around €9bn and we expect the LNG business contribution to increase to 25% or €2.3bn (9M 2011 contribution is 25%). If we apply a multiple of 8x to this stream, we infer a potential equity valuation of just over €18bn. This represents €8 per share and c. 14% of our sum-of-the-parts value of around €56/share. This value captures some of the value of TOTAL’s upstream reserve value of gas that feed in to its liquefaction facilities.

Limited financial disclosure


around €18bn or €8 per share

112



Figure 71: TOTAL - Liquefaction capacity – net (MT pa)

Source: J.P. Morgan

Figure 72:TOTAL - LNG sales by quarter (MT)

Source: J.P. Morgan

Figure 73: TOTAL - LNG sales by plants (MT pa)

Source: J.P. Morgan

0

5

10

15

20

25

30

35

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Yemen Indonesia Abu Dhabi Nigeria Oman Qatar Norway Angola Australia Russia

Under Construction

Possible

0

0.5

1

1.5

2

2.5

3

3.5

4

2007 2008 2009 2010 2011

LNG sales by quarter

0

2

4

6

8

10

12

14

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Indonesia (Bontang) Nigeria (NLNG) Abu Dhabi (Adgas) Qatar (Qatargas I) Qatar (Qatargas II) Oman Norway (Snohvit) Yemen LNG

113



Chevron


Figure 74: Location of key LNG assets


Chevron’s LNG position is primarily focused on the Asia-Pacific region, with major Australian LNG developments at Wheatstone and Gorgon, both operated by Chevron, serving as the flagship projects. Chevron also has non-operated interests in the Browse Basin fields that will feed the Browse LNG development, and in the North West Shelf Venture, both of which are also in Australia. In West Africa, Chevron holds an interest in the Angola LNG project which is close to completionand in Olokola LNG in Nigeria which remains in concept stage.


Chevron’s upstream strategy is to grow profitably in core areas and build new legacy positions by achieving world-class operational performance, maximizing and growing the base business, leading the industry in selection and execution of major capital projects, achieving superior exploration success, growing and developing equity gas resource base, and identifying, capturing and effectively incorporating new core upstream businesses. In our view, LNG development is a key component of this strategy, securing an outlet for Chevron’s a large worldwide natural gas resource base and leveraging Chevron’s skills in major capital projects execution.

Operational liquefaction capacity (MT pa)

Liquefaction under construction (MT pa)

Operational re-gasif ication capacity (bcm pa)

LNG project (FEED or under study) (MT pa)

16.3

(NW Shelf, 17%)

(Gorgon LNG, 47%)

15.0

(Wheatstone, 74%)

8.9

5.2

(Angola LNG, 36%)

12.0

(Browse, 16.7-20%)

12.6

(Olokola LNG, 20%)

4.7

(Delta Caribe , 10%)

(Sabine Pass, Capacity subscribed by Chevron –

10.2Bcm/y)

40

Katherine Lucas Minyard, CFA

(1-212) 622-6402

[email protected]

LNG exposure is Australia focused

LNG has long been a key

strategic focus

114



Australian LNG developments commercialize largest natural gas resource base in the country. The dominant resources and projects in Chevron’s LNG portfolio are in Australia, where the company holds more than 10% of its year-end 2010 net proved oil equivalent reserves, and 25% of its proved natural gas reserves. Chevron’s current LNG production in Australia is close to 50 kboepd, all from the non-operated North West Shelf (NWS) Venture. However, we estimate this will increase another 420 kboepd once Gorgon and Wheatstone are fully operational, making the upcoming developments perhaps far more important than the existing production.

Chevron’s currently-producing LNG operations in Australia are in the NWS Venture, Chevron holds a 16.7% interest in the project, which operates offshore fields to feed five LNG trains and a domestic gas plant. In 2010, NWS produced over 630 kboepd (106 kboepd net to Chevron), of which more than 70%, or 2.7 bcfpd, was natural gas (456 mmcfd net to Chevron). About 70% of the NWS natural gas, or half of the total production, was sold as LNG to utilities in Japan, South Korea, and China, and most of these sales were governed by long-term contracts.

In 2009, Chevron sanctioned the Gorgon LNG project, in which it holds just over 47% interest and serves as operator. The ~$40bn Gorgon project is expected to commercialize 40 TCF of natural gas from the Jansz and Gorgon fields via liquefaction at a three-train, 15 MT pa facility on Barrow Island, off the northwest coast of Australia, and a domestic pipeline. First gas is expected in 2014E, and at last update, Chevron had agreements in place for the sale of more than 90% of its equity LNG under long-term contracts with crude oil-indexed pricing, with utilities in Japan and South Korea as primary clients. As of mid-2011, Chevron had awarded more than $25bn in contracts and the project was ~30% constructed.

More recently, Chevron sanctioned the Wheatstone project. Chevron operates and holds a 73.6% interest in the onshore project, which includes an 8.9 MT paliquefaction facility, a separate domestic natural gas facility, and related storage and transportation infrastructure. Chevron also operates and holds a 92% interest in the Iago and Wheatstone fields, which will provide 80% of full-capacity natural gas for the liquefaction facility. First volumes are currently scheduled for 2016E. As of project sanctioning, Chevron had contracted 60% of its equity LNG off-take, with an ultimate target of at least 80%, including the impact of selling down equity, which we estimate would be modest. Chevron estimates its net investment in Wheatstone would be in the range of $16bn to $22bn.

West Africa LNG adds geographic diversity, but gas destinations may be less lucrative than Asia-Pacific. Chevron also holds a 36.4% interest in the Angola LNG project, a 5.2 MT pa LNG plant expected to begin operations in 2012E, as of most recent guidance. The facility is designed to process 1.1 bcfpd of natural gas, resulting in average daily sales of 670 mmcfd of re-gasified LNG and 63 kbpd ofNGLs. The project is also expected to supply 125 mmcfd of natural gas for domestic use in Angola. Total investment is estimated at $9.0bn. At the time of the project’s sanctioning, in late 2007, the LNG was scheduled to be delivered to the US, raising the potential for Henry Hub-based pricing if the gas cannot be sold in to another higher priced destination.

Also in West Africa, Chevron holds a 19.5% interest in Olokola LNG in Nigeria. Although there is no timing for a final investment decision, the vision is for a multi-train liquefaction facility northwest of Escravos, east of Lagos along the Gulf of Guinea coast.

Only operational plant is NWS

Venture

Gorgon LNG is well underway

Wheatstone LNG now following

Angola LNG on stream early

2012

115



Liquefaction assets

Upon completion of the Wheatstone project in 2016E, Chevron will hold 18.3 MT pa of net liquefaction capacity, largely concentrated in Australia and focused on sales to the Asia-Pacific market. Just over 10% of its capacity, the Angola LNG project, will be outside the Asia-Pacific region, consistent with the Asia-Pacific focus in the portfolio as a whole.

Table 30: Chevron - major liquefaction assets

Liquefaction plant Location Start-upGross capacity

(MT pa)Chevron Interest

Net capacity (MT pa)

Asia-PacificNorth West Shelf Venture Australia 1989 16.3 17% 2.7Gorgon Australia 2014 15.0 47% 7.1Wheatstone Australia 2016 8.9 74% 6.6

West AfricaAngola LNG Angola 2012 5.2 36% 1.9

Total capacity 45.4 40% 18.3

Potential developments Location Interest Comments

Browse LNG Australia 16.7-20% Preliminary field development plan submitted in 2010Olokola LNG Plant Nigeria 20% FID timing remains uncertainDelta Caribe LNG Venezuela 10% Declaration of commerciality accepted by Venezuela in

2010

Source: Company reports, industry sources, and J.P. Morgan.

Although there is also the potential for additional LNG projects, we are reluctant to factor projects not yet approved into our outlook. However, choosing among the potential developments, we would prioritize Browse LNG over projects in Venezuela and West Africa, given Chevron's proven familiarity with Australian LNG developments and the marketing of LNG into Asia, which we expect would be the logical target market for Browse LNG cargoes.

LNG re-gasification assets

Chevron’s primary presence in the LNG market is in the liquefaction of equity gas and the marketing of LNG cargoes, primarily into the Asia-Pacific market. However, we note that Chevron does have a small presence in re-gasification, having contracted capacity of 1 bcfpd at the third-party Sabine Pass re-gasification terminal in Louisiana. Given the pricing imbalance between international natural gas—especially oil-linked pricing—and North American natural gas, we expect Chevronto remain focused on its net long position in global LNG instead of its US domestic re-gasification presence.

LNG shipping assets

Consistent with its ownership interest in the NWS LNG project, CVX holds a one-sixth interest in seven LNG tankers that transport LNG cargoes for the project.


At this point, Chevron reports its LNG operations as part of the international upstream segment. Chevron does not disclose realized prices for its NWS LNG, and has also not disclosed full commercial terms for its Gorgon and Wheatstone projects, although it has indicated that the long-term contracts for both projects are indexed to oil.

Big interests in big LNG projects

Very small presence in US re-

gasification

116



In valuing Chevron’s LNG portfolio, we focus on four projects: NWS, Gorgon, Wheatstone and Angola LNG. We model oil-linked pricing for the three Asia-focused projects and Henry Hub-based realized pricing for Angola LNG. We assign no value to other future projects that are not yet approved, and we do not at this point assign any value to Chevron’s contracted re-gasification capacity in the US. Overall, we estimate the remaining NPV of the four main LNG projects at just under $17 per share, accounting for 14% of our $120 per share price target.

For NWS LNG, we assume shipments continue to the expiration of the current concession, through 2034E, and remain at current levels of roughly 320 mmcfpd net to Chevron. Given that the facility has been delivering LNG since 1989, we assume pricing is somewhat less favorable than the new contracts being signed in Asia Pacific. We base our revenues on a delivered LNG price of $7.2 per mcf, or 8% of our long-term $90/bbl oil price modeling assumption, and also assume netmaintenance capex of about $30m pa (or $0.25 per mcf). Using these parameters, we would estimate free cash flow of $300-400m annually through 2034E, net to Chevron, with prices and costs escalating at 2% annually. On our estimates, this would result in a net NPV of $4.1bn, or just over $2 per share.

For Gorgon and Wheatstone, we employ the same DCF model template, staggering the capex and production to adjust for the difference in timing of the two projects. Although we do not have specific LNG pricing for each contract from Chevron, we base our pricing on the broader industry curve provided by the company in recent presentations, which would suggest an LNG price of $14 per mcf at a long-term oil price of $90/bbl. For Gorgon, we model a forward NPV (excluding our estimate of capex spent through the end of 2011) of $40.4bn for the full project, and $19.1bn for Chevron’s 47.3% interest. This corresponds to just over $9.5 per share. For Wheatstone, given that the project is recently sanctioned, we would estimate that 95% of the capital expenditures have not yet been spent, making the project less valuable in terms of forward NPV than Gorgon. We estimate a year-end 2011 NPV of $9.3bn for the project as a whole, or $6.9bn net to Chevron, corresponding to about $3.4 per share, though we note that our analysis does not include any netbenefit to Chevron from future equity sell-downs.

For Angola LNG, given that the start-up is expected in 2012E, we assume that the majority of the $9.0bn in capital expenditures will have been spent as of the end of 2011. We also assume pricing consistent with our outlook for North American LNG pricing, noting that cargoes delivered elsewhere could be a source of improved economics. Our model suggests that on a $6 per mcf natural gas price long-term, the Angola LNG project would generate $250m in free cash flow annually, net to Chevron, in the initial years of the project. Assuming a 25-year life and a 2% annual price and cost inflation factor, we estimate the remaining NPV of the Angola LNG project at $3.7bn net to Chevron, or about $1.8 per share.

Estimated LNG value $17 per

share

117



Exxon Mobil


Figure 75: Exxon Mobil - Location of LNG assets

Source: J.P. Morgan. * Average effective interest shown for RasGas Trains 1-7.

ExxonMobil’s LNG portfolio is largely weighted toward liquefaction facilities in the Middle East, and more specifically a large aggregate position in 12 LNG trains in Qatar. Exxon Mobil also holds an interest in an LNG plant in Indonesia, and is participating in two major LNG projects currently under development—Gorgon in Australia and PNG LNG in Papua New Guinea. On the receiving end, Exxon Mobil has re-gasification capacity in three major terminals: South Hook LNG in Wales, Adriatic LNG in Italy, and Golden Pass LNG in Texas.


Exxon Mobil’s upstream strategy is to identify, evaluate, selectively pursue, and capture the highest-quality resource opportunities ahead of competition. Guided by a multi-decade view on the evolution on the energy supply-demand balance that suggests power generation is the single-largest driver of energy demand through 2040, Exxon Mobil sees natural gas as the fastest-growing major fuel over the next three decades. Additionally, with demand growth outstripping local production capacity in Asia-Pacific and Europe, Exxon Mobil sees LNG meeting 15% of global gas demand by 2040.


Liquefaction under construction(MT pa)

Operational Re-gasif ication capacity (bcm pa)

LNG project (FEED or under study) (MT pa)

5

(Scarborough, 50%)

(Gorgon, LNG, 25%)

15.0

13.8

(PT Arun, 30%)

(PNG LNG, 33%)

6.6

9.9

(Qatargas 1 -Trains1-3, 10%)

15.6

(Qatargas 2 - Trains 4-5 , 24%)

36.3

(RasGas- Trains 1-7, 29.5%*)

21 (South Hook, 24%)

8

(Adriatic, 69%)21

(Golden Pass terminal, 18%)

Katherine Lucas Minyard, CFA

(1-212) 622-6402

[email protected]

LNG portfolio centered in Qatar

Strategy acknowledges the long

term potential of gas

118



Exxon Mobil has positioned itself accordingly in the LNG market, with a portfolio that is largely designed to commercialize large natural gas deposits as delivered LNG cargoes into the growing Asian market. Exxon Mobil’s currently-producing facilities in Qatar and its facilities under development in Australia and PNG also benefit from oil-linked pricing, providing balance in a global portfolio that also has a large North American natural gas resource position.

Qatar position dominates producing portfolio as Exxon Mobil commercializes vast non-associated gas resource. Exxon Mobil is partnered with Qatar Petroleum in the development of the North Field, commercializing in excess of 25 billion boe of non-associated natural gas. With the start-up in 2009 and 2010 of four new major 7.8 MT pa LNG projects (Qatargas 2 Trains 4 & 5, RasGas Trains 6 & 7), Exxon Mobil increased its net position in Middle East LNG to 15.5 MT pa of liquefaction capacity, accounting for nearly 80% of its current liquefaction capacity.

Cargoes from Qatargas 1 supply LNG to Japan and Spain, while shipments from Qatargas 2 are primarily delivered to the South Hook LNG terminal in the UK. Cargoes from the seven RasGas trains are delivered to Europe, Asia, and the US.

Southeast Asia position expanding as Gorgon and PNG LNG join PT Arun LNG in Exxon Mobil’s portfolio. Outside the Middle East, Exxon Mobil is growing its LNG position in the Australia-Pacific region, participating in the Gorgon project and serving as operator of the PNG LNG project. When both projects are complete, Exxon Mobil will hold just over 10 MT pa of net liquefaction capacity in the region. As mentioned above, the Chevron operated Gorgon project, in which Exxon Mobil holds a 25% interest, is expected to commercialize 40 TCF of natural gas from the Jansz and Gorgon fields via liquefaction at a three-train, 15 MT pa facility. First gas is expected in 2014E, and Exxon Mobil has contracted its equity gas to Petrochina and India’s Petronet LNG.

The PNG LNG project includes a 6.6 MT pa facility, and is expected to commercialize 9 TCF of natural gas over the life of the project. The project is estimated to cost $15bn for the first phase, with first LNG volumes expected in 2014. PNG LNG will provide a long-term LNG supply to four major customers in Asia: Chinese Petroleum Corporation, Taiwan; Osaka Gas Company Ltd; Tokyo Electric Power Company; and Unipec Asia Company Ltd, a subsidiary of Sinopec.

Liquefaction assets

Once Gorgon and PNG LNG are complete, expected during the middle of the decade, Exxon Mobil will hold 25.6 MT pa of net liquefaction capacity, 60% of which will be its current position in Qatar. The remainder will be in the Australia/Southeast Asia region, with LNG deliveries targeting the Asian market as well as the European market.

Qatar is the world’s largest LNG

exporter

Also has growth positions in

Australia and PNG

119



Table 31: Exxon Mobil - liquefaction facilities

Liquefaction plant Location Start-upGross capacity

(MT pa)

Exxon Mobil

Interest

Net capacity (MT pa)

Middle EastQatarGas 1 (Trains 1-3) Qatar Various 9.9 10% 1.0QatarGas 2 (Trains 4,5) Qatar 2009 15.6 24% 3.7RasGas Train 1,2 Qatar 1999 6.6 25% 1.7RasGas Train 3 Qatar 2004 4.7 30% 1.4RasGas Train 4 Qatar 2005 4.7 34% 1.6RasGas Train 5 Qatar 2006 4.7 30% 1.4RasGas Train 6 Qatar 2009 7.8 30% 2.3RasGas Train 7 Qatar 2010 7.8 30% 2.3

Asia-PacificPT Arun LNG plant Indonesia 1978 13.8 30% 4.1Gorgon LNG Australia 2014 15.0 25% 3.8PNG LNG Papua New Guinea 2014 6.6 33% 2.2

Total capacity 97.2 26% 25.6

Potential developments Location Interest Comments

Scarborough Australia 50% Development planning progressing

Source: Company reports, industry data, and J.P. Morgan.

LNG re-gasification assets

Exxon Mobil’s re-gasification assets are in Europe and the US. It holds an interest in three large LNG terminals, in the UK, Italy, and the US Gulf Coast. Given Exxon Mobil’s view that Europe will continue to need imported LNG, and the current pricing imbalance between European natural gas and North American natural gas, we would expect Exxon Mobil to focus on its European re-gasification facilities rather than its US facility in the near term.

Table 32: ExxonMobil - LNG re-gasification facilities

Re-gasification facility Location Start-upGross capacity

(mmcfpd) InterestNet capacity

(mmcfpd)South Hook LNG terminal UK 2009 2,000 24% 480Adriatic LNG terminal Italy 2009 775 69% 535Golden Pass terminal US Gulf Coast 2010 2,000 18% 352

Total capacity 4,775 29% 1,367

Source: Company reports and J.P. Morgan.


As with Chevron, Exxon Mobil’s LNG operations are embedded in the international E&P segment results, and the company does not disclose pricing formulas or the specific economic details of its LNG projects. However, we believe we can approximate the remaining NPV of its LNG portfolio with a few key parameters. We focus on the liquefaction projects, as at this point, we view the re-gasification assets and other related LNG infrastructure as supporting the commercialization of the LNG, rather than as stand-alone commercial assets.

We estimate the total value of the liquefaction portfolio is $64bn to $75bn, or $13.3-15.5 per share, heavily skewed to the currently-producing facilities in Qatar and Indonesia, and accounting for 14-17% of our $92 per share price target.

Modest re-gasification position

LNG estimated value $64bn to

$75bn or $13.3 to $15.5 per share

120



First, we note that the majority of Exxon Mobil’s liquefaction capacity is up and running, with the successful start-up of the last four major LNG trains in Qatar in 2009 and 2010. As such, we would anticipate that 19.6 MT pa of net capacity, associated with Exxon Mobil’s interests in the Qatargas, RasGas, and PT Arun LNG projects, should require only maintenance capex, making these projects sources of cash for the rest of the corporate portfolio - for LNG-related investment, other investment opportunities, or returns to shareholders.

Second, we would expect the majority of the LNG volumes from these projects to command oil-linked pricing, as the cargoes are primarily delivered to the Asian and European markets. Although the contracts are not necessarily as new as some of the more recently-signed contracts throughout the industry, and as such we do not necessarily believe they would receive pricing commensurate with what we have modeled for Gorgon and Wheatstone, we are comfortable modeling a long-term blended LNG price of $9-10.8 per mcf, or 10-12% of our long-term oil price of $90/bbl.

We also assume net maintenance capex of just under $250m annually (or $0.25 per mcf). In the absence of specific fiscal terms, we estimate a net producer take of 50%. Using these parameters, we would estimate near-term annual free cash flow generation of just over $4.5bn, net to Exxon Mobil, with prices and costs escalating at 2% annually. Assuming another 25 years of operations, this analysis results in a net NPV of $47.8bn to $58.5bn, or $9.9-12.1 per share on blended pricing of 10-12% of the oil price. As a comparison, this would increase to a range of $11.5-14.2 per share on a 40% net government take assumption, and would drop to $8.2-10.0 per share on a 60% net government take.

For Gorgon, we use a similar valuation method as that discussed in the Chevron section. We base our pricing on the broader industry curve shown in recent Chevronpresentations, which would suggest an LNG price of $14 per mcf at a long-term oil price of $90/bbl. For Gorgon, we model a forward NPV (excluding our estimate of capex spent through the end of 2011) of $40.4bn for the full project, and $10.1bn for its 25% interest. This corresponds to $2.1 per share.

Finally, for PNG LNG, we use a loftier pricing curve, similar to what we used for Gorgon, given what we believe are relatively newer contracts, as the project only received final approval in 2009. We have also used a long-term LNG price of $14 per mcf to correspond with $90/bbl long-term oil. We also estimate about 35% of the $15bn in capital investment would have already been spent as of year-end 2011, leaving just over $10bn in remaining capex between 2012E and project start-up in 2014E. At a government take level of 40%, we would estimate project free cash flow of a bit under $3bn annually once the project were up and running, or just below $1bn annually for Exxon Mobil on a 33% interest. We model a forward project NPV of $19.4bn, or $6.4bn net to Exxon Mobil, for $1.3 per share in value.

121



Gazprom

Figure 76: Gazprom - summary of LNG assets (net capacity)


Gazprom has the largest gas reserves and gas production among listed oil & gas companies, but it has had little interest in LNG until very recently, preferring to stick to its core business of pipeline gas. We understand that the idea to enter the LNG markets only came to Gazprom's CEO Alexey Miller (appointed in 2001) after his visit to the World Gas Congress in Tokyo in 2003, where the LNG market’sdevelopment was showcased. After Miller's return to Moscow, he instructed his management team to develop Gazprom's LNG strategy. The foray into LNG began with some one-off re-sale operations of LNG cargoes and swap operations with BP and GDF SUEZ in 2005-2006. At first, Gazprom seemed to be interested only in downstream (transportation to degasification) operations.

Buying 50% plus 1 share of the RD Shell-operated Sakhalin-2 project in February2007 gave Gazprom its first access to liquefaction capacity (50% of 9.6 MT pa), RD Shell-developed liquefaction technology of double-mixed refrigerant and direct contacts with some of the world’s largest end-users of LNG in the Asia Pacific region. At the moment, Sakhalin-2 LNG remains the only operational LNG project in Russia. There are plans for green field liquefaction capacity in the Arctic (Shtokman LNG), Pacific (Vladivostok LNG) and brown field expansion of Sakhalin-2 (Trains 3 and 4).

Apart from the equity stake in Sakhlin-2, Gazprom set up a stand-alone LNG marketing subsidiary- Gazprom Global LNG (GG LNG). It is headquartered in London with regional offices in Singapore and Houston. GG LNG buys and sells

Operational Liquef action capacity (Mt/y)




4.8 (Sakhalin-2)

1.2 (Sakhalin-2 train 3)

1.2Vladivostok LNG

3.75 (Shtokman1)

4

Cameron LNG, Lake Charles

2.5Costa Azul, Mexico

Nadia Kazakova, CFA

(44-20) 7325-6373

[email protected]

Resource rich but technology poor

Gazprom holds 50% plus 1 share in Sakhalin-2 project, operated

by RD Shell

A separate subsidiary Gazprom Global LNG was set up to build a

well-head to end user chain

122



LNG in single and multi-cargo deals. It has a long-term arrangement (2009-2028) to buy 1 MT pa of LNG from Sakhalin Energy. It charters LNG carriers and has arrangements to use re-gas capacity at the Costa Azul LNG terminal in Baja California, Mexico (100% owned by Sempra). GG LNG also structures complex deals with Gazprom affiliates involving pipeline gas, time swaps, options, and equity investments along the entire value chain from well-head to end user.


Gazprom's has a clear LNG manifesto - Strategy for LNG Production and Delivery –which forms part of Gazprom’s overall strategy:

Achieve LNG production levels of 76.5 MT pa by 2030, which could potentially amount to 14% of the global LNG market via new LNG production projects in Russia, participating in LNG projects abroad and purchasing LNG from independent projects and developing its own LNG marketing business.

Target countries of the Asia-Pacific region and to a lesser extent countries of the Atlantic region and Europe as primary markets for sales of LNG in the medium-term.

Globalize company's presence on foreign markets, diversify supplies and consolidate position of Gazprom as an international energy company.

Liquefaction assets

The Sakhalin-2 liquefaction plant has 2 trains with total name plate capacity of 9.6 MT of LNG (2x 4.8 MT pa). Gazprom owns 50% plus 1 share (RD Shell (27.5% – 1 share), Mitsui and Co. (12.5%) and Mitsubishi Corporation (10%)). The project (both upstream development and LNG operations) is operated under a PSA agreement that was signed in 1996.

Gazprom purchased 50% plus 1 share in Sakhalin Energy for $7.45 bn in April 2007. The current book value (as of 2Q11) is RUB151.4 bn or $5.3 bn for the stake, valuing the entire operations (oil & gas upstream/mid-stream and LNG) at $10.6bn. The fall in book value is due to redemption of preference shares and dividends paid.

The natural gas for liquefaction is produced at two offshore gas platforms - the Lunskoye-A platform (Lun-A) and Piltun-Astokhskoye-B platform (PA-B). They are linked to the LNG plant by 300 km of offshore and 1,600 km of onshore pipelines via an onshore processing facility and a booster station.

The gas liquefaction process in the LNG plant uses RD Shell-licensed double mixed refrigerant (DMR), which was tailored for severe cold seasons in Sakhalin. The plant officially opened with a delay in February 2009.

Sakhlin-2 has three purpose-built double-hulled LNG tankers, each with 145,000 M3

capacity. The carriers are on long-term charter and owned and operated by a Russo-Japanese shipping consortium. An extra tanker was leased in Sep 2011 – the 145,000 M3 Stena Blue Sky is on long-term charter from Stena Bulk.

Sakhalin Energy produced 5.3 MT of LNG in 2009, 10 MT in 2010 and 5.5 MT in H1 2011. Around 98% of the annual LNG plant capacity is contracted on a long-term basis. About 65% of the overall LNG volume produced is supplied to Japan. The rest is supplied to South Korea, and other destinations including India, Kuwait, China, and Taiwan.

RD Shell-built Sakhalin -2 remains the only operational

LNG plant in Russia

50% stake in Sakhalin -2 is

valued at $5.3bn in Gazprom's books

Offshore gas platforms linked by

1,900 km of pipelines to

liquefaction plant/export facilities in Prigorodnoye

123



Table 33: Sakhalin-2 long-term supply contracts

Contract signed Contracts for the supply of LNG from Sakhalin-2 MT pa Contract dates Term Destination

Nov-04 TEPCO 1.5 2007-2029 FOB JapanJun-04 Kyūshū Electric Power Company 0.5 2009-2027 X-ship JapanJun-05 Toho Gas 0.5 2009-2027 X-ship JapanOct-04 Shell Eastern Trading Ltd 37 over 20 years 2008-2027 X-ship Mexico (?)Feb-05 Tokyo Gas 1.1 2007-2031 FOB JapanJul-05 Korea Gas Corporation 1.5 2008-2028 FOB South KoreaApr-06 Hiroshima Gas Co.Ltd 0.21 2008-2028 FOB JapanMay-06 Tōhoku Electric Power Company 0.42 2010-2030 FOB JapanAug-07 Chūbu Electric Power Company 0.5 2011-2026 X-ship JapanMar-09 Osaka Gas 0.2 JapanApr-09 Gazprom Global LNG (GG LNG) 1.0 2009-2028 X-ship (?) Mexico (?)Apr-09 Shell Eastern Trading Ltd * 1.0 2009-2028 X-ship Mexico (?)Jan-11 Guharat State Petroleum Company (GSPC) 0.2 2011-2012 X-ship India

Estimated total contracted 9.48Total capacity 9.6Capacity booked under long-term contracts 99%

Contract signed Other contracts for LNG from unidentified sources MT pa Contract dates Term DestinationJun-11 GAIL 2.5 25 years X-ship (?) IndiaJun-11 Petronet 2.5 25 years X-ship (?) IndiaJun-11 Guharat State Petroleum Company (GSPC) 2.5 25 years X-ship (?) India

Estimated total contracted 7.5

Source: J.P. Morgan estimates, Bloomberg.

The addition of an extra train to the existing LNG plant at Prigordnoye in Sakhalin appears to be the quickest and most economical way for Gazprom to add LNG capacity. The existing facilities have already allocated space for an extra train and it might be relatively easy to fit an extra 4.6 MT facility on to the existing LNG chain.

Officially, the source of gas for the expansion would be existing gas reserves of Piltun-Astokhskoye & Lunskoye fields. However, additional gas reserves are required. Gazprom is currently developing the offshore Kirinskoye field. It is situated near to the Sakhalin-2 Lunskoye field and is part of Salkhalin-III Kirinski block. Gazprom has recently accelerated development of the Kirinskoye field and a larger Kirinski block. It uses sub-sea production trees, a manifold for an underwater production facility rather than floating production platforms – cutting edgetechnology in Russia.

First gas production at the Kirinskoye field is planned for Q4 2012. The nearby South Kirinskoye field could be launched in 2013. The annual gas production of theKirinskoye field is estimated at 4.2 bcm (estimated gas reserves of 100-130 bcm). Output from the South Kirinskoye field (part of Kirinsky block) could be double that, given estimated gas reserves of 230 bcm (Source: Interfax). While both fields could be a source for Sakhalin-2 expansion, the current plan is to connect the Kirinskoye field to the Sakhalin-Khabarovsk-Vladivostok pipeline rather than to a much nearer Sakhalin-2 pipeline. In our view, if Sakhalin-2 explanation is approved as early as end 2011/early 2012, the Kirinskoye field/Kirinky block fields are the most obvious sources of gas. According to media reports (Bloomberg), RD Shell may offer Gazprom assets in Asia- possibly access to liquefaction capacity in Australia – in exchange for a deal to expand Sakhalin-2. That could be a win-win situation for Gazprom: it would be able to sell Kirinskoye field gas at a much better margin than if sold domestically or eventually via Vladivostok LNG (unlikely to be launched before 2017). Gazprom might also get access to brand new liquefaction assets outside Russia. RD Shell would get additional equity liquefaction capacity at a fraction of the

Sakhalin-2 expansion seems to

be seriously considered- could

precede Vladivostok LNG

Kirinsky block fields could

potentially supply gas to

Sakhalin-2

124



cost at a time when LNG prices in target markets (Japan, Korea and China) are very firm.

Another indication that Sakhalin-2 expansion might go ahead is the recent news that Gazprom Global LNG (GGLNG) ordered 2 new LNG tankers in July 2011. They will be built in South Korea and delivered in Q4 2013 and Q2 2014. Delivery dates are too early for Vladivostok LNG, but would be perfect to service Sakhalin-2 Train3. We have also seen GGLNG signing MoUs with three Indian gas companies to supply up to 7.5 MT pa of LNG (2.5 MT each) for 25 years. The timing suggests that Gazprom is confident of having extra LNG available within the medium term – again, pointing to Sakhalin-2 expansion being seriously considered. We would rate this project as the most likely to be implemented among all other Gazprom's projects (Vladivostok and Shtokman).

Green field projects

Vladivostok LNG. The plan is to build a 10 MT pa liquefaction plant on the Russian Pacific coast, in Perevoznoy Bay (south west from Vladivostok). The plant is to sit at the end of the yet-to-be constructed Yakutia-Khabarovsk-Vladivostok (Perevosnoy Bay) pipeline. The 2,035 km gas pipeline would feed from the giant Chayandinkoye oil and gas field in the Yakutia region. The 1.32 TCM gas /584 mmb oil field is under exploration - first commercial oil production is not expected before 2014 and first gas before 2016. The cost of the LNG plant is estimated by Gazprom to be $7bn (as of May 2011). Potentially, 70% of LNG output would go to Japan and 30% to South Korea.

There are numerous technical challenges to the Chayandinskoye gas field development: high levels of helium, low reservoir pressure and hydrate formation in producing wells. The construction of the gas pipeline might start in 2012, but the recent cuts in Gazprom's capex budget for 2012 might indicate some delays in both field development and pipeline build-out. If Gazprom sticks to the current time-table, the LNG plant could be launched in 2016-2017. In our view, delays are extremely likely.

Along with timing/technical issues, there are also environmental concerns. The area is currently sparsely populated and has a number of nature reserves. The construction of the second large gas pipeline and a large LNG plant in the region could be taxing.

Potentially, there is an alternative scenario for Vladivostok LNG development, in our view. There is a newly launched 6 bcm gas pipeline from Sakhalin to Vladivostok (to be expanded to 30 bcm). The gas is fed from existing Sakhalin-1 fields with plans to link in Sakhalin-3 green fields. Under the current plan, the pipeline is to be extended 239 km to the Russia/North Korea border (at Khasan), and then across North Korea to South Korea. Perevoznoy Bay is effectively on the route of this extension and the pipe can potentially feed a future LNG plant (rather than take gas to Korea). It might speed up the construction of LNG liquefaction facilities. The final decision will depend on the outcome of political negotiations/pre-FEED studies. In April 2011, a consortium of Japanese companies and Gazprom agreed to conduct a pre-FEED for the construction of a liquefied natural gas (LNG) plant with production capacity of 10 MT pa, a preliminary feasibility study on the compressed natural gas (CNG) pilot project and a preliminary study on gas-chemical complex project. The study was to be completed by end 2011.

Gazprom Global LNG (GGLNG)

orders 2 new LNG tankers and

signs supply contracts with India

LNG projects targeting Asian

markets might be given priority

The East Siberian gas field

developments are technically

challenging

Sakhalin gas could be fed into

Vladivostok LNG

125



Figure 77: East Siberia/Far East gas developments

Source: Gazprom. Note: Sakhalin—Khabarovsk-Vladivostok pipeline is now complete (6 bcm capacity)

Figure 78: Key facts for Vladivostok LNG Summary: The plant is being

planned in Vladivostok (Far East) based on gas production

from East Siberia and Sakhalin

Shareholders: Gazprom and

foreign partners

Capacity: based on

preliminary estimates annual capacity could amount to 10mn

tons annually

Source of gas: Sakhalin-

1/Sakhalin-2 state’s share piped via Sakhalin-

Khabarovsk-Vladivostok

pipeline, East Siberian gas via Sakha-Yakutia-Khabarovsk-

Vladivostok pipeline

Key market: Japan, Korea,

China

Timing: after 2017

Investments: $7 bn for LMG

plant

Source: J.P. Morgan estimates.

Shtokman LNG. The Shtokman development has been on the drawing board for over 10 years and remains the least likely to take off the ground, in our view. The 3.9 tcm Shtokman gas field was discovered in 1988. It lies 555 km offshore to the east of Murmansk in the Barent Sea and is in 350m of water. The original idea was to develop the field and link it to 7.5 MT liquefaction facilities (onshore at Teriberka). LNG output was to be exported, primarily to the US. The field would also be connected by a pipeline into the Russian Unified Gas system for supplies to domestic and international customers (via the Nord Stream).

The Shtokman development would require three stages. Stage one is the most complex and capital intensive stage. It would involve construction of one offshore platform (there is one for each phase), drilling of sub-sea wells and a 580-km subsea pipeline to the onshore facilities. The initial (stage 1) production capacity is planned at 23.7 bcm pa (for 25 years). The gas will be supplied to 7.5 MT LNG plant at Teribeka in Murmansk region as well as in to a 1.365-km Teribeika-Volkhov trunk pipeline. The new land pipeline would supply domestic customers in the Leningrad region as well as international buyers via Nord-Stream pipeline. The project would require 8 LNG tankers for the first stage of the operations.

On the drawing board for over 10

years and remains the least likely to take off the ground

During 1st stage of

development, a 7.5 MT pa, one train LNG plant to be built

126



Figure 79: Shtokman field development

Source: Gazprom

Figure 80: Key facts Summary: LNG plan is planned near

Murmansk (Russian North ), FID expected

2010

Shareholders: Gazprom (51%), Total (25%),

Statoil (24%)

Capacity: 1st phase: LNG plant with

capacity of 7.5mn tons. The second and the

third trains are discussed with 7.5mn ton

capacity each

Source of gas: 1.9 tcm (12.5 bn boe)

Shtokman gas field

Key market: Europe, Asia

Timing: Train 1 – 2017; trains 2,3 – 2018-

2020(?)

Investments: $28bn (1st stage) incl.

$10.8bn for LNG plant and tankers. Total investment budget is $44bn incl. $17bn for

LNG


Total costs of the first stage of more than $20bn are to be shared proportionally by Stage-1 shareholders: Gazprom (51%), TOTAL (25%) and Statoil (24%). The second and the third stages will expand production capacity to 72 bcm and potentially to 95 bcm pa (for 50 years) and liquefaction capacity to 14.4 MT pa. Total cost of all three stages is estimated at up to $44 bn.

Gazprom has postponed the Shtokman development a number of times and currently plans to put the field on stream in 2016 and to start LNG production in 2017. A final investment decision has been delayed from end 2011 to early 2012. The current book value of Shtokman Development AG (100%) is $1.157bn (as of end Q2 2011).

127



Table 34: Projected cost of Shtokman development

Projected Shtokman costs, $bn Stage 1 Stage 2-3 Notes

Sea production complex 13.2 7.5

Full well stream to shore, construction of 2 offshore platforms, drill 20 sub-sea wells, 580-km sub-sea pipeline to 7.5 MT pa LNG plant at Teribeika in Murmansk region

LNG plant 6.8 3.9Increase LNG capacity from 7.5 MT pa (stage 1) to 14.4 MT pa liquefaction at stage 2 and 3

Onshore pipeline 4.3 2.5 1,365km, 1,400km onshore link to North European Gas Pipeline (NEGP)LNG tankers 4.0 2.3 8-12 LNG tankers with capacity of up to 250,000 mcm each

Total costs 28.0 16.0

First stage (23.7-25bcm of capacity with output maintained for 25 years) = $15bn, financed proportionally to stakes. Launch pipeline deliveries in 2013, LNG deliveries in 2014. All three phases could cost $43-44bn

Source: J.P. Morgan estimates, Argue FSU (as of May 09).

The development of the offshore field and onshore facilities is a challenge, but the technical details have been mostly ironed out. The key element of the field development is subsea completion of wells, equipped with assembly, automatically regulated butterfly valves and hydrate inhibitor injection systems. The wells will be joined by subsea pipelines and manifolds. For the transportation of gas/gas condensate from the field, two-phase flow undersea pipelines are to be constructed. It would be the longest ever built, at 550 km, to shore over very uneven seabed.

Onshore, the project envisages construction of an LNG Plant, LNG Storage, Sea Port and Gas Treatment Unit, all part of Port Transportation Technological Complex. The LNG is to be constructed in 3 stages: start-up (phase 1), expansion phases 2 and 3. Under the start-up phase, a single 7.5 MT pa train will be built, based on Propane pre-cooled Mixed Refrigeration Cycle (C3/MR). The plant would be operational 333 days pa.

From a technical point of view, TOTAL cites the large scale of the project as one of the key challenges: the floating production unit would be one of the largest in the world, a unique subsea pipeline would need to be built and a mega-LNG plant to be constructed - all in a remote area, 550-km offshore in open sea with no near-by developments. The Shtokman field is an ice free area (occurring only once every 3-5 years), but the weather conditions are very harsh, equivalent to the northern part of the North Sea (strong winds, icing, 3-month long polar night). Ice drift and icebergs are one of the main concerns - the Shtokman floating production platform would be the first – and the largest - to operate in ice conditions.

The technical challenges might pale in comparison with the effect of the economic turbulence. Shtokman LNG cargoes were to be delivered to the US market. However, the surge of US gas shale production and the decline in US gas prices has killed these plans. European markets could be an option, but Russian LNG would compete with Russian piped gas, which is cheaper to produce and deliver. There might be a more complex option of swap operations with other LNG producers targeting Asian gas markets. However, the scale of the Shtokman development is probably too large for such swaps.

In addition, the foreign shareholders in Shtokman consortium have effectively said that Shtokman is uneconomic under the current Russian tax regime. They are asking for concessions similar to those granted to Novatek's Yamal LNG project. They include zero production tax on gas and gas condensate for 12 years, zero export duty on produced LNG and gas condensate, state subsidies for the infrastructure development (estimated at approx. $13bn). The Russian government is considering a

Large scale project faces numerous challenges

Large scale project in a remote location, in harsh weather

conditions

Low gas prices in the US made the economics questionable

Lack of tax breaks might delay FID and potentially bury the

project

128



special tax regime for offshore developments (which would cover Shtokman), but indicated that no specific tax breaks would be granted before the Final Investment Decision (FID) is taken by the Shtokman partners. So, it becomes a "Catch-22" situation: a positive FID is unlikely without the tax breaks, while tax breaks could only be granted if FID has been made. The final investment decision was expected by end 2011, but has been delayed.

There also have been media reports that TOTAL might be exiting Shtokman in order to focus on the Yamal LNG project, where it has 20% (Novatek 80%). The French company denied sending a letter to Shtokman partners which informed them of TOTAL's lack of interest in the Shtokman (source: RBC).

Re-gasification assets

Gazprom does not own any re-gas assets outright. It has made attempts to acquire interests in US re-gasification facilities, but these have been put on ice. At the moment, Gazprom via Gazprom Global LNG (GGLNG) has long-term re-gasification capacity at Sempra’s Costa Azul in West Mexico. It is about 1 MT paand was effectively sub-leased from RD Shell in April 2009. The re-gas capacity was originally for Sakhalin -2 LNG volumes, but cargoes have been diverted away.

GGLNG had a short-term agreement with Petronas at the Dragon terminal in Wales,but ended it after delivering a couple of cargoes. Gazprom has a multi-year contract for Cameron LNG re-gas terminal in the US Gulf, but this has not been used.

Table 35: Gazprom's re-gas exposure

Terminal name Location Status Capacity owners Capacity

Rabaska TerminalBeauport, Quebec, Canada Suspended (approval obtained)

Gaz Métro, Enbridge Inc. and Gaz de France 500 mmcf/day (5 MT pa)

Costa Azul LNG terminal Baja California, Mexico

Shell made a subleasing deal for a quarter of capacity with Gazprom Global LNG. No cargoes arrived from Sakhalin so far. Sempra LNG/RD Shell

1,000 mmcf/day (10 MT pa) split 50/50 between Sempra LNG and RD Shell

Dragon LNG Wales, UK

Delivered 2 cargoes in 2009 under cooperation agreement signed in Oct 09, but subsequently ended a short-term agreement with Petronas.

Dragon LNG (BG Group, 50%; Petronas, 50%)

6 billion cubic metres of LNG a year (operational from Sep 2009)

Cameron LNG terminal Lake Charles, USA

Multi-year contract to deliver 2 cargoes a month from Jun 2010 at pre-determined price formlula. Not currently used. Sempra (100%)

1.5 billion cubic feet per day of initial send out capacity (operational from July 2009)

Source: J.P. Morgan estimates, Company data

LNG shipping assets

Gazprom has a number of dedicated LNG tankers on long-term and short-term time charters. The company owns no tankers directly, the exposure is via Sakhalin Energy (4 LNG tankers on long-term charter) and also via 100%-owned subsidiary Gazprom Global LNG (GG LNG) which has a couple of ships on charter and has just ordered two ice 2 class LNG tankers for delivery in 2013-2014.

Sakhalin Energy has dedicated chartered LNG carriers. Three double-hulled 145,000 M3 LNG tankers were specially built for Sakhalin Energy in Japan in 2008. They are owned and operated by Russo-Japanese consortia (with Sovcomflot on the Russian side) and are on long-term time lease with the Sakhalin Energy. In September 2011, Sakhalin Energy charted a 145,000 M3 LNG tanker – the Stena Blue Sky (Dragon Ship) from Stena Bulk. Its first voyage with Sakhalin Energy LNG was to China.

129



Gazprom Global LNG Limited (GGLNG), Gazprom's dedicated LNG marketing subsidiary, has separate arrangements for LNG tankers. GGLNG is marketing at least 1 MT of Sakhalin-2 LNG and has time charters on at least 2 LNG tankers. The subsidiary has also signed a contract with Sovcomflot (100% owned by the Russian state) to charter two 170,000 M3 vessels for 15 years. The tankers will be constructed in a South Korean shipyard and delivered in Q4 2013 and Q2 2014. We assume the tankers are charted to ship LNG produced at yet-to-be agreed on Train 3 of the Sakhalin-2 LNG complex.

Table 36: Gazprom LNG shipping assets

Name of subsidiary/associates

Contract Date LNG carrier Status Capacity

Sakhalin Energy Oct-07 Grand Elena

On 20-year charter with Sakhalin Energy. Owned by the consortium of Sovcomflot (40%) and Nippon Yusen Kabushiki Kaisha (NYK) (60%) companies.

147,000 m3, Moss-type, 1C ice-class vessels

Sakhalin Energy Oct-07 Grand Aniva

On 20-year charter with Sakhalin Energy. Owned by the consortium of Sovcomflot (40%) and Nippon Yusen Kabushiki Kaisha (NYK) (60%) companies.

147,000 m3, Moss-type, 1C ice-class vessels

Sakhalin Energy Apr-08 Grand Mereya

On long-term charter. Owned by the consortium of Prisco, Mitsui O.S.K. lines, Ltd (MOL) and Kawasaki Kisen Kaisha, Ltd (K Line). 145,000 m3, Moss-type

Gazprom Global LNG Limited (GGLNG) Apr-09 Clean Power LNG ship Mid-term time charterGazprom Global LNG Limited (GGLNG) Mar-10

"Neva River" (ex-"Celestine River")

On term time charter from "K" Line LNG Shipping (UK) Limited (KLNG)

Sakhalin Energy Sep-11Stena Blue Sky (Dragon Ship)

Charted on long-term basis from Stena Bulk, renamed Dragon ship 145,000 m3

Gazprom Global LNG Limited (GGLNG) Jul-11

Atlantic max type, ice 2 class

To be on 15-year charter. Will be constructed by South Korean shipyard STX Offshore & Shipbuilding, owned by Sovcomflot. Delivery in Q4 2013 170,000 m3

Gazprom Global LNG Limited (GGLNG) Jul-11

Atlantic max type, ice 2 class

To be on 15-year charter. Will be constructed by South Korean shipyard STX Offshore & Shipbuilding, owned by Sovcomflot. Delivery in Q2 2014 170,000 m3


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Novatek

Novatek is a Russian independent gas and liquids producer – it does not have any LNG assets at the moment. In 2010-2011, the company purchased a license for 1.24 tcm South Tambeyskoye gas and gas condensate field from one of Novatek's major shareholders. In March 2011, TOTAL purchased 20% in the Yamal LNG development. Novatek stated that it would hold on to 51% of the project and 29% is to be sold to other investors. The development will go ahead only if additional shareholders are found. Novatek is in negotiations with the Qatari government on potential investments.

Figure 81: Yamal LNG development

Source: Novatek

Figure 82: Key facts Summary: The LNG plant to be built at Sabetta,

natural gas come from Tambeyskoye group of fields

Shareholders: Novatek (51%), Total (20%), yet-to-be

found (29%)

Capacity: Stage 1: 15 mn tons = 3 trains 5 mn tons

each

Source of gas: 1.24 tcm (8bn boe) South Tambei field,

1 tcm (6.6 bn boe)

Timing: Novatek targets LNG plant commissioning in

4Q2016

Key markets: US

Investments: $10-$20 bn by shareholders, $13 bn+ by

the government

Technological challenges: ice-class LNG carriers

needed, the Kara sea is frozen 10 months a year


Nadia Kazakova, CFA

(44-20) 7325-6373

[email protected]

Novatek owns 51% stake, TOTALholds 20% interest and 29% is

yet to be sold

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The total cost of the project is estimated by the Russian government to exceed RUB1 trillion ($33bn). Yamal LNG shareholders plan to spend $18-20bn on the field development and LNG facility with the balance being financed by the Russian government (port, LNG vessels and ice-breakers fleet). The complete FEED study should be ready by year end 2012. The FID is expected by end 2012/early 2013. Planned launch of the first LNG train is in Q4 2016.

A number of key issues are yet to be resolved. The Yamal LNG development plan envisages production of 25 bcm of gas and construction of a 15 MT LNG plant and export port facilities at Sabetta. The field development is relatively inexpensive: Novatek forecasts RUB10 bn / $3.3bn in capex with a launch planned for 2016. Construction of the LNG plant and the port facilities could prove to be more difficultand expensive. According to TOTAL’s presentation, the challenges include (1) four months of polar night with average temperatures below -20C (2) sea frozen for 270 days a year, leaving only 90 days for ice-free navigation. Ice breaker LNG tankers are required (3) 30km to be dredged in the mouth of Ob to allow for passage of LNG tankers (4) permafrost melting down 1-2 meters in summers, requiring special construction technologies.

The Yamal LNG shareholders are relying on the Russian government to finance some of the facilities, including the port harbor, approach channel, seaway channel (including 30-km of dredging), ice protection construction and administrative facilities. The government is also expected to finance development and construction of LNG fleet and ice breakers (if required).

The bigger challenge is transportation options for Yamal LNG cargoes. Novatek is looking at Europe, Asia and South America as potential target markets. However, there might be difficulties in shipping LNG all year around from the ice-bound Yamal. Novatek is looking at an option of trans-shipment of cargoes in Norway or direct routes to target markets. For either option, Novatek would most likely need a number of powerful and yet-to-be built ice-breakers in addition to ice class LNG tankers designed specifically for the project (they have maximum ice breaking abilities of over 2.3-2.4 meters on even ice). Even if the cost of transportation is effectively subsidized by the Russian state, the risks and costs of a year- round Arctic LNG route could prove to be prohibitive, in our view.

Project economics are heavily reliant on government support and tax holidays. In addition to various technical challenges, Yamal LNG economics appear to rely heavily on tax concessions granted by the government. The project will be effectively tax-free (no production tax, export duty or property tax) for the first 12 years after the launch of LNG production (or until 250 bcm of natural gas and 12 MTof gas condensate is produced). The corporate income tax rate is then reduced from 20% to 15.5%. We estimate that the project is loss making excluding tax breaks at stage 1 of the development and over 60% of project's NPV is attributable to tax breaks for Stage 2 development.

Table 37: NPV calculations for Yamal LNG ($m)

Yamal LNG stages WACC

Capex excl state

financingLNG price

(Asia, 2016E) Total NPVNPV of tax

breaksNPV ex

tax breaksIRR (with

tax breaks)

Stage 1: Full field development, all natural gasliquefied, condensate exported 12.7% 16,525 $9.4/mmbtu 354 938 -585 13%Stage 2: full field development, natural gas sold domestically at initial stage, liquefied at a later stage, all condensate exported 12.7% 26,301 $9.4/mmbtu 4,052 2,465 1,586 22%


Total cost of Yamal LNG

development is approx. $33bn,

$20bn to be financed by shareholders and remainder by

the Russian government

The project relies heavily on

state support

LNG transportation through

Arctic all year around could be a

challenge

Project economics rely heavily

on tax breaks

132



Oil Search

Figure 83: Oil Search - summary of LNG assets (net capacity, MT pa shown)



We have classified Oil Search as a “niche” type exposure to the global LNG industry thematic. The company’s LNG exposure is confined to a 29% non-operating interest in the ExxonMobil led PNG LNG project located in the Southern Highlands and Port Moresby regions of Papua New Guinea. The 2 train, 6.6 MT pa integrated (gas supply and liquefaction) project was sanctioned in December 2009 and is scheduled for first LNG in 2014.

Oil Search has a long history of oil exploration and production in PNG and with it, highly entrenched community and government relations. These relationships are a core company attribute and are valued by project operator Exxon Mobil.

PNG is a new LNG province with the PNG LNG project set to be the first LNG project based in the resources-rich nation. US listed E&P Interoil is contemplating a second PNG sited project, Gulf LNG based on the Elk/Antelope gas discoveries. However, this project is significantly less mature than the in construction PNG LNG project.

PNG has a number of attractions as an LNG province including: 1) proximity to North Asian and South East Asian customers, 2) supportive government with extensive experience in administering complex resources projects, 3) attractive fiscal

Benjamin Wilson

(61-2) 9220-1384

[email protected]

Niche exposure to global LNG

industry thematic

PNG is an attractive new LNG

province due to labor cost

advantage and proximity to Asian customers

133



environment (~2% well head royalty, 30% corporate tax and an advanced profits tax which is levied when project returns exceed an IRR of 17.5%), 4) low cost local labor pool and unrestricted capacity to imported labor, and 5) onshore location of gas resources (in PNG LNG case) which reduces capital intensity.

Developing and operating a mega project in PNG is not without its risks of course. The current political situation of two leaders claiming rights to the office of Prime Minister highlights the attendant sovereign risk. Land owner disputes and tribal rivalry are issues that are ever present and managed by both the project operators and the central PNG government. However, we think the risk of nationalization of petroleum resources is extremely remote given the country's reliance on foreign aid and the importance of the PNG LNG project to the future of the PNG economy.

The impact of the PNG LNG project on PNG is hard to overstate. We estimate the project will drive a 60-70% increase in 2010 level GDP when it reaches peak production in 2015. It is truly a nation building project.

The PNG LNG development is a ‘stick build’ process as opposed to the increasingly common modular approach. The decision made in the FEED process to opt for stick build was cost driven. Given the comparatively low labour costs of PNG nationals and the Philippines, Malaysian, Pakistan etc offshore workers, the additional on-site fabrication time associated with a stick build process is not nearly as burdensome in a cost sense as it would be in Australia for example (where modular developments tend to be favoured). Additionally, the ample site area (for lay down and construction facilities) and temperate weather (as opposed to Sakhalin in Russia for example) make the PNG LNG site ideal for a stick build. The stick build approach does,however, introduce an added degree of complexity and is the biggest risk to project schedule and budget in our view.

The PNG LNG project sponsors recently announced a 5% increase to the project budget (now US$15.7bn versus US$15bn original budget) primarily driven by the stronger A$. Much of the early project civil works were denominated in A$. We model PNG LNG project capex of US$16.9bn - higher again than the recent revised guidance.

As Oil Search’s legacy oil assets in PNG wind down, commercialization of the company’s sizeable gas resources takes on increasing importance. The foundation PNG LNG project and a risk weighted contribution from a third brown field train comprise ~85% of our company NAV currently making it the most leveraged LNG exposure in our Australian E&P coverage universe. The off-take contracts entered into by project operator Exxon Mobil are within 10% of oil parity meaning Oil Search also has a very strong linkage to JCC oil prices.

Liquefaction assets

We think the PNG LNG project is one of the leading green field LNG developments in the Australia/PNG region. The project’s onshore gas resource location and access to low cost labor combine to generate a cost base that is lower than new green field developments in Australia. In addition to the capital cost advantage, PNG has comparatively attractive fiscal terms and the PNG LNG project off-take contracts reflect near peak cycle slender discounts to oil parity. These factors combine to produce strong modeled project returns. We estimate an IRR of 18% in US$ terms

Project risks include land owner

disputes, tribal rivalry and

sovereign stability

‘Stick build’ as opposed to the

increasingly popular modular

developments

PNG LNG to comprise 85% of

our group NAV

Project IRR modeled at 18% in

US$ terms, stronger than current

green field proposals at 10-15%.

134



and 21% in A$ terms. Such returns are higher than forecast returns for other greenfield LNG projects that are due to commence construction in coming years which have normalized to the 10-15% IRR range.

We think a third (and eventually fourth) train for the PNG LNG project is one of the most prospective brown field expansion opportunities in the region. There issignificant gas resources located around the PNG LNG project area that could underpin a third train. The most immediate prospect is an extension to the Hides gas and condensate field which currently contributes ~5 TCF of the second train PNG LNG project dry gas resources of ~9 TCF. The PNG LNG project partners plan to drill the first Hides development well in 1H 2012 which will target the gas water contact point in the reservoir and determine how much additional gas resources may be contained in the field. The gas water contact has not previously been establishedby previous exploration wells.

If it transpires that the Hides resource is sufficient to underpin a third train then the development case is relatively simple. Scope additions would include an expansion of the Hides gas conditioning plant, some compression and/or looping of the onshore pipeline and the liquefaction train itself. The foundation PNG LNG project LNG tanks and jetty are already sized for three trains. However, a fourth train may require an additional jetty to facilitate more frequent tanker loadings when operating at peak capacity. We estimate an IRR of 31% for a brown field third train expansion.

The table below provides a summary description of the PNG LNG project.

Table 38: PNG LNG project description

Liquefaction trains 2LNG production capacity 6.6 MT paProject sanction date Dec 2009First LNG due 2014Capex US$15.7bn (updated Dec 2011), budget at sanction US$15bnOperator Exxon MobilEquity participants Exxon Mobil (33.2%), Oil Search (29.0%), PNG Government (16.8%), Santos

(13.5%), Nippon Oil (4.7%), PNG Landowners (2.8%)Total resources ~9.1 TCF gas, ~225mmbbls liquidsGas supply 982 mmscfpdOff-take contracts Sinopec 2 MT pa, TEPCO 1.8 MT pa, Osaka Gas 1.5 MT pa, CPC Taiwan

1.2 MT paPrimary EPC contractors Chiyoda/JGC (LNG plant), Saipem (offshore pipeline), CBI/Clough JV (hides

gas plant), Spiecapag (onshore pipeline), McConnell Dowell/CCC JV (infrastructure), Clough/Curtain JV (early works), Jacobs (associated gas)

Source: Company reports.


Our Oil Search NAV is primarily comprised of its exposures to the PNG LNG foundation project and a potential third expansion train. The table below displays our Oil Search NAV on a scenario build up basis. We have shown three long term oil prices (US$70, US$90 and US$110/bbl Brent real prices), our base case in US$90/bbl real long term with 0.80US$/A$.

Assuming our base case we value Oil Search’s exposure to the PNG LNG foundation project at A$7,805m or A$5.91 per share and a third expansion train at A$2,298m or A$1.74/shr. Note the valuations presented in the table below are on a 100% un-risked basis.

Third train highly likely

Estimate 31% IRR for Train 3

PNG LNG

Around A$10bn or A$7.65 per

share

135



Table 39: LNG contribution to Oil Search NAV

LT Brent oil (US$/bbl) 70 90 110LT A$/US$ 0.80 0.80 0.80

Company Valuation Scenario (un-risked projects included)Share

price (A$)DCF

(A$/shr)Upside to

DCF valueDCF

(A$/shr)Upside to

DCF valueDCF

(A$/shr)Upside to

DCF valueOil Search Base Case: Oil business (excluding PNG LNG) 6.35 0.95 -85% 1.13 -82% 1.31 -79%

+ PNG LNG project 5.07 -20% 7.04 11% 8.88 40%+ Third Train PNG LNG, 3tcf, 30% OSH share 6.29 -1% 8.78 38% 11.14 76%+ Mananda 5 Development 6.38 0% 8.97 41% 11.45 80%


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Santos

Figure 84: Santos - summary of LNG assets (net capacity, MT pa shown)



Raising its equity LNG participation is central to Santos' corporate strategy of becoming a leading Australian and Asian energy player. Santos already has a strong presence in the East Coast Australian gas market by virtue of its long held Cooper Basin assets, however its ambition is to drive a transition to oil linked pricing by accessing Asian LNG markets. Santos aims to have 70% of its group production linked to oil pricing by 2015, only 30% of its 2011 production is currently oil linked.

Santos has 11.4% in the ConocoPhillips operated Darwin LNG project which commenced LNG sales in 2006. Darwin LNG is situated in Australia’s Northern Territory and is fed by gas and condensate fields in jointly administered waters between Australia and East Timor.

Santos is seeking to expand its LNG presence via two projects that are in development, 1) a non-operating 13.5% interest in the PNG LNG project and 2) a 30% operating interest in the Gladstone LNG project in Queensland, Australia. We have discussed the PNG LNG project at length in the section on Oil Search. Gladstone LNG is a CBM-to-LNG project very similar to the QC LNG project being developed by BG Group. Santos’s GLNG project commenced development ~3 months after BG Group's project and is virtually fully contracted to Petronas and Kogas, both of whom are participants in the JV along with TOTAL.

Benjamin Wilson

(61-2) 9220-1384

[email protected]

Corporate strategy to transition

from domestic gas pricing to oillinked pricing

Small interest in ConocoPhillips

operated Darwin LNG

137



Santos has a third potential development project, Bonaparte LNG, which is a Floating LNG concept to commercialize the Petrel, Tern and Frigate gas fields in the Timor Sea. Bonaparte LNG is a JV between GDF Suez (60% and operator) and Santos (40%). The aim is to develop a 2 MT pa FLNG project with FID targeted for 2014 and first LNG by 2018. Pre-FEED contracts with Granherne Ltd and DORIS Engineering were let in early 2011. As the FID target for Bonaparte LNG is quite distant we do not yet include a specific valuation for the project in our Santos group NAV calculation.

We have identified Santos as an advantaged LNG project portfolio owner within the sphere of Australian listed LNG exposures. Santos has a clear path to oil linked pricing through the GLNG and PNG LNG projects and is well positioned to supply the Asian basin market. Santos has sought to align itself with experienced operators, starting with ConocoPhillips in the Darwin LNG project, Exxon Mobil in the PNG LNG JV and TOTAL and Petronas in the GLNG JV. Santos has a strong set of off-take customers, predominantly Japanese and Korean buyers with Petronas also taking half of the GLNG output. Upon completion of PNG LNG and GLNG, Santos will have an equity interest of 3.6 TM pa of LNG capacity.

Liquefaction assets

The three tables below display the key characteristics of the operating Darwin LNG project and the in development PNG LNG and GLNG projects.

Table 40: Darwin LNG project description

Trains 1LNG production capacity 3.5 MT paProject commission date 2006Capex Phase 1 gas recycling US$1.8bn, Phase 2 LNG development US$1.2bnOperator ConocoPhillipsEquity participants ConocoPhillips (57.2%), Santos (11.4%), Inpex (11.3%), ENI (11.0%),

Tokyo Gas/TEPCO (9.2%)Gas supply 541 mmscfpdOff-take contracts Output sold to Tokyo Gas and TEPCO under a 17 year agreement


Table 41: PNG LNG project description

Trains 2LNG production capacity 6.6 MT paProject sanction date Dec 2009First LNG due 2014Capex US$15.7bn (updated Dec 2011), budget at sanction US$15bnOperator Exxon MobilEquity participants Exxon Mobil (33.2%), Oil Search (29.0%), PNG Government (16.8%),

Santos (13.5%), Nippon Oil (4.7%), PNG Landowners (2.8%)Total resources ~9.1 TCF gas, ~225mmbbls liquidsGas supply 982 mmscfpdOff-take contracts Sinopec 2 MT pa, TEPCO 1.8 MT pa, Osaka Gas 1.5 MT pa, CPC

Taiwan 1.2 MT paPrimary EPC contractors Chiyoda/JGC (LNG plant), Saipem (offshore pipeline), CBI/Clough JV

(hides gas plant), Spiecapag (onshore pipeline), McConnell Dowell/CCC JV (infrastructure), Clough/Curtain JV (early works), Jacobs (associated gas)


Santos has limited counterparty

risk given its strong suite of off-

take contracts

138



Table 42: Gladstone LNG project description

Trains 2LNG production capacity 7.8 MT paProject sanction date Jan 2011First LNG due 2015Capex US$16bn at sanctionOperator SantosEquity participants Santos (30%), Petronas (27.5%), Total (27.5%), Kogas (15%)Total resources Coal seam gas 2P reserves as at Jan 2011 ~5tcf plus 0.75tcf gas supply

contract from Santos conventional gas resources in Cooper Basin. EUR from project coal seam gas acreage ~9.9 TCF.

Gas supply 1,262 mmscfpdOff-take contracts Petronas 3.5 MT pa, Kogas 3.5 MT paPrimary EPC contractors Fluor (upstream gas development), Saipem (gas trunkline), Bechtel

(liquefaction plant)


Gladstone LNG is a complex project which along with the three other Queensland CBM-to-LNG projects has assumed a high profile due to the community and landowner opposition to the development of the coal seam gas fields that will feed the project. The project's complexity is driven by two issues, 1) competition for skilled labor with other Australian LNG projects in development and 2) management of land owner and community opposition to large scale coal seam gas developments.

GLNG – competition for skilled labor

One of the biggest challenges facing LNG developers in Australia is competition for skilled and semi-skilled labor to execute the projects. Australia is effectively a closed labor pool with limited ability to import workers from abroad. The sheer number of LNG projects in development combined with the multitude of minerals projects in train has created an environment of rampant wage cost escalation.

The figure below highlights the number of LNG projects currently under construction in Australia – seven currently (excluding PNG LNG).

Santos has sought to insulate itself from labor cost escalation by agreeing to fixed price contracts with EPC providers where possible. On GLNG, the Bechtel and Saipem EPC contracts for delivery of the two train liquefaction plant on Curtis Island in Gladstone and the 42 inch main overland trunk-line are fixed price turnkey contracts. The EPC contract with Fluor for delivery of the upstream gas project is not fully fixed; rather the contract contains a fixed per unit schedule of rates e.g. fixed cost per km of infield pipeline, with variability around the number of units required.

While a fixed price, turnkey contract does not necessarily guarantee that a project will not experience cost overruns, we believe Santos has taken every precaution possible to ensure a favorable outcome. Despite these measures taken by Santos to limit cost escalation we carry 8% cost overrun which gives a total budget of A$17.3bn versus the original budget of A$16bn.

139



Figure 85: Australia, PNG, Timor Leste LNG projects

GLNG – managing community and land owner opposition

A large scale onshore gas development is new to populated regions of Eastern Australia. Historically most gas production for the East Coast has come from the offshore Gippsland Basin and the onshore Cooper Basin which is in a desert region. The areas in which Santos, BG Group, Origin/ConocoPhillips and RD Shell are proposing to develop their coal seam gas resources are in areas of Queensland that are used for irrigated cropping (in the case of BG Group and RD Shell) and low intensity grazing (Santos and Origin/ConocoPhillips).

Petroleum and mineral resources rights in Australia are held by the relevant states, therefore the freehold land owner has no specific rights to the resources underlying their properties. This creates a fundamental mismatch of incentives in that landowners generally have no specific incentive to support gas developments on their property as by definition the only compensation required to be paid is for loss of economic value and other amenities.

Landowners, environmental advocacy groups and ministers from state and federal governments have voiced concerns over the potential impact of large scale coal seam gas developments on local and regional aquifers, and on the above ground farming activities. Disposal of the large volumes of produced water is proving to be a major challenge for all CBM-to-LNG project sponsors.

140



The issues associated with large scale CBM developments, particularly the interaction between water extraction and disposal and existing fresh water hydraulic systems, are complex and evolving. While there is broad political support at both state and federal level for the projects, the public opposition is difficult to ignore. Broadly speaking we believe that the Santos operated GLNG project and the Origin/ConocoPhillips APLNG project are less exposed than either the BG QC LNG project or the RD Shell/PetroChina project due to location of acreage being in less intensively farmed regions and coal seams sitting deeper which means less water production.


The table below displays our Santos NAV on a scenario build up basis. We have shown three long term oil prices (US$70, US$90 and US$110/bbl Brent real prices), our base case in US$90/bbl real long term with 0.80US$/A$.

Assuming our base case, we value Santos’ exposure to the Darwin LNG project at A$1,340m or A$1.44 per share (included in the “Base Case” category in the table below), its 13.5% interest in the PNG LNG foundation project at A$4,490 or A$4.81per share, its 30% interest in GLNG at A$4,134 or A$4.43 per share and its interest in a third expansion train for PNG LNG at A$1,937m or A$2.08 per share. Note the valuations presented in the table below are on a 100% un-risked basis.

Table 43: LNG contribution to STO NAV

LT Brent oil (US$/bbl) 70 90 110LT A$/US$ 0.80 0.80 0.80

Company Valuation Scenario (un-risked projects included)

Share price (A$)

DCF (A$/shr)

Upside to DCF

valueDCF

(A$/shr)

Upside to DCF

valueDCF

(A$/shr)

Upside to DCF

value

STO Base Case: Existing projects incl. GLNG equity sell down, capital raising, A$23/t carbon tax, excl. LNG

12.65 7.93 -37% 9.10 -28% 10.23 -19%

+ PNG LNG project 11.33 -10% 13.91 10% 16.20 28%+ 2 train GLNG 13.68 8% 18.35 45% 22.54 78%+ Third Train PNG LNG 15.17 20% 20.42 61% 25.22 99%


Around A$11.9bn or A$12.77 per

share

141



Woodside

Figure 86: Woodside - summary of LNG assets (net capacity, MT pa shown)



Woodside has a clear LNG strategy to maintain and build on its position as the number one LNG producer in Australia. With the forthcoming addition of the Pluto-1 project in March 2012 (WPL’s total LNG net equity will increase to 6.6 MT pa), Woodside’s position looks secure until 2015 at the earliest when Chevron's 15 MT pa(7.1 MT pa net Chevron) Gorgon project is due on line or BG Group’s 8.5 MT paQCLNG project (BG net equity 8 MT pa).

As operator of the giant North West Shelf Venture (NWSV) in Western Australia, Woodside's history of LNG production dates back to commissioning of the first two 2.5 MT pa trains in 1989. Since then, Woodside and its JV partners (Chevron, RD Shell, BP, BHP and Mitsubishi/Mitsui) have added three further trains (the last in 2008) for a total operating capacity of 16.3 MT pa making the NWSV one of the largest single site LNG projects globally.

Woodside is a high profile player in the Australian and broader Asian basin LNG industry. Its virtual sole risking of the Pluto green field LNG development in 2007 signaled Woodside's arrival as an aggressive, growth driven LNG player. At the time of project sanctioning, Woodside was aiming for the Pluto project to be the quickest development from gas discovery to LNG sales. Its ambition was not limited to Pluto-1, at the time of project sanctioning in July 2007 Woodside commenced studies into a second and third Pluto expansion trains. Indeed, at one point former Woodside management articulated an aspirational goal for up to five Pluto trains.

Benjamin Wilson

(61-2) 9220-1384

[email protected]

Clear strategy to maintain #1

position in Australian LNG

The sanctioning of Pluto-1 in

2007 signaled a more aggressive

LNG growth strategy

142



Woodside has also been seeking to mature two further green field LNG projects - the ~12 MT pa Browse LNG project in the Browse Basin in offshore northern Western Australia and the 4-5 MT pa Sunrise Floating LNG project in joint waters between Australia and East Timor.

Woodside’s LNG strategy is characterized by a desire for operatorship. The company operates the NWSV and Pluto as well as the proposed Browse and Sunrise projects. As we have discussed previously in this note, LNG operatorship is an importanthallmark of a strategically advantaged LNG player. Woodside has a strong history of LNG sales to Japanese, Korean and Chinese customers which is important whennegotiating future LNG supply agreements.

Despite these two considerable strengths, we have not identified Woodside as a strategically advantaged LNG project portfolio owner within the sphere of Australian listed LNG exposures. The Woodside LNG growth story has lost some of its luster in recent years. A total 15 months schedule deferral and 33% cost overrun for Pluto-1, now due in March 2012, has highlighted the difficulties associated with executing a large scale resources project in Australia. Furthermore, the prospect of Pluto expansion trains looks set to be reliant on third party gas as Woodside's efforts to discover equity gas to feed the brown field expansion have not been as successful as hoped. We also note that the Browse and Sunrise projects are struggling to make forward momentum towards FID while competing projects, mainly from much larger operators (e.g. Chevron, RD Shell, Exxon Mobil), have secured customers and entered construction.

The charts below demonstrate the issues that Woodside has experienced over the past 12 months in maturing its projects. The first chart displays the current state of Australian/PNG projects (against contract commitments), specifically their development status and off-take arrangements and the second displays the same chart from October 2010. Some five projects have moved into construction and several more have secured off-take contracts. It is apparent that Woodside’s projects have moved little over the same time frame.

Woodside LNG strategy

characterized by project

operatorship

Five competing LNG projects in

Australia have moved into

construction since Oct 2010

143



Figure 87: Australian/PNG LNG projects and off-take agreements - current


1 Browse: CPC Corp signed a preliminary key terms agreement with Woodside in 2007 for the Browse project. The other Browse KTA has lapsed.

2 Curtis Is. LNG: We expect that PetroChina will sign an off-take agreement for at least its equity share of the first 2 trains of Curtis Island LNG, ie 50% or 4.0 MT pa

3 BG's QCLNG Project has signed off-take agreements for ~10 MT pa. We expect the first two trains to be 8.5 MT pa with the remainder to be supplied by BG's global portfolio

4 BG's contract with Chubu Electric is for 120 cargoes. We estimate this could be between 0.4 MT pa and 0.8 MT pa, with the midpoint of 0.6 MT pa in the chart above

5 Ichthys: The Kogas contract with Ichthys has not been signed but was reportedly announced by the Korean Ministry 17 Aug 2011. The Japanese contracts are also yet to be finalized.

6 Prelude: it is unclear how much of the Osaka Gas contract and Kogas impending contract (announced by the Korean Ministry 17 Aug 2011) is firmly from Prelude as their combined size (0.8 MT

pa Osaka and 3.64 MTpa Kogas) exceeds Prelude's capacity. Some may be RD Shell portfolio capacity.

0.55

0.4

0

0

0.8

0

0.2

5

4.3

0.2

0.089.5

4

5

2.1

5

3.3

4.25

0

2

4

6

8

10

12

14

16

Tokyo Gas Kansai Electric Osaka Gas Sinopec

TEPCO PETRONAS CNOOC GNL Quintero

PowerGas Chubu Electric GSCaltex Gujarat State Petroleum Corp

PetroChina Petronet Sempra Import Terminal KOGAS

Kyushu Electric CPC Corp Nippon Oil Inpex

Toho Total Not Contracted

mtpaIn Construction Pre FID Pre FEED

144



Figure 88: Australian/PNG LNG projects and off-take agreements – October 2010


The NWSV remains a world class project and the Pluto project is on the verge of delivering cash flows. However, Woodside’s strategic LNG advantage beyond these two projects is challenged in our view.

Liquefaction assets

Woodside has an operating interest in the five NWSV LNG trains for total net equity production capacity of 2.7 MT pa. The project description is displayed in the table below.

Table 44: North West Shelf Venture project description

Trains 5LNG production capacity 16.3 MT paProject commission date T1 1989 (2.5 MT pa), T2 1989 (2.5 MT pa), T3 1992 (2.5 MT pa), T4 2004

(4.4 MT pa), T5 2008 (4.4 MT pa) Operator WoodsideEquity participants* Woodside (16.7%), Chevron (16.7%), BP (16.7%), RD Shell (16.7%), BHP

(16.7%), Mitsubishi/Mitsui (16.7%)Off-take contracts Original 25 year contracts signed in 1985 were with Japanese buyers Chubu

Electric, Chugoku Electric, Kansai Electric, Kyushu Electric, Osaka Gas, Toho Gas, Tohoku Electric, TEPCO, Tokyo Gas and Shizuoka Gas. A 25 year contract for 3.3 MT pa was agreed with CNOOC in 2002. Kogas has been buying NWS LNG since 2003.

Source: Company reports. * CNOOC has a ~5.3% equity interest in gas resources but no equity interest in LNG infrastructure.

The Pluto-1 LNG project is due on line by March 2012. The project is described in the table below.

145



Table 45: Pluto LNG project description

Trains 1LNG production capacity 4.3 MT paProject sanction date July 2007First LNG due March 2012 (updated July 2012), target at sanction end CY10Capex A$14.9bn (updated June 2011), cost estimate at project sanction A$11.2bnOperator WoodsideEquity participants Woodside (90%), Tokyo Gas (5%), Kansai Electric (5%)Total resources 5.5 TCF gas, 83 mmbbls gas liquidsGas supply 652 mmscfpdOff-take contracts Tokyo Gas 1.9 MT pa, Kansai Electric 1.9 MT paPrimary EPC contractors Foster Wheeler and WorleyParsons


The Pluto project has been hit by significant deferrals and cost overruns. To a certain extent the project has been a victim of changes to industrial relations laws which contributed to three separate strikes. While this industrial action was not related to Woodside’s actions it is indicative of the challenges associated with executing large scale resources projects in Australia presently. The chart below highlights the impact of these cost overruns on Pluto-1 costs relative to peer projects.

Figure 89: LNG project EPC costs ($ per T)


On 17 June 2011, Pluto-1 suffered its third schedule & cost overrun (a further 6 months and A$900m).

Table 46: Pluto-1 capex increases over time

A$bn (100%)A$m Cumulative

increase capex% Cumulative

increase capexMths Cumulative

Increase time% cumulativeIncrease time

Pre-FID expenditure 0.8Post-FID capex estimate (27 July 2007) 11.21st revised cost over-run high estimate (20 Nov 2009) 1.1 1.1 11% - -Total capex at Nov 2009 13.12nd revised cost over-run estimate (30 Nov 2010) 0.9 2.0 18% 7-8 mths ~17%Total capex at Nov 2010 14.03rd revised cost over-run estimate (17 June 2011) 0.9 2.9 26% ~14 mths ~34%Total capex at June 2011 14.9


0

500

1000

1500

2000

2500

3000

3500

4000

PRODUCING

UNDER DEVELOPMENT

FID PENDING

146



Figure 90: Pluto-1 timetable – key dates


Pluto expansion trains

Woodside’s self imposed deadline for Pluto-2 FID of end CY 2011 under former management has been abandoned. For various reasons, we think FID is highly unlikely before the end of 2012. The most pressing factor is the delays to internal and external resource definition (including Woodside licence appraisal, an inability to reach terms with Hess for WA-390-P gas, and lack of news on the Scarborough/Thebe front). A further issue is the lack of gas sales contracts, particularly as a number of rival projects with similar start-up dates have recently been sanctioned, locking away customer demand. A third issue is funding, as the credit rating agencies have made quite clear that Woodside’s BBB+/Baa1 rating band (it is on negative watch) would probably be downgraded if it took on another large funding requirement without 3+ months of successful operational history behind Pluto-1 (now due to start-up in Feb 2012). On 11 October 2011, Moody’s re-affirmed the Baa1 (neg) rating, on the understanding that Woodside would adopt a less aggressive expansion timetable and reduce its equity interest in its projects.

Pluto expansion trains stalled by lack of resources

147



Browse LNG

The Browse LNG project is a proposed green field project to commercialize large gas discoveries in the Browse Basin, situated north of the Greater Carnarvon basin in which NWSV gas resources are located. The project concept is for a 12 MT pa onshore processing facility located on the Kimberley Coast at James Price Point. The project equity ownership is as follows: Woodside (46%, operator), BP (17%), Chevron (17%), RD Shell (10%, BHP (17%). The Browse JV is the same as the NWSV with the exception of Mitsubishi/Mitsui who are in the NWSV, but are not in Browse.

The Browse project faces a series of significant challenges. The proposed site location at James Price Point is an area of cultural and environmental significance. Woodside had reached an agreement with the traditional owners of James Price Point (as represented by the Kimberley Land Council) in May 2011. However, in December 2011 the Western Australia Supreme Court ruled that the State's move to compulsorily acquire land at James Price Point invalid. This is likely to result in further delays as Woodside seeks to clarify the “notices of intention to acquire”. In any case, Woodside announced in December 2011 that it is seeking an extension to the Browse retention licenses to allow an extension of the required FID date from mid CY 2012 into 1H CY 2013. This is a clear indication that Woodside is not ready to move forward with the Browse project.

Aside from traditional owner opposition, we believe the Browse project is suffering from a lack of joint venture party alignment. We believe the Browse JV partners (excluding Woodside) would prefer to delay the commercialization of a Browse green field project and instead pipe the gas back to the NWSV in 2022+ to fill capacity on the five trains in place. The Browse project is technically complex, high cost and high in CO2 all of which combine to produce a very challenging project.

Sunrise LNG

The Sunrise project is a JV including Woodside (33.4% operator), ConocoPhillips (30%), RD Shell (26.6%) and Osaka Gas (10%). Sunrise is seeking to commercialize wet gas fields in joint waters between Australia and East Timor. The JV's preferred development concept for Sunrise is a Floating LNG solution. JV participant RD Shell is currently constructing the world’s first FLNG development on the Prelude resource in the Browse Basin. The economics of a FLNG project are strong, particularly given the condensate rich composition of the Sunrise gas resource.

The issue with Sunrise lies in the East Timorese government requirement that the liquefaction component of the project be based onshore in East Timor. An onshore East Timor based liquefaction has not been considered by the Sunrise JV partners due to technical (deep trench to cross), commercial (+US$5bn cost) and sovereign risk issues. Both the Timor Leste government and the Australian government are required to approve the project concept in order for a development to proceed. Former Woodside management admitted it had reached an impasse on Sunrise. New Woodside management is attempting to broach the impasse. However, for now the project remains a stalemate.

Browse large green field development

Browse proposed site location is culturally and environmentally

sensitive.

Sunrise project remains in

stalemate

148



LNG shipping assetsWoodside’s LNG shipping fleet interests are aligned with its ownership interest in the North West Shelf JV. Woodside has a 16.7% interest in the North West Shelf Shipping Service Company (NWSSSC) which own and operates a fleet of seven LNG carriers (Northwest Sanderling, Snipe, Shearwater, Sandpiper, Sea Eagle, Stormpetrel and Swan) dedicated to transporting NWSV LNG to North Asian customers and other destinations as spot sales dictate. Six of the NWSSSC vessels feature the older Moss Rosenberg technology. The 2004 addition of the Northwest Swan represents the first use within the Woodside fleet of the Membrane Containment System. The Northwest Swan is the largest in the fleet with a capacity of 135,500M3.

The shipping arrangements for the Pluto project involve the foundation customers (Tokyo Gas and Kansai Electric) providing a vessel each and Woodside leasing a purpose built vessel (the Woodside Donaldson).

As Woodside’s shipping assets are dedicated to specific projects we believe that it has minimal merchant LNG shipping capacity.

LNG portfolio valuationThe table below displays our Woodside NAV on a scenario build up basis. We have shown three long term oil prices (US$70, US$90 and US$110 per barrel Brent real prices). Our base case is US$90/bbl real long term with 0.80US$/A$. Woodside’sleverage to LNG developments is strong.

While Woodside's LNG related disclosure is strong relative to peers it is not so detailed at the cost line to derive a 100% accurate breakout of the LNG related assets of the NWSV. Note the NWSV also produces oil, LPG, condensate and domestic gas. For the purposes of this exercise we have pro-rated our NWSV NAV according to revenue contribution which is disclosed.

Assuming our base case we value Woodside’s exposure to the NWSV LNG project (only) at A$5,962m or A$7.52 per share (included in the “Base Case” category in the table below) and its 90% interest in the Pluto-1 foundation project at A$16,697m or A$21.05 per share. On this basis, Woodside is clearly a highly leveraged LNG play.

We also carry value for projects that are yet to be sanctioned, including a Pluto-2 expansion train, Browse LNG and Sunrise LNG. As these projects are yet to be sanctioned and are yet to secure customers they warrant a high degree of risk weighting. We value a Pluto-2 train, assuming Woodside 90% equity interest, at A$6,488m or A$8.18 per share. We value a Browse development tied back to NWSV (the brown field option) at A$4,559m or A$5.75 per share. We value a Browse green field development at James Price Point at A$10,775m or A$13.58 per share. We value a Sunrise FLNG development at A$2,914m or A$3.67 per share.

Note the valuations presented in the table below are on a 100% un-risked basis.

Table 47: LNG contribution to Woodside NAVLT Brent oil (US$/bbl) 70 90 110LT A$/US$ 0.80 0.80 0.80

Company Valuation Scenario (unrisked projects included)Share price

(A$)DCF

(A$/shr)Upside to

DCF valueDCF

(A$/shr)Upside to

DCF valueDCF

(A$/shr)Upside to

DCF value

WPL Base Case: Existing projects + Pluto 1, Laverda oil 50%, incl A$23/t carbon tax

31.30 30.72 -2% 35.80 14% 38.76 24%

+ Pluto 2 assuming WPL 90% equity gas 35.55 14% 43.98 40% 49.95 60%+ Sunrise FLNG 37.73 21% 47.65 52% 55.11 76%+ either Browse tie-back to North West Shelf (Option 1) 41.72 33% 53.40 71% 64.90 107%+ or Browse greenfield at James Price Point (Option 2) 45.77 46% 61.23 96% 74.23 137%


Woodside has a 1/6th

interest in NWSSC which owns 7 vessels

149



Origin Energy

Figure 91: Origin Energy - Summary of LNG assets (net capacity, MT pa shown)

Source: J.P. Morgan. *Note: Liquefaction capacity under development will fall to 3.4 MT pa post recent agreement with Sinopec (12/12/11) going binding


We have classified Origin Energy (Origin) as a “niche” exposure to the global LNG industry thematic. The company’s only LNG exposure is via its 42.5% stake in the APLNG projected located in Queensland, Australia. We expect this stake to fall to 37.5% once the recently announced agreement with Sinopec moves to binding –likely in Q1 2012. Gas for the APLNG project will be sourced from Coal Seam Gas (CSG) fields located across a wide area of the Queensland interior. APLNG holds the largest reserves and is the largest producer of CSG in Australia. It holds permits covering 17,000 km2 in the Bowen and Surat Basins in central southern Queensland. Origin began exploring for CSG in the mid 1990s. The company acquired its first CSG interests in the Peat field in 1996 and entered into its first long term CSG supply agreement in 1999 with BP’s Bulwer Island Refinery. Origin continued to build its CSG interests by accumulating exploration interests and acquiring CSG interests from Transfield and Tri-Star Petroleum in 2002.

In 2008, Origin sold 50% of its CSG assets to ConocoPhillips for an upfront payment of US$5.0bn, with additional payments due to the JV of A$1.15bn to carry Origin’s share of budgeted development and operating costs up to FID for Train 1. Following the sell-down to ConocoPhillips, the APLNG partners have made a number of significant steps towards realizing the value of the project. In particular, the following milestones were reached in 2011:

Operational Liquefaction capacity

Liquefaction capacity under development

Operational Re-gasif ication capacity

(APLNG)

3.8

Jason Steed

(61-2) 9220-1551

[email protected]

Niche exposure to global LNG

industry thematic

Origin sold 50% of its CSG

assets to ConocoPhillips in 2008

150



Feb-11: APLNG and Sinopec sign non-binding HoA for 4.3 MT pa LNG supply over 20 years and 15% equity interest.

Jul-11: APLNG takes FID on first phase of two train project. Capex expectations set at US$14bn for first phase and at US$20bn for full two-train development.

Nov-11: APLNG and Kansai Electric sign 20-year agreement for 1 MT pa.

Dec-11: APLNG and Sinopec sign a non-binding HoA for further LNG supply and additional equity taking Sinopec to 25% ownership in APLNG.

The recent HoA signed with Sinopec completed the marketing of APLNG's second train, with FID now expected to be taken in Q1 2012. Total capital expenditure for the two-train project is estimated to be US$20bn, which includes a contingency of US$2.5bn. This estimate covers the period from FID until the commencement of gas deliveries from Train 2 expected in early 2016. Origin will manage the upstream project, while ConocoPhillips will manage the overall downstream project. A JV between McConnell Dowell Constructors and Consolidated Contractors Australia has entered a fixed price pipeline construction contract.

Liquefaction assets – APLNG project description

The table below sets out the key characteristics of the APLNG project.

Table 48: APLNG project description

Trains 2LNG production capacity 9.0 MT paProject sanction date July 2011First LNG due 2015Capex US$20bn Operator ConocoPhillipsCurrent Equity participants Origin (42.5%), ConocoPhillips (42.5%), Sinopec (15%)Total resources 11,000 PJ 2POff-take contracts Sinopec (7.6 MTpa), Kansai (1.0 MT pa)Primary EPC contractors MCJV (gas trunkline), Bechtel (liquefaction plant)



We value Origin’s business ex APLNG at $13.77, which is broadly in line with the current share price, and implies that APLNG is valued by the market at nil. Our current valuation of $18.95 per share assumes a two train project, but includes a risk weighting on train two (T2) of 50%. On a two train fully de-risked basis, we value Origin at $21 per share. Our $13.73 valuation of Origin's underlying business is based on an EV/EBITDA multiple of 8.0x, noting that AGK is currently trading at 8.3x EV/EBIDA and 8.1x EV/EBITDA on an Ex-Upstream basis. Our $18.95 June 2012 Target Price for Origin is based on a sum-of-parts valuation. We apply different costs of capital to each of the individual business units in an effort to appropriately reflect the risk profile of each segment. Our group post-tax WACC of 9.1% reflects a combination of the assumptions in the individual segments. The key figures that make up this discount rate are a post-tax cost of equity of 10.7% and a post-tax cost of debt of 5.3%. We apply a Beta of 1.1 within this calculation.

The key downside risks to our valuation are: failure of the APLNG second train to reach FID; lower than forecast oil prices; lower than forecast electricity and gas retail tariffs; and lower than estimated wholesale electricity prices.

APLNG valued around A$5.2 per

share

151



Inpex

As seen in Figure 93, Japan is the world’s largest LNG importer, comprising more than 30% of the global LNG trade. As Japan reduced dependence on oil and coal and consciously increased the use of gas, it helped to develop a parallel Indonesian supply LNG industry in the 1970’s. Indeed, Inpex was one of the first foreign firms to enter Indonesia in the early days of Suharto regime in 1966 and became instrumental in the hydrocarbon discoveries in Kalimantan, for the Offshore Mahakam PSC (which ironically supplies the Bontang LNG plant whose supplies to Japan have been declining in face of higher domestic consumption in Indonesia and higher asking prices for the contracted LNG). As per Figure 93, Japan has built up a diversified set of LNG suppliers – in 2008 it purchased LNG from 14 countries.

Figure 92: Suppliers of LNG to Japan

Source: Natural Resources and Energy, J.P. Morgan

Although Inpex is the largest upstream company of Japan, the responsibility for LNG imports largely rests with the utilities- Kansai Electric Power, Chubu Electric, Kyushu Electric, Osaka Gas, Toho Gas, Tokyo Electric etc. In fact the two largest LNG export facilities in Indonesia- Bontang in East Kalimantan and Arun in Aceh province were constructed in the 1970s under long term supply contracts with Japanese utilities. However with Inpex building out two large scale LNG projects, it is expected to play an increasingly important role in securing Japan’s gas supplies.


Inpex’s upstream strategy may be broadly defined as achieving a balanced diversified portfolio by acquiring projects differentiated by stages- exploration, development or production or contract types – PSC, CA etc. As of June, 2011, Inpex operated 71 projects in 26 countries.

Inpex is currently involved in 2 large scale LNG projects under development- Ichthys in Australia and Abadi in Indonesia. The two large gas fields were discovered in 2000. Ichthys is currently awaiting FID (expected by mid-January 2012) and Abadi is currently awaiting FEED - scheduled for H1 2012.

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Brynjar Eirik Bustnes, CFA

(852) 2800-8578

[email protected]

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Inpex has a clearly defined upstream growth strategy with three central tenets:

1. Growth – build resources and acquire projects in various phases.

2. Gas supply chain - link overseas gas resources with domestic Japanese market.

3. Diversification out of conventional oil and gas into other forms of energy, including unconventional forms (recently acquired 40% interest in Nexen’s shale assets in Horn River in Canada).

Domestic gas business

Central to Inpex’s LNG strategy is building on an integrated domestic gas value supply chain which connects international gas assets to the domestic distribution network. Inpex has a leading gas distribution network, supplying industrial and residential users around the Tokyo Metropolitan region comprising over 1,400 kms of pipelines. Indeed, Teikoku Oil, which was fully integrated into Inpex in October 2008, had commissioned Japan's first long distance pipeline between Tokyo and Niigata Prefecture in 1962.

Inpex’s Minami-Nagaoka gas field is the largest gas field in Japan and (about 20 years in production) makes up approximately 40% of the total gas production in Japan. Inpex, along with Shizuoka Gas and Tokyo Gas feeds into the self-owned 1,400km trunk pipeline network that stretches across the Kanto-Koshinetsu region surrounding the Tokyo metropolitan area, supplying gas to city gas companies and industries along the pipeline.

The company’s annual sales volume in FY 2010 reached 1.7 bcm which is 3.5x compared to 15 years back in 1996 (0.5 bcm). The medium to long term domestic gas sales target through its own network is 2.5-3.0 bcm. For this, in May 2011, the company decided to construct Toyama line- extending from Itoigawa city, Niigata Prefecture to Toyama City, Toyama Prefecture.

Inpex is currently building the Noetsu LNG receiving terminal in Joetsu City, Niigata Prefecture, with a re-gasification capacity of about 1.6 MT pa. Construction commenced in July 2009 and is expected to enter operation in 2014. Inpex plans to feed the gas from the Ichthys, Abadi and Minami-Nagaoka gas fields into this LNG terminal. Of the outstanding gas off-take contracts from Ichthys, Inpex and TOTALhave self-contracted 0.9 MT pa each of which Inpex has further agreed to purchase 0.2 MT pa from TOTAL, to feed 1.1 MT pa LNG through its Noetsu receiving terminal.

The supplies to the Noetsu LNG terminal will feed the north side of the domestic network and supplies from the Sodeshi LNG terminal (of Shizuoka Gas with supplies from 2010 onwards) in the south, will result in largely improved capacity to supply the domestic market. Inpex will be the only Japanese company to have a complete natural gas value chain in place, from development and production through liquefaction, transport and re-gasification and supplying into pipelines. This helps Inpex not to be overexposed to any particular low return part of the gas value chain (like liquefaction and shipping) but be integrated through the cycle along with retaining capabilities and capacity to grow the high return upstream business.

Inpex’s central strategy is to organically integrate overseas

gas assets into its Japanese gas

network

153



Figure 93: Inpex – domestic gas business region

Source: Company reports

Figure 94: Inpex – domestic pipeline network


Inpex has a stated growth strategy of growing total production, up from about 400kboped (about 45% gas) at present to 800-1,000 kboepd by 2020 (Figure 96). The growth is underpinned by 3 strategic long term projects which include the two LNG projects- Ichthys and Abadi (with the Kashagan oil project in Kazakhstan being the third one). The Ichthys and Abadi projects combined at peak production will add between 275-300 kboepd gas and liquid condensate combined to the base production.

Figure 95: Inpex – production growth targets underpinned by 2 major LNG projects


Overall growth closely tied in

with LNG business growth

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Liquefaction assets

Table 49: Inpex- summary of liquefaction assets

Liquefaction plant Start dateInpex equity supply

Gross capacity MT pa

Inpex equity

Net capacity MT pa

Darwin LNG 2006 11.30% 3.3 11.30% 0.37 Bontang LNG

Train 1 1978 30-35%* 2.6 0% -Train 2 1978 30-35%* 2.6 0% -Train 3 1978 30-35%* 2.6 0% -Train 4 1983 30-35%* 2.6 0% -Train 5 1984 30-35%* 2.7 0% -Train 6 1986 30-35%* 2.7 0% -Train 7 1986 30-35%* 2.7 0% -Train 8 1986 30-35%* 3.0 0% -

Tangguh LNGTrain 1 2009 6-9% 3.8 7.79% 0.30 Train 2 2009 6-9% 3.8 7.79% 0.30

Current capacity 1.0Ichthys LNG

Train 1 2016-2017(e) 74.8% 4.2 74.8% 3.14 Train 2 2016-2017(e) 74.8% 4.2 74.8% 3.14

Abadi FLNGTrain 1 2016-2017(e) 31%# 2.5 31%# 0.78

Planned capacity 7.1Vladivostok LNGUnder study 10 TBD TBD

Source: Company reports and J.P. Morgan estimates; *60-70% feed gas supply from 50-50 Inpex-TOTAL owned Offshore Mahakam

fields; #Inpex Masela (51.93% Inpex corp. owned) has a 60% equity stake in the project

Tangguh LNG (7.6 MT pa capacity)

Inpex owns 7.79% in the Tangguh LNG project through MI Berau, which owns 22.86% of which Inpex owns 44%, and remaining through KG Berau Petroleum. The BP led Tangguh LNG project involves the liquefaction of the gas from the Tangguh fields (estimated to be over 19 TCF). The project was commissioned in 2009 with first cargo loaded in July of that year. The first cargo was bound for POSCO’s LNG re-gasification terminal in South Korea. Tangguh is Indonesia’s third largest LNG centre after Bontang and Arun. Gas from the offshore platforms is fed into pipelines to the two onshore liquefaction trains, each with a production capacity of 3.8 MT pa. Studies for a third train are underway.

The Tangguh LNG project has long term supply contracts in place to supply 2.6 MT pa to CNOOC’s Fujian terminal in China (CNOOC also has a 13.9% interest in the Tangguh project) at $3.35 per mmbtu, capped at oil price equivalent of $38/bbl, 1.15MT pa to K-Power and POSCO in South Korea and a flexible contract to supply upto 3.7 MT pa to Sempra’s LNG re-gasification terminal in Baja California, Mexico.

Inpex has liquefaction plants

under development which will

increase its net operable capacity to almost 8x its present

1 MTpa capacity by 2017

All current operable and planned

liquefaction capacity in the Asia-Pacific region

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Offshore Mahakam Block - Bontang LNG (21.6 MT pa capacity)

Though Inpex does not have a direct equity interest in the Bontang LNG plant (Indonesia) it is a major stakeholder as it supplies LNG from its 50% owned giant Offshore Mahakam block in East Kalimantan. The block accounts for about two thirds of the gas feed for the Bontang LNG plant, which has supply contracts with Japanese LNG utilities. The plant has 8 trains and the capacity to produce 21.64 MT pa (the capacity was increased to 24.59 MT pa by increasing efficiency but declined subsequently due to gas feed supply issues). So far, over 10 TCF gas has been supplied to Japan, Korea and Taiwan.

The plant has faced supply issues due to under-production at the gas fields of the three major feed providers (TOTAL/Inpex, VICO and Unocal (now Chevron)). Also it is understood that there are no penalties for non-performance from the plant which has non-incentivized additional investment required into the maintenance of the plant and has rather led to diversion of feed gas to the domestic fertilizer plants through Pertamina.

Inpex and TOTAL plan to spend about $16.5bn over 2011-17 to develop the block and stem the natural production decline (Chevron has also raised its investment plansto increase production from the Kutei Basin). However since the Mahakam PSC expires 2017, the proposed investment may be conditional on securing an extension. (Indonesia’s state owned company PT Pertamina is understood to target a majority stake in the block after contract expiration and 100% stake by 2027).

Darwin LNG (3.3 MT pa capacity)

Inpex has an 11.3% equity ownership in the Darwin LNG and the Bayu-Undan Unit, which supplies feed gas into the plant. This project involves the transport of natural gas from the Bayu-Undan gas-condensate field in the Timor Sea via a 500km subsea pipeline to the LNG Plant in Darwin. It has been supplying 3 MT pa LNG to Japan since 2006 under long term contracts with Tokyo Gas (1 MT pa) and Tokyo Electric (2 MT pa). Indeed, this was the first LNG project where Tokyo Gas and TEPCO were not just buyers, but also equity holders of the project.

Ichthys LNG (8.4 MT pa capacity)

Ichthys is the biggest of the planned projects (LNG and otherwise) in Inpex’s development pipeline. The Ichthys project is a 74.8:24:1.2 JV between Inpex, TOTAL and Osaka Gas (recently acquired equity stakes with signing the gas off-take agreements) to produce gas, LNG and condensate from the Ichthys field in the Browse basin, offshore Western Australia. As per the project concept, the gas will undergo preliminary processing offshore to remove most of the condensate (to be stored in FPSO) and other raw liquids. The gas will then be sent to the onshore processing facility in Darwin (Northern Territory) by an 885 km pipeline. The Ichthys Project is expected to start up in late 2016 and will produce 8.4 MT pa of LNG (2 trains) and 1.6 MT pa of LPG, along with 100,000 bpd condensate at peak. All output gas has been contracted (with around 70% headed for Japan) and the project is currently awaiting FID.

Two major green field

developments underway to add almost 7.7 MT pa net operable


Figure 96: Abadi & Ichthys LNG


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Table 50: Ichthys project overview

Ichthys Natural Gas (TCF) Condensate (mn bbls) Total (mn BOE)Reserves 12.8 527 2,663

Inpex TOTAL Osaka GasOwnership 74.8% 24% 1.2%

LNG (MT pa) Condensate (’000 BOPD) LPG (MT pa)Capacities 8.4 100 1.6

Low end (US$B) High end (US$B)Capex requirement 25 35

FEED FID First shipmentTime line 2010 2011 2015

Source: Company data, J.P. Morgan estimates.

Abadi LNG (2.5 MT pa capacity)

Abadi is the second big LNG project in Inpex’s pipeline. The Masela Block is located approximately 800 km east of West Timor, Indonesia, and approximately 400 km north of Darwin, Northern Territory, Australia. According to the plan of development for the Abadi field approved by the Indonesian Government in December 2010, 2.5 MT pa of LNG will be produced from the Abadi field using Floating Liquefied Natural Gas (FLNG) technology and the production start up is currently expected in 2016-17. Inpex Masela is now preparing for the Front End Engineering and Design (FEED) in H1 2012. Inpex Masela, after recently farming out a 30% stake to RD Shell, has a 60% working interest in the field, with PT EMP Energi Mega holding the remaining working interest. Inpex owns a 51.93% working interest in Inpex Masela. Inpex Masela is further required to sell down another 10% of the project to an Indonesian nominated partner as part of the PSC terms. We believe RD Shell’s involvement in the project is a big positive due to its pioneering development of FLNG technology.

Vladivostok LNG (10 MT pa capacity)

A Japanese consortium comprising Inpex, Itochu, Japex, and Marubeni signed a pre-FEED joint study agreement with Gazprom for the natural gas utilization project in Vladivostok area in April 2011. The joint study consists of pre-FEED for construction of LNG plant (10 MT pa), feasibility study for CNG plant and a gas-chemical complex. The joint study is scheduled for completion near end 2011. The study follows a preliminary feasibility study done by Japan's METI, Itochu, Japex and Gazprom from May 2009 to July 2010. For more details, please refer to the section on Gazprom.


Inpex does not explicitly breakout the performance of its LNG business. However, we expect the primary value drivers for the business to be the two major LNG projects- Ichthys and Abadi.

Ichthys: Inpex recently fulfilled the last milestone towards the FID (target January2012), when it announced signing of SPAs for all gas off-take. However the capex level is still the missing item, which remains the key variable for FID. We build in a $25-35bn capex range into our DCF value and using $30bn as our base case, we get a $17.6bn project NPV, which yields US$6.6/BOE based on a reserve base at 12.8 TCF for natural gas and 527 million bbls for condensate. We use a long-term oil price of US$85/bbl and a WACC of 8% for the project. The full value of the project is about 27% of our estimated full value for Inpex. However considering the stake of the project, we only include 20% of the Inpex's share of Ichthys value into our JPY 750k PT. This is equivalent to 8.5% of our current PT.

Ichthys and Abadi LNG projects

are the major value drivers for the LNG business

157



Abadi: Similar to Ichthys, we believe Abadi contains uncertainties, resulting in only a very small fraction of the project NPV currently being included in our PT (10%). We value Abadi based on a 20% discount to the EV/BOE valuation from Ichthys, which yields a full project value of $9.7 billion. The discount relative to Ichthys is due to some technical uncertainties and a later project start up. The 10% of project value we include is at a slight premium to the valuation obtained based on the 10% sale to Energi Mega Persada late 2009, when oil prices were below current levels. The sales price was $77.25m for the 10% stake, yielding an overall project value of $772.5m (compared with 100% of $9.7bn).

We take a much simpler approach to the Abadi project due to less information regarding the project being available. By assuming similar capex levels (per unit reserve – $11 per boe), WACC, and oil price, we take the EV per boe from theIchthys project and apply a 20% discount due to these uncertainties. We justify this as Abadi is holding natural gas and condensate in similar proportions, while a possible more expensive offshore FLNG solution is being offset due to lack of a need for a long distance pipeline to onshore facilities.

We include only 10% (or JPY10,000 per share) of Inpex’s value in this project in our PT due to the many uncertainties around in the project being realized, which comprises around 1.3% of our PT. If include 100% of Inpex's value of this project, then it comprises around 9% the full value.

Table 51: Inpex value breakup: Ichthys + Abadi constitute 37% of the overall SOTP

(000 JPY) TotalJPY per

sharePercentage

includedPT JPY Per

share

Base EV 1,813,000 496,000 100% 496,000Net cash and equiv (Incl bonds/securities) 968,374 265,000 80% 212,000Minority Interest 117,494 32,000 100% 32,000Base equity value 2,663,880 729,000 100% 676,000Ichthys 1,163,544 318,000 20% 64,000Abadi 379,129 104,000 10% 10,000Total 4,206,552 1,151,000 65% 750,000Ichthys+Abadi as % of Total value 37% 10%

Source: Company data, J.P. Morgan estimates.

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Overview China LNG

Politically driven

Chinese natural gas supplies have grown rapidly over the last five years since the first LNG import cargo arrived at the first import terminal (Guangdong Dapeng) in 2006. Higher domestic production, LNG and piped gas imports have all played amuch bigger role in meeting China’s growing energy needs. Natural gas demand comes from new residential and industrial demand, in addition to fuel oil for direct burning to produce power. LPG for residential use has also been partially replaced by natural gas, as gas prices have been kept lower than fuel oil and LPG prices to incentivize switching. Another source of future demand growth would be CNG in transportation to displace demand growth in gasoline. Anecdotally we've been hearing about shortages at CNG stations, especially in regions where CNG prices are less than half of gasoline-equivalent.

The Chinese government adopted a number of laws and regulations that require provincial governments to increase the use of clean energy including natural gas to replace the use of coal in order to reduce air pollution. As such, local governments are politically motivated to increase their natural gas demand and related supply. A preferential value-added tax rate of 13% is also charged for natural gas, as compared to a 17% value-added tax rate for crude oil. The Ministry of Finance also granted a VAT rebate on losses (versus a reference price) from gas imports via pipeline and LNG terminals for 2010-20 as a form of subsidy.

LNG versus piped gas imports

LNG imports will complement additional volumes via the Central Asia pipeline from Turkmenistan into West-East pipeline 2 (WEP2). More LNG supply deals are being secured for the terminals currently under construction and expansion plans for existing terminals. Recently, there has been talk of the Chinese state importers trying to secure more Australian term contracts because they are more cost competitive. Spot LNG cargoes are also going to be a permanent feature to meet the swing in demand during winter.

The total cost for PetroChina of obtaining additional piped gas supplies is likely to increase as the construction of a third West-East pipeline is necessary to deliver the gas to east China, where demand for gas is most concentrated and consumers are able to afford to pay higher gas prices than central and west China. Turkmen pipedsupplies are expected to be 15 BCM in 2011 and 30 BCM in 2012. The pipedimports have been more expensive than the average cost of LNG imports, at an average cost of $9.9 per mmbtu compared to $8.4 per mmbtu in 10M 2011.Turkmenistan and China agreed in November to increase total supply to 65BCM paby 2020.

Table 52: Natural gas supply sources by company for Jan-Nov 2011 - BCM

Domestic output Piped gas import LNG import Total supply y/y %PetroChina 67.8 12.7 1.08 81.6 19%Sinopec 13.3 - - 13.3 19%CNOOC & Others 12.3 - 13.5 25.8 35%Total 93.4 12.7 14.6 120.7 22%y/y % 10% 336% 29%

Source: OGP, J.P. Morgan estimates.

First LNG imports in 2006

Government policy is ‘gasifying’

China’s energy mix

More LNG supply deals to be

signed….

…even though they are more

expensive than piped gas

159



Table 53: China's natural gas sources - BCM pa

2010A 2011E 2012E 2013E 2015EDomestic production 93.6 102 110 120 158LNG 12.9 15 19 25 50Cross-border pipelines 3.5 15 30 36 65Total gas available 110 132 159 181 273

Source: J.P. Morgan estimates, Company data.

In the proposal for the 12th Five Year Economic Plan, China wants to double the proportion of natural gas in its primary energy mix to exceed 8% and reduce carbon dioxide emissions by 17%. Gas demand, including Hong Kong and Macau which are dependent on China for gas supplies, would grow 18% YoY to around 130 BCM in 2011 and possibly to 250 BCM by 2015. Heavy industrial users have been encouraged to switch to natural gas from coal and fuel oil for power generation and transport fuel, while residential users have been encouraged to switch from LPG and coal-based gas. We expect these two segments to grow faster than supplies to fertilizers. The emerging trend of oil refineries switching to natural gas as fuel for furnaces and as petrochemical feedstock, to increase the oil-product yield, will also add to natural gas demand.

Figure 97: Natural gas consumption by segment since 1995 – BCM pa

Source: National Bureau of Statistics

Pricing

Natural gas wellhead prices and gas pipeline tariffs are regulated in China. Theexisting pricing policy says producers are given room to raise wellhead prices by up to 10% for gas produced onshore. In contrast, prices for gas produced offshore are market-driven (but selling into regulated onshore market). The NDRC has the authority to set the wellhead prices and pipeline tariffs, while city gate prices are decided at the provincial levels. Imported gas is priced and sold within the same framework set by the NDRC for domestic gas production.

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To encourage higher domestic output and imports, we expect the policy direction in the long term to link prices with competing fuels and narrow the gap between domestic and imported gas prices. But prices are likely to be kept sufficiently low in the near term to encourage significant switching and hence grow demand (which we believe is currently the primary policy target). Natural gas prices are currently kept lower than prices for LPG and gasoline. For example; CNG used in transportation is priced at less than a 0.75 ratio to 90-RON gasoline.

The share of natural gas for making chemicals and fertilizers has declined since 1995 by policy design. The long-term target is to displace LPG and coal-based gas by raising the proportion of residential demand. Gas in to power generation has also increased over the years. Previously, gas-fired generators were under-utilized due to a lack of gas supply. Gas-fired capacity is about 3% of total installed capacity.

Figure 98: Natural gas demand by segments since 1995 - % share

Source: National Bureau of Statistics

Natural gas pricing trial reform– main impact is on Guangdong

On 26 December, 2011, the NDRC launched a gas pricing trial reform for two south provinces Guangdong and Guangxi. The trial allows the gas suppliers to negotiate for better pricing with end-users within the maximum cap allowed. The maximum cap is calculated from 2010 prices of fuel oil and LPG, with a 10% discount. The cap in turn protects the consumers with a guaranteed price ceiling. The existing nationwide pricing mechanism sets natural gas prices on a cost-plus system, under which the NDRC sets the wellhead prices plus pipeline tariffs.

The trial abolishes the cost-plus system by allowing gas suppliers to set their own wellhead and pipeline tariffs within the price caps. It is not known how long the trial may take before being implemented nationwide.

These two provinces have been selected because of two reasons: (i) PetroChina's high-cost Turkmen imports via WEP2 will be supplied to Guangdong province this year, and 2) city gate prices are already the highest in China and the caps imposed are similar to existing prices, and hence the trial won’t affect the consumers.

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Guangdong’s gas supplies are mainly from CNOOC parent’s Guangdong Dapeng (8 bcn for Jan-Nov11) and offshore production (6-7 bcm). Demand for the province is around 12 bcm. The city gate price cap of Rmb2.74/M³ is much higher compared to the previous wellhead price of Rmb1.15/M³. WEP2 pipeline tariffs to Guangdong are still being negotiated but industry sources say it will likely be closer to PetroChina’s WEP tariff of Rmb0.84/M³ to Shanghai. Guangdong Dapeng's average LNG import cost was Rmb2/M³ during 11M 2011, while PetroChina’s WEP2 import cost was Rmb2.1/M³.

PetroChina will likely cover the cost of imports from Turkmenistan, but it may not be highly profitable at the Rmb2.74/M³ maximum city gate price, if taking into consideration the long-distance pipeline tariffs of delivering from west China to Guangdong in south China.

CNOOC parent does not see a threat to its LNG import volumes even with as much as 9 bcm of supply from WEP2 by 2013 (5BCM estimated for 2012). This is because it expects the additional supply to be absorbed by demand growth and replacing some LPG demand, and its average LNG import cost is likely to remain lower than PetroChina's Turkmen supplies. Guangxi province has a price cap of Rmb2.57/M³ and it consumes around 0.2 bcm.

LNG

LNG imports are an important piece of the strategic drive to raise natural gas consumption as part of the broader theme of energy security for China. Policymakers want to develop domestic capability for the construction of the receiving terminals, shipping capacity and equity stakes if possible tied into long-term supply contracts.

Table 54: Existing terminals, import volumes and average costs

Operator Name ProvinceCapacity

MT pa Target Operational

date 2010 imports2010 average cost

(US$/mmbtu)11M 2011

imports11M 2011 average cost (US$/mmbtu)

CNOOC Dapeng Guangdong 6.7 7.8 2006 5.84 6.4 5.93 8.8CNOOC Putian Fujian 2.6 5.2 2008 2.03 5.1 2.36 6.5CNOOC Yangshan Shanghai 3.0 6.0 2009 1.48 6.8 1.62 7.9PetroChina Rudong Jiangsu 3.5 6.5 May 2011 NIL NIL 0.73 15.6PetroChina Dalian Liaoning 3.0 6.5 Nov 2011 NIL NIL 0.06 17.8

Source: General Administration of Customs; J.P. Morgan estimates, Bloomberg.

Table 55: Chinese equity participation in LNG liquefaction assets

Source Project Operator Year Ends Contract volumeCNOOC listco Australia Australia NWS Woodside-led 2006 2031 3.7CNOOC listco Indonesia Tangguh LNG BP-led 2007 2032 2.6CNOOC parent Australia QC LNG BG Group 2014 2034 3.6PetroChina Australia Arrow LNG Shell-PetroChina 2017 - 4.0Sinopec parent Australia APLNG Origin, ConocoPhillips 2015 2035 7.6


LNG will play a key role

162



Figure 99: Utilization rates of re-gasification terminals - %

Source: General Administration of Customs, J.P. Morgan estimates.

Figure 100: LNG re-gasification terminal capacity versus actual imports and SPA/HOA volumes –MT pa

Source: J.P. Morgan estimates, Company data, Bloomberg

Figure 101: LNG imports by location since 2006 when first imports landed in China - MT pa

Source: General Administration of Customs, J.P. Morgan estimates

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Figure 102: Average weighted LNG spot prices of Chinese imports for 2009-11- US$/mmbtu

Source: General Administration of Customs, J.P. Morgan estimates.

Table 56: Re-gasification terminals under construction – MT pa

Operator Name Province Capacity Target YearCNOOC Ningbo Zhejiang 3.0 6.0 2012CNOOC Zhuhai Guangdong 3.5 7.0 2013CNOOC Yuedong, Jieyang Guangdong 2.0 4.0 2013Sinopec Qingdao Shandong 3.0 6.0 2013PetroChina Tangshan, Caofeidian Hebei 3.5 6.5 2013CNOOC Yangpu Hainan 2.0 3.0 2014

Source: J.P. Morgan, Company data.

Table 57: Re-gasification terminals proposed – MT pa

Operator Name Province Capacity Target YearSinopec Tieshan Guangxi 3.0 5.0 2015PetroChina Shenzhen Guangdong 3.0 4.1 2015PetroChina Jinxi Liaoning - - NACNOOC Shenzhen Shenzhen 4.0 4.0 2015CNOOC Qinhuangdao Hebei 2.0 3.0 NACNOOC Binhai Jiangsu 3.0 - NACNOOC Floating terminal Tianjin - - NACNOOC Yingkou Liaoning - - NASinopec Wenzhou Zhejiang 2.0 - NASinopec Tanggu Tianjin - - NASinopec Lianyungang Jiangsu - - NASinopec Macau Guangdong 3.0 6.0 NA

Source: J.P. Morgan, Company data.

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164



Figure 103: Locations of China's LNG terminals in operation, under construction and planned

Source: Bloomberg.

Table 58: Ownership structure of CNOOC Group's terminals

Terminal Shareholders

Guangdong DapengCNOOC Gas & Power 33%, BP 15%, Shenzhen Gas 10%, Guangdong Yuedean 6%, Guangzhou Gas 6%, Shenzhen Energy 4%, Hong Kong Electric 3%, Hong Kong and China Gas 3%, Dongguan Fuel Industrial 2.5% and Foshan Gas 2.5%

Fujian CNOOC Gas & Power 60%, Fujian Investment and Development 40%Shanghai Shenergy 55%, CNOOC Gas & Power 45%Zhejiang Ningbo CNOOC Gas & Power 51%, Zhejiang Province Energy 29%, Ningbo Power Development 20%Hainan CNOOC Gas & Power 65%, Hainan Provincial Development 35%

Guangdong ZhuhaiCNOOC Gas & Power 25%, Guangdong Yuedean 30%, 45% split among Guangzhou Development City Gas, Guangdong Hong Kong Energy,Zhongshan Zhonghui, Jiangmen City Construction, Foshan City Gas Pipe, Zhuhai Economic Zone Power Development

Guangdong Yuedong CNOOC Gas & Power Shenzhen CNOOC Gas & Power


Table 59: Ownership structure of PetroChina's terminals

Terminal ShareholdersJiangsu Rudong Kunlun Energy (PetroChina's subsidiary) 55%, Pacific Oil and Gas 35%, Jiangsu Guoxin 10%Dalian Kunlun Energy 75, Dalian Port 20%, Dalian City 5%


Table 60: Ownership structure of Sinopec's terminals

Terminal ShareholdersQingdao Sinopec 99%, Qingdao Port 1%


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CNOOC

CNOOC and its parent company are the biggest Chinese owners of LNG assets because they had first mover advantage. Gas sales contracts are mainly to its power plants located next to its re-gas terminals, city gas distributors, and small volumes for CNG in transportation and industrial users. There are plans for a pipeline to link all of its re-gasification terminals to improve the distribution of its LNG imports to its customers.

CNOOC parent is the operator and holds the majority stakes in all three re-gasification terminals with a combined 12.7 MT pa capacity. CNOOC listco has equity stakes in the Northwest Shelf and Tangguh liquefaction projects.

Table 61: CNOOC's existing terminals and import costs

Re-gasification terminals Start dateGross capacity

MT pa 2010 imports 2010 average cost 11M2011 imports 11M2011 average cost SupplyDapeng, Guangdong 2006 6.7 5.84 6.4 5.93 8.8 NWS, QatarPutian, Fujian 2008 3.0 2.03 5.1 2.36 6.5 TangguhYangshan, Shanghai 2009 3.0 1.48 6.8 1.62 7.9 MLNG


Table 62: CNOOC's terminals under construction

Re-gasification terminals Scheduled start date Gross capacity MT paNingbo, Zhejiang 2012 3.0Zhuhai, Guangdong 2013 3.5Yuedong, Guangdong 2013 2.0Yangpu, Hainan 2014 2.0

Source: J.P. Morgan estimates, Company data. Table

Table 63: CNOOC's planned terminals

Re-gasification terminals Scheduled start date Gross capacity MT pa

Shenzhen, Guangdong 2015 4.0Qinhuangdao, Hebei NA 2.0Jiangsu NA 3.0Floating terminal, Tianjin NA NA Yingkou, Liaoning NA NA


Table 64: CNOOC's existing LNG contracts

Source Project Operator Year Ends Volume Equity stakeAustralia Australia NWS Woodside-led 2006 2031 3.7 YMalaysia MLNG Tiga MLNG 2009 2034 3.0Qatar Qatargas 3 Qatargas 2009 2034 2.0Indonesia Tangguh LNG BP-led 2007 2032 2.6 YFlexible Portfolio Total 2010 2030 1.0


Table 65: CNOOC's future LNG supply contracts

Source Project Operator Year Ends Volume Equity stake

Australia Curtis LNG BG Group 2014 2034 3.6 Y (parent)Qatar Qatargas 2 Qatargas 2013 2038 5.0Unspecified GDF Suez GDF 2013 2016 2.6



(852) 2800-8578

[email protected]

166



Table 66: CNOOC's stakes in liquefaction assets

Liquefaction plant Start date Gross capacity MT pa EquityAustralia NWS 2004 16.3 5.3%Tangguh LNG 2009 7.6 13.9%Curtis LNG 2014 8.5 10.0%


We do not ascribe any specific value to CNOOC’s LNG assets. Import terminals are held at parent level. Although two upstream equity stakes are held by listco theircontribution to CNOOC’s overall NPV is small.

167



PetroChina

PetroChina is the largest Chinese natural gas supplier in terms of domestic production and imports. Each year, PetroChina signs gas sales agreements with customers subject to the plans specified by the government. For LNG, gas sales agreements are similar to its onshore gas sales, according to management.

PetroChina has been importing LNG spot cargoes so far, because its term supply contracts are commencing after its first two re-gasification terminals are ready. The Jiangsu and Dalian terminals started operating in 2011 with a combined 6.5 MT pacapacity, while PetroChina's first contract with Qatar may only supply full volumes by 2013.

Table 67: PetroChina's re-gasification terminals in operation

Re-gasification terminals Start date Gross capacity MT pa 11M2011 imports 11M2011 average cost Supply

Rudong, Jiangsu May 2011 3.5 0.73 15.6 QatarDalian, Liaoning Nov 2011 3.5 0.06 17.8 Qatar


Table 68: PetroChina's re-gasification terminals under construction

Re-gasification terminals Scheduled start date Gross capacity MT pa

Caofeidian, Hebei 2013 3.5


Table 69: PetroChina's planned re-gasification terminals

Re-gasification terminals Scheduled start date Gross capacity MT paShenzhen, Guangdong 2015 3.0Jinxi, Liaoning NIL NIL


Table 70: PetroChina's gas supply contracts

Source Project Operator Year Ends VolumeEquity stake

Qatar Qatargas 4 Qatargas 2012 2037 3.0Qatar Qatargas 4 Qatargas 2013 2038 2.0Australia Gorgon LNG Chevron, Exxon, Shell 2014 2034 2.0Australia Gorgon LNG Chevron, Exxon, Shell 2014 2034 2.3


Table 71: PetroChina's liquefaction asset

Liquefaction plant Start date Gross capacity MT pa Equity Net capacity MT pa

Australia Arrow LNG 2017 8 (first stage) 50% 4


We do not ascribe any specific value to PetroChina’s LNG assets. Import terminals are actually held through a 50.5% owned listed subsidiary Kunlun Energy (135 HK) with overall NPV accruing to PetroChina relatively small. LNG supply contracts are however, as far as we understand, held by PetroChina.


(852) 2800-8578

[email protected]

168



Sinopec

Sinopec's domestic natural gas production is mainly used to meet demand from its refining and chemical operations. It is likely that Sinopec’s LNG imports will be used to serve its internal demand, to reduce consumption of oil products for power and heat generation and in turn to increase its refinery product yield.

Sinopec’s first LNG terminal Shandong will receive cargoes from PNG LNG, but the terminal is scheduled for 2013 completion, while Exxon Mobil and its partners are expected to start first deliveries from the project in 2014. Sinopec’s only stake in liquefaction capacity is in APLNG – this is held by its state parent Sinopec Group (initially 15%).

Sinopec Group signed an agreement in December 2011 with ConocoPhillips and Origin Energy for another 10% in the 9 MT pa APLNG project in Queensland, Australia raising its total stake to 25%. In the same agreement, Sinopec will buy another 3.3 MT pa of LNG from 2015 for 20 years, bringing the total contracted volumes to 7.6 MT pa.

Table 72: Sinopec's re-gasification terminal under construction

Re-gasification terminals Scheduled start date Gross capacity MT pa Supply

Qingdao, Shandong 2013 3.0 PNG LNG


Table 73: Sinopec's planned re-gasification terminals

Re-gasification terminals Scheduled start date Gross capacity MT paTieshan, Guangxi 2015 3.0Tanggu, Tianjin NIL NILLianyun, Jiangsu NIL NILWenzhou, Zhejiang NIL 2.0Macau NIL 3


Table 74: Sinopec's LNG supply contracts

Source Project Operator Year Ends Volume Equity stakeAustralia APLNG Origin, Conoco 2015 2035 7.6 Y (parent 25%)Papua New Guinea PNG LNG Exxon, Oil Search 2015 2035 2.0


Table 75: Sinopec's liquefaction asset

Liquefaction plant Start date Gross capacity MT pa Equity

APLNG 2015 9.0 (first two trains) 25% (parent)


We do not ascribe any specific value to Sinopec’s LNG assets. Import terminals are held at listco level, while upstream equity stakes are held by its parent. In any event, contribution to Sinopec’s overall NPV is relatively small.


(852) 2800-8578

[email protected]

169



Overview India LNG

Supply / demand outlook

Infrastructure and domestic gas supply constraints have historically limited gas usage in India. However, with increased gas availability with the discovery of gas off the east coast of the country (KG-D6 primarily), a significant build out of gas pipeline infrastructure has taken place. This has connected new demand centers to supply sources, and has spurred gas demand growth. Availability of gas at reasonable price points will also spur conversions from liquid to gaseous fuels.

Table 76: India gas demand-supply

FY10 FY11 FY12E FY13E FY14E FY15EDemand (mmscmd) 193.6 211.2 222.0 253.5 269.2 278.8Demand (bcm) 69.7 76.0 79.9 91.2 96.9 100.4

Domestic supply (mmscmd) 112.5 137.4 132.9 150.3 166.3 183.3Domestic supply (bcm) 40.5 49.5 47.8 54.1 59.9 66.0LNG (mmscmd) 33.8 35.6 46.8 61.2 67.5 74.7LNG (bcm) 12.2 12.8 16.8 22.0 24.3 26.9Total Supply (mmscmd) 146.3 173.0 179.7 211.5 233.8 258.0Total Supply (bcm) 52.7 62.3 64.7 76.1 84.2 92.9


Incremental sources of domestic supply are concentrated in the medium term on the east coast of the country (mainly KG-D6), where we believe the RIL-BP JV will be able to work through the difficulties faced to reach a production rate of 90 mmcmpd. We also build in commencement of supplies from other GSPC / ONGC field developments.

Demand growth is driven by new gas based power projects. However, while a much larger quantity of gas based power capacity is being constructed/planned in the country, our power/utilities team assumes a lower effective demand number from these, limited by domestic gas constraints. Fertilizer plants will continue to move from liquid to gaseous fuels. The growth of the city gas distribution (CGD) business will also stimulate demand growth.

With demand exceeding supply and domestic gas sources unable to ramp up production to previously expected levels, we expect imports of LNG to remain robust, particularly to supply key sectors such as refining/steel/CGD, which are accorded a low priority for allocation of domestic gas.

Domestic gas supplies are not ramping up as was earlier anticipated – primarily due to a fall in production from the KG-D6 development, where the reservoir has proved to be more complex than expected. However, further studies are being carried out, and post the on-boarding of BP as a JV partner, RIL has submitted plans to develop other parts of the field to boost output. The bulk of state-owned ONGC’s gas fields are mature, and the company is fighting hard to simply maintain output levels.

While demand for LNG has been robust, import capacity increases will only occur in the next 12-18 months. PLNG will commission its Kochi terminal at the end of 2012, and it will raise capacity at its existing Dahej terminal with the completion of a second jetty in late 2013. GAIL expects to commission its west coast Dabhol

Indian gas demand remains supply constrained

domestic supplies stagnant

LNG import capacity increases

only in the next 12-18 months

170



terminal in by end Q1 2012. However this will initially operate only at 50-60% capacity on an annual basis, as a breakwater is yet to be constructed. As a result, LNG volume growth is likely to be muted over the near-term. This is reflected in our LNG import forecasts (Table 74).

Table 77: LNG import terminal projects in the pipeline

Project TimelinePLNG Kochi Sep 2012PLNG Dahej - jetty Sep-Dec 2013PLNG Dahej - expansion End 2016GAIL Dabhol Mar 2012


Spot LNG prices have continued to rise over the past few months – these are nowclose to liquid fuel levels. This could begin to have an impact on demand fromindustrial users. In particular, we expect spot LNG prices to be firm in the winter, which could affect near-term industrial consumption growth.

Figure 104: R-LNG vs. liquid fuels (US$/mmbtu)

Source: Bloomberg, J.P. Morgan estimates

Exacerbating the rise in LNG prices has been the recent depreciation in the INR (18% since August 2011) – necessitating price hikes, which could also impact demand from industrial users.

Figure 105: INR exchange rate

Source: Bloomberg.

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Petronet LNG


Petronet LNG (PLNG) currently operates a 10 MT pa LNG terminal at Dahej on the western coast of India. This facility's capacity is to be ramped up in 2 steps - to 12.5 MT pa with the completion of a second jetty (expected in late 2013), with additional re-gasification facilities to be added later, raising capacity to 17.5 MT pa. PLNG is also constructing a new terminal at Kochi (5 MT pa) on the south-western coast. This facility is expected to be completed in Q4 2012.


PLNG is engaged in the business of sourcing LNG and providing re-gasification services, and is continuing to focus on this segment of the value chain, with capacity expansion at the existing Dahej terminal, and the construction of a new terminal at Kochi. Given the large mismatch between gas demand and supply in India, PLNG plays a key role bridging that gap by providing the necessary import capacity. While various LNG terminals are being planned across India (GAIL's 5 MT pa Dabhol terminal will start up in Q1 2012), PLNG remains the largest player. Given the projected rise in domestic gas demand, we believe that the build out of pipeline infrastructure and additional LNG import capacity are required.

A key question is the sourcing of long-term gas supplies. At Dahej, PLNG has a long-term contract with RasGas of Qatar for 7.5 MT pa, and a 1.5 MT pa supply contract from Gorgon LNG, Australia to be delivered to its Kochi terminal. However, this leaves un-booked import capacity that so far has been partly filled by sourcing spot/medium -term LNG supplies. With the capacity expansion at Dahej and start-up of Kochi, PLNG would need to begin tying in additional long-term supplies. We note that there have been news reports of possible tie-ups with Russian suppliers and potential new agreements with Qatar.

Liquefaction assets

PLNG currently operates a single re-gasification terminal. It does not possess any liquefaction assets.


At present, PLNG has one operational LNG terminal at Dahej. The nameplate capacity for this terminal is 10 MT pa (currently operating at a rate of ~10.5 MT pa). A jetty that will raise capacity to 12.5 MT pa is under construction and expected to be completed in late 2013. The company is soon to decide whether additional re-gasification capacity of 5 MT should be added at this terminal. We note that construction would likely take around 42 months.

A new LNG terminal is being constructed at Kochi, with a capacity of 5 MT pa. It is expected to be completed by the end of 2012.

Pradeep Mirchandani, CFA

(91-22) 6157-3591

[email protected]

Petronet is leading India's build

out of LNG import capacity

172



LNG shipping assets

PLNG has a time charter arrangement with a consortium led by the Shipping Corporation of India for three LNG tankers. These are responsible for transporting the long-term quantity of gas contracted from RasGas (7.5 MT pa) to the Dahej terminal.


PLNG is exclusively an LNG company. We value PLNG using a DCF valuation, to arrive at our price target of Rs190 of which the Kochi terminal accounts for ~Rs32 per share.

Key upside risks are a moderation in LNG prices and key downside risks are a road map to ramp up of domestic gas supplies.

Table 78: PLNG valuation

FY12 FY13 FY14 FY15 Terminal cash flow (Mar-21)EBITDA 17,227 21,338 26,131 32,184 Cash Tax Payable (4,056) (4,402) (5,394) (7,194)Working Capital changes 3,898 (3,441) (2,470) 7,241 Capex (17,041) (11,500) (6,500) (3,000)Adjusted free cash flow 28 1,995 11,767 29,231 12,120

Terminal growth rate 3.0%WACC 11.7%DCF ValuationNet Present Value of explicit cash flows 94,065 NPV of Terminal Value (Mar-21) 67,881 Enterprise Value 161,946 Less: Net Debt (Mar11) 20,936 Equity Value 141,010 No. Shares (millions) 750 Per Share Equity Value 188


173



Appendix I: LNG exporting countries

The following table lists the countries that can, or are expected to be able, to export LNG. At end 2011, there were only eighteen countries in the world with LNG export facilities – no new countries joined this fairly elite group during 2011. By 2015, this number will have increased by only two to twenty (given first exports from Angola and Papua New Guinea). By the end of 2018, we expect the number of countries exporting LNG to reach twenty-eight although we have reservations about the ability of two countries – Iran and Iraq – to attract the necessary capital and expertise and deliver the projects. We have pushed Venezuela out to 2020 - industry historians may recall that in 1960 the British Gas Council proposed importing LNG from Venezuela to Canvey Island.

Specific to Iran, we note that in 2010, the US Congress passed the Comprehensive Iran Sanctions, Accountability, and Divestment Act (CISADA) - this allows the President to impose sanctions on any company that invests $20m or more in Iran's oil & gas sector. The US Treasury Department has also designated Iran and its central banks as a ‘territory of primary money laundering concern’ – a move designed to pressure all banks and companies not to deal with Iran's financial system. The threat of sanction has persuaded most major oil companies to sever all ties with Iranalthough many national oil companies still procure crude from Iran.

Table 79: LNG exporting countries

OECD LNG exporters Non-OECD LNG exporters

Producing 2009 (16) Australia Abu DhabiNorway AlgeriaUSA (Alaska) Brunei

EgyptEquatorial GuineaIndonesiaLibyaNigeriaMalaysiaOmanRussiaTrinidad & TobagoQatar

2010 (18) - PeruYemen

2011 (18) - -2012E (19) - Angola2013E (19) - -2014E (20) - Papua New Guinea2015E (20) - -2016E (21) Canada -2017E (22) - Iraq2018E (28) Brazil

- CameroonEast TimorIranMozambiqueTanzania


We are more confident that both Mozambique and Tanzania will become a new East African LNG export hub – this is ideally located to supply the west coast of India and Asia Pacific. Specific to Mozambique, ENI believes that it has discovered up to 22.5

Only 18 countries exported LNG in 2011

Iran may fall off the list of potential supply points

More confident about East

African LNG hub

174



TCF at its Mamba South-1 discovery in the Offshore Area, Rovuma Basin (ENI 70%, ENH 10%, KOGAS 10% and GALP 10%). Following the successful Barquentine-3 appraisal well (encountered more than 202m of natural gas pay), the separate consortium led by Anadarko (Area 1- Anadarko 36.5%, Mitsui 20%, ENH 15%, Bharat PetroResources 10%, Videocon 10% and Cove Energy 8.5%) now estimates recoverable resources to range from 15 to 30+ TCF with estimated 30 to 50+ TCF of gas in place in the Oligocene and Eocene reservoirs. This is the sixth successful penetration in the complex that includes Windjammer, Lagosta, Barquentine and Camarao discoveries (the WLBC gas complex – Offshore Area 1). Anadarko now refers to a large scale LNG development to consist of at least 2 trains and with the flexibility to expand to 6 trains. The governments of both Mozambique and Tanzania are actively encouraging LNG developments in their country.

Table 80: Schedule for LNG project Final Investment Decision (FID)2012 MT pa On stream 2013 MT pa On stream 2014 MT pa On stream

Brass LNG 10.0 2018 Abadi FLNG 2.5 2019 Bonaparte LNG 2.0 2019Browse LNG 12.0 2017 Cash Maple FLNG 2.0 2017 Colombia LNG 1.0 2020Ichthys LNG 8.4 2017 Curtis Island LNG 8.0 2018 Tangguh LNG T3 3.8 2018Kitimat LNG 5.3 2016 Kribi LNG 3.5 2018PNG FLNG 2.0 2017 Mozambique LNG 10.0 2018Pluto LNG T2 4.3 2015 Newcastle LNG 1.0 2017Sabine Pass LNG 9.0 2016 Tanzania LNG 6.6 2018Sengkang LNG 1.5 2015Shtokman LNG 7.5 2019

60.0 33.6 6.8


Israel could also join the club of LNG exporters - the US Geological Survey estimates 120 TCF of recoverable gas in the Levant Basin which straddles Lebanon and Palestine. Indeed, Noble Energy has talked about a 15 MT pa plant, potentially located in Cyprus, to process gas from its giant (> 10 TC) Leviathan gas discovery.

As a reminder of the non-OECD bias of LNG supplies, twenty-four of the twenty-eight countries that may export LNG by 2018 are not members of the OECD (Figure 109). We believe that this will continue to place a price and value premium on LNG that is sourced from countries within the OECD, e.g. North America and Australia.

Figure 106: LNG exporting countries


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Appendix II: LNG export projects

We maintain a global database on all liquefaction projects - sanctioned, pending sanction and those in concept stage (Table 78). As per Figure 110, following the substantial capacity additions in 2009 and 2010, we have already witnessed a dramatic slow down in capacity additions in 2011 which we expect will continue through to 2014. We then expect an acceleration in new capacity in 2015 through to 2018.

Figure 107: Liquefaction capacity - annual growth (MT pa)


The impact on global liquefaction capacity is shown in Figure 111. This shows that capacity growth (2000-10 CAGR 7%) broadly matched demand growth in the last decade (2000-10 8%). However, it suggests that capacity growth could fall behind demand growth 2010-2016. Between 2011 and 2015, we forecast a capacity CAGR of 5%. Furthermore, this assumes that (i) there are no unexpected, material plant outages (ii) there is no lost capacity due to upstream resource depletion (iii) all new projects are efficiently commissioned on schedule. On balance, we therefore expect the market to continue to tighten.

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176



Figure 108: Global liquefaction capacity (MT pa)


As per Figure 112, the world’s average liquefaction train size will continue to rise. From a starting level of just over 1 MT pa, we estimate an average train size of 3.7 MT pa by 2020 based on a forecast total of 193 trains. This mirrors an equivalent trend in refining for ever larger refineries.

Figure 109: Number of LNG trains and global average capacity (MT pa, RHA)


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177



Table 81: LNG capacity additions 2012-2020E

2012E 2013E 2014ECountry Project MT pa Country Project MT pa Country Project MT paAngola Angola LNG 5.2 Algeria GL3Z Arzew 4.7 Australia Gorgon LNG T1 5.0Australia Pluto LNG T1 4.3 Skikda LNG 4.5 QC LNG T1 4.3

PNG PNG LNG T1 3.3Capacity b/f 95 291.2 Capacity b/f 97 300.7 Capacity b/f 99 309.9Trains / Additions 2 9.5 Trains / Additions 2 9.2 Trains / Additions 3 12.6Capacity c/f 97 300.7 Capacity c/f 99 309.9 Capacity c/f 102 322.4YoY growth 3% YoY growth 3% YoY growth 4%Average train size 3.1 Average train size 3.1 Average train size 3.2Exporting countries 19 Exporting countries 19 Exporting countries 202015E 2016E 2017ECountry Project MT pa Country Project MT pa Country Project MT paAustralia AP LNG T1 4.5 Abu Dhabi ADGAS T4 4.0 Australia Prelude LNG 3.5

Darwin LNG T2 1.0 Australia AP LNG T2 4.5 Browse LNG T1 4.0Gladstone T1 3.9 Fishermans Island 3.0 Cash Maple LNG 2.0Gorgon LNG T2 5.0 Gladstone LNG T2 3.9 Gorgon LNG T4 5.0Pluto LNG T2 4.3 Gorgon LNG T3 5.0 Ichthys LNG T1-2 8.4QC LNG T1 4.3 Wheatstone LNG T1 4.5 Newcastle LNG 1.0

Indonesia Sengkang LNG 1.5 Canada Kitimat LNG T1 5.3 QC LNG T3 4.3PNG PNG LNG T2 3.3 Indonesia Senoro-Donggi LNG 2.0 Scarborough LNG 5.0

Libya Marsa El Brega 2.6 S. Australia LNG 1.0Malaysia Sarawak FLNG 1.0 Wheatstone T2 4.5Russia Sakhalin LNG T3 5.0 Canada Prince Rupert T1-2 8.0USA Freeport LNG T1-2 9.0 Iraq Khawr al-Amaya 2.0

Sabine Pass T1-2 9.0 Malaysia Progress FLNG 1.5PNG PNG LNG T3 3.3

Gulf LNG Train 1 2.5Gulf FLNG 2.0

USA Lake Charles T1 5.0Capacity b/f 102 322.4 Capacity b/f 110 350.2 Capacity b/f 125 408.9Trains / Additions 8 27.8 Trains / Additions 15 58.8 Trains / Additions 19 62.9Capacity c/f 110 350.2 Capacity c/f 125 408.9 Capacity c/f 144 471.8YoY growth 9% YoY growth 17% YoY growth 15%Average train size 3.2 Average train size 3.3 Average train size 3.3Exporting countries 20 Exporting countries 21 Exporting countries 222018E 2019E 2020ECountry Project MT pa Country Project MT pa Country Project MT paAustralia Browse T2-3 8.0 Australia Bonaparte FLNG 2.0 Colombia Colombia LNG 1.0

Curtis Isl. T1-2 8.0 Indonesia Abadi FLNG 2.5 Iran Persian LNG 16.2Sunrise FLNG 3.6 Iran Pars LNG T2 5.0 Nigeria NLNG T8 8.5

Brazil Santos FLNG 2.7 Iran LNG T1-2 10.0 OK LNG 12.6Cameroon Kribi LNG 3.5 Malaysia SK 205 FLNG 3.0 Russia Pechora LNG 2.6Canada BC LNG 1.8 Mozambique Mozambique T2 5.0 Yamal LNG T2-3 10.0

Progress LNG 7.4 Nigeria Brass LNG T2 5.0 USA Cove Point T1-2 7.8Egypt Damietta T2 4.8 NLNG T7 5.0 Cameron LNG T1-3 12.0Equatorial Guinea Punta Eur T2 4.4 Russia Shtokman LNG T2 5.3 Jordan LNG T1-2 9.0Indonesia Tangguh T3 3.8 Yamal LNG T1 5.0 Venezuela GM de Ayacucho 4.7Iran Pars LNG T1 5.0Mozambique Mozambique T1 5.0Nigeria Brass LNG T1 5.0Norway Snohvit LNG T2 4.3Russia Shtokman T1 7.5

Vladivostok T1-2 10.0Tanzania Tanzania T1 6.6Trinidad ALNG Train X 5.0USA L.Charles T2-3 10.0Capacity b/f 144 471.8 Capacity b/f 167 578.2 Capacity b/f 178 626.0Trains / Additions 23 106.4 Trains / Additions 11 47.8 Trains / Additions 15 84.4Capacity c/f 167 578.2 Capacity c/f 178 626.0 Capacity c/f 193 710.4YoY growth 23% YoY growth 8% YoY growth 13%Average train size 3.5 Average train size 3.5 Average train size 3.7Exporting countries 28 Exporting countries 28 Exporting countries 30


178



Appendix III: LNG importing countries

We also maintain a database on all LNG re-gasification terminals worldwide. This helps us to anticipate new sources of demand. By the end of 2011, we estimate that 25 countries will have operational re-gasification capacity, i.e. the ability to import LNG. During 2011, three countries commissioned their first LNG import terminals –Dubai (FSRU), Netherlands (GATE LNG) and Thailand (Rayong LNG). Our database on re-gasification projects suggests that by end 2015, the number of countries with LNG import terminals will have almost doubled to 47 (Figure 113). This is an unprecedented pace of growth. As per Figure 114, we expect that the number of re-gasification terminals will increase from 90 at year end 2011 to as many as 159 terminals.

Figure 110: Number of countries with re-gasification terminals


Figure 111: Number of re-gasification terminals


We estimate that global aggregate re-gasification capacity will rise from 565 MT pa at end 2011 to 777 MT pa by end 2015. This represents a re-gasification capacity CAGR of 8%.

Figure 112: Re-gasification capacity (MT pa)


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Of note, the number of theoretical supply point to import point connections will rise from 2,430 at end 2011 (90 multiplied by 27) to 5,600 at end 2015 (160 multiplied by 35), an increase of 130%. The embedded ‘optionality’ of the global LNG systemwill thus rise very materially – buyers will have more choice as indeed will sellers. A higher number of supply and import points ought to make it harder for any single supplier to control pricing. Furthermore, the market's deeper liquidity ought to provide some protection from potential demand or supply shocks.

Table 82: New LNG re-gasification terminals

Country 2010 2011 2012E 2013E 2014E 2015EAlbania - - - - - 1 Argentina - 1 - - - - Bahamas - - - - 1 - Bahrain - - - - 1 - Bangladesh - - - - 1 - Brazil - - - - 1 -Canada - - - - - 1Chile 1 - - - - - China 1 2 2 3 2 2 Colombia - - - - 1 - Croatia - - - - - - Cyprus - - - - 1 - Dominican Republic - - - - - - Dubai - 1 - - - - Estonia - - - - - 1 France 1 - - - - -Germany - - - - - - Greece - - - - - - India - 1 3 - - 4 Indonesia - - 1 2 1 - Ireland - - - - - - Israel - - - 1 - - Italy - - 1 1 3 3 Jamaica - - - - 1 - Japan - - 1 1 1 2 Kuwait - - - - - - Lithuania - - - - 1 - Malaysia - - 1 - - - Mexico - 1 - - 1 1 Netherlands - 1 - 1 1 - Pakistan - - - 2 1 - Panama - - - - - 1 Philippines - - - - - 1 Poland - - - - 1 - Portugal - - 1 - - - Puerto Rico - - - - - - Singapore - - - 1 - - Slovenia - - - - - - South Africa - - 1 - - - South Korea - - - - - 1 Spain - - 1 - - - Sri Lanka - - - 1 - - Sweden - - 1 - - Taiwan - - - - - - Thailand - 1 - - - - Turkey - - - - - - UK - - - 1 - - Uruguay - - - 1 - - Ukraine - - - - 1 - US 1 1 - 1 - 1 Vietnam - - - 1 - 1 Total number of LNG import terminals 4 8 13 18 21 21


180



Figure 113: LNG re-gasification terminals - 2011 to 2015E


Floating storage and re-gasification units

So called FSRUs are becoming more popular as very practical alternatives to conventional onshore re-gasification terminals. They are purpose built LNG tankers with vaporization equipment. They can offer three specific advantages:

1. Easier permitting - since they do not require land requisition and site conversion. Local opposition to onshore sites can often slow down projects e.g. in Italy.

2. Cheaper - since a vessel may cost $100m and the conversion may be done for only $50m; this compares to an onshore facility which (depending on its size and location) may cost $0.5bn to $1.0bn.

3. Quicker to install - given the aforementioned features, an FSRU may be operational within 12-18 months whereas a conventional onshore terminal may take 3-4 years to build and commission.

Eight FSRUs are already operational in Argentina (2), Brazil (2), Chile (1), Dubai(1), Italy (1) and Kuwait (1). In Table 80, we list other venues for FSRUs. Exmar, Excelerate Energy, Golar LNG and Hoegh LNG are the world’s leading providers of FSRUs.

2010 terminals

2011 addition

2012E addition

65

31 (’10)

2

2013E addition

2014E addition

2015E addition

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Table 83: Potential FSRU projects

Country Location Project developers Capacity (GM3 pa) Start dateEMEAAlbania Fiere ASG Power, Gruppo Falcione 8.0 2015Germany Wilhelmshaven Excelerate Energy, RWE, Nord-West Oelleitung 5.1 2017Israel Ashkelon / Ashdod TBC 4.0 2014Italy Livorno OLT Offshore 1.5 2012

Senigallia Ancona GDF Suez, Hoegh LNG 5.0 2015Falconara Marittima Api (Nova Energia) 1.5 2015

Jordan Red Sea Ministry of Energy & Mineral Resources 1.0 TBCLithuania Klaipeda Port, Baltic Sea Klaipedos Nafat 1.0 2014South Africa Mossel Bay PetroSA 1.0 2012UK Port Meridian Hoegh LNG 8.0 2013AsiaBangladesh Maiskhali Island PetroBangla 5.0 2014Indonesia West Java Pertamina, PGN 1.5 2013

North Sumatra Pertamina, PGN 1.5 2013Malaysia Malacca Straits Petronas 5.0 2012Pakistan Port Qasim Dana Gas 1.5 2013

Khalifa Point Global Edison, Cavalier Energy 4.0 2013Vietnam Vietnam PV Gas, DNV TBC 2013AmericasBrazil TBC Utility consortium 2.5 2014Mexico Lazaro Cardenas KMX de GNL 5.1 2014Jamaica Port Esquivel or Kingston Harbour Exmar, Petroleum Corp of Jamaica 2.3 2014Uruguay Rio De La Plata ANCAP, ENARSA, UTE TBC 2013USA Port Dolphin Hoegh LNG TBC 2013


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Appendix IV: LNG shipping

LNG ships obviously enable LNG delivery from exporter to importer. Historically, this has been a Supply Point A to Demand Centre B fixed 'milk run’. However, by unlocking ships from such fixed routes, this basic role of LNG ships has evolved to enable LNG suppliers to capture regional price arbitrage and to help optimize overall LNG portfolio returns. As such, LNG ships have become more valuable and strategically important assets.

Population of players

The first LNG carrier, the Methane Pioneer, transported a cargo of LNG from Lake Charles to Canvey Island in the UK in 1959. In the 54 years since then, the population of LNG shippers has remained relatively small and is dominated by liquefaction players that want to have control over the shipping process to their customers, typically via dedicated fleets. Another factor inhibiting population growth is the relatively high new build costs ($220m to $300m) - LNG shipping is a niche market which is dominated by a number of very large companies, some state-owned (Table 81).

Table 84: Owners and operators of LNG vessels

State entities Utilities IOCs Conglomerates Listed shippers Private shippersADNOC (National Gas Shipping)

GDF SUEZ (Maran Gas Maritime)

BG Group (Methane Services) Hanjin Group Awilco LNG

Bluesky LNG (Taiwan Maritime Transport)

Gazprom Global LNG Gas Natural BP (Shipping) Hyundai Exmar * DynagasPetronas (MISC Bhd) Kansai Electric Power Chevron (Shipping) * Golar LNG Knutsen OAS ShippingQatar (Nakilat) Petronet LNG ConocoPhillips Mitsui OSK Lines Hoegh LNG ** SK ShippingSonatrach (BW Gas, Hyproc Shipping)

TEPCO (LNG Marine Transport) ENI

I.M. Skaugen (Norgas Carriers) Stena Bulk

Sovcomflo Exxon Mobil STX Pan OceanRD Shell (STASCO)Repsol YPFStatoil

Source: J.P. Morgan.. * Also provide FSRU units.

Most participants in liquefaction, public and private, also own LNG ships either directly or through joint ventures. However, there are also a number of pure shipping companies, many of which are listed. Listed utilities that import LNG also have shipping fleets. A number of commodity traders also lease vessels e.g. EGL Group, Vitol, Gunvor, Morgan Stanley and J.P. Morgan.

LNG shipping set for a couple ofgood years ahead

Relatively small population of

shippers

183



Figure 114: Global LNG shipping fleet - size distribution

Source: J.P. Morgan. Q-Max vessels first entered the market in 2009. These vessels are 360m long and can carry 266,000 cubic

meters of gas. Their size precludes them from berthing at most LNG re-gasification terminals.

Supply / demand dynamics

Notwithstanding a relatively small and disciplined population of ship owners, the market is prone to imbalances and this leads to volatile freight rates. One cause of over-supply is when new ships that are dedicated to an export project are delivered on schedule, but the liquefaction facility that they are to serve is late to commission. This occurred in mid-2010 which pushed short term charter rates down to $30,000 per day.

Charter rates for LNG vessels, sometimes referred to as floating gas pipelines, have surged from the lows of mid-2010 of c.$30,000 per day – a level that is close to break-even for most tankers – to over $125,000 per day for long term charter on Atlantic routes. Two factors have triggered a quadrupling of rates - a recovery in Asian LNG demand and the Fukushima disaster – both have raised demand for long haul LNG. In just two years, the level of idle capacity has fallen from 30% of the global fleet to less than 10%. We count over 360 LNG vessels in operation and another 63 are currently on order.

0

20000

40000

60000

80000

100000

120000

140000

160000

1 31 61 91 121 151 181 211 241 271 301 331 361

Average 78,500 DWT

Q-Flex

Q-Max

Global fleet 361 vessels, 28.4 MT DWT capacity

More long haul LNG expected as

Atlantic Basin feeds Asia Pacific

Charter rates have quadrupled

from 2010 lows

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Figure 115: LNG shipping routes and current freight rates ($/mmbtu)


Figure 118 shows the current costs expressed in $ per mmbtu. The longest, most expensive route – from Atlantic LNG to Tokyo – is around $4.3 per mmbtu. Given a cost of LNG of around $6 per mmbtu, this route is still a viable one given recent clearing prices in Tokyo harbor over $17 per mmbtu.

We see three important changes in the LNG shipping market that will impact charter rates in the medium term: (i) the expansion of the Panama Canal (ii) the development of ice-breaking LNG vessels (iii) efforts to raise fleet efficiency via cargo swaps and back haul cargoes.

The $5.25bn expansion of the Panama Canal will enable LNG carriers to pass through it by Q4 2014. Only Q-size vessels will be unable to fit through the expanded canal. The toll for LNG vessels has yet to be agreed. Clearly, it will reduce the journey time for cargoes from the Atlantic Basin in to Asia Pacific. For example, a journey from Atlantic LNG (Trinidad) to Japan via the Suez Canal would take 11 days less via the Panama Canal.

The design of new ice-breaking LNG vessels will also enable supplies of Russian Arctic LNG to reach Asian markets without sailing via the Suez Canal. Aker Arctic has completed the design and model testing of tankers that may be able to travel to Asia via Russia’s North Sea Route (NSR). These Arctic 7 vessels can travel at speeds up to 19.5 knots in clear water and 5.5 knots through ice that is 1.5m thick. As a result of relatively high temperatures in 2011, the NSR was open for a record of five months.

Trinidad to Quintero , $2.1/MMBtu

Trinidad to Tokyo , $4.3/MMBtu

Trinidad to Zeebrugge, $1.3/MMBtu

Nigeria to Montoir , $1.3/MMBtu

Nigeria to Cove Point, $1.7/MMBtu

Middle east to Hazira, $0.5/MMBtu

Middle east to Tokyo, $2.1/MMBtu

Middle east to Huelva, $2.0/MMBtu

Australia to Hazira, $1.3/MMBtu

Australia to Tokyo, $1.2/MMBtu

North Africa to Sines, $0.3/MMBtu

Panama Canal expansion will

reduce journey times to Asia

LNG ice-breakers may also open

up a shorter route to Asia

185



Historically, LNG carriers were typically dedicated to a specific export project and tied to a specific route – the so called ‘milk run’. However, just as we have seen innovation in LNG contracting (with a shift to greater destination flexibility), we are also seeing ships being used more tactically and commercially. This is leading to enhanced fleet efficiency which is necessary given average vessel utilization in 2011 was just 75% versus a peak of over 90% in 2004. Two initiatives that are leading to higher vessel utilization are:

1. Cargo swaps – rather than two tankers crossing each other, buyers and sellers are coordinating more via cargo swaps. So, for example, if a seller has agreed to supply a cargo to Tokyo from West Africa and another seller has agreed to supply a European buyer from Peru, it may be possible for the two sellers to swap their obligations.

2. Back haul cargoes – rather than a ship returning empty to its liquefaction plant after unloading its cargo, it is possible for it to reload on route from another LNG facility and to empty that cargo at another re-gasification terminal.

So, the global fleet may be used more efficiently and certain key routes (US and Russia to Asia) shortened. At the same time, the average size of LNG vessels is slowly increasing, more ships are expected to be delivered in 2013 and the start-up of several new sources of LNG supply in Australia in 2014-15 will also target Asia Pacific with a shorter haul thereto.

However, at roughly the same time, the advent of North American non-conventional gas as a source of LNG exports post-2015 means that there will be increased demand for long haul LNG shipping, if this source gas is to reach both the key demand centers in Asia Pacific and Europe. This will raise the fleet’s average ton per mile.

On balance, these factors may mitigate further day rate inflation, although we would expect the LNG shipping market to remain tight throughout 2012 and in to early 2013.

Vessel specification

The largest LNG carrier is the Q-Max vessel (Figure 119). One Q-Max carrier brings enough energy for 70,000 homes for one year – these are high density energy parcels.Assuming an LNG discharge volume of around 260,000 M3 from a Q-Max vessel (the world’s largest with a 7.5% heel), if the cargo sells for $10 (15) per mmbtu, it has a sales value between $90m and $130m. This compares to the world's largest Ultra Large Crude Carriers (ULCC) which carry cargoes of 0.55 MT - at $100 per barrel, such a large cargo has a market value of over $400m, four times the value of the largest LNG cargo.

Fleet utilization can rise as

vessels are used more efficiently

We expect LNG day rates to

remain high through 2012

LNG cargoes worth $90m to

$130m+

186



Figure 116: LNG vessels - evolution since inception


The rise in LNG freight rates has been in stark contrast to the decline in oil tanker freight rates which have declined due to surplus vessel capacity. This has caused the share price of an LNG vessel owner e.g. Golar LNG to diverge (2011 correlation coefficient -0.88) markedly from an oil tanker owner, e.g. Frontline (Figure 120).

Figure 117: Share price of Golar LNG versus Frontline (NOK)


SCF Arctic Specifications: Size – 71,500 m3

DWT – 40586 tonsBuilt in – 1969Current owner – SCF Group

Al SamriyaSpecifications: Size – 261,700 m3

DWT– 154940 tons Built in – 2009Current owner – Qatar Gas (Nakilat)

Incr

eas

ing

size

0

50

100

150

200

250

300

350

400

Golar LNG Frontline

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Appendix V: Floating LNG

There are three key drivers to deploy liquefaction offshore:

1. A means to monetize fields that are very remote and which otherwise are a stranded resource.

2. A means to reduce / avoid gas flaring and sub-optimal gas re-injection.

3. An alternative to the conventional onshore solution where costs have increased and delays are very common.

On 20 May 2011, RD Shell took the final investment decision on the Prelude Floating Liquefied Natural Gas (FLNG) Project in Australia. The project is 100% RD Shell and is the world's first FLNG facility. Shell Global Solutions (the group’s in house R&D center) had spent over 12 years developing the technology for FLNG. The key challenges were sloshing-resistant containment systems, process topsides and offloading systems.

Via a 15 year strategic partnership with Samsung and Technip, the vessel will be built in a South Korean shipyard. When on station in 2017, some 200km offshore Australia, it will recover c.3 TCF of gas from the Prelude field, discovered by RD Shell in 2007, over a 25 year period. Prelude should produce at least 5.3 MT pa of liquids, comprising 3.6 MT pa of LNG, 1.3 MT pa of condensate and 0.4 MT pa of liquefied petroleum gas.

Table 85: Floating LNG - pros and cons

Pros Cons

Construction occurs in a controlled environment (shipyard) – this benefits safety, costs and schedule control risks.

Development model is not cheap – RD Shell has indicated around $3,250 per ton (including upstream) -this implied unit development costs of $23 per boe (assuming $11.5bn and 3 TCF).

Removes need for offshore compression, dredging close to shore and jetty construction, onshore construction of roads, lay down areas and accommodation facilities.

Higher operating and maintenance costs than onshore plants with limited expansion / de-bottlenecking options.

Reduced onshore impact – avoids potentially lengthy and controversial land requisition.

Given untested model, LNG buyers may enforce a price discount and it may be more expensive (if not impossible) to secure project finance.

Less CO2 intensive than conventional onshore liquefaction – RD Shell’s environmental impact statement for Prelude LNG estimates 15-20% lower.

Controversial for some countries if a nation’s gas resources are developed and exported with minimal local content and no inward fixed asset investment e.g. Timor-Leste.Unclear whether extreme weather conditions (e.g. cyclones and typhoons in Asia) might require the vessel to be tugged away (we understand that Shell’s design is meant to stay on station during extreme weather).


RD Shell plans to deploy other FLNG vessels elsewhere around the world to develop otherwise stranded gas resources (a report by the Commonwealth Scientific and Industrial Research Organization estimated 140 TCF of stranded gas in Australia alone). Globally, stranded gas resources may total 1,275 TCF which is approximately 15% of global gas resources (Figure 121). We note that it has recently agreed to purchase a 30% stake in the Abadi field, offshore Indonesia from Inpex. Given resources of 9 TCF and 330 mmb condensate, this is tagged as a FLNG project, with capacity of 2.5 MT pa and 8.4 kbpd condensate.

Prelude FLNG ‘marinised’

proven onshore technology for

the first time

Pros of FLNG outweigh the cons, but it is not cheap

Global stranded gas opportunity

set is very big

188



Figure 118: Distribution of gas resources by field size – the potential addressable market for FLNG


There are two main FLNG concepts – small scale vessel based projects designed to handle gas from small fields and the large scale barge based concept designed for fields with gas reserves in excess of 3 TCF. As per Table 83, we count twelvepotential FLNG projects, of which RD Shell is currently involved in four: in Australia (2), Indonesia (1) and Iraq (1). Including Prelude FLNG, these projects carry a total capacity of 30.4 MT pa.

Table 86: Potential FLNG projects

Country Project Project sponsors Project statusCapacity (MT

pa) On stream

Australia Prelude LNG RD Shell 100% Under development 3.5 2017Bonaparte LNG GDF Suez 60%, Santos 40% Under review – FID 2014 2.0 2019Cash Maple FLNG PTTEP (50%), PTT (50%) ** Under review – FID 2012 3.6 2017

Australia / East Timor Sunrise FLNG *Woodside 33.44%, RD Shell 26.56%, ConocoPhillips 30.0%, Osaka Gas 10.0% Under review 3.6 2018

Brazil Santos FLNGPetrobras 51.1%, BG 16.3%, Repsol 16.3%, GALP 16.3% Under review – FID 2013 2.7 2018

Indonesia Abadi FLNGInpex Masela 60%, RD Shell 30%, PT Energi Mega Persada 10% (PT EMP)

Under review – FID 2013-14 2.5 2019

Iraq Khawr al-Amaya FLNG RD Shell 50%, Mitsubishi 50%Under review – FID 2013-

14 2.0 2017Malaysia Sarawak FLNG Petronas 100% Under review – FID 2012 1.0 2016

SK 205 FLNG Petronas 50%, Petrovietnam 50% * Under review 3.0 2019Nigeria Progress FLNG Mitsubishi, Peak Petroleum * Under review 1.5 2017

Papua New Guinea Gulf FLNGLiquid Niguini Gas (InterOil 52.5% + Pacific LNG Operations 47.5%), Flex LNG ** Under review – FID 2012 2.0 2017

TBC Hoegh LNG, DSME, Petromin ** Under review 3.0 2019Total potential capacity 30.4

Source: J.P. Morgan. * Part of the Greater Sunrise and Troubador fields lies in the Timor Sea’s Joint Development Area. ** Precise ownership rights yet to be confirmed.

Interestingly, RD Shell may not actually be the first company to produce LNG from the offshore if Petronas progresses its project offshore Sarawak as it has scheduled –the FEED contract was awarded in February 2011 to Technip and DSME.

3922

1043

719

347 337

73 40

500

1000

1500

2000

2500

3000

3500

4000

< 0.1 TCF 0.1 - 0.25 TCF0.25 - 0.5 TCF 0.5 - 1.0 TCF 1 - 5 TCF 5 - 50 TCF 50 - 100 TCF

Nu

mb

er o

f fie

lds

Recoverable gas reserves

Onshore liquefaction

Floating liquefaction potential

12 potential FLNG projects

including Prelude LNG

189



Appendix VI: A brief history of LNG

Below, we list some key dates in the history of the LNG industry….the world’s first……

1873 ….German engineer Karl von Linde built the first compressor refrigeration machine.

1917 ….LNG plant began operations in West Virginia, USA.

1941….commercial liquefaction plant was built in Cleveland, Ohio.

1944….major LNG incident - an LNG storage tank at a peak-shaving plant in Cleveland fails; LNG spills in to a sewer and an explosion kills 128 people. In 1979, an explosion at the Cove Point terminal (USA) kills one person. In 2004, explosions and fire destroy part of the liquefaction plant in Skikda, Algeria, killing 27 people.

1959….LNG tanker (Methane Pioneer) brings a cargo of LNG from Lake Charles, Louisiana to Canvey Island, UK.

1964….large scale liquefaction plant (Arzew GL4Z or Camel plant) began operations in Algeria, sourcing gas from the Hassi R’Mel field – its first cargo was imported by the UK.

1969….LNG exports from the US to Asia when Kenai Peninsula LNG (Alaska) delivered its first cargo to Japan.

1974….when the US did not import a single LNG cargo (recurs in 1986).

1999….LNG plant in the Atlantic Basin was commissioned in Trinidad (Atlantic LNG).

2004….offshore re-gasification facility (Port Pelican - owned by Excelerate Energy)began operations in the Gulf of Mexico.

2010….coal bed methane to LNG project was sanctioned by BG Group in Queensland, Australia.

2011….floating liquefaction project, Prelude LNG, sanctioned by RD Shell for Prelude field, offshore Australia.

190



Appendix VII: Glossary of terms in LNG

Liquefaction & re-gasification

Neither liquefaction nor re-gasification are complicated chemical processes – they simply induce a phase change for methane (CH4) – from gas to liquid and vice versa whilst also involving some purification of the source gas to meet the shipper’s / customer’s requirements. Figure 122 shows the key steps in liquefaction and Table x the key steps for re-gasification.

LNG is produced for the purpose of efficient storage and transportation of natural gas. By converting natural gas to liquid by liquefaction process reduces its volume nearly 600 times (a 600:1 ratio). In a physical comparison, the same amount of natural gas held in a beach ball can be stored and transported in a table-tennis ball.This compression makes the shipping of LNG economic.

Figure 119: Liquefaction process


Acid gas: a gas that contains compounds, such as CO2, H2S, or mercaptans that can form an acid in solution with water.

Aggregator: 1) acts on behalf of groups of producers to collect producer supplies and sell the gas in commingled blocks to end-users. Prior to deregulation, a limited number of aggregators operated. Aggregators do not take title to the gas but simply find markets and negotiate prices for pools of producers. An aggregator is also called core transport agent; 2) also a firm that bargains on behalf of a large group of consumers to achieve the lowest possible price for utilities such as electricity and gas. The firm “aggregates” or combines many smaller customers into one large customer for purposes of negotiation and then purchases the utility commodity on behalf of the group.

Annual contract quantity: the annual delivery quantity contracted for during each contract year as specified in a gas sales or LNG contract.

Feed Gas

Liquefaction

Propane refrigerating system

Ethylene refrigerating system

Methane compressor

Fuel Gas distribution

Plant fuel

Vapour recovery

LNG storage and loading

Ship vapors

LNG to ship

Marine facilitiesNGL stabilization

NGL storage

SweeteningDehydrationMercaptan

removalMercury

removal

Gas specifications

Gas Conditioning

H2S < 4 ppmCo2 < 50 ppmH2O < 1 ppm

Hg < 10 ng/m3

Higher Heating Value (Wobbenumber)

Related to upstream and transport facilities

191



Annual delivery program (ADP): a key document for both the buyer and seller in determining how they will work together over the life of an LNG project to achieve the efficient delivery and receipt of LNG cargoes; normally agreed between the parties before the beginning of each contract year. For an ex-ship sale, the ADP deals with the dates on which the sellers’ LNG ships will deliver LNG to the buyers’ terminals. For a Free on board (FOB) sale, the ADP covers the dates of arrival of the buyers’ ships at the LNG plant. Whether the sale is ex-ship or FOB, the ADP provides a basis for decisions on how buyers and sellers will operate their facilities during the contract year covered. Usually, the procedures to be adopted to develop the ADP are agreed upon in the Sales and Purchase Agreement (SPA).

Beach gas: natural gas transported through offshore pipelines to a number of gas gathering and processing terminals at or near a coastal region.

Beach price: price applying to natural gas at landfall.

Black start: the initial operation of a facility that begins with no utilities in service.

British thermal unit (Btu): an energy unit; the quantity of heat necessary to raise the temperature of one pound-mass of water one degree Fahrenheit from 58.5°F to 59.5°F under a standard pressure of 30 inches of mercury at 32°F. The following conversions would apply to gas that contains exactly 1,000 Btu/cf – approximately true for most gas delivered in the US:

1 cubic foot (cf) = 1,000 Btu, 1 therm = 100 cf = 100,000 Btu mcf = 1 mmBtu

1 BCF = 1 trillion Btu, 1 TCF = 1 quad = 1 quadrillion Btu

Bubble point: the temperature and pressure at which a liquid first begins to vaporize to gas.

Calorific value: the quantity of heat produced by the complete combustion of a fuel. This can be measured dry or saturated with water vapor, net or gross. The general convention is dry and gross.

City gas: treated and conditioned gas for consumer use.

City-gate rate: the rate charged a distribution utility by its suppliers; refers to the cost of the natural gas at the point at which the distribution utility historically takes title to the natural gas (also called gate rate).

City-gate station (city gate): the point or measuring station at which a gas-distribution utility physically receives gas from a pipeline or transmission company; the point at which the backbone transmission system connects to the distribution system. There is not necessarily a change of ownership at a city-gate station.

Combined-cycle gas turbine (CCGT): this is the combination of simple gas turbines with a heat-recovery steam generator (HRSG) and a steam turbine in a power generation plant. Gas is combined with air and burned, with the expanded gas turning the blades of the gas turbines to power an electricity generator (the Brayton thermodynamic cycle). The hot exhaust gases are passed to the HRSG, in which water is converted to steam that is used in a single steam turbine to power another generator (the Rankine thermodynamic cycle). Also called combined cycle generation.

192



Combined heat and power (CHP): the simultaneous generation of two forms of energy from a single fuel source. Electrical energy is produced through gas turbines and heat energy (steam) is produced through a heat-recovery steam generator. See Combined-cycle gas turbine.

Common carrier: a facility obligated by law to provide service to all potential users without discrimination, with services to be prorated among users in the event capacity is not sufficient to meet all requests. In the US, interstate oil pipelines are common carriers, but interstate natural gas pipelines are not (they are open-access contract carriers).

Company-used gas: natural gas consumed by a gas distribution or gas transmission company or the gas department of a combination utility, for example, fuel for compressor stations.

Compressed natural gas (CNG): natural gas that has been compressed under high pressures (typically between 3,000 and 3,600 psi) and held in a container; expands when released for use as a fuel.

Cryogenics: the production and application of low-temperature phenomena. The cryogenic temperature range is usually from –150°C (–238°F) to absolute zero (–273°C, or –460°F), the temperature at which molecular motion essentially ceases. A most important commercial application of cryogenic gas liquefaction techniques is the storage, transportation, and re-gasification of LNG.

Dehydration: the removal of water from a fluid.

Dehydrator: natural gas processing equipment that removes water vapor. Typically, glycol dehydration units are used to dry gas before it is sent to a gas transmission line. If the gas is to be sent to a cryogenic expander plant or LNG plant, then the gas is typically dehydrated using molecular sieves.

Dew-point: the temperature, at a given pressure, at which a vapor will form a first drop of liquid on the subtraction of heat. Further cooling of the liquid at its dew point results in the condensation of part or all of the vapor as a liquid.

Engineering, procurement and construction (EPC) contract: 1) a legal agreement setting out the terms for all activities required to build a facility to the point that it is ready to undergo preparations for operations as designed. 2) the final contracting phase in the development of the export portion of the LNG chain that defines the terms under which the detailed design, procurement, construction and commissioning of the facilities will be conducted. Greenfield LNG project development entails a wide variety of design, engineering, fabrication and construction work far beyond the capabilities of a single contractor. Therefore, an LNG project developer divides the work into a number of segments, each one being the subject of an EPC contract. For example, separate EPC contracts are executed for construction of onshore LNG plant and related infrastructure, for the offshore production facilities and for the pipeline from the offshore location to the plant site.

Environmental-impact assessment (EIA): an assessment of the impact of an industrial installation or activity on the surrounding environment, conducted beforework on that activity has commenced. The original baseline study, a key part of this process, describes the original conditions.

193



Federal Energy Regulatory Commission (FERC): the chief energy regulatory body of the US government. FERC is responsible for regulating LNG facilities in the US. FERC is considered an independent regulatory agency responsible primarily to Congress, but is housed in the US Department of Energy.

Feedstock gas (feedgas): dry gas used as raw material for LNG, petrochemicals and gas-to-liquids (GTL) plants.

Flash point: the temperature under very specific conditions at which a combustible liquid will give off sufficient vapor to form a flammable mixture with air in a standardized vessel. It is related to the volatility of the liquid.

Flash vapors: gas vapors released from a stream of natural gas liquids as a result of an increase in temperature, or a decrease in pressure.

Front-end engineering and design (FEED) contract: 1) a legal agreement setting out the terms for all activities required to define the design of a facility to a level of definition necessary for the starting point of an engineering, procurement, and construction (EPC) contract; 2) generally, the second contracting phase for the development of the export facilities in the LNG chain which provides greater definition than the prior Conceptual design phase. In an LNG project, the most important function of the FEED contract is to provide the maximum possible definition for the work to be performed by the EPC contractor. This enables potential EPC contractors to submit bids on a lump-sum basis, with the least possibility that the contract cost will change through undefined work or through claims for unanticipated changes in the work. Clear definition of contract costs is important not only for cost control purposes, but also for purposes of project financing – LNG project lenders will normally limit their lending commitment to a specific percentage of forecast project costs, and cost overruns will have to be covered by the borrower’s equity investment.

Fuel gas: a process stream internal to a facility that is used to provide energy for operating the facility.

Fuel loss: a proportion of natural gas received by a pipeline or local distribution company that is retained to compensate for lost and unaccounted for natural gas.

Gas processing: the separation of oil and gas, and the removal of impurities and NGLs from natural gas.

Gas treatment: removal of impurities, such as sulphur compounds, carbon dioxide and water vapor from natural gas.

Gas/condensate ratio: for a gas condensate reservoir, the ratio of gas to condensate is reported in cubic feet per barrel. The inverse ratio (condensate-gas ratio, CGR) is also used, and is reported in barrels per mmcf.

Gas to liquids (GTL): a processing technology that converts natural gas into high-value commodity liquid fuels and blending agents, petrochemicals feedstocks and chemicals by changing its chemical structure. GTL produces products that can be easily traded as commodities on world markets.

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Gas-to-oil ratio (GOR): the number of standard cubic feet of gas produced per barrel of crude oil or other hydrocarbon liquid. In some parts of the world, the units are cubic metres of gas per cubic metre of liquid produced.

Gigajoule (GJ): a joule is an international unit of energy defined as the energy produced from one watt flowing for one second. A very small unit of energy, there are 3.6m joules in a kilowatt-hour. For gas, one gigajoule is equal to 960 cf under standard temperature and pressure conditions. Roughly, 1 gigajoule (Gj) = mcf; one terajoule (Tj) = 1 mmcf; one petajoule (Pj) = 1 BCF; one exajoule (Ej) = 1 TCF.

Green field LNG facility: a new LNG facility constructed on a new site.

Hub: a contractual point where buyers and sellers execute transactions for gas. Hubs can be notional or physical, trans-regional (one or more transmission system operators (TSOs)) or within-country (one TSO). Hubs generally consist of a Hub Services Agreement (operator) and Standard Trading Contract (trader). Examples of notional hubs are the National Balancing Point (NBP) in the UK and the Title Transfer Facility (TTF) in the Netherlands. Physical hubs include the Henry Hub in the US and the Zeebrugge Terminal (ZBT) in Belgium. See Market centre.

Henry Hub: pipeline interchange near Erath, Louisiana, US, where a number of interstate and intrastate pipelines interconnect through a header system. It is the standard delivery point for the Nymex natural gas futures contract in the US, the benchmark gas price in the US Gulf.

Liquefaction plant: facility which converts natural gas at ambient temperature and pressure to liquefied natural gas.

Liquefied natural gas (LNG): an odorless, colorless non-corrosive and non-toxic product of natural gas consisting primarily of methane (CH4) that is in liquid form at near atmospheric pressure.

LNG feed gas requirements to LNG plant: The amount of gas reserves required to economically support the development of an LNG liquefaction plant, allowing for gas lost in the process of production, liquefaction and transport of the LNG to end-markets (typically 10-15%).

LNG project characteristics: primary LNG project components are: 1) upstream development of long-term, natural gas supply for feed-gas to an LNG plant; 2) downstream development of liquefaction, storage and loading facilities; 3) marine transportation; and 4) further downstream, development of receiving terminals for re-gasification and pipeline transportation to market.

LNG refrigerant (for liquefaction) cycles: natural gas liquefaction requires removal of sensible and latent heat over a wide temperature range using a refrigerant. The refrigerant may be part of the natural gas feed (an open-cycle process), or a separate fluid continuously re-circulated through the liquefier (a closed-cycle process). Three general types of refrigeration cycle are used:

Cascade refrigerant cycle: feedstock natural gas is cooled, condensed and sub-cooled in heat exchange with propane, ethylene (or ethane) and finally methane in three discrete stages. The three refrigerant circuits generally have multistage

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refrigerant expansion and compression, each typically operating at three evaporation-temperature levels. After compression, propane is condensed with cooling water or air, ethylene is condensed with evaporating propane and methane is condensed with evaporating ethylene.

Expander cycle: in its simplest form, process refrigeration in an expander cycle is provided by compression and expansion of a single-component gas stream. High-pressure cycle gas is cooled in counter-current heat exchange with returning cold-cycle gas. The cycle gas is expanded through an expansion turbine, reducing its temperature to a lower temperature than would be given by expansion through a Joule-Thomson valve.

Mixed-refrigerant cycle (MRC): uses a mixed refrigerant(s) instead of the multiple pure refrigerants in the cascade cycle. The mixture composition is specified so the liquid refrigerant evaporates over a temperature range similar to that of the natural gas being liquefied. A mixture of nitrogen and hydrocarbons (usually in the C1 to C5 range) is normally used to provide optimal refrigeration characteristics. MRC provides greater thermodynamic efficiency, lower power requirement and use of smaller machinery.

LNG storage tanks: vessels that are specially constructed to contain LNG. The tanks are generally constructed of nickel steel (steel containing 9% nickel) to withstand cryogenic temperatures and are insulated to maintain the LNG at –161°C. Some of the stored LNG boils off and the resulting vapor is used as fuel gas for the plant. There are three main designs of LNG storage tanks: single containment, double containment and full containment. The difference in these systems lies in the functionality of the secondary containment, when the primary containment is breached. For single containment, neither liquid nor vapor will be held by the secondary containment; for double containment, liquid will be contained and for full containment, liquid and vapor will be contained.

LNG value chain: in planning, funding and executing an LNG project, each element of the complex chain that links the natural gas in the ground to the ultimate consumer (from the wellhead to the burner tip) is considered. The main links are natural gas production, liquefaction, shipping, receiving terminal (including re-gasification), distribution of the re-gasified LNG and, lastly, consumption of the gas.

mmBtu: one million British thermal units.

mcf, MCF, Mcf: a measurement of volume denoting one thousand cubic feet of natural gas. 1,000 cf of gas = 1.03 mmBtu (also, 1 kWh = 3,412 Btu).

Methane (CH4): the simplest hydrocarbon and the main constituent of natural gas, it is also known as C1 in the carbon complexity chain.

mmt/y, Mtpa: million tonnes a year/per annum.

Natural gas liquids (NGLs): liquid hydrocarbons, such as ethane, propane, butane, pentane and natural gasoline, extracted from field gas.

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Natural-gas processing: 1) the purification of field gas at gas-processing plants (or gas plants), or the fractionation of mixed natural gas liquids (NGLs) to natural gas products to meet specifications for use as pipeline quality gas. Gas processing includes removing liquids, solids, and vapors, absorbing impurities and odorizing; 2) the process of separating NGLs by absorption, adsorption, refrigeration or cryogenics from a stream of natural gas.

Project financing: most commonly used method to finance construction of industrial infrastructure, because of the nonrecourse (to project sponsors) nature of the debt financing supporting the project. Typically, the developer pledges the value of the plant and part or all of its expected revenues as collateral to secure financing from private lenders. In the event of financial distress, the debt holders have recourse only to the project assets in place at that time.

Figure 120: Re-gasification process


Re-gasification plant: a plant that accepts deliveries of liquefied natural gas and vaporizes it back to its gaseous form by applying heat so that the gas can be delivered into a pipeline system. Sea water is often used as a source of heat to vaporize the gas.

Floating Storage & Re-gasification Unit (FSRU) – This is an offshore based re-gasification unit which accepts LNG from an LNG carrier and offloads it via pipeline to shore.

Send-out capacity: the volume of natural gas that can be converted by a liquefaction facility and subsequently shipped over a specified period of time.

Separator: a vessel used to separate a multiphase mixture of fluids into its separate phases, for example, vapor, oil, water, solids.

Shrinkage: the reduction in volume of wet natural gas caused by the removal of natural gas liquids, hydrogen sulphide, carbon dioxide, water vapor and other impurities from the gas

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Sour gas: natural gas that contains significant amounts of hydrogen sulphide (usually greater than 16 ppm) and possibly other sulphur compounds (mercaptans, carbonyl sulphide). Also called acid gas.

Spot gas: natural gas that is available and purchased on a short-term basis and is furnished to customers on an as-available basis.

Sweet gas: natural gas that contains such small amounts of hydrogen sulphide (and other sulphur compounds) and carbon dioxide that it can be transported or used without purifying, with no deleterious effect on piping and equipment.

Treating plant: a facility that treats raw natural gas to remove undesirable impurities such as carbon dioxide, hydrogen sulphide and water vapor.

Turnaround: a period of brisk activity at a plant or receiving terminal when processing units, or portions of them, are shut down either for scheduled maintenance or for the installation of new equipment and systems.

Unconventional gas: natural gas that cannot be produced using existing technologies.

Utilization factor: a ratio of the maximum demand of a system or part of a system to its rated capacity.

Wet gas: a gas containing condensable hydrocarbons or other liquids. The term is subject to varying legal definitions as specified by applicable statutes. Natural gasoline, butane, pentane and other light hydrocarbons can be removed by chilling and pressure or extraction. Usually maximum allowable is 7 pounds/mmcf for water content and 0.02 gallons/mmcf for natural gasoline (also known as associated gas).

Shipping & Marketing

Natural gas liquefied as LNG is transported in an LNG Carrier (LNGC) - a ship specially designed to transport LNG. The LNG is stored in a special containment system and maintained at around –160C or -270F at around atmospheric pressure. LNGC cryogenic cargo tanks are functionally big thermos containers where the LNG remains boiling at a constant pressure for the duration of the voyage. Some gas is removed to prevent a build-up in pressure – this is known as boil-off-gas or BOG and can be used as fuel for ship propulsion or re-liquefied and returned to the cargo.

LNG can be transported by sea for any project market distance – short, medium or long sea shipping. However, it is the most economic for transporting gas to market over long distances. Currently a common size LNGC has an average cargo space storage volume of around 140,000 M3 (cargo deadweight about 64,000 tons LNG). A smaller size LNGC may have a capacity as little as 1,100 M3 (500 tons). Large LNG Carriers (L-LNGCs) can now carry a cargo volume of 266,000 m3 (cargo deadweight about 122,000 tonnes LNG – Q-Max class) to reduce delivery costs.

Acquiring shipper: in the context of capacity release, a shipper who acquires firm capacity rights from a releasing shipper (also known as a replacement shipper).

Admeasurement: the confirmed or official dimensions of an LNG ship.ATS)

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Arbitrage: the simultaneous purchase and sale of an asset in order to profit from a difference in the price, usually on different exchanges or marketplaces. Where appropriate infrastructure exists, LNG offers the opportunity for price arbitrage between different gas markets.

Articles of agreement: the document containing all particulars relating to the terms of agreement between the Master of the LNG vessel and the crew.

Average daily quantity (ADQ): the monthly contracted quantity of gas divided by the number of customers’ operating days in that month.

Bare-boat charter: a charter in which the bare ship is chartered without crew; the charterer, for a stipulated sum takes over the vessel for a stated period of time with a minimum of restrictions; the charterer appoints the master and the crew and pays all running expenses.

Beam: the width of a ship; also called breadth.

Bill of lading (B/L): a document by which the Master of a ship acknowledges having received in good order and condition (or the reverse) certain specified goods consigned to him by some particular shipper, and binds himself to deliver them in similar condition, unless the perils of the sea, fire or enemies prevent him, to the consignees of the shippers at the point of destination on their paying him the stipulated freight. A bill of lading specifies the name of the master, the port and destination of the ship, the goods, the consignee, and the rate of freight; documentation legally demonstrating a cargo has been loaded. The bill of lading is signed by the Master of the ship and the contract supplier.

Boatswain (Bosun): on an LNG vessel, tantamount to a foreman; directly supervises maintenance operations.

Boil-off vapor: usually refers to the gases generated during the storage of volatile liquefied gases, such as LNG. LNG boils at slightly above –163°C at atmospheric pressure and is loaded, transported and discharged at this temperature, which requires special materials, insulation and handling equipment to deal with the low-temperature and the boil-off vapor (heat leakage keeps the cargo surface constantly boiling). On a typical voyage an estimated 0.1% - 0.25% of the cargo converts to gas each day, depending on the efficiency of the insulation and the roughness of the voyage. In a typical 20-day voyage, anywhere from 2% - 6% of the total volume of LNG originally loaded may therefore be lost. Normally an LNG tanker is powered by steam turbines with boilers. These boilers are dual fuel and can run on either methane or oil or a combination of both. The gas produced in boil off is traditionally diverted to the boilers and used as a fuel for the vessel. Before this gas is used in the boilers it must be warmed up to roughly 20C by using the gas heaters. The gas is either fed into the boiler by tank pressure or it is increased in pressure by the LD compressors.

Break bulk: to commence discharge of cargo.

Bulk cargo: any liquid or solid cargo loaded on to a vessel without packaging (for example, oil or LNG).

Burner tip: the point at which natural gas is used as a fuel.

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Cargo: one standard cargo is 2.644 bcf or 0.0532 million tons of LNG.

Cargo handling: the act of loading and discharging a cargo ship.

Cargo loading: a typical cargo cycle starts with the tanks in a "gas free" condition (full of fresh air), which allows maintenance on the tank and pumps. Cargo cannot be loaded directly into the tank, as the presence of oxygen means would create explosive atmospheric conditions within the tank. Also, the temperature difference could cause damage to the tanks.

1. The tank must be ‘inerted’ by using the inert gas plant, which burns diesel in air to remove the oxygen and replace it with carbon dioxide (CO2). This is blown into the tanks until it reaches below 4% oxygen and a dry atmosphere. This removes the risk of an explosive atmosphere in the tanks.

2. The vessel goes into port to "gas-up" and "cool-down", as one still cannot load directly into the tank: The CO2 will freeze and damage the pumps and the cold shock could damage the tanks. Liquid LNG is brought onto the vessel and taken along the spray line to the main vaporizer which boils off the liquid into gas. This is then warmed up to roughly 20°C in the gas heaters and then blown into the tanks to displace the "inert gas". This continues until all the CO2 is removed from the tanks. The inert gas is blown ashore via a pipe by large fans called "HD compressors". The vessel is then gassed up and warm. The tanks are still at ambient temperature and are full of methane.

3. The next stage is cool-down. Liquid LNG is sprayed into the tanks via spray heads, which vaporizes and starts to cool the tank. The excess gas is blown ashore to be re-liquified or burned at a flare stack. Once the tanks reach about -140°C the tanks are ready to load bulk.

4. Bulk loading starts and liquid LNG is pumped from the storage tanks ashore into the vessel tanks. Displaced gas is blown ashore by the HD compressors. Loading continues until typically 98.5% full is reached. The vessel can now proceed to the discharge port.

Cargo plan: a plan giving the quantities and description of the various grades carried in the ship’s cargo tanks, after the loading is completed.

Cash-out: a procedure in which shippers are allowed to resolve imbalances by cash payments, in contrast to making up imbalances with gas volumes in-kind.

Certificate of registry: a document specifying the nation registry of the vessel.

Charter party: contractual agreement between a ship owner and a cargo owner, usually arranged by a broker, whereby a ship is chartered (hired) either for one voyage or a period of time.

Charter rates: tariff applied for chartering tonnage in a particular trade.

Charterer: the entity to whom is given the use of the whole of the carrying capacity of a ship for the transportation of cargo to a stated port for a specified time. See Time charter party

http://en.wikipedia.org/wiki/Gas_flare

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Classification society: private organizations that arrange inspections and advise on the hull and machinery of a ship. Supervise vessels during their construction and afterwards, in respect to their seaworthiness, and places vessels in grades or classes according to the society’s rules for each particular type. It is not compulsory by law that a ship owner has his vessel built according to the rules of any classification society. In practice, the difficulty in securing satisfactory insurance rates for an un-classed vessel makes it a commercial obligation. The major classification societies –American Bureau of Shipping, Lloyds Register of Shipping, Det Norske Veritas, Bureau Veritas and Germanischer Lloyd – have included the International Maritime Organization (IMO) LNG Gas Codes in their rules.

Committed gas contract: a source specific natural gas sales contract that commits the seller to deliver natural gas, from specific described reserves or sources.

Cost, insurance and freight (CIF): used in international trade statistics and sales contracts, transactions on CIF basis mean the purchase price includes all costs of moving the goods from the point of embarkation to their destination. With respect to LNG shipping, this means that the buyer purchases the gas at the point of vessel loading or during its transit to the receiving terminal, while the agreed price includes shipping charge and insurance for the load.

Crude price parity: This relates to LNG contract pricing wherein parity is a crude indexed slop of 0.1724 (given a ratio of 5.8:1 gas:oil). So, an LNG price of $17.24 per mmbtu would represent parity with a crude price of $100 per barrel. A slope of 0.16 (0.15) thus corresponds to a crude price discount of 7.2% (13.0%). Japanese LNG contract prices are based on individual pricing formulae. Generally, Indonesian LNG prices are linked to ICP (Indonesian crude price) and other Asian LNG prices are linked to JCC (see later definition). There is a time lag between the movement of crude oil and LNG prices. Older contracts generally have a cap and a floor price (creating a so-called S-curve price profile), while more recent pricing schemes are more likely top drop this and instead offer a discount to crude parity, depending on the supply/demand environment at the time of signing the contracts. At the peak of the market in mid-2008, there was no discount. The generic pricing formula is:

Price (LNG) = A (slope) * Index (ex JCC) + B (constant)

A – this determines the leverage to oil prices, the higher A, the higher the LNG price.

B – the residual constant which also takes in to account shipping and transportation costs.

Cubic capacity: the volumetric measurement of the ship’s cargo compartments.

Cubic feet a day (cf/d): at standard conditions, the number of cubic feet of natural gas produced from a well over a 24-hour period, normally an average figure from a longer period of time. Generally expressed as mcf/d = thousand cubic feet a day; mmcf/d = million cubic feet a day; bcf/d = billion cubic feet a day; or tcf/d = trillion cubic feet a day.

Cubic foot (cf): The amount of gas required to fill a volume of 1 cubic foot under stated conditions of temperature, pressure and water vapor.

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Cubic meter (cm): unit of measurement for gas volume. The amount of gas required to fill the volume of one cubic meter.

Custody transfer measuring system (CTMS): LNG ships are fitted with high-accuracy liquid-level, temperature and vapor-pressure measuring equipment. The cargo tanks are calibrated by an independent measurer so that the volume of cargo can be determined accurately. The CTMS is accepted by the buyer and the seller of the cargo as the basis for the quantity purchased or sold. Samples of the LNG cargo are taken ashore and analyzed to determine the cargo’s chemical composition from which the heating value can be calculated. The heating value is then multiplied by the volume loaded or discharged from the ship to obtain the British thermal unit (Btu) content of the delivered cargo, which is used as the basis for cargo invoices, import duties and fiscal accounting.

Dead freight factor: percentage of a ship’s carrying capacity that is not utilized.

Dead freight: space booked by shipper or charterer on a vessel, but not used.

Deadweight tonnage (DWT): a measure of ship carrying capacity: 1) the number of metric tonnes (2,204.6 pounds) of cargo, stores and bunkers that a vessel can transport; 2) the difference in weight between a vessel when it is fully loaded and when it is empty (in general transportation terms, the net) measured by the water it displaces when submerged to the deep-load line. A vessel’s cargo is less than its DWT.

Deliverability (LNG ships): one major aspect of LNG project planning consists of estimating the transportation capacity required, taking into account the time necessary for each function in the chain of events within a typical round voyage of an LNG carrier. A typical delivery calculation for a 137,500-cm LNG carrier might beas per Table 84.

Table 87: LNG vessel capacity calculation

One way distance (nautical miles) 6,000Ship service speed (knots) 19Ship service speed (mph) 21.9

Sea days (round trip) 26.3Port days (round trip) 2Total voyage days 28.3Ship operating days per annum 350Ship capacity (cm) 137,500Less 7.5% heel (cm) -10,313Discharge quantity (cm) 147,813Annual deliverable quantity (cm) 1,827,050LNG specific gravity 0.45Annual vessel deliverability (ton) 822,173Per vessel per trip (ton) 66,516LNG export train operating capacity (million tons pa) 5.0Operating days per annum 330Daily output (tons) 15,152Requires 1 ship every - days 4.4


A new technology next generation LNG carrier is about to be developed. This is a shallow draft High Speed LNG Carrier (HS-LNGC), capable of 60-75 knots service speed, three times the speed of a conventional LNGC of 19 knots. Given the same

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LNG cargo capacity with combination of speed and the same fuel consumption to that of a conventional LNGC of service speed 19 knots, effectively the HS-LNGC could reduce the number of ships in an LNG delivery system by two-thirds. For example, a three ship LNGC service could be reduced to one HS-LNGC thus giving both capital investment and overall cost savings in the shipping delivery component of the supply chain in an LNG contract.

Demurrage: a fee, per day or per hour, agreed to be paid by the charterer or receiver of the cargo, for the detention of a vessel, loading or unloading, beyond the lay-time allowed in the charter party.

Diversion: the flexible routing of LNG cargoes where gas suppliers will seek to move cargoes to markets. Diversion rights for sellers and buyers in LNG supply contracts create opportunities for physical arbitrage, depending on the correlation of such demand and price variations between regional markets.

Draft: the depth of a ship in the water; vertical distance between the waterline and the keel, expressed in feet in the US, elsewhere in meters; also Draught.

Dry (or lean) gas: 1) gas that has been treated to remove liquids and inert gases making it suitable for shipping in a pipeline; 2) natural gas from the well containing no water vapor that will liquefy at ambient temperature and pressure, i.e. the gas is water dry. Gas is usually priced on a dry basis. See Pipeline quality gas; 3) a gas whose water content has been reduced by dehydration or; 4) a gas containing little or no hydrocarbons that could be recovered as a liquid condensate.

Emergency-shutdown systems (ESD): a system, usually independent of the main control system that is designed to safely shut down an operating system. For example, at ship-shore interface, LNG cargo transfer between ship and shore is accomplished by a series of shore-based articulated loading arms, usually three or four liquid arms and a single vapor arm. The configuration is similar at both the loading and discharge terminals. These arms have flexibility in three directions to allow for relative motion between ship and shore. If this allowable motion is exceeded, alarms sound on the ship and shore. Cargo transfer is automatically stopped, either by the shore pumps shutting down during loading, or the ship’s pumps shutting down during unloading.

Enabling agreement: provides the general terms and conditions for the purchase, sale, or exchange of LNG, pipeline gas and electricity, but does not list specific contract details.

End-users: the ultimate consumers of natural gas, including residential, commercial, industrial, wholesale, cogeneration and utility electricity-generation customers.

Enriching: the process of increasing the heat content of natural gas by mixing it with a gas of higher Btu content.

Ensign: flag carried by a ship to show her nationality.

Escalator clause: a clause in a gas purchase or sale contract that permits adjustment of the contract price under specified conditions.

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Export-credit agencies (ECAs): government agencies whose mission is to facilitate the export sale of goods and services by providing credits that are more attractive than those available commercially and by providing security for credit and political risk that may not be available at an economic cost from private-sector finance sources. ECAs of the US, Europe and Japan have been consistent financing sources for LNG projects; includes Export-Import Banks of the US (USEXIM) and Japan Bank for International Cooperation (JBIC), the UK’s Export Credit Guarantee Department (ECGD), Germany’s Hermes, France’s Coface and Italy’s Sace.

Ex-ship contract: in an LNG ex-ship contract, ownership of the LNG transfers to the buyer as the LNG is unloaded at the receiving terminal, payment is due at that time. See Cost, insurance and freight contract and Free on board contract

Force Majeure: a term commonly used in contracts to describe an event or effect that cannot be reasonably controlled. This term essentially frees one or both parties from liability of obligation when an extraordinary event or circumstance prevents one or both parties from fulfilling their contractual obligations.

Free-on-board (FOB) contract: in an LNG FOB contract, the buyer lifts the LNG from the liquefaction plant and is responsible for transporting the LNG to the receiving terminal. The buyer is responsible for the shipping, either owning the LNG ships or chartering them from a ship-owner. In a FOB contract, the seller requires assurance that the shipping protocols provide a safe and reliable off-take for the LNG to prevent disruption to the sales and purchase agreement (SPA).

Freight: charge made for the transportation of a cargo.

Fuel: The fuel that an LNG vessel runs on is dependent on many factors which include the length of the voyage, desire to carry a heel for cool down, price of oil versus price of LNG. There are three fuel modes available:

Minimum boil off/max oil - In this mode tank pressures are kept high to reduce boil off to a minimum and the majority of energy comes from the fuel oil. This maximizes the amount of LNG delivered, but does allow tank temperatures to rise due to lack of evaporation. The high cargo temperatures can cause storage problems and offloading problems.

Max boiloff / Minimum oil - In this mode the tank pressures are kept low and there is a greater boil-off, but still there is a large amount of fuel oil used. This decreases the amount of LNG delivered but the cargo will be delivered cold which many ports prefer.

100% Gas - Tank pressures are kept at a similar level to maximum boil off but this is not enough to supply all the boilers. To force increased supplies, a spray pump is started in one tank to supply liquid LNG to the forcing vaporizer - this tanks liquid LNG and turns it into a gas that is useable in the boilers. In this mode no fuel oil is used.

Recent advances in technology have allowed re-liquefaction plants to be fitted to vessels, allowing the boil off to be re-liquefied and returned to the tanks. Because of this, the vessels' operators and builders have been able to contemplate the use of

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more efficient slow speed d (previously most LNG carriers have been steam turbinepowered).

Grounding: contact by a ship with the bottom while she is moored or anchored or under way.

Harbor dues: various local charges against all seagoing vessels entering a harbour, to cover maintenance of channel depths, buoys, lights; not all harbours assess this charge.

Heads of agreement (HOA): a preliminary agreement covering the outline terms for the sale and purchase of LNG or natural gas.

Heat rate: the measure of efficiency in converting input fuel to electricity. Heat rate is expressed as the number of Btu of fuel (for example, natural gas) per kilowatt hour (Btu/kWh). Heat rate for power plants depends on the individual plant design, its operating conditions and its level of electricity output. The lower the heat rate the more efficient the plant is.

Heating value: the amount of heat produced from the complete combustion of a unit quantity of fuel. There are two heating values: the gross (high) and the net (low) heating value. The gross value is that which is obtained when all of the products of combustion are cooled to standard conditions, and the latent heat of the water vapor formed is reclaimed. The net value is the gross value minus the latent heat of vaporization of the water.

Heel: it is normal practice to keep onboard 5% to 10% of the cargo after discharge in one tank. This is referred to as the heel and this is used to cool down the remaining tanks that have no heel before loading. This must be done gradually otherwise one can ‘cold shock’ the tanks if you load directly into warm tanks. Cool down can take roughly 36 hours on a Moss vessel so carrying a heel allows cool down to be done before the vessel reaches port giving a significant time saving.

Indexing: tying the commodity price of natural gas in a contract to published prices of other commodities or price indices – see Crude price parity.

Japan Crude-Oil Cocktail (JCC): The Japanese Customs-cleared Crude or Crude Cocktail price is quoted by the Japanese finance ministry, it is designed to represent the average CIF price of all imported crude oil and raw oil in a specified trading period. It is usually quoted on a monthly basis.

Knot: unit of speed in navigation, which is the rate of one nautical mile (6,080 feet or 1,852 metres) per hour.

Lay-time: time allowed by the ship owner to the voyage charterer or bill of lading holder in which to load and/or discharge the cargo. It is expressed as a number of days or hours.

LNG cargo-containment systems: the method of storing LNG during marine transport. One of four methods is normally employed: Self-Supporting Prismatic Type ‘B’ (Conch/IHI), Dual Membrane (Gaz Transport), Single Membrane (Technigaz), and Self-Supporting Spherical Type ‘B’ (Kværner Moss).

http://en.wikipedia.org/wiki/Steam_turbine

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LNG markets: there are two primary LNG markets: (1) the Atlantic basin includes Belgium, France, Italy, Spain, Portugal, Greece, Turkey and the east coast of the US; (2) the Pacific basin includes India, Japan (world’s largest), South Korea, Taiwan, China and the west coast of the US. These two regions are often referred to as East and West of the Suez Canal.

Net capacity (shipping): the number of tons of cargo that a vessel can carry when loaded in salt water to her summer freeboard marks (also called cargo-carrying capacity, cargo deadweight and useful deadweight).

Offload (shipping): discharge of cargo from a ship.

Price indexation: a practice whereby a contract price is linked to another, generally more liquid or less complex product price or economic indicator. This allows the resulting price to vary in accordance with another factor. Gas contract prices are often linked to major crude oil indices, derivative prices, such as certain fuel oil prices, or, less frequently, energy or economic growth indicators, such as a country’s GDP.

Reloads – Some re-gasification terminals are able and have regulatory permission to reverse the flow of LNG from a discharging vessel back on to the vessel, enabling a cargo to be diverted to another higher priced market. This has to be done with the permission of the original cargo vendor and can take up to 5 days for a conventional cargo (so requires two back-to-back loading slots). It is typically done to take advantage of arbitrage opportunities under contracts that do not allow this. Tariffs for reloading vary by country and terminal.

Sales and purchase agreement (SPA): a definitive contract between a seller and buyer for the sale and purchase of a quantity of natural gas or LNG for delivery during a specified period at a specified price.

Sales gas: natural gas treated and conditioned to meet gas purchaser specifications.

Spot voyage: a charter for a particular vessel to move a single cargo between specified loading port(s) and discharge port(s) in the immediate future.

Swing gas: natural gas bought on short notice to meet unexpected daily demands not covered under long-term contracts.

Tail gas: the exhaust gas from any processing unit that is at a low pressure and is usually vented, treated for contaminant removal or combusted.

Take-or-pay (TOP) clause: contract clause in a sales and purchase agreement (SPA) requiring a minimum quantity of natural gas to be paid for, whether or not delivery is accepted by the purchaser.

TCF (trillion cubic feet): volume measurement of natural gas approximately equivalent to one Quad.

Therm: a unit of heating value equal to 100,000 Btu, in common use in the UK; about 56 therms are derived by setting fire to a barrel of crude oil; one therm has around the same heat content as 100 cf of natural gas.

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Time charter: a form of charter party issued when an LNG vessel is chartered for an agreed period of time. A time charter party is the contract between owner and charterer, and identifies the salient characteristics of the ship and the obligations of the ship owner; specifically the ship owner provides a ship capable of the specified performance and operates the ship according to that performance standard set by the charterer. The charterer pays the owner for the hire of the vessel at an agreed rate.

Tolling agreement: an agreement whereby one party owns (and bears the risks on) the inputs to and outputs from a process, as well as the rights to a portion of the process capacity (the tollee). Another party agrees to operate the process or facility and charges a tolling fee per unit of input that is transformed, or per unit of capacity to which rights are granted (the toller). Under an LNG liquefaction tolling agreement, one company sends a volume of feed gas to a liquefaction facility, wherein the gas is liquefied in return for a pre-established tolling charge.

Tonne mile: a measurement used in the economics of transportation to designate 1 tonne being moved 1 mile; useful to the shipper because it includes the distance to move a commodity in the calculation.

Tonnage: a shipping term referring to the total number of tonnes registered or carried or the ship’s carrying capacity.

Tonne, metric: a metric tonne equals 1,000 kilograms or 2,204.6 pounds. The capacity of an LNG baseload plant is typically expressed in tonnes and the unit capital costs for producing LNG are expressed as $/tonne.

Train (liquefaction): an independent unit for gas liquefaction. An LNG plant may comprise one or more trains.

Transfer pricing: a transfer price is the amount of money that one unit of an organization charges for goods and services to another unit of an organization. Perhaps the most important aspect in this area is the Arm’s Length Principle regularly challenged by fiscal authorities, a common principle in International Accounting Standards to see that a transfer price has been calculated and agreed according to normal, fair, equitable, business principles.

Ultimate customer: customer that purchases energy for consumption and not for resale. See End-user

Wobbe Index: it represents a measure of the heat released when a gas is burned at a constant pressure, and is defined as the gross calorific value divided by the square root of the density of the gas relative to the density of air.

Working gas: volume of natural gas expected to be cycled from a gas-storage facility.

World-scale rates: a schedule of nominal freight rates against which tanker rates for all voyages, at all market levels, can be compared and readily judged.

Useful LNG related websites

We list the websites of companies with a material exposure to the LNG value chain.

207



www.sempralng.com/Pages/About/Regas.htm, www.ogj.com, www.total.com, www.pwc.com, www.beg.utexas.edu, www.capeplc.com, www.linde.com, www.saipem.com, www.sbmoffshore.com, www.technip.com, www.cbi.com, www.fmctechnologies.com, www.fluor.com, www.fwc.com, www.kbr.com, www.chiyoda-corp.com/en, eng.daelim.co.kr, www.gsholdings.com/eng/, www.jgc.co.jp/en/index.html, www.worleyparsons.com, www.awilcolng.no, www.exmar.be, www.golar.com, www.hoeghlng.com, www.wartsila.com, , www.panocean.com, www.dsme.co.kr/en, www.shi.samsung.co.kr/eng, www.sembcorpmarine.com, www.stxons.com/service/eng/main.aspx, www.chevron.com, www.exxonmobil.com, www.bg-group.com, www.shell.com, www.total.com, www.santos.com, www.woodside.com.au/, www.cove-energy.com, www.flexlng.com, www.ophirenergy.com, www.cheniere.com/, www.interoil.com, www.lngenergyltd.com, www.energyworldcorp.com, www.inpex.co.jp/english/, www.lnglimited.com.au/, www.medcoenergi.com/, www.nobleenergyinc.com, www.oilsearch.com, www.petronetlng.com

http://www.petronetlng.com/

http://www.oilsearch.com/

http://www.nobleenergyinc.com/

http://www.medcoenergi.com/

http://www.lnglimited.com.au/

http://www.inpex.co.jp/english/

http://www.energyworldcorp.com/

http://www.lngenergyltd.com/

http://www.interoil.com/

http://www.cheniere.com/

http://www.ophirenergy.com/

http://www.flexlng.com/

http://www.cove-energy.com/

http://www.woodside.com.au/

http://www.santos.com/

http://www.total.com/

http://www.shell.com/

http://www.bg-group.com/

http://www.exxonmobil.com/

http://www.chevron.com/

http://www.stxons.com/service/eng/main.aspx

http://www.sembcorpmarine.com/

http://www.shi.samsung.co.kr/eng/

http://www.dsme.co.kr/en

http://www.panocean.com/

http://www.wartsila.com/

http://www.gsholdings.com/eng/

http://www.chiyoda-corp.com/en/

http://www.kbr.com/

http://www.fwc.com/

http://www.fluor.com/

http://www.fmctechnologies.com/

http://www.cbi.com/

http://www.technip.com/

http://www.sbmoffshore.com/

http://www.saipem.com/

http://www.linde.com/

http://www.capeplc.com/

http://www.beg.utexas.edu/

http://www.pwc.com/

http://www.total.com/

http://www.ogj.com/

http://www.sempralng.com/Pages/About/Regas.htm

208



Appendix VIII: Company financials

BG Group

Overweight

Company DataPrice (p) 1,448Date Of Price 11 Jan 12Price Target (p) 1,900Price Target End Date 31 Dec 1252-week Range (p) 1,595 - 1,105Mkt Cap (£ bn) 49.0Shares O/S (mn) 3,384

BG Group (BG.L;BG/ LN)

FYE Dec 2010A 2011E(Prev)

2011E(Curr)

2012E(Prev)

2012E(Curr)

2013E(Prev)

2013E(Curr)

Adj. EPS FY (p) 76.83 74.95 79.02 85.47 80.79 97.09 102.17Revenue FY (£ mn) 12,097 12,560 12,466 14,050 12,879 15,737 14,621Adj P/E FY 18.8 19.3 18.3 16.9 17.9 14.9 14.2EBITDA FY (£ mn) 5,925 6,375 6,615 7,193 6,802 8,227 8,354EBITDA margin FY 49.0% 50.7% 53.1% 51.2% 52.8% 52.3% 57.1%Pretax Profit Adjusted FY (£ mn)

4,415 4,744 4,996 5,260 4,976 5,922 6,233

Dividend (Net) FY (p) 13.7 15.0 15.0 16.5 16.5 18.2 18.2Net Yield FY 0.9% 1.0% 1.0% 1.1% 1.1% 1.3% 1.3%Source: Company data, Bloomberg, J.P. Morgan estimates.

BP

Overweight

Company DataPrice (p) 475Date Of Price 11 Jan 12Price Target (p) 575Price Target End Date 30 Jun 1252-week Range (p) 515 - 361Mkt Cap (£ bn) 90.1Shares O/S (mn) 18,958

BP (BP.L;BP/ LN)

FYE Dec 2010A 2011E 2012E 2013E 2014EAdj. EPS FY (p) 1.09 1.18 1.10 1.05 1.01Bloomberg EPS FY (p) 1.13 1.14 1.14 1.20 1.18EBIT FY ($ mn) 31,703 35,376 33,683 32,138 30,903Net Attributable Income FY ($ mn)

20,521 22,375 20,874 19,855 19,088

Dividend (Net) FY (p) 4.5 17.9 20.4 22.3 24.0Net Yield FY 0.9% 3.8% 4.3% 4.7% 5.1%Debt adjusted Cashflow FY ($ mn)

29,226 29,925 37,382 33,739 33,287

EV/DACF FY 5.4 5.6 4.3 4.3 4.3Source: Company data, Bloomberg, J.P. Morgan estimates. NB: unit for EPS figures is £.

Royal Dutch Shell B

Neutral

Company DataPrice (p) 2,414Date Of Price 11 Jan 12Price Target (p) 2,400Price Target End Date 30 Jun 1252-week Range (p) 2,498 - 1,768Mkt Cap (£ bn) 152.2Shares O/S (mn) 6,308

Royal Dutch Shell B (RDSb.L;RDSB LN)

FYE Dec 2010A 2011E 2012E 2013EAdj. EPS FY (p) 2.94 4.19 3.84 3.84Bloomberg EPS FY (p) 3.08 4.36 4.57 4.82Adj P/E FY 12.6 8.9 9.7 9.7Dividend (Net) FY (p) 106.8 105.8 111.9 115.3Net Yield FY 4.4% 4.4% 4.6% 4.8%EBITDA FY ($ mn) 57,118 70,230 69,915 71,251EBITDA margin FY 9.8% 11.0% 10.8% 11.0%Net Attributable Income FY ($ mn)

18,073 26,060 22,742 23,089

Source: Company data, Bloomberg, J.P. Morgan estimates.

209



ENI

Overweight

Company DataPrice (€) 16.50Date Of Price 11 Jan 12Price Target (€) 21.00Price Target End Date 30 Jun 1252-week Range (€) 18.66 - 11.83Mkt Cap (€ bn) 59.8Shares O/S (mn) 3,622

ENI (ENI.MI;ENI IM)

FYE Dec 2010A 2011E 2012E 2013EAdj. EPS FY (€) 1.90 2.03 2.07 2.33Bloomberg EPS FY (€) 1.88 2.06 2.23 2.44Adj. EBIT FY (€ mn) 17,304 18,495 19,384 20,847Pretax Profit Adjusted FY (€ mn)

17,393 18,995 19,734 21,197

Net Attributable Income FY (€ mn)

6,869 7,357 7,514 8,451

Adj P/E FY 8.7 8.1 8.0 7.1EV/DACF FY 5.8 4.8 4.5 4.2Div Yield FY 6.2% 6.5% 6.8% 7.1%Source: Company data, Bloomberg, J.P. Morgan estimates.

Repsol YPF

Neutral

Company DataPrice (€) 22.20Date Of Price 11 Jan 12Price Target (€) 25.00Price Target End Date 30 Jun 1252-week Range (€) 24.90 - 17.31Mkt Cap (€ bn) 27.1Shares O/S (mn) 1,221

Repsol YPF (REP.MC;REP SM)

FYE Dec 2010A 2011E 2012EAdj. EPS FY (€) 1.66 1.82 2.25Bloomberg EPS FY (€) 1.74 1.82 2.26Adj. EBIT FY (€ mn) 4,714 4,922 5,917Pretax Profit Adjusted FY (€ mn)

3,856 4,157 5,345

Net Attributable Income FY (€ mn)

2,032 2,224 2,745

Adj P/E FY 13.3 12.2 9.9EV/DACF FY 5.7 5.5 6.3Div Yield FY 4.8% 5.3% 5.9%Source: Company data, Bloomberg, J.P. Morgan estimates.

Statoil

Underweight

Company DataPrice (Nkr) 152.40Date Of Price 11 Jan 12Price Target (Nkr) 145.00Price Target End Date 30 Jun 1252-week Range (Nkr) 161.70 -

108.10Mkt Cap (Nkr bn) 485.4Shares O/S (mn) 3,185

Statoil (STL.OL;STL NO)

FYE Dec 2010A 2011E 2012EAdj. EPS FY (Nkr) 13.14 15.68 16.66Bloomberg EPS FY (Nkr) 13.40 15.77 17.62Adj. EBIT FY (Nkr mn) 142,730 179,331 182,791Pretax Profit Adjusted FY (Nkr mn)

141,630 179,331 181,546

Net Attributable Income FY (Nkr mn)

42,232 49,844 52,128

Adj P/E FY 11.6 9.7 9.1EV/DACF FY 6.3 5.4 5.3Div Yield FY 4.5% 4.8% 5.0%Source: Company data, Bloomberg, J.P. Morgan estimates.

210



TOTAL

Overweight

Company DataPrice (€) 39.88Date Of Price 11 Jan 12Price Target (€) 49.00Price Target End Date 31 Dec 1252-week Range (€) 44.55 - 29.40Mkt Cap (€ bn) 89.5Shares O/S (mn) 2,245

TOTAL (TOTF.PA;FP FP)

FYE Dec 2010A 2011E(Prev)

2011E(Curr)

2012E(Prev)

2012E(Curr)

Adj. EPS FY (€) 4.64 5.28 5.24 4.97 5.14Bloomberg EPS FY (€) 4.65 - 5.21 - 5.33Adj. EBIT FY (€ mn) 21,503 25,309 25,742 23,791 24,094Pretax Profit Adjusted FY (€ mn)

21,277 25,036 25,354 23,534 23,703

Adj P/E FY 8.6 7.6 7.6 8.0 7.8Div Yield FY 5.8% 6.4% 5.8% 6.7% 6.1%EV/DACF FY 5.4 5.2 5.3 5.1 4.8Dividend (Net) FY (€) 2.28 2.44 2.28 2.56 2.39Source: Company data, Bloomberg, J.P. Morgan estimates.

Chevron Corp

Underweight

Company DataPrice ($) 107.77Date Of Price 11 Jan 1252-week Range ($) 110.99 -

86.68Mkt Cap ($ mn) 215,397.00Fiscal Year End DecShares O/S (mn) 1,999Price Target ($) 120.00Price Target End Date 31 Dec 12

Chevron Corp (CVX;CVX US)

FYE Dec 2010A 2011E 2012E 2013EEPS Reported ($)Q1 (Mar) 2.46 3.17A 3.19 -Q2 (Jun) 2.58 3.89A 3.51 -Q3 (Sep) 2.06 3.44A 3.99 -Q4 (Dec) 2.49 2.87 4.15 -FY 9.53 13.48 14.84 15.40Bloomberg EPS FY ($) 9.32 13.85 12.93 13.79Source: Company data, Bloomberg, J.P. Morgan estimates. 'Bloomberg' above denotes Bloomberg consensus estimates.

Exxon Mobil Corp

Underweight

Company DataPrice ($) 85.08Date Of Price 11 Jan 1252-week Range ($) 88.23 - 67.03Mkt Cap ($ mn) 412,042.40Fiscal Year End DecShares O/S (mn) 4,843Price Target ($) 92.00Price Target End Date 31 Dec 12

Exxon Mobil Corp (XOM;XOM US)

FYE Dec 2010A 2011E 2012E 2013EEPS Reported ($)Q1 (Mar) 1.33 2.14A 2.08 -Q2 (Jun) 1.60 2.17A 2.08 -Q3 (Sep) 1.44 2.13A 2.30 -Q4 (Dec) 1.84 1.89 2.53 -FY 6.22 8.34 8.99 10.90Bloomberg EPS FY ($) 5.98 8.53 8.37 9.12Source: Company data, Bloomberg, J.P. Morgan estimates. 'Bloomberg' above denotes Bloomberg consensus estimates.

211



Gazprom

Neutral

Company DataPrice ($) 5.63Date Of Price 11 Jan 12Price Target ($) 6.94Price Target End Date 31 Dec 1252-week Range ($) 8.77 - 4.40Mkt Cap ($ bn) 129.0Shares O/S (mn) 22,915

OAO Gazprom (GAZP.RTS;GAZP RU)

FYE Dec 2009A 2010A 2011E 2012EAdj. EPS FY ($) 1.16 1.32 1.60 1.59Revenue FY ($ mn) 94,500 118,449 153,200 153,805EBITDA FY ($ mn) 35,631 44,529 53,886 56,272Net Attributable Income FY ($ mn)

26,650 30,284 36,552 36,549

Adj P/E FY 4.8 4.3 3.5 3.5EV/EBITDA FY 4.0 3.2 2.7 2.5EBITDA margin FY 37.7% 37.6% 35.2% 36.6%Dividend (Gross) FY ($) 0.08 0.09 0.15 0.16Source: Company data, Reuters, J.P. Morgan estimates.

Novatek

Underweight

Company DataPrice ($) 134.90Date Of Price 11 Jan 12Price Target ($) 82.90Price Target End Date 31 Dec 1252-week Range ($) 164.00 -

101.00Mkt Cap ($ bn) 41.0Shares O/S (mn) 304

OAO Novatek (NVTKq.L;NVTK LI)

FYE Dec 2009A 2010A 2011E 2012EAdj. EPS FY ($) 2.70 4.40 5.96 6.97Revenue FY ($ mn) 2,834 3,853 5,539 6,515EBITDA FY ($ mn) 1,233 1,872 2,814 3,073Net Attributable Income FY ($ mn)

821 1,335 1,809 2,117

Adj P/E FY 49.9 30.7 22.6 19.3EV/EBITDA FY 27.6 18.2 12.1 11.1EBITDA margin FY 43.5% 48.6% 50.8% 47.2%Dividend (Gross) FY ($) 0.09 0.13 0.17 0.20Source: Company data, Reuters, J.P. Morgan estimates.

Oil Search

Company Data52-week range (A$) 7.64 - 5.43Market capitalisation (A$ bn) 8.71Market capitalisation ($ bn) 8.90Fiscal Year End DecPrice (A$) 6.57Date Of Price 12 Jan 12Shares outstanding (mn) 1,325.2ASX100 3,416.6ASX200-Res 4,634.9NTA/Sh^ ($) 2.27Net Debt^ ($ bn) 0.85

Oil Search Limited (Reuters: OSH.AX, Bloomberg: OSH AU)

Year-end Dec (US$) FY09A FY10A FY11E FY12E FY13ETotal Revenue ($ mn) 512.2 583.6 691.2 716.1 716.7EBITDA ($ mn) 333.7 343.7 480.8 474.4 490.3Net profit after tax ($ mn) 133.7 185.7 203.4 191.6 200.0EPS (A$) 0.112 0.138 0.150 0.140 0.145P/E (x) 58.6 47.6 43.8 46.9 45.2Cash flow per share ($) 0.245 0.305 0.279 0.249 0.354Dividend ($) 0.040 0.040 0.040 0.040 0.050Net Yield (%) 0.6% 0.6% 0.6% 0.6% 0.8%Normalised* EPS (A$) 0.094 0.107 0.150 0.140 0.145Normalised* EPS chg (%) -54.7% 13.9% 39.7% -6.5% 3.7%Normalised* P/E (x) 69.8 61.3 43.8 46.9 45.2Source: Company data, Bloomberg, J.P. Morgan estimates.

212



Santos Limited

Company Data52-week range (A$) 16.90 - 10.11Market capitalisation (A$ bn) 12.04Market capitalisation ($ bn) 12.32Fiscal Year End DecPrice (A$) 12.75Date Of Price 12 Jan 12Shares outstanding (mn) 944.5ASX100 3,416.6ASX200-Res 4,634.9NTA/Sh^ (A$) 9.53Net Debt^ (A$ bn) 0.36

Santos Limited (Reuters: STO.AX, Bloomberg: STO AU)

Year-end Dec (A$) FY09A FY10A FY11E FY12E FY13ETotal Revenue (A$ mn) 2,249.0 2,337.0 2,615.5 2,949.4 3,159.0EBITDA (A$ mn) 1,150.3 1,244.0 1,462.1 1,709.1 2,084.0Net profit after tax (A$ mn) 432.3 500.0 1,015.5 552.2 804.1EPS (A$) 0.549 0.593 1.153 0.619 0.895P/E (x) 23.2 21.5 11.1 20.6 14.2Cash flow per share (A$) 1.501 1.502 1.613 1.375 1.566Dividend (A$) 0.420 0.370 0.300 0.300 0.300Net Yield (%) 3.3% 2.9% 2.4% 2.4% 2.4%Normalised* EPS (A$) 0.319 0.446 0.575 0.619 0.895Normalised* EPS chg (%) -63.2% 39.6% 29.0% 7.6% 44.6%Normalised* P/E (x) 39.9 28.6 22.2 20.6 14.2Source: Company data, Bloomberg, J.P. Morgan estimates.

Woodside Petroleum

Company Data52-week range (A$) 50.85 - 29.76Market capitalisation (A$ bn) 26.08Market capitalisation ($ bn) 26.67Fiscal Year End DecPrice (A$) 32.37Date Of Price 12 Jan 12Shares outstanding (mn) 805.7ASX100 3,416.6ASX200-Res 4,634.9NTA/Sh^ ($) 17.46Net Debt^ ($ bn) 5.28

Woodside Petroleum Limited (Reuters: WPL.AX, Bloomberg: WPL AU)

Year-end Dec (US$) FY09A FY10A FY11E FY12E FY13ETotal Revenue ($ mn) 3,759.2 4,246.0 4,900.1 5,628.7 6,703.3EBITDA ($ mn) 2,597.4 2,907.0 3,449.6 4,210.8 5,063.1Net profit after tax ($ mn) 1,530.6 1,564.0 1,743.9 1,760.3 2,215.3EPS ($) 2.176 2.023 2.198 2.157 2.677P/E (x) 15.2 16.4 15.1 15.4 12.4Cash flow per share ($) 1.982 2.722 3.447 3.535 4.420Dividend ($) 0.950 1.050 1.120 1.080 1.330Net Yield (%) 2.9% 3.2% 3.5% 3.3% 4.1%Normalised* EPS ($) 1.588 1.820 2.206 2.157 2.677Normalised* EPS chg (%) -29.2% 14.6% 21.2% -2.2% 24.1%Normalised* P/E (x) 20.9 18.2 15.0 15.4 12.4Source: Company data, Bloomberg, J.P. Morgan estimates.

Inpex Corporation

Company DataPrice (¥) 510,000Date Of Price 12 Jan 12GPS_AUTO_153_4Market Cap ($ mn) 24,262Shares O/S (mn) 3.6652-week Range (¥) 674,000 -

425,500TOPIX 727DPS (¥) 6,000Div Yield 1.2%GPS_AUTO_1076052_

Inpex Corporation (Reuters: 1605.T, Bloomberg: 1605 JT)

¥ in mn, year-end Mar FY10A FY11A FY12E FY13E FY14ERevenue (¥ bn) 840.4 943.1 1,141.9 1,027.3 1,029.6Revenue growth (%) -21.9% 12.2% 21.1% -10.0% 0.2%Operating Profit (¥ bn) 461.7 529.7 666.1 569.7 546.5Operating Profit growth (%) -30.4% 14.8% 25.7% -14.5% -4.1%Recurring Profit (¥ bn) 442.0 508.6 668.4 573.7 551.9Recurring Profit growth (%) -28.3% 15.1% 31.4% -14.2% -3.8%Net Profit (¥ bn) 107 129 153 136 127Net Profit growth (%) -26.1% 20.0% 19.1% -11.1% -6.5%EPS (¥) 53,360 44,526 44,097 40,443 38,008P/E (x) 9.6 11.5 11.6 12.6 13.4EV/EBITDA (x) 3.1 2.5 2.0 2.3 2.2Source: Company data, Bloomberg, J.P. Morgan estimates.

213



CNOOC

Company DataShares Outstanding (mn) 44,669GPS_AUTO_153_4Market Cap ($ mn) 86,371Price (HK$) 15.02Date Of Price 12 Jan 12Free float (%) 33.6%Avg Daily Volume (mn) 84Avg Daily Value (HK$ mn) 1,033Avg Daily Value ($ mn) 133HSCEI 10,517GPS_AUTO_1252_4Fiscal Year End Dec

CNOOC (Reuters: 0883.HK, Bloomberg: 883 HK)

Rmb in mn, year-end Dec FY09A FY10A FY11E FY12E FY13ERevenue (Rmb mn) 105,195 183,053 231,773 196,329 188,782Net Profit (Rmb mn) 29,244 54,410 64,921 51,149 47,507EPS (Rmb) 0.65 1.22 1.45 1.15 1.06DPS (Rmb) 0.35 0.39 0.58 0.46 0.53Revenue Growth (%) (17%) 74% 27% (15%) (4%)EPS Growth (%) (34%) 86% 19% (21%) (7%)ROCE 22% 32% 33% 24% 21%ROE 18% 28% 29% 21% 18%P/E 18.7 10.0 8.4 10.7 11.5P/BV 3.1 2.5 2.4 2.2 2.0EV/EBITDA 9.1 5.1 4.6 5.4 5.7Dividend Yield 2.9% 3.2% 4.8% 3.8% 4.4%Source: Company data, Bloomberg, J.P. Morgan estimates.

Sinopec Corp - H

Company DataShares Outstanding (mn) 86,702Market Cap (Rmb mn) 686,683Market Cap ($ mn) 108,833Price (HK$) 8.88Date Of Price 12 Jan 12Free float (%) 19.6%Avg Daily Volume (mn) 205Avg Daily Value (HK$ mn) 1,098Avg Daily Value ($ mn) 141HSCEI 10,517GPS_AUTO_1252_4Fiscal Year End Dec

Sinopec Corp - H (Reuters: 0386.HK, Bloomberg: 386 HK)

Rmb in mn, year-end Dec FY09A FY10A FY11E FY12E FY13ERevenue (Rmb mn) 1,345,052 1,913,182 2,617,829 2,384,441 2,383,843Net Profit (Rmb mn) 61,760 71,800 78,130 80,016 80,360EPS (Rmb) 0.71 0.83 0.90 0.92 0.93DPS (Rmb) 0.18 0.21 0.23 0.23 0.24Revenue Growth (%) (10%) 42% 37% (9%) (0%)EPS Growth (%) 117% 16% 9% 2% 0%ROCE 16% 19% 19% 18% 16%ROE 18% 18% 17% 16% 14%P/E 10.1 8.7 8.0 7.8 7.8P/BV 1.7 1.5 1.3 1.2 1.0EV/EBITDA 5.8 4.6 4.4 4.1 3.8Dividend Yield 2.5% 2.9% 3.2% 3.2% 3.3%Source: Company data, Bloomberg, J.P. Morgan estimates.

PetroChina

Company DataShares Outstanding (mn) 183,021Market Cap (Rmb mn) 1,844,852Market Cap ($ mn) 292,143Price (HK$) 10.78Date Of Price 12 Jan 12Free float (%) 13.3%Avg Daily Volume (mn) 126Avg Daily Value (HK$ mn) 1,411Avg Daily Value ($ mn) 182HSCEI 10,517GPS_AUTO_1252_4Fiscal Year End Dec

PetroChina (Reuters: 0857.HK, Bloomberg: 857 HK)

Rmb in mn, year-end Dec FY09A FY10A FY11E FY12E FY13ERevenue (Rmb mn) 1,019,275 1,465,415 1,418,941 1,336,341 1,342,447Net Profit (Rmb mn) 103,387 139,992 135,037 136,387 135,422EPS (Rmb) 0.56 0.76 0.74 0.75 0.74DPS (Rmb) 0.27 0.29 0.33 0.34 0.33Revenue Growth (%) (5%) 44% (3%) (6%) 0%EPS Growth (%) (10%) 35% (4%) 1% (1%)ROCE 14% 17% 15% 13% 12%ROE 13% 16% 14% 13% 12%P/E 15.5 11.5 11.9 11.8 11.8P/BV 1.9 1.7 1.6 1.5 1.4EV/EBITDA 7.4 6.0 5.9 5.8 5.6Dividend Yield 3.1% 3.3% 3.8% 3.8% 3.8%Source: Company data, Bloomberg, J.P. Morgan estimates.

214



Petronet LNG Ltd.

Company DataShares O/S (mn) 750GPS_AUTO_153_4Market Cap ($ mn) 2,299Price (Rs) 161.60Date Of Price 11 Jan 12Free float (%) 34.8%3-mth trading value (Rs bn) 0.083-mth trading value ($ mn) 1.503-mth trading volume (mn) 0.31BSE30 16,165GPS_AUTO_1252_4Fiscal Year End Mar

Petronet LNG Ltd. (Reuters: PLNG.BO, Bloomberg: PLNG IN)

Rs in mn, year-end Mar FY09A FY10A FY11A FY12E FY13ERevenue (Rs mn) 84,287 106,029 131,057 209,410 273,089Net Profit (Rs mn) 5,184 4,045 6,196 9,264 10,439Asia EPS (Rs) 6.91 5.39 8.26 12.35 13.92DPS (Rs) 1.75 1.75 2.00 3.50 3.50Revenue growth (%) 28.6% 25.8% 23.6% 59.8% 30.4%EPS growth (%) 9.2% -22.0% 53.2% 49.5% 12.7%ROCE 21.4% 15.2% 19.4% 23.8% 22.5%ROE 28.8% 19.2% 25.2% 31.0% 28.4%P/E 23.4 30.0 19.6 13.1 11.6EV/EBITDA 14.9 16.2 11.5 8.4 6.9Dividend Yield 1.1% 1.1% 1.2% 2.2% 2.2%Source: Company data, Bloomberg, J.P. Morgan estimates.

Origin Energy

Company Data52-week range (A$) 17.22 - 12.00Market capitalisation (A$ bn) 14.65Market capitalisation ($ bn) 14.99Fiscal Year End JunPrice (A$) 13.49Date Of Price 12 Jan 12Shares outstanding (mn) 1,086.2ASX100 3,416.6ASX200-Ind 5,712.6NTA/Sh^ (A$) 8.67Net Debt^ (A$ bn) 4.06Inst. Holdings -

Origin Energy Limited (Reuters: ORG.AX, Bloomberg: ORG AU)

Year-end Jun (A$) FY10A FY11A FY12E FY13E FY14ETotal Revenue (A$ mn) 8,865.6 10,955.0 14,788.8 16,958.5 17,506.1EBITDA (A$ mn) 1,304.0 1,782.0 2,399.5 2,635.5 2,736.8EBIT (A$ mn) 895.4 1,194.0 1,767.2 1,960.4 2,059.8Net profit after tax (A$ mn) 612.0 186.0 886.5 1,009.0 1,045.7EPS (A$) 0.698 0.196 0.804 0.888 0.920P/E (x) 19.3 68.9 16.8 15.2 14.7Dividend (A$) 0.500 0.500 0.515 0.554 0.581Net Yield (%) 3.7% 3.7% 3.8% 4.1% 4.3%Normalised* NPAT (A$ mn) 584.6 673.0 886.5 1,009.0 1,045.7Normalised* EPS (A$) 0.666 0.733 0.804 0.888 0.920Normalised* EPS chg (%) 10.1% 10.0% 9.8% 10.4% 3.6%Normalised* P/E (x) 20.2 18.4 16.8 15.2 14.7Source: Company data, Bloomberg, J.P. Morgan estimates.

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Valuation Methodology and Risks

BG Group (Overweight Price Target: 1,900p)

Valuation methodology:

Our target price remains strongly connected to our core NAV. We roll forward ourprice target from 30 June to 31 December 2012 and base it on our revised core NAV of 1960p. It still implies a 4% discount to our core NAV. This is below BG Group's long run average premium of 3% to reflect practical multiple constraints on BG Group’s share price.

Risks to Our View:

LNG contract pricing risk – earnings power would be weakened if the contracting market moved away from oil price parity pricing (6:1 oil:gas ratio) since this could reduce the scope for LNG price arbitrage.

Exploration risk – persistent exploration failure would threaten BG Group's ability to replace its reserves efficiently and this could undermine its valuation relative to its larger peers.

Project execution risk – material delays to major projects e.g. QC LNG or the various phases in the pre-salt Brazil would damage confidence in management and project value.

Asset performance – weaker than expected natural gas demand, either as a result of sluggish economic growth or warmer than normal weather (during winter heating periods) could reduce BG Group gas field output. This could result in a 'production miss' or reduced volume growth expectations.

Political risk – unexpected, adverse fiscal changes e.g. in Kazakhstan could damage growth prospects and asset value therein.

BP (Overweight Price Target: 575p)

Valuation methodology:

Our 575p Dec-11 price target for BP captures (i) the reinstatement of BP's dividend with its Q4 2011 results (ii) a positive resolution to the risk of gross negligence versus negligence, as per our Central Case Macondo Liability analysis (iii) further progress towards its $25bn - $30bn divestment target (iv) further evidence that BP's abilities to access new high potential exploration acreage (as per BP's alliance with RIL in the Krishna Godavari Basin, off the East Coast of India) is intact. Our price target still assumes a discount of around 30% to our sum-of-the-parts value of around 800 pence that is consistent with our Central Case and compares to BP's long runaverage discount of 26%.

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Risks to Our View :

Macro factors – As an integrated oil & gas company, BP’s earnings and cash flow are naturally sensitive to oil and natural gas prices and refining margins. BP does not hedge any of these top line macro exposures.US dollar – BP is US dollar long and has a US dollar-based dividend policy. Dollar

weakness could erode BP’s sterling dividend which is important given the dividend yield sensitivity of the UK market.Asset integrity / project execution – Unexpected asset integrity issues eg field or

refinery downtime, delays to projects and capital budget over-runs can damage perceptions of management quality and, ergo, BP’s stock market valuation.Industrial accidents – Unexpected industrial accidents involving BP assets could

expose the company to loss of earnings, asset confiscation and potential litigation risk.Russian risk – Via its 50% stake in TNK-BP, BP carries a significant production,

reserve, cash flow and earnings exposure to assets in Russia. The perceived value of this asset is vulnerable to an escalation in Russian country risk and any signs of company-specific corporate governance problems.Gross Negligence - There is risk that BP will be found grossly negligent and thus face much higher overall Macondo related liabilities than our Central Case.Divestment program fails - Although it is a seller's market for upstream assets, there is a risk that this changes and BP fails to complete its $25bn to $30bn divestment program.

Royal Dutch Shell B (Neutral Price Target: 2,400p)

Valuation Methodology :

We leave our SOTP at 2,650p: we apply our long-term oil price of $85/bbl (US natural gas price of $5.90/mmbtu) and RD Shell’s 2010 Form 20-F disclosures relating to upstream reserves, downstream assets and off balance sheet liabilities. We still believe that a 10% discount to our SOTP is appropriate and therefore keep our price target at 2,400p. However, we roll forward our target date from 31 December 2011 to 30 June 2012.

Risks to Our View :

Macro factors – As an integrated oil & gas company which does not hedge prices or margins, RD Shell’s earnings and cash flow are naturally sensitive to oil and natural gas prices and refining margins.

Industrial accidents – Unexpected industrial accidents involving RD Shell assets could expose the company to loss of earnings, asset confiscation and potential litigation risk.

Fiscal regimes – Unexpected or adverse changes to the upstream fiscal regimes that apply to any of RD Shell’s key operating areas could reduce its value.

Acquisition risk - RD Shell's balance sheet is strengthening fast as larger than expected divestments and a higher than expected oil price raise cash flow. A large acquisition could dilute returns and perceptions of capital controls.LNG pricing risk – As one of the largest IOC producers of LNG, a prolonged period of LNG market over-capacity could dilute the returns from RD Shell’s LNG projects. This damage could prove more permanent if LNG's pricing relationship with the oil price is weakened.

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ENI (Overweight Price Target: €21.00)


Our price target is derived from our SOTP valuation and is set at a 20% discount to our SOTP– very close to average long term discount on this name. We expect this discount to narrow as ENI’s asset structure becomes simpler.

Risks to Our View :

The main generic risks to our rating and price target come from crude oil or natural gas prices or refining margins significantly below/above our projections. Specifically for ENI, downside risks include a further decline in the natural gas demand in Italy which is likely to put pressure on the operating margin of the company.

Repsol YPF (Neutral Price Target: €25.00)


We roll forward our price target of €25 from 31 December 2011 to 30 June 2012 which is derived from our SOTP valuation. Our price target is set at a c.12% discount to our SOTP, this is lower than the long-term average discount for Repsol YPF. We believe that near-term catalysts like YPF divestment, exploration results from Brazil, West Africa etc will help the stock's performance.

Risks to Our View :

The main generic risks to our rating and price target come from crude oil or natural gas prices or refining margins significantly below our projections. Specifically for Repsol, downside risks include a further weakness in the refining margins and possible disappointments in the company's ongoing exploration campaign - offshore Brazil, GoM and Venezuela.

Statoil (Underweight Price Target: Nkr145.00)


We roll forward our price target from 31 December 2011 to 30 June 2012. Our price target of Nkr145 is derived from our SOTP valuation - no change to our key assumptions or our SOTP valuation. Our price target for the stock is set at a c.24% discount to our SOTP of NKr190 – this is in-line with the 12 month average discount suffered by the stock. We still believe that a discount will prevail until Statoil shows a clearer, sustainable improvement in its upstream performance.

Risks to Our View :

The main generic risks come from crude oil or natural gas prices or refining margins significantly below our projections. For Statoil specifically, negative risks include any slippage to production targets resulting from higher core decline rates in Norwegian production or if lower crude prices prevent Statoil from sanctioning new projects. Positive risks include further success in the international portfolio, notably in the deepwater US Gulf and offshore Brazil. Changes in crude prices affect Statoil’s shares more than its peers given its greater upstream leverage.

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TOTAL (Overweight Price Target: €49.00)


We increase our price target from €47 to December 2011 to €49 to December 2012 -no change to our key assumptions or our SOTP valuation. Our price target for the stock is set at a 13% discount to our SOTP – this is below the 12 month average discount suffered by this name as we expect the stock to re-rate helped by a much stronger production outlook and improvement in its exploration business. We also believe that the higher discount suffered by this name in 2011 was partly a reflection of the weaker equity markets.

Risks to Our View :

The following risks could prevent the stock from achieving our price target and rating. The main generic risks come from crude oil or natural gas prices or refining margins significantly below our projections. For Total specifically, negative risks could come from project slippage relative to the last guidance, but positive risks could come from better-than expected volume growth in 11-12.

Gazprom (Neutral Price Target: $6.94)

Valuation Methodology :Our PT (Dec-12E) for Gazprom is $6.94/share. We use a similar valuationapproach for all oil and gas companies, which is based on a 50% weight of DCFbased fair value and 50% weight of value based on target (normalized) PER (‘15E). We calculate our target PER multiple by dividing the DCF-based (target) Market Cap by our estimated (normalized) earnings in 2012E. We calculate DCF fair value based on explicit financial forecasts until 2015 and discounted terminal value. We use 2.5% as the terminal value growth rate and a WACC of 12%.

Risks to Our View :We believe the key risks that could keep our rating and target price from beingachieved include the following:Long-term risks include increasing competition and falling gas prices in bothdomestic and international markets. Upside risk could come from faster thananticipated liberalization of the domestic gas prices and a sharp and sustainableincrease in oil and gas prices internationally.Click here to enter text.

Novatek (Underweight Price Target: $82.90)


We revise our PT (Dec-12) for Novatek from $91.1/share to $82.9/share on the back of higher output forecast and addition of NPV of purchased upstream assets into our valuations.

We keep our valuation approach for all oil and gas companies, which is based on a 50% weight of DCF-based fair value and 50% weight of value based on target (normalized) PER (‘15E). We calculate the target PER multiple by dividing our DCF-based (target) Market Cap by our estimated (normalized) earnings in 2012E. (Effectively we assume that there is a 50% chance of next year's oil prices being normalized rather than the bottom of the cycle). Our new target PER 15E is 8.6x vs our previous target PER 13E of 11.4x.

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Risks to Our View :

We believe the key risks that could keep our rating and target price from being achieved include the following:Lower than expected output growth if demand fails to recover, lower than expected increase in domestic gas prices, inability to re-finance debt, and exposure to fluctuations in oil prices. Upside risks include access to export markets before 2016, successful development of Yamal LNG, M&A activity.

Inpex (Overweight Price Target: JPY750,000)Valuation MethodologyOur JPY750,000 Dec-2012 PT is based on SOTP of DCF for base operation using US$85/bbl LT oil price and WACC of 8% at 100% (JPY476k), cash (JPY265k) at 80% (lots of cash rich undervalued companies in Japan), Ichthys (JPY318k) at 20% (reflecting the stage of the project) and Abadi (JPY104k) at 10% (to show its potential and existence). PT yields 17x FY11E EPS and 17x FY12E EPS.

Risks to Our ViewRisks to our rating and PT are lower-than-expected oil price, higher than expected capex, operational delays or cost overruns.

CNOOC (Underweight Price Target HK$12.50)Valuation MethodologyOur PT is based on DCF (10.7% WACC and US$85/bbl LT oil price) with a 20% premium due to current oil price higher than DCF LT oil input.

Risks to Our ViewRisks to our rating and PT are higher production, oil price and cost control relative to our expectations. Higher WFT threshold is also a risk to the upside, but may be offset by increased resource taxes (from 5% to 10%).

Sinopec Corp – H (Overweight Price Target HK$9.40)Valuation MethodologyOur PT is based on 5x 2011E EV/EBITDA, similar to PetroChina’s valuation at our PetroChina PT. Our PT implies an 8.6x 2012E P/E. Although we see a slight discount to peers as justified due to current high oil prices resulting in refining losses, Sinopec currently trades at 7x 2012E P/E, which we see as too low considering where peers are trading at.

Risks to Our ViewRisks to our rating and PT for Sinopec include lower oil and/or NDRC cutting product prices below profitability levels and China relaxing credit earlier than expected.

PetroChina (Underweight Price Target HK$8.50)Valuation MethodologyPT is based on 10% premium to DCF value (US$85/bbl LT oil and 10.6% WACC) due to market’s focus on PE and current oil prices higher than our LT oil price assumption.

Risks to Our ViewRisks to rating and PT include higher oil prices, gas prices and NDRC following up with product prices.

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Chevron (Underweight Price Target $120.00)Valuation MethodologyWe maintain our December 2012 price target of $120/share for CVX, implying 10% potential upside from current price levels. We base our target price primarily on DCF, based on our estimate of CVX’s segment-level free cash flows discounted at a WACC of 7.8%. We determine upstream free cash flows based on the operating cash flows generated by the production outlook of the current commercial resource base, less the annual capital required to replace the produced resources. For other segments, we forecast ten years of free cash flows, then calculate a terminal value based on an inflation-adjusted growth in free cash flows thereafter.

Risks to Rating and Price Target

Active exploration portfolioExploration activities are an important source of growth for CVX, which is particularly active in global deepwater, especially in the Gulf of Mexico and West Africa. Should CVX’s exploration activities experience a prolonged successful streak, we believe investor sentiment could increase, causing CVX to outperform its peers.

Downstream restructuring CVX has indicated that it is undertaking restructuring activities in its downstream segment, including the expected divestiture of refining assets. Should CVX's divestiture plan prove successful or result in offer prices that are above market expectations, we believe that CVX could outperform the peers.

Industry consolidation activitiesAs CVX is one of the larger global integrated oil companies, maintaining a healthy balance sheet and ample access to capital, we believe that CVX could use acquisitions as a mechanism for growth. Should CVX use its balance sheet to embark on large-scale acquisitions that are accretive, we believe that could increment investors’ appetite for CVX shares, causing it to outperform its peers.

Exxon (Underweight Price Target $92.00)

Valuation MethodologyWe maintain our December 2012 price target of $92/share for XOM, implying 7% potential upside from current price levels. We base our target price primarily on DCF, based on our estimate of XOM’s segment-level free cash flows discounted at a WACC of 7.9%. We determine upstream free cash flows based on the operating cash flows generated by the production outlook of the current commercial resource base, less the annual capital required to replace the produced resources. For other segments, we forecast ten years of free cash flows, then calculate a terminal value based on an inflation-adjusted growth in free cash flows thereafter.


North American natural gas exposureFollowing the mid-2011 acquisition of XTO, XOM is now the largest producer of natural gas in North America. Accordingly, if North American natural gas prices were to increase above current market expectations, we believe XOM could benefit from its exposure, resulting in the stock's outperforming the peers.

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High level of global downstream exposureWith 6.3 mmbpd of refining capacity, XOM is the world’s largest refiner. Should refining margins strengthen, especially on unexpectedly high increases in global refined product demand, we believe XOM’s downstream segment could exceed expectations, potentially causing XOM to outperform the peers.

Active exploration portfolioXOM maintains a global portfolio of exploration activities in diverse regions such as Madagascar, Brazil, and the Arctic. Should XOM’s exploration pipeline result in a string of successful prospects, especially in frontier plays, we believe investor sentiment on exploration as a growth mechanism for XOM could be boosted, causing XOM to outperform the peers.

Industry consolidation activitiesAs the largest of the US integrated oils, with a healthy balance sheet and ~3 billion shares held in treasury stock, we believe that one way in which XOM could grow is via large-scale acquisition. Should XOM use its balance sheet to embark on large-scale acquisitions that were accretive or deemed to take place at a highly favorable price, we believe that XOM could outperform the peers.

Oil Search (Neutral Price Target A$8.01)

Valuation MethodologyOur Jun-12 price target for OSH is A$8.01/share. We include full value for PNG LNG T1 & T2, and 50% of Train 3. We employ a WACC of 10% for OSH. Risks to Rating and Price Target

The main upside and downside risks to our price target are favourable/unfavourable spot oil price movements, progress towards the company’s highly material PNG LNG project, and exploration success to find gas for Train 3 and beyond.

Santos(Overweight Price Target A$18.59)

Valuation MethodologyOur Jun-12 price target for STO is A$18.59/share. This reflects our DCF valuation inclusive of full value for PNG LNG T1&2, 80% of estimated value for GLNG T1&2, and 50% of estimated value of PNG LNG T3. We employ a WACC of 9% for STO.


The main downside risks are the oil price and domestic gas prices, execution risk for GLNG build, and exploration success for PNG LNG Train 3.

Woodside Petroleum (Underweight Price Target A$44.64)

Valuation MethodologyOur Jun-12 price target for WPL is A$44.64/share. This is based upon our sum of the parts DCF valuation. We apply a 50% risk weighting to a theoretical Laverda oil development, 50% risk weighting to Pluto-2 assuming 90% WPL equity gas and future Hess milestone payments, a 70% risk weighting for a Browse tie-back to NWS option (comparable to a 35% risk weighting on a standalone Browse at James Price

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Point development), and a 20% risk weighting to Sunrise. We employ a WACC of 9.0% for WPL.


The main upside risks are the oil price, and progress toward key milestones for its LNG projects. In the near term, one of the most relevant upside risks is further exploration/appraisal success for WPL’s planned Pluto-2 project, or to a lesser extent an agreement for third party gas supply into the project.

Origin Energy (Overweight Price Target A$18.95)

Valuation MethodologyOur $18.95 June 2012 Target Price for ORG is based on a sum-of-parts valuation. We apply different costs of capital to each of the individual business units in an effort to appropriately reflect the risk profile of each segment. Our group post tax WACC of 9.2% reflects a combination of the assumptions in the individual segments. The key figures that make up this discount rate are a post-tax cost of equity of 10.7% and a post-tax cost of debt of 5.3%. We apply a Beta of 1.1 within this calculation


The key downside risks to our valuation are: failure of the APLNG second train to reach FID; lower than forecast oil prices; lower than forecast electricity and gas retail tariffs; and lower than estimated wholesale electricity prices

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BG Group: Summary of FinancialsProfit and Loss Statement Valuation, performance and production

£ in millions, year end Dec FY09 FY10 FY11E FY12E FY13E £ in millions, year end Dec FY09 FY10 FY11E FY12E FY13E

Exploration & production 2,087 2,431 3,277 3,066 3,902 Brent crude, $/bbl 62.67 80.34 110.91 95.00 90.00

LNG 1,551 1,583 1,521 1,735 2,171 US Gas, $/MMBtu 4.16 4.38 4.03 4.10 4.95Transmission & Distribution 426 460 374 408 429

Power 158 63 0 0 0 Valuation

Corporate & other -11 -7 -5 -20 -30 Mkt Cap (� bn)

Total Segmental EBIT 4,211 4,531 5,168 5,189 6,472 P/E adjusted 21.5 18.8 18.3 17.9 14.2

P/CF 1.2 1.1 1.0 1.0 0.8

Finance Costs (144) (116) (172) (213) (239) P/FCF 1029.8% 483.6% -355.1% -122.5% -153.0%

Pre-Tax Income 3,941 4,415 4,996 4,976 6,233 EV/DACF 1419.0% 1272.9% 1289.5% 1302.0% 1112.6%

Less: Tax (1,708) (1,722) (2,248) (2,165) (2,680) CF Yield 0.1% 0.1% 0.1% 0.1% 0.1%

Tax Rate 43.3% 39.0% 45.0% 43.5% 43.0% FCF Yield 1.7% 2.8% -1.6% -6.3% -4.7%

Minorities 96 96 70 66 70 FCF yield ex-w/c 0.9% 1.9% -1.4% -4.8% -3.7%

Dividend Yield 0.9% 0.9% 1.0% 1.1% 1.3%

Adjusted Net Income 2,263 2,598 2,678 2,746 3,483 Buyback Yield 0.0% 0.0% 0.0% 0.0% 0.0%

Growth (26.2%) 14.8% 3.1% 2.5% 26.8% Combined Yield 0.9% 0.9% 1.0% 1.1% 1.3%

Avg. shares in issue (m) 3,363.00 3,381.00 3,389.00 3,399.00 3,409.00 Ratios

Net debt to equity 20.4% 26.0% 38.7% 51.6% 57.3%

Adjusted EPS (pence) 67.29 76.83 79.02 80.79 102.17 Net Debt to Capital Employed 17.1% 20.7% 28.0% 34.1% 36.5%

EPS growth(%) NM 14.2% 2.9% 2.2% 26.5% ROE 15.8% 15.2% 13.9% 12.8% 14.3%

DPS (pence) 12.3 13.7 15.0 16.5 18.2 ROCE 23.5% 19.1% 15.0% 11.9% 12.1%

DPS growth(%) 9.9% 10.7% 10.0% 9.9% 10.0%

Production

Group oil, kbopd 182 174 165 184 237

Group gas, mmcfpd 2,768 2,831 2,890 3,098 3,344

Group Total, kboepd 644 646 647 700 794

Y/Y growth 3.6% 0.3% 0.2% 8.2% 13.4%

Balance sheet Cash flow statement

£ in millions, year end Dec FY09 FY10 FY11E FY12E FY13E £ in millions, year end Dec FY09 FY10 FY11E FY12E FY13E

Tangible fixed assets 13,460 18,103 23,444 29,650 35,612 Consolidated Net Income 2,263 2,598 2,678 2,746 3,483

Other non current assets 7,610 7,732 8,466 8,976 9,411 DD&A 1,131 1,394 1,447 1,613 1,882

Total non current assets 21,070 25,835 31,909 38,625 45,023 Cash Tax Payable 1,263 1,234 1,723 1,727 2,133

Other items -17 -321 -72 -131 -154

Cash and cash equivalent 693 1,622 1,004 1,004 1,004 Cash Earnings 4,640 4,904 5,776 5,954 7,343

Other current assets 4,519 4,760 5,410 5,410 5,410 Increase in working capital (206) (450) (249) (249) (314)

Total current assets 5,212 6,383 6,415 6,415 6,415 Cash flow from Operations 4,846 5,354 6,024 6,204 7,657

Total assets 26,282 32,218 38,324 45,040 51,437

Capex (4,328) (5,451) (6,788) (7,819) (7,844)

Short term debt 717 806 3,840 7,459 10,366 Other investing cash flow -798 610 -18 257 0

Other current liabilities 4,431 4,886 5,641 6,844 7,439 Cash Flow from Investing -5,126 -4,841 -6,806 -7,562 -7,844

Total current liabilities 5,148 5,692 9,480 14,303 17,805

Share Buybacks 0 0 0 0 0

Long term debt 3,111 5,410 5,456 5,456 5,456 Dividends (s/h & minorities) (407) (447) (477) (534) (588)

Other non current liabilities 3,638 4,024 4,096 3,777 3,777 Other cash flow from financing 2,051 2,526 2,214 534 588

Total non current liabilities 6,749 9,434 9,551 9,232 9,232 Cash flow from Financing 1,644 2,079 1,737 0 0

Total liabilities 11,897 15,126 19,032 23,535 27,037 Change in Net debt -306 912 -3,034 -3,619 -2,907

Shareholders' equity

Minorities 96 96 70 66 70 Debt adjusted Cash Flow 3,640 4,197 4,387 4,634 5,697

Total Equity 14,385 17,092 19,293 21,505 24,400 Free cash flow 426 912 (1,245) (3,619) (2,907)

Total Liabilities and Shareholders Equity 26,282 32,218 38,324 45,040 51,437 FCF ex-W/C Changes 632 1,362 -996 -3,370 -2,593CFPS 1.4 1.5 1.7 1.8 2.2

Net debt/ (cash) 2,956 4,466 7,500 11,119 14,026

Capital Employed 17,341 21,558 26,793 32,624 38,427

Source: Company reports and J.P. Morgan estimates.

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BP: Summary of FinancialsProfit and Loss Statement Valuation, performance and production

$ in millions, year end Dec FY10 FY11E FY12E FY13E FY14E $ in millions, year end Dec FY10 FY11E FY12E FY13E FY14E

E&P 27,689 29,885 28,389 27,330 26,151 Brent crude, $/bbl 80.34 110.00 95.00 90.00 85.00

R&M 4,883 7,169 6,894 6,407 6,352 US Gas, $/MMBtu 4.38 4.43 5.40 5.90 5.90Other & Corporate -869 -1,678 -1,600 -1,600 -1,600

Total Segmental EBIT 31,703 35,376 33,683 32,138 30,903 Valuation

Mkt Cap ($ bn)

Finance Costs (1,046) (907) (920) (850) (825) P/E adjusted 6.5 6.2 6.6 7.0 7.2

Pre-Tax Income 30,657 34,469 32,763 31,288 30,078 P/CF 4.5 4.6 3.7 4.1 4.1

Less: Tax (9,741) (11,711) (11,531) (11,093) (10,663) P/FCF 13.0 -13.9 22.7 8.2 -1160.0

Tax Rate 31.8% 34.0% 34.2% 34.5% 34.5% EV/DACF 5.4 5.6 4.3 4.3 4.3

Minorities 395 383 357 340 327 CF Yield 22.0% 21.6% 27.0% 24.4% 24.2%

FCF Yield 21.6% 0.8% 12.8% 17.9% 5.9%

Adjusted Net Income 20,521 22,375 20,874 19,855 19,088 FCF yield ex-w/c 5.8% 4.1% 2.4% 11.9% -0.2%

Growth 40.8% 9.0% (6.7%) (4.9%) (3.9%) Dividend Yield 1.0% 4.0% 4.5% 4.9% 5.3%

Avg. shares in issue (m) 18,792.91 18,967.63 18,953.93 18,879.19 18,808.18 Buyback Yield -0.1% -0.0% 0.7% 0.9% 0.9%

Combined Yield 0.9% 3.9% 5.2% 5.9% 6.3%

Adjusted EPS (cents) 1.09 1.18 1.10 1.05 1.01

EPS growth(%) 40.4% 8.3% NM NM NM Ratios

Adjusted EPS (pence) 70.5 73.5 68.8 65.7 63.4 Net debt to equity 27.0% 27.6% 19.0% 5.5% 5.2%

EPS growth(%) 41.9% 4.3% -6.4% -4.5% -3.5% Net Debt to Capital Employed 21.2% 21.6% 16.0% 5.2% 4.9%

DPS (cents) 7.0 29.0 32.8 35.8 38.5 ROE 21.6% 19.6% 16.3% 14.2% 12.6%

DPS growth(%) (87.5%) 314.3% 12.9% 9.2% 7.7% ROCE 16.9% 15.3% 13.6% 13.3% 11.8%

DPS (pence) 4.5 17.9 20.4 22.3 24.0

DPS growth(%) (87.3%) 299.5% 14.1% 9.2% 7.7% Production

Group oil, kbopd 2,374 2,088 2,101 2,034 1,993

Group gas, mmcfpd 8,401 8,328 9,035 9,101 9,481

Group Total, kboepd 3,774 3,476 3,607 3,551 3,573

Y/Y growth -4.4% -7.9% 3.7% -1.6% 0.6%



Cash and cash equivalent 18,556 8,586 14,680 31,527 31,408 Consolidated Net Income 20,521 22,375 20,874 19,855 19,088

Other current assets 15,530 7,833 8,803 8,803 8,803 DD&A 11,539 11,876 11,180 11,126 11,397

Current assets 96,853 82,108 92,419 109,888 110,679 Cash tax payable (6,610) (7,497) (7,382) (7,101) (6,826)

Tangible fixed assets 110,163 128,345 136,335 133,909 147,212 Other items -3,240 -11,953 18,022 17,161 16,655

Other non current assets 15,538 15,590 15,590 15,590 15,590 Cash Earnings 22,210 14,801 42,694 41,041 40,313

Total non current assets 175,409 204,705 214,470 213,469 228,197 Change in working capital 2,123 (15,636) 2,700 200 200

Total assets 272,262 286,813 306,889 323,357 338,876 Cash flow from Operations 20,087 30,437 39,994 40,841 40,113

Short term debt 14,626 7,986 7,016 7,016 7,016

Other current liabilities 22,924 22,235 26,384 30,376 34,213 Capex (18,947) (19,146) (22,550) (24,050) (25,050)

Total current liabilities 83,879 78,607 84,286 88,278 92,115 Other investing cash flow 14,987 -10,236 3,030 15,000 0

Cash Flow from Investing -3,960 -29,382 -19,520 -9,050 -25,050

Long term debt 30,710 33,767 33,767 33,767 33,767

Other non current liabilities 61,782 59,444 59,444 59,444 59,444 Share Buybacks 169 59 -977 -1,303 -1,303

Total non current liabilities 92,492 93,211 93,211 93,211 93,211 Dividends (s/h & minorities) (2,627) (4,089) (5,770) (6,290) (6,802)

Total liabilities 176,371 171,818 177,497 181,489 185,326 Other cash flow from financing 3,298 802 (250) (250) (250)

Shareholders' equity Cash flow from Financing 840 -3,228 -6,998 -7,843 -8,356

Minorities 904 1,094 1,451 1,791 2,118 Change in Net debt -297 5,849 -7,065 -16,847 119

Total Equity 95,891 114,994 129,392 141,868 153,550

Total Liabilities and Shareholders Equity 272,262 286,812 306,889 323,357 338,876 Debt adjusted cash flow 29,226 29,925 37,382 33,739 33,287

Free cash flow 10,217 (9,970) 6,095 16,847 (119)

Net debt/ (cash) 25,864 31,713 24,649 7,802 7,921 FCF ex-W/Capital Changes 8,094 5,666 3,395 16,647 -319

Capital Employed 121,755 146,708 154,041 149,670 161,471 CFPS 1.2 0.8 2.3 2.2 2.1


225



Royal Dutch Shell B: Summary of FinancialsProfit and Loss Statement Valuation, performance and production

$ in millions, year end Dec FY09 FY10 FY11E FY12E FY13E $ in millions, year end Dec FY09 FY10 FY11E FY12E FY13E

Exploration & Production 18,333 33,230 39,463 37,606 36,979 Brent crude, $/bbl 62.67 80.34 110.00 95.00 90.00

Gas & Power 2,423 4,060 7,733 7,811 7,811 US Gas, $/MMBtu 4.16 4.38 4.43 5.40 5.90Oil Products 2,290 2,969 4,063 4,749 5,432

Chemicals 410 1,983 2,385 1,503 2,059 Valuation

OIS & Corporate 408 -719 -649 -643 -636 Mkt Cap ($ bn)


P/CF 0.6 0.4 0.3 0.3 0.3

Finance Costs 1,664 (140) 84 1,185 1,039 P/FCF -221.7% 326.1% 177.1% 226.6% 196.1%

Pre-Tax Income 25,529 41,383 53,079 52,211 52,683 EV/DACF 1023.6% 792.6% 560.9% 482.3% 438.0%

Less: Tax (12,194) (23,117) (26,570) (27,938) (28,194) CF Yield 0.2% 0.2% 0.3% 0.3% 0.4%

Tax Rate 47.8% 55.9% 50.1% 53.5% 53.5% FCF Yield 2.7% 7.3% 8.8% 8.5% 9.1%

Minorities 118 333 365 347 361 FCF yield ex-w/c -1.6% 5.0% 8.8% 3.8% 3.3%

Dividend Yield 5.5% 5.5% 5.5% 5.8% 6.0%


Growth (59.3%) 56.4% 44.2% (12.7%) 1.5% Combined Yield 5.5% 5.5% 5.5% 5.8% 6.0%

Avg. shares in issue (m) 6,128.90 6,139.28 6,245.33 6,230.33 6,290.33

Ratios

Adjusted EPS (cents) 1.89 2.94 4.19 3.84 3.84 Net debt to equity 18.6% 20.9% 15.0% 10.9% 6.8%

EPS growth(%) NM 56.2% 42.2% NM NM Net Debt to Capital Employed 15.7% 17.3% 13.1% 9.8% 6.4%

Adjusted EPS (pence) 120.3 190.4 259.3 248.3 248.0 ROE 8.5% 12.2% 15.9% 12.9% 12.2%

EPS growth(%) -50.0% 58.3% 36.2% -4.2% -0.1% ROCE 7.3% 10.7% 14.4% 12.2% 11.9%

DPS (cents) 168.0 168.0 174.7 181.7 181.7

DPS growth(%) 5.0% 0.0% 0.0% 3.0% 0.0% Production

DPS (pence) 106.3 106.8 105.8 111.9 115.3 Group oil, kbopd 1,680 1,709 1,701 1,700 1,738

DPS growth(%) 14.5% 0.5% (0.9%) 5.8% 3.0% Group gas, mmcfpd 8,483 9,305 9,391 10,867 11,111


Y/Y growth -3.3% 5.4% 0.2% 7.5% 2.3%


$ in millions, year end Dec FY09 FY10 FY11E FY12E FY13E $ in millions, year end Dec FY09 FY10 FY11E FY12E FY13E



Total current assets 96,457 112,894 119,143 124,584 130,931 Cash tax payable (9,243) (15,362) (18,959) (18,889) (19,607)

Tangible fixed assets 131,619 142,705 145,809 155,571 164,705 Other items 2,389 3,115 4,807 18,881 23,303


Total non current assets 195,724 209,666 210,961 221,877 230,769 Change in working capital (2,331) (5,929) (10,191) (2,000) 0

Total assets 292,181 322,560 330,104 346,461 361,701 Cash flow from operations 21,488 27,350 39,335 43,623 46,392

Short term debt (4,171) (9,951) (9,951) (9,951) (9,951)


Total current liabilities 84,789 100,552 91,519 95,251 97,818 Other investing cash flow 1,604 3,427 5,770 0 0

Cash Flow from Investing Acitivites -26,234 -21,972 -21,881 -27,241 -28,741

Long term debt (30,862) (34,381) (34,381) (34,381) (34,381)

Other non current liabilities 104,290 116,560 116,864 116,864 116,864 Share Buybacks 0 0 0 0 0


Total liabilities 154,046 172,780 164,051 167,783 170,350 Other cash flow from financing 9,803 7,931 (325) (478) (526)

Shareholders' equity Cash flow from Financing -723 -1,653 -10,476 -10,942 -11,304

Minorities 1,704 1,767 2,132 2,479 2,840 Change in Net debt 17,233 5,574 -6,249 -5,440 -6,347

Total Equity 136,431 148,013 163,922 176,199 188,510


Free cash flow (5,469) 3,725 6,978 5,440 6,347

Net debt/ (cash) 25,314 30,888 24,639 19,198 12,851 FCF ex-W/Capital Changes -3,138 9,654 17,169 7,440 6,347

Capital Employed 161,745 178,901 188,560 195,398 201,361 CFPS 3.1 3.5 4.7 6.7 7.4


226



ENI: Summary of FinancialsProfit and Loss Statement Valuation, performance and production

€ in millions, year end Dec FY09 FY10 FY11E FY12E FY13E € in millions, year end Dec FY09 FY10 FY11E FY12E FY13E

Exploration & Production 9,484 13,884 15,566 15,616 16,574 Brent crude, $/bbl 62.67 80.34 110.00 95.00 90.00

Gas & Power 3,683 3,119 2,679 3,005 3,165 US Gas, $/MMBtu 4.16 4.38 4.43 5.40 5.90Refining & Marketing -357 -171 -342 -239 -152

Chemicals -426 -113 -81 -61 20 Valuation

Corporate & other 528 585 672 1,063 1,239 Mkt Cap (bn)


P/CF 5.2 4.0 3.3 3.2 3.0

Finance Costs 149 89 500 350 350 P/FCF -18502.7% -98472.0% 4632.0% 10758.1% 3667.7%

Pre-Tax Income 13,061 17,393 18,995 19,734 21,197 EV/DACF 7.3 5.8 4.8 4.5 4.2

Less: Tax 7,049 9,459 10,424 10,792 11,201 CF Yield 19.1% 25.1% 30.0% 31.3% 33.4%

Tax Rate 54.0% 54.4% 54.9% 54.7% 52.8% FCF Yield 4.5% 6.9% 8.5% 7.6% 9.7%

Minorities 950 1,065 1,214 1,427 1,545 FCF yield ex-w/c 2.7% 2.9% 2.2% 0.9% 2.7%

Dividend Yield 6.2% 6.2% 6.5% 6.8% 7.1%


Growth (50.2%) 35.7% 7.1% 2.1% 12.5% Combined Yield 6.2% 6.2% 6.5% 6.8% 7.1%



Adjusted EPS 1.40 1.90 2.03 2.07 2.33 Net Debt to Capital Employed 31.4% 31.9% 29.1% 27.0% 24.1%

EPS growth(%) NM 35.7% 7.1% 2.1% 12.5% ROE 10.1% 12.3% 12.1% 11.4% 11.8%

DPS 1.00 1.00 1.04 1.09 1.15 ROCE 7.2% 8.9% 8.8% 8.6% 9.2%

DPS growth(%) (23.1%) 0.0% 4.0% 5.0% 5.0%

Production

Group oil, kbopd 1,007 997 896 969 1,026

Group gas, mmcfpd 4,374 4,540 3,900 4,094 4,328

Group total, kboepd 1,796 1,816 1,600 1,708 1,807

Y/Y growth 0.4% 1.1% -11.9% 6.7% 5.8%





Total non current assets 79,963 87,191 90,813 95,354 99,715 Cash tax payable 7,049 9,459 10,424 10,792 22,402

Cash and cash equivalent 1,625 1,549 2,820 3,360 4,944 Other items -4,099 -3,949 714 1,077 -10,005

Total assets 73,339 81,847 85,469 90,010 94,369 Cash Earnings 17,823 21,771 27,834 28,955 30,602

Change in working capital (1,901) (1,726) 0 0 0

Short term debt 137 115 98 98 98 Cash flow from Operations 19,724 23,497 27,834 28,955 30,602

Long term debt 24,800 27,783 27,783 27,783 27,783

Total liabilities 23,038 26,119 24,865 24,325 22,741 Capex (13,695) (13,870) (14,462) (14,112) (14,115)

Shareholders' equity Other investing cash flow 847 931 1,500 0 0

Minorities 3,978 4,522 5,736 7,164 8,709 Cash Flow from Investing -12,848 -12,939 -12,962 -14,112 -14,115

Total Equity 50,301 55,728 60,605 65,685 71,628 Share Buybacks 0 0 0 0 0

Total Liabilities and Equity 73,339 81,847 85,469 90,010 94,369 Dividends (s/h & minorities) (2,956) (4,099) (3,695) (3,861) (4,053)

Other cash flow from financing 4,224 2,285 0 0 1

Net debt 23,038 26,119 24,865 24,325 22,741 Cash flow from Financing 1,268 -1,814 -3,695 -3,861 -4,052


Change in Net debt 4,662 3,081 -1,254 -540 -1,584

Debt adjusted Cash Flow 11,117 14,605 17,411 18,163 19,401

Free cash flow (314) (59) 1,254 540 1,584

Free cash flow (ex-w/c) 1,587 1,667 1,254 540 1,584

CFPS -0.1 -0.0 0.3 0.1 0.4


227



Repsol YPF: Summary of FinancialsProfit and Loss Statement Valuation, performance and production


Exploration & Production 884 1,473 1,661 2,007 1,922 Brent Crude, $/bbl 62.67 80.34 110.00 95.00 90.00

Refining & Marketing 647 977 808 1,230 1,752 US Gas, $/MMBtu 3.66 4.38 4.43 5.40 5.90YPF 789 1,625 1,578 1,834 1,927

Gas Natural 745 849 933 939 961 Valuation

LNG 50 127 259 253 279 Mkt Cap (bn)

Corporate -354 -336 -316 -345 -349 P/E adjusted 20.9 13.3 12.2 9.9 8.7

Total Segmental EBIT 2,761 4,714 4,922 5,917 6,491 P/CF 4.9 4.1 4.0 4.5 3.4

P/FCF -4225.8% 653.7% 6174.0% -1572.9% -91826.8%

Finance Costs (468) (858) (765) (572) (571) EV/DACF 7.4 5.7 5.5 6.3 4.9

Pre-Tax Income 2,293 3,856 4,157 5,345 5,919 CF Yield 20.5% 24.4% 24.9% 22.5% 29.2%

Less: Tax 832 1,561 1,686 2,296 2,440 FCF Yield 4.9% 18.7% 6.5% -1.2% 5.7%

Tax Rate 36.3% 40.5% 40.6% 42.9% 41.2% FCF yield ex-w/c -0.2% 17.5% 7.9% -3.6% 7.4%

Minorities 166 263 247 305 348 Dividend Yield 3.9% 4.8% 5.3% 5.9% 6.4%

Buyback Yield 0.0% 0.0% 0.0% 0.0% -0.0%

Adjusted Net Income 1,295 2,032 2,224 2,745 3,132 Combined Yield 3.9% 4.8% 5.3% 5.9% 6.4%

Growth (50.6%) 57.0% 9.5% 23.4% 14.1%

Ratios

Avg. shares in issue (m) 1,221.00 1,221.00 1,221.00 1,221.00 1,221.00 Net debt to equity 73.4% 45.4% 40.6% 45.1% 42.7%

Net Debt to Capital Employed 42.4% 31.2% 28.9% 31.1% 29.9%

Adjusted EPS 1.06 1.66 1.82 2.25 2.57 ROE 6.1% 7.8% 8.2% 9.5% 10.2%

EPS growth(%) NM 57.0% 9.5% 23.4% 14.1% ROCE 4.2% 5.8% 6.3% 7.5% 8.0%

DPS 0.85 1.05 1.16 1.27 1.40 Production

DPS growth(%) (19.1%) 23.5% 10.0% 10.0% 10.0% Group oil, kbopd 438 437 401 422 427

Group gas, mmcfpd 2,808 2,700 2,491 2,367 2,298

Group Total, kboepd 906 887 816 817 809

Y/Y growth -4.8% -2.1% -8.0% 0.1% -0.9%





Total non current assets 43,310 45,753 45,759 47,097 49,059 Cash tax payable (1,168) (1,627) (1,602) (2,181) (2,318)

Total Current assets 14,773 21,878 23,049 21,329 21,299 Other items 770 106 -1,322 -940 -774

Total assets 58,083 67,631 68,821 68,429 70,358 Cash Earnings 6,119 7,641 6,635 7,523 8,191

Change in working capital (590) (590) (1,693) (733) (2,031)

Cash flow from Operations 6,709 8,231 8,328 8,256 10,222

Short term debt 3,499 4,362 4,362 4,362 4,362


Total Current Liabilities 11,993 15,773 15,773 13,742 13,743 Other investing cash flow 56 -27 0 0 0

Cash Flow from Investing -7,854 -73 -3,476 -5,240 -5,240

Long term debt 15,411 14,940 14,940 14,940 14,941

Other non current liabilities 9,288 10,932 10,932 10,932 10,932 Dividends (s/h & minorities) (1,935) (806) (1,282) (1,410) (1,552)

Total non current liabilities 24,699 25,872 25,872 25,872 25,873 Other cash flow from financing 4,440 (653) (765) (572) (572)

Total liabilities 36,692 41,645 41,645 39,614 39,616 Cash flow from Financing 2,505 -1,459 -2,047 -1,982 -2,123

Shareholders' equity

Minorities 1,440 1,846 2,093 2,398 2,746 Change in Net debt 7,796 -3,696 -764 1,719 31

Total Equity 21,391 25,986 27,176 28,815 30,742

Total Liabilities and Shareholders Equity 58,083 67,631 68,821 68,429 70,358 Debt adjusted Cash Flow 5,541 6,604 6,726 6,075 7,904

Free cash flow (640) 4,137 438 (1,719) (29)

Net debt 14,654 10,958 10,194 11,913 11,945 FCF ex-W/Capital Changes -50 4,727 2,131 -987 2,002

Capital Employed 34,605 35,098 35,276 38,330 39,941 CFPS -0.5 3.4 0.4 -1.4 -0.0


228



Statoil: Summary of FinancialsProfit and Loss Statement Valuation, performance and production

Nkr in millions, year end Dec FY09 FY10 FY11E FY12E FY13E Nkr in millions, year end Dec FY09 FY10 FY11E FY12E FY13E

Exploration & production* 111,881 125,730 170,570 167,383 162,714 Brent crude, $/bbl 62.67 80.34 110.00 95.00 90.00

Natural Gas* 16,500 13,500 12,335 14,080 14,113 US Gas, $/MMBtu 4.16 4.38 4.43 5.40 5.90Manufacturing & Marketing 2,100 1,700 - - -

Fuel and Retail 1,500 2,200 1,667 1,751 1,872 Valuation

Marketing, Processing & Renewable energy - - 8,194 14,757 15,086 Mkt Cap (Nkr bn)

Other Operations -1,100 -400 -1,100 -1,100 -1,100 P/E adjusted 12.6 11.6 9.7 9.1 8.8

Total Segmental EBIT 130,881 142,730 179,331 182,791 178,573 P/CF 6.2 5.6 4.9 4.6 4.4

P/FCF 7380.2% 8688.3% 6234.1% -2610.1% -

Finance Costs (300) (1,100) 0 (1,246) (1,245) EV/DACF 7.0 6.3 5.4 5.3 5.2

Pre-Tax Income 129,081 139,593 178,464 180,595 176,257 CF Yield 16.3% 18.0% 20.6% 21.9% 22.8%

Less: Tax 92,286 98,800 128,720 128,613 122,044 FCF Yield 6.8% 5.6% 6.2% 0.9% 1.8%

Tax Rate 70.7% 69.8% 71.8% 70.8% 68.8% FCF yield ex-w/c 2.6% 4.6% 3.0% -2.4% -1.8%

Minorities (598) (598) (767) (805) (861) Dividend Yield 4.4% 4.5% 4.8% 5.0% 5.3%

Buyback Yield 0.1% 0.1% 0.0% 0.0% 0.0%

Adjusted Net Income 37,697 42,232 49,844 52,128 54,423 Combined Yield 4.4% 4.6% 4.8% 5.0% 5.3%

Growth (34.7%) 12.0% 18.0% 4.6% 4.4%



Adjusted EPS (Nkr) 12.07 13.14 15.68 16.66 17.38 Net Debt to Capital Employed 27.3% 23.5% 19.2% 20.9% 21.6%

EPS growth(%) NM 8.8% 19.3% 6.3% 4.3% ROE 18.8% 18.7% 18.9% 17.3% 15.9%

DPS (Nkr) 6.00 6.24 6.55 6.88 7.22 ROCE 13.7% 14.3% 15.3% 13.7% 12.5%

DPS growth(%) (17.2%) 4.0% 5.0% 5.0% 5.0%

Production

Group oil, kbopd 1,061 968 931 981 978

Group gas, mmcfpd 4,440 4,428 4,127 4,348 4,562


Y/Y growth 2.8% -5.3% -5.1% 5.4% 2.0%


Nkr in millions, year end Dec FY09 FY10 FY11E FY12E FY13E Nkr in millions, year end Dec FY09 FY10 FY11E FY12E FY13E



Current assets 116,384 148,762 155,960 138,770 124,497 Cash tax payable 100,773 93,266 122,284 123,428 117,186

Net fixed assets 340,835 348,204 371,644 420,794 468,330 Other items -16,673 -22,092 -5,602 -6,781 -6,396


Total non current assets 446,456 449,356 472,796 521,946 569,482 Change in working capital (5,687) (15,429) (6,436) (6,431) (6,102)

Total assets 562,840 643,008 673,646 705,606 738,869 Cash flow from operations 173,774 174,081 214,716 221,542 219,265

Short term debt 8,150 11,730 11,730 11,730 11,730


Total current liabilities 111,805 136,135 129,699 123,268 117,166 Other investing cash flow -206 -2,063 23,605 0 0

Cash Flow from Investing Acitivites -75,356 -76,218 -65,260 -94,331 -94,331

Long term debt 95,962 99,797 99,797 99,797 99,797

Other non current liabilities 154,955 171,458 171,458 171,458 171,458 Share Buybacks -343 -294 0 0 0


Total liabilities 362,722 416,613 410,177 403,746 397,644 Other cash flow from financing 34,719 19,956 0 0 0

Shareholders' equity Cash flow from Financing 11,291 567 -19,974 -20,973 -22,022

Minorities 1,799 6,853 6,853 6,853 6,853 Change in Net debt 29,304 -5,586 -7,198 17,190 14,274

Total Equity 200,118 226,395 263,468 301,859 341,224


Free cash flow 6,085 5,164 7,197 (17,190) (14,274)

Net debt 75,267 69,681 62,483 79,673 93,946 FCF ex-W/Capital Changes 11,772 20,593 13,633 -10,759 -8,171

Capital Employed 275,385 296,076 325,951 381,531 435,170 CFPS 1.9 1.6 2.3 -5.4 -4.5


229



TOTAL: Summary of FinancialsProfit and Loss Statement Valuation, performance and production


Exploration & production 13,885 19,003 23,453 22,252 24,891 Brent crude, $/bbl 62.67 80.34 110.00 95.00 90.00

Refining & marketing 1,173 1,518 1,324 1,113 1,354 US Gas, $/MMBtu 4.16 4.38 4.43 5.40 5.90Chemicals 314 1,124 1,161 1,130 1,206

Corporate & other 290 -143 -195 -400 -400 Valuation

Total Segmental EBIT 15,663 21,503 25,742 24,094 27,051 Mkt Cap (bn)

P/E adjusted 11.5 8.6 7.6 7.8 6.8

Finance Costs (264) (226) (389) (391) (362) P/CF 7.0 4.7 4.6 4.2 3.8

Pre-Tax Income 15,399 21,277 25,354 23,703 26,689 P/FCF -13414.7% 3127.1% 28949.7% 57047.0% 597721.5%

Less: Tax (7,436) (10,755) (13,733) (12,605) (13,999) EV/DACF 8.0 5.4 5.3 4.8 4.3

Tax Rate 48.3% 50.5% 54.2% 53.2% 52.5% CF Yield 14.3% 21.2% 21.8% 23.7% 26.0%

Minorities (178) (234) (250) (250) (200) FCF Yield 5.0% 9.0% 6.1% 6.2% 6.4%

FCF yield ex-w/c 3.0% 3.7% 0.3% -0.2% -0.1%

Adjusted Net Income 7,785 10,288 11,371 10,848 12,490 Dividend Yield 5.8% 5.8% 5.8% 6.1% 6.4%

Growth (44.1%) 32.2% 10.5% (4.6%) 15.1% Buyback Yield -0.0% -0.1% 0.0% 0.0% 0.0%

Combined Yield 5.7% 5.7% 5.8% 6.1% 6.4%

Avg. shares in issue (m) 2,217.00 2,217.00 2,217.00 2,217.00 2,217.00

Ratios

Adjusted EPS 3.48 4.64 5.24 5.14 5.88 Net debt to equity 25.3% 21.3% 20.2% 16.5% 14.4%

EPS growth(%) NM 33.4% 13.0% NM 14.4% Net Debt to Capital Employed 21.6% 18.7% 17.9% 14.8% 13.3%

DPS 2.28 2.28 2.28 2.39 2.51 ROE 14.8% 17.0% 17.0% 14.8% 15.5%

DPS growth(%) 0.0% 0.0% 0.0% 5.0% 5.0% ROCE 12.4% 14.7% 14.7% 13.1% 14.1%

Production

Group oil, kbopd 1,381 1,339 1,242 1,292 1,401

Group gas, mmcfpd 4,923 5,674 6,147 6,357 6,212


Y/Y growth -2.6% 4.1% -0.5% 3.7% 3.4%





Total non current assets 77,996 85,512 93,102 99,578 107,321 Cash Tax Payable 7,700 10,980 14,121 12,996 14,361

Other items -5,032 1,296 502 1,389 940

Cash and cash equivalent 11,662 14,489 14,794 14,949 14,964 Cash Earnings 16,744 28,977 32,973 33,860 37,078

Other current assets 38,095 42,447 42,447 36,660 34,730 Change in working capital (3,316) (496) 1 299 100

Total Current assets 49,757 56,936 57,241 51,609 49,694 Cash flow from Operations 20,060 29,473 32,972 33,560 36,978

Total assets 127,753 143,718 150,342 151,186 157,014

Capex (11,711) (12,278) (14,217) (17,029) (17,029)

Short term debt 6,994 9,653 9,653 8,337 7,898 Other investing cash flow -922 -735 0 0 0

Other current liabilities 27,411 30,597 30,598 26,426 25,035 Cash Flow from Investing -10,268 -11,957 -13,490 -15,102 -17,029

Total Current Liabilities 34,405 40,250 40,251 34,763 32,933

Share Buybacks 22 49 0 0 0

Long term debt 19,437 20,783 20,783 20,783 20,783 Dividends (s/h & minorities) (5,086) (5,098) (5,055) (5,307) (5,573)

Other non current liabilities 20,369 21,216 21,216 21,216 21,216 Cash flow from Financing -2,868 -3,348 -5,055 -5,307 -5,573

Total non current liabilities 39,806 41,999 41,999 41,999 41,999 Change in Net debt 2,895 -535 741 -1,471 -454

Total liabilities 74,211 82,249 82,250 76,762 74,932

Shareholders' equity Debt adjusted Cash Flow 12,624 18,719 19,239 20,955 22,979

Minorities 987 857 1,107 1,357 1,557 Free cash flow (659) 2,827 305 155 15

Total Equity 52,552 60,414 66,980 73,061 80,518 FCF ex-W/C Changes 2,657 3,323 304 -144 -85

Total Liabilities and Shareholders Equity 127,753 143,718 150,342 151,186 157,013 CFPS -0.3 1.3 0.1 0.1 0.0

Net debt 13,566 13,031 13,772 12,301 11,847



230



Chevron Corp: Summary of FinancialsIncome Statement - Annual FY10A FY11E FY12E FY13E Segment-level earnings - Quarterly 1Q11A 2Q11A 3Q11A 4Q11ERevenues 204,928 213,125 221,650 230,516 E&P 6,093A 6,845A 5,897A 5,535

Cost of products sold 116,467 107,206 110,248 116,435 R&M 660A 1,138A 1,338A 479Gross profit 88,461 105,919 111,402 114,081 Chemicals 0A 0A 0A 0

SG&A 4,767 4,815 4,863 4,911 Other 0A 0A 0A 0

DD&A 13,063 12,257 13,006 13,303 Segment-level earnings 6,753A 7,983A 7,235A 6,014Other operating expenses 38,546 39,544 40,127 40,472

Operating Income 32,085 49,304 53,407 55,394Corporate & other (378)A (170)A (355)A (300)

Net interest income / (expense) (30) (239) (182) (138) Taxes - - - -

Other 0 0 0 0 Operating earnings 6,375A 7,813A 6,880A 5,714Pretax income 32,055 49,065 53,225 55,257

Taxes 12,919 22,079 23,951 24,865 Reported Earning 6,211A 7,732A 7,829A 5,714Tax rate (%) 40.3% 45.0% 45.0% 45.0%

Reported net income 19,136 26,986 29,274 30,391 Average diluted shares outstanding 2,009A 2,009A 1,999A 1,991

Non-recurring items, disc ops 337 0 0 0Adjusted net income 18,799 26,986 29,274 30,391 Operating EPS 3.17A 3.89A 3.44A 2.87

Average diluted shares outstanding 2,007 2,002 1,973 1,973 EPS growth rate (%) 29.2%A 51.0%A 67.1%A 15.4%Dividend per share - - - -

EPS 9.53 13.48 14.84 15.40

EPS growth rate (%) 80.6% 41.4% 10.1% 3.8% Production (kboepd) 2,759A 2,694A 2,599A 2,731Dividend per share 2.84 3.09 3.18 3.28 production growth (y/y) (0.9%)A (1.9%)A (5.1%)A (2.0%)

EBITDA 46,315 63,352 68,409 70,658Production (kboepd) 2,761 2,696 2,729 2,770

WTI crude price ($/bbl) 79.50 95.06 107.38 118.00 WTI crude price ($/bbl) 94.24A 102.57A 89.59A 93.82

Henry Hub natural gas price ($/mcf) 4.40 4.03 4.10 4.75 Henry Hub natural gas price ($/mcf) 4.20A 4.38A 4.06A 3.49

Balance Sheet and Cash Flow Data FY10A FY11E FY12E FY13E Ratio Analysis FY10A FY11E FY12E FY13ECash and cash equivalents 17,070 19,607 24,832 34,219 Valuation

Other current assets 31,771 31,771 31,771 31,771 P/E (adjusted) 11.3 8.0 7.3 7.0

Total current assets 48,841 51,378 56,603 65,990 P/CF 6.9 5.3 4.9 4.7Net PP&E 104,504 119,079 135,034 150,776 Enterprise value/EBITDA 4.0 2.9 2.7 2.6

Other assets 31,424 31,424 31,424 31,424 EV/DACF 5.9 4.6 4.2 4.1Total assets 184,769 201,881 223,061 248,190

Ratios

Total debt 11,476 10,376 10,343 10,302 Net debt/equity (5.3%) (7.5%) (10.1%) (14.2%)Total liabilities 78,958 78,520 79,206 79,911 Net debt/capital (5.6%) (8.1%) (11.2%) (16.6%)

Minority interests 0 0 0 0 Net coverage ratio 2.5 4.0 4.1 4.2Preferred stock - - - - ROE 19.0% 23.6% 21.9% 19.5%

Shareholders' equity 105,811 123,361 143,855 168,279 ROCE 19.7% 25.4% 24.2% 22.3%Net Income 19,136 26,986 29,274 30,391 Yield and cash returns

DD&A 13,063 12,257 13,006 13,303 CFPS 15.62 20.25 22.17 22.90

Deferred taxes 559 662 719 746 CF yield 16.4% 21.4% 23.4% 24.2%Other (1,475) 638 739 44,433 FCF yield 2.5% 3.6% 4.1% 4.8%

Cash earnings 31,283 40,543 43,737 45,179 Dividend yield 2.6% 2.9% 2.9% 3.0%Change in working capital 76 0 0 0 Dividend payout ratio 29.8% 22.9% 21.4% 21.3%

Cash flow from operations 31,359 40,543 43,737 45,179 Buyback yield 0.1% 1.5% 1.1% 0.2%

Capex (19,612) (26,000) (29,700) (29,784) Total cash returns (%) 3.1% 5.0% 4.6% 3.1%Dividends (5,674) (6,186) (6,279) (6,468)

Share buybacks (net) (306) (3,250) (2,500) 500

Change in debt 882 (1,100) (33) (41) Mkt Cap (current) ()Change in preferred stock - - - - Enterprise Value (current)

Other uses of cash (1,305) (1,470) (0) (0)Change in cash 5,344 2,537 5,225 9,387

Free cash flow 10,366 13,073 14,037 15,395

Source: Company reports and J.P. Morgan estimates.Note: $ in millions (except per-share data).Fiscal year ends Dec

231



Exxon Mobil Corp: Summary of FinancialsIncome Statement - Annual FY10A FY11E FY12E FY13E Segment-level earnings - Quarterly 1Q11A 2Q11A 3Q11A 4Q11ERevenues 383,221 466,118 505,184 547,276 E&P 8,675A 8,541A 8,394A 8,547

Cost of products sold 197,959 254,020 283,687 306,065 R&M 1,099A 1,356A 1,579A (63)Gross profit 185,262 212,098 221,497 241,210 Chemicals 1,516A 1,321A 1,003A 1,250

SG&A 14,683 14,683 14,683 14,683 Other 0A 0A 0A 0

DD&A 14,760 16,801 17,344 17,167 Segment-level earnings 11,290A 11,218A 10,976A 9,734Other operating expenses 102,601 109,110 114,306 118,861

Operating Income 53,218 71,504 75,164 90,500Corporate & other (640)A (538)A (646)A (700)

Net interest income / (expense) (154) (421) (502) (261) Taxes - - - -

Other (105) (311) (371) (193) Operating earnings 10,650A 10,680A 10,330A 9,034Pretax income 52,959 70,772 74,292 90,046

Taxes 21,561 30,078 31,574 38,270 Reported Earning 10,650A 10,680A 10,330A 9,034Tax rate (%) 40.7% 42.5% 42.5% 42.5%

Reported net income 30,460 40,694 42,718 51,776 Average diluted shares outstanding - - - -

Non-recurring items, disc ops - - - -Adjusted net income 30,460 40,694 42,718 51,776 Operating EPS 2.14A 2.17A 2.13A 1.89

Average diluted shares outstanding 4,897 4,877 4,749 4,749 EPS growth rate (%) 61.1%A 36.0%A 47.7%A 2.8%Dividend per share 0.44A 0.47A 0.47A 0.47

EPS 6.22 8.34 8.99 10.90

EPS growth rate (%) 55.3% - - - Production (kboepd) 4,820A 4,396A 4,282A 4,759Dividend per share 1.74 1.85 1.88 1.97 production growth (y/y) 10.5%A 10.0%A (3.8%)A (4.2%)

EBITDA 67,978 88,305 92,508 107,667Production (kboepd) 4,447 4,564 4,538 4,543

WTI crude price ($/bbl) 79.50 95.06 107.38 118.00 WTI crude price ($/bbl) 94.24A 102.57A 89.59A 93.82

Henry Hub natural gas price ($/mcf) 4.40 4.03 4.10 4.75 Henry Hub natural gas price ($/mcf) 4.20A 4.38A 4.06A 3.49

Balance Sheet and Cash Flow Data FY10A FY11E FY12E FY13E Ratio Analysis FY10A FY11E FY12E FY13ECash and cash equivalents 8,455 8,455 20,894 48,087 Valuation

Other current assets 50,529 50,529 50,529 50,529 P/E (adjusted) 13.7 10.2 9.5 7.8

Total current assets 58,984 58,984 71,423 98,616 P/CF 8.7 7.1 6.6 5.8Net PP&E 199,548 214,292 229,494 244,874 Enterprise value/EBITDA 5.4 4.1 3.9 3.4

Other assets 43,978 43,978 43,978 43,978 EV/DACF 7.6 6.3 5.7 4.6Total assets 302,510 317,254 344,894 387,468

Ratios

Total debt 15,014 17,358 14,537 13,836 Net debt/equity 31.6% 30.8% 17.8% 2.4%Total liabilities 155,671 158,918 157,044 157,491 Net debt/capital 23.0% 22.6% 13.8% 2.0%

Minority interests 5,840 5,840 5,840 5,840 Net coverage ratio 3.6 4.3 4.3 5.3Preferred stock - - - - ROE 20.7% 25.7% 22.7% 22.5%

Shareholders' equity 146,839 158,336 187,850 229,977 ROCE 17.9% 21.9% 21.4% 24.5%Net Income 30,460 40,694 42,718 51,776 Yield and cash returns

DD&A 14,760 16,801 17,344 17,167 CFPS 9.76 11.97 12.85 14.76

Deferred taxes (1,135) 902 947 1,148 CF yield 12.1% 16.2% 17.4% 20.0%Other (145) 0 0 68,943 FCF yield 4.3% 4.9% 5.5% 7.9%

Cash earnings 43,940 58,397 61,009 70,091 Dividend yield 2.1% 2.2% 2.2% 2.3%Change in working capital 3,845 0 0 0 Dividend payout ratio 28.0% 22.2% 20.9% 18.1%

Cash flow from operations 47,785 58,397 61,009 70,091 Buyback yield (3.1%) (5.0%) (1.0%) 0.0%

Capex (26,871) (31,545) (32,546) (32,547) Total cash returns (%) 5.7% 8.1% 3.6% 2.6%Dividends (8,498) (9,022) (8,929) (9,375)

Share buybacks (net) (12,050) (19,900) (4,000) 0

Change in debt (6,210) 2,344 (2,821) (701) Mkt Cap (current) ()Change in preferred stock - - - - Enterprise Value (current)

Other uses of cash 2,976 (275) (275) (9,650)Change in cash (2,868) 0 12,439 27,193

Free cash flow 23,890 26,577 28,188 37,269

Source: Company reports and J.P. Morgan estimates.Note: $ in millions (except per-share data).Fiscal year ends Dec

232



Gazprom: Summary of FinancialsProfit and Loss Statement Cash flow statement


Revenues 118,449 153,200 153,805 140,273 144,393 EBIT 36,503 43,301 41,452 28,418 25,554

% change Y/Y 25.3% 29.3% 0.4% -8.8% 2.9% Depreciation & amortisation 8,025 10,585 14,821 16,099 17,603Gross Margin (%) 48.8% 45.8% 46.5% 43.1% 41.3% Change in working capital/Other 11,425 2,010 4,440 10,280 6,048EBITDA 44,529 53,886 56,272 44,518 43,156 Taxes (7,873) (8,989) (9,435) (6,811) (6,233)

% change Y/Y 25.0% 21.0% 4.4% -20.9% -3.1% Cash flow from operations 48,081 46,907 51,278 47,987 42,971EBITDA Margin 37.6% 35.2% 36.6% 31.7% 29.9%

EBIT 36,503 43,301 41,452 28,418 25,554 Capex (34,333) (41,688) (33,989) (34,710) (32,889)% change Y/Y 27.5% 18.6% -4.3% -31.4% -10.1% Disposal/(Purchase)/Other (252) (4,910) (5,038) (5,384) (5,040)EBIT Margin 30.8% 28.3% 27.0% 20.3% 17.7% Net Interest (596) (473) (225) (103) (265)

Net Interest (596) (473) (225) (103) (265) Free cash flow 12,899 (164) 12,025 7,790 4,777Earnings before tax 39,128 46,669 47,211 32,881 29,953

% change Y/Y 18.5% 19.3% 1.2% -30.3% -8.9% Equity raised/repaid (15) 0 0 0 0

Tax (7,873) (8,989) (9,435) (6,811) (6,233) Debt Raised/repaid -4,063 6,463 -7,352 -15,196 -14,079as a % of EBT 21.6% 20.8% 22.8% 24.0% 24.4% Other (1,815) (762) (2,479) (1,903) (1,744)

Net Income (Reported) 30,284 36,552 36,549 25,263 23,013 Dividends paid (1,783) (2,101) (3,457) (3,762) (3,003)% change Y/Y 13.6% 20.7% -0.0% -30.9% -8.9% Beginning cash 8,224 14,515 18,139 16,988 4,099

Shares Outstanding 22,915.31 22,915.31 22,915.31 22,915.31 22,915.31 Ending cash 14,515 18,139 16,988 4,099 -9,830

EPS (reported) 1.32 1.60 1.59 1.10 1.00 DPS 0.09 0.15 0.16 0.13 0.11% change Y/Y 13.6% 20.7% (0.0%) (30.9%) (8.9%)

Balance sheet Ratio Analysis$ in millions, year end Dec FY10 FY11E FY12E FY13E FY14E $ in millions, year end Dec FY10 FY11E FY12E FY13E FY14E

Cash and cash equivalents 14,434 18,139 16,988 4,099 (9,830) EBITDA margin 37.6% 35.2% 36.6% 31.7% 29.9%

Accounts receivable 24,819 32,323 32,570 29,801 30,725 Operating margin 30.8% 28.3% 27.0% 20.3% 17.7%Inventories 10,667 14,761 14,711 13,258 13,672 Net profit margin 25.6% 23.9% 23.8% 18.0% 15.9%

Others 11,182 14,462 14,565 13,336 13,745 SG&A/Sales 11.3% 10.6% 9.9% 11.3% 11.4%Current assets 61,103 79,686 78,835 60,494 48,312

Sales per share growth 13.9% 12.7% 12.4% 13.9% 13.9%

LT investments 36,890 72,612 53,264 51,222 50,645 EPS growth 13.6% 20.7% (0.0%) (30.9%) (8.9%)Net fixed assets 179,665 200,518 208,502 227,879 242,366Total assets 302,453 356,835 382,120 389,465 398,139 ROE 14.8% 15.2% 13.2% 8.3% 7.1%

ROCE 14.6% 15.8% 15.4% 10.6% 9.5%Liabilities

ST loans 6,256 11,269 13,954 12,654 8,599 Production (mboe/day) 9,459 9,650 9,431 9,493 9,582Payables 26,860 35,584 34,767 35,014 37,375 Production oil (mbpd) 1,232 1,256 1,260 1,306 1,304Others 0 1,568 1,467 1,268 1,309 Production gas (mboe/day) 8,227 8,394 8,171 8,187 8,279

Total current liabilities 33,116 48,421 50,188 48,936 47,283 Refining throughput (mbpd) 758 830 839 781 781Long term debt 36,821 38,252 23,975 6,333 (7,298)Other liabilities 18,469 18,622 18,674 18,865 19,099 Interest coverage (x) 61.2 91.6 184.2 276.1 96.3

Total liabilities 88,405 105,296 92,837 74,134 59,083 Net debt to equity 13.4% 12.5% 7.2% 4.7% 3.3%Shareholders' equity 204,662 240,741 277,290 302,553 325,566 Net debt 28,643 31,382 20,941 14,887 11,131

BVPS 9 11 12 13 14 Net debt/EBITDA (ny) 0.5 0.6 0.5 0.3 0.2


233



Novatek: Summary of FinancialsProfit and Loss Statement Cash flow statement


Revenues 3,853 5,539 6,515 7,246 8,487 EBIT 1,654 2,515 2,730 2,874 3,613

% change Y/Y 36.0% 43.7% 17.6% 11.2% 17.1% Depreciation & amortisation 218 300 343 394 453Gross Margin (%) 55.0% 56.5% 52.9% 49.8% 52.1% Change in working capital/Other (139) 124 177 125 39EBITDA 1,872 2,814 3,073 3,268 4,066 Taxes (356) (484) (547) (577) (731)

% change Y/Y 51.9% 50.4% 9.2% 6.3% 24.4% Cash flow from operations 1,377 2,454 2,703 2,816 3,374EBITDA Margin 48.6% 50.8% 47.2% 45.1% 47.9%

EBIT 1,654 2,515 2,730 2,874 3,613 Capex (2,267) (1,851) (1,697) (1,159) (791)% change Y/Y 56.6% 52.0% 8.6% 5.3% 25.7% Disposal/(Purchase)/Other 39 (94) 0 0 0EBIT Margin 42.9% 45.4% 41.9% 39.7% 42.6% Net Interest 39 (94) 6 11 40

Net Interest 39 (94) 6 11 40 Free cash flow (811) 416 1,012 1,668 2,623Earnings before tax 1,682 2,305 2,678 2,827 3,596

% change Y/Y 64.3% 37.0% 16.2% 5.6% 27.2% Equity raised/repaid 0 0 0 0 0

Tax (356) (484) (547) (577) (731) Debt Raised/repaid 1,116 431 -985 0 0as a % of EBT 21.2% 21.0% 20.4% 20.4% 20.3% Other (10) 0 0 0 0

Net Income (Reported) 1,335 1,809 2,117 2,236 2,847 Dividends paid (323) (463) (573) (636) (742)% change Y/Y 62.6% 35.6% 17.0% 5.6% 27.3% Beginning cash 347 337 976 493 1,589

Shares Outstanding 303.63 303.63 303.63 303.63 303.63 Ending cash 337 976 493 1,589 3,534

EPS (reported) 4.40 5.96 6.97 7.36 9.38 DPS 0.13 0.17 0.20 0.22 0.27% change Y/Y 62.6% 35.6% 17.0% 5.6% 27.3%

Balance sheet Ratio Analysis$ in millions, year end Dec FY10 FY11E FY12E FY13E FY14E $ in millions, year end Dec FY10 FY11E FY12E FY13E FY14E

Cash and cash equivalents 335 976 493 1,589 3,534 EBITDA margin 48.6% 50.8% 47.2% 45.1% 47.9%

Accounts receivable 284 408 480 534 625 Operating margin 42.9% 45.4% 41.9% 39.7% 42.6%Inventories 61 88 103 115 135 Net profit margin 34.6% 32.7% 32.5% 30.9% 33.5%

Others 288 414 486 541 634 SG&A/Sales 6.4% 5.7% 5.8% 4.7% 4.2%Current assets 968 1,885 1,563 2,779 4,927


LT investments 2,293 2,200 2,200 2,200 2,200 EPS growth 62.6% 35.6% 17.0% 5.6% 27.3%Net fixed assets 6,077 6,738 8,089 8,852 9,188Total assets 9,339 10,823 11,851 13,831 16,315 ROE 27.7% 29.4% 27.5% 24.0% 24.9%

ROCE 17.0% 18.8% 20.7% 18.9% 20.4%Liabilities

ST loans 824 395 932 604 604 Production (mboe/day) 751 993 1,061 1,127 1,199Payables 933 1,250 1,565 1,807 2,015 Production oil (mbpd) 84 94 100 107 114Others 125 203 223 224 256 Production gas (mboe/day) 667 805 862 922 987

Total current liabilities 1,057 1,848 2,720 2,635 2,874 Refining throughput (mbpd) - 95 99 98 98Long term debt 1,542 2,402 879 1,207 1,207Other liabilities 422 422 422 422 422 Interest coverage (x) (42.0) 26.8 (458.2) (251.0) (89.7)

Total liabilities 3,020 4,672 4,021 4,264 4,503 Net debt to equity 36.9% 26.6% 15.7% 2.2% -14.2%Shareholders' equity 4,818 6,164 7,708 9,308 11,413 Net debt 2,030 1,821 1,318 222 -1,723

BVPS 18 23 28 33 40 Net debt/EBITDA (ny) 0.7 0.6 0.4 0.1 (0.4)


234



Inpex Corporation: Summary of FinancialsIncome Statement Cash flow statement

¥ in millions, year end Mar FY10 FY11 FY12E FY13E FY14E ¥ in millions, year end Mar FY10 FY11 FY12E FY13E FY14E

Revenues 840,427 943,080 1,141,900 1,027,300 1,029,600 EBIT 462 530 666 570 547

% change Y/Y (21.9%) 12.2% 21.1% (10.0%) 0.2% Depr. & amortization 92,766 163,429 160,816 142,179 146,253EBITDA 554,434 693,171 826,866 711,879 692,753 Change in working capital - - - - -

% change Y/Y -26.9% 25.0% 19.3% -13.9% -2.7% Taxes -325126 -368696 -498072 -423355 -410516

EBIT 462 530 666 570 547 Cash flow from operations 241,373 274,093 335,808 307,758 298,828

% change Y/Y NM 14.8% 25.7% NM NM

EBIT Margin 54.9% 56.2% 58.3% 55.5% 53.1% Capex -274,000 -285,000 -249,750 -232,750 -202,750

Net Interest 3,079 -561 -260 1,373 2,834 Disposal/(purchase) - - - - -

Earnings before tax 442,027 508,587 668,372 573,655 551,916 Net Interest 3,079 -561 -260 1,373 2,834

% change Y/Y -28.3% 15.1% 31.4% -14.2% -3.8% Other 22,188 -546,563 25,000 0 0

Tax -325,126 -368,696 -498,072 -423,355 -410,516 Free cash flow - - - - -

as % of EBT 73.6% 72.5% 74.5% 73.8% 74.4%

Net income (reported) 107 129 153 136 127 Equity raised/(repaid) - - - - -

% change Y/Y -26.1% 20.0% 19.1% -11.1% -6.5% Debt raised/(repaid) 99,081 33,195 0 0 0

Shares outstanding 2 4 4 4 4 Other -17,184 504,434 0 0 0

EPS (reported) 53,360 44,526 44,097 40,443 38,008 Dividends paid -12,960 -18,270 -21,923 -21,923 -21,923

% change Y/Y (25.7%) (16.6%) (1.0%) (8.3%) (6.0%) Beginning cash 162,845 216,395 182,025 271,161 324,247

Ending cash 221,343 178,284 271,161 324,247 398,402

DPS 5,500 5,000 6,000 6,000 6,000

Balance sheet Ratio Analysis

¥ in millions, year end Mar FY10 FY11 FY12E FY13E FY14E ¥ in millions, year end Mar FY10 FY11 FY12E FY13E FY14E

Cash and cash equivalents 216,395 182,025 271,161 324,247 398,402 EBITDA margin 66.0% 73.5% 72.4% 69.3% 67.3%Accounts receivable 131,525 152,423 184,557 166,035 166,407 Operating margin 54.9% 56.2% 58.3% 55.5% 53.1%

Inventories 12,322 12,137 13,534 12,893 13,796 Net margin 12.8% 13.7% 13.4% 13.3% 12.4%

Others 19,952 9,077 9,100 9,100 9,100

Current assets 492,855 492,932 615,621 649,545 724,975

Sales per share growth (21.9%) (27.6%) 21.1% (10.0%) 0.2%

LT investments 923,624 1,558,474 1,535,567 1,589,434 1,636,446 Sales growth (21.9%) 12.2% 21.1% (10.0%) 0.2%

Net fixed assets 358,094 379,863 357,413 328,415 301,914 Net profit growth -26.1% 20.0% 19.1% -11.1% -6.5%

Total Assets 2,013,778 2,680,379 2,841,041 2,963,785 3,091,207 EPS growth (25.7%) (16.6%) (1.0%) (8.3%) (6.0%)

Liabilities Interest coverage (x) - 1,235.38 3,180.54 - -

Short-term loans 4,872 4,441 4,441 4,441 4,441

Payables 97,812 106,750 119,034 113,401 121,345 Net debt to equity -6.4% -2.3% -6.3% -8.3% -11.1%

Others 125,221 143,537 143,537 143,537 143,537 Sales/assets 0.44 0.40 0.41 0.35 0.34

Total current liabilities 227,905 254,728 267,012 261,379 269,323 Assets/equity 1.41 1.50 1.67 1.31 1.31

Long-term debt 235,511 268,706 268,706 268,706 268,706 ROE 8.0% 7.6% 7.4% 6.2% 5.5%

Other liabilities 59,759 59,562 59,562 59,562 59,562 ROCE 30.0% 27.1% 28.3% 23.0% 21.2%

Total Liabilities 523,175 582,996 595,280 589,647 597,591

Shareholders' equity 1,379,975 2,012,281 2,143,658 2,258,036 2,363,513

BVPS 585,129.39 550,405.09 586,371.92 617,658.51 646,510.60


235



CNOOC: Summary of FinancialsIncome Statement Cash flow statement

Rmb in millions, year end Dec FY09 FY10 FY11E FY12E FY13E Rmb in millions, year end Dec FY09 FY10 FY11E FY12E FY13E

Revenues 105,195 183,053 231,773 196,329 188,782 EBIT 40,083 71,405 85,105 66,693 61,696

% change Y/Y (17%) 74% 27% (15%) (4%) Depr. & amortization 15,943 27,687 27,098 28,142 28,722EBITDA 56,026 99,092 112,203 94,834 90,419 Change in working capital 1,706 -33 10,000 -1,718 367

% change Y/Y (11%) 77% 13% (15%) (5%) Taxes -8761 -18240 -21764 -17147 -15926

EBIT 40,083 71,405 85,105 66,693 61,696 Cash flow from operations 49,480 81,109 100,729 76,194 75,102

% change Y/Y (26%) 78% 19% (22%) (7%)

EBIT Margin 38% 39% 37% 34% 33% Capex -42,417 -31,947 -49,748 -47,361 -50,584

Net Interest 104 -518 -518 -583 -565 Disposal/(purchase) - - - - -

Earnings before tax 40,580 72,650 86,685 68,296 63,433 Net Interest 104 -518 -518 -583 -565

% change Y/Y (30%) 79% 19% (21%) (7%) Other - - - - -

Tax -11,336 -18,240 -21,764 -17,147 -15,926 Free cash flow 7,063 49,162 50,981 28,834 24,518

as % of EBT 27.9% 25.1% 25.1% 25.1% 25.1%

Net income (reported) 29,244 54,410 64,921 51,149 47,507 Equity raised/(repaid) 0 0 0 0 0

% change Y/Y (34%) 86% 19% (21%) (7%) Debt raised/(repaid) 4,812 13,575 -4,304 -4,304 -4,304

Shares outstanding 44,669 44,669 44,669 44,669 44,669 Other - - - - -

EPS (reported) 0.65 1.22 1.45 1.15 1.06 Dividends paid -15,693 -14,390 -21,737 -23,214 -22,107

% change Y/Y (34%) 86% 19% (21%) (7%) Beginning cash 19,762 22,615 39,571 34,815 36,131

Ending cash 22,676 41,024 34,815 36,131 34,238

DPS 0.35 0.39 0.58 0.46 0.53



Cash and cash equivalents 52,067 70,487 65,730 67,046 65,154 EBITDA margin 53% 54% 48% 48% 48%Accounts receivable 13,116 20,235 25,620 21,702 20,868 Operating margin 38% 39% 37% 34% 33%

Inventories 3,146 4,076 5,161 4,372 4,204 Net margin 28% 30% 28% 26% 25%

Others 2,542 5,855 5,855 5,855 5,855

Current assets 70,871 100,653 102,367 98,975 96,081

Sales per share growth (17%) 74% 27% (15%) (4%)

LT investments 4,847 10,485 10,780 11,164 11,663 Sales growth (17%) 74% 27% (15%) (4%)

Net fixed assets 166,550 215,353 245,075 264,294 286,156 Net profit growth (34%) 86% 19% (21%) (7%)

Total Assets 242,268 326,490 358,222 374,433 393,900 EPS growth (34%) 86% 19% (21%) (7%)

Liabilities Interest coverage (x) - 191.23 216.53 162.63 159.99

Short-term loans 122 21,631 21,631 21,631 21,631

Payables 15,608 18,550 26,873 23,627 23,306 Net debt to equity (19%) (17%) (14%) (13%) (12%)



Long-term debt 18,570 11,716 11,716 11,716 11,716 ROE 18% 28% 29% 21% 18%

Other liabilities 18,721 29,149 29,149 29,149 29,149 ROCE 22% 32% 33% 24% 21%


Shareholders' equity 173,936 215,766 231,027 253,663 273,765

BVPS 3.89 4.83 5.17 5.68 6.13


236



Sinopec Corp - H: Summary of FinancialsIncome Statement Cash flow statement


Revenues 1,345,052 1,913,182 2,617,829 2,384,441 2,383,843 EBIT 84,431 105,004 113,936 119,089 117,781

% change Y/Y (10%) 42% 37% (9%) (0%) Depr. & amortization 50,487 59,223 61,929 64,987 67,069EBITDA 134,918 164,227 175,864 184,076 184,849 Change in working capital 15,571 -1,109 -19,072 -574 -533

% change Y/Y 86% 22% 7% 5% 0% Taxes -4027 -25689 -25627 -28017 -28161


% change Y/Y 221% 24% 9% 5% (1%)


Net Interest -7,105 -7,312 -10,466 -10,614 -8,782 Disposal/(purchase) 594 16,126 0 0 0

Earnings before tax 80,568 103,693 103,443 113,091 113,673 Net Interest -7,105 -7,312 -10,466 -10,614 -8,782

% change Y/Y 264% 29% (0%) 9% 1% Other - - - - -

Tax -16,084 -25,689 -25,627 -28,017 -28,161 Free cash flow 39,200 72,696 7,048 31,220 84,864

as % of EBT 20.0% 24.8% 24.8% 24.8% 24.8%

Net income (reported) 61,760 71,800 78,130 80,016 80,360 Equity raised/(repaid) - - - - -

% change Y/Y 117% 16% 9% 2% 0% Debt raised/(repaid) -4,116 11,687 5,000 5,000 5,000

Shares outstanding 86,702 86,702 86,702 86,702 86,702 Other - - - - -


% change Y/Y 117% 16% 9% 2% 0% Beginning cash 7,008 8,728 17,008 9,243 25,171

Ending cash 8,750 17,004 9,243 25,171 94,657

DPS 0.18 0.21 0.23 0.23 0.24





Others 23,091 42,450 58,085 52,906 52,893

Current assets 201,280 260,229 341,628 328,024 397,434

Sales per share growth (10%) 42% 37% (9%) (0%)

LT investments - - - - - Sales growth (10%) 42% 37% (9%) (0%)

Net fixed assets 584,968 630,299 682,021 730,686 726,125 Net profit growth 117% 16% 9% 2% 0%

Total Assets 877,842 995,154 1,128,248 1,167,924 1,237,448 EPS growth 117% 16% 9% 2% 0%

Liabilities Interest coverage (x) 18.99 22.46 16.80 17.34 21.05

Short-term loans 58,898 17,019 17,019 17,019 17,019

Payables 97,749 132,528 165,007 151,056 150,774 Net debt to equity 42% 32% 31% 26% 12%






Shareholders' equity 375,661 419,047 477,364 537,088 597,070

BVPS 4.33 4.83 5.51 6.19 6.89


237



PetroChina: Summary of FinancialsIncome Statement Cash flow statement


Revenues 1,019,275 1,465,415 1,418,941 1,336,341 1,342,447 EBIT 143,444 187,777 189,234 186,780 181,129

% change Y/Y (5%) 44% (3%) (6%) 0% Depr. & amortization 92,259 113,209 129,430 147,598 160,737EBITDA 235,703 300,986 318,664 334,378 341,866 Change in working capital 37,833 31,741 -1,031 -1,833 136

% change Y/Y (7%) 28% 6% 5% 2% Taxes -16412 -26169 -39888 -39255 -38800


% change Y/Y (10%) 31% 1% (1%) (3%)


Net Interest -3,813 -4,338 -8,621 -9,703 -6,772 Disposal/(purchase) - - - - -

Earnings before tax 140,032 189,305 189,941 186,930 184,761 Net Interest -3,813 -4,338 -8,621 -9,703 -6,772

% change Y/Y (14%) 35% 0% (2%) (1%) Other - - - - -

Tax -33,473 -38,513 -39,888 -39,255 -38,800 Free cash flow -19,359 40,777 -41,548 5,140 93,521

as % of EBT 23.9% 20.3% 21.0% 21.0% 21.0%

Net income (reported) 103,387 139,992 135,037 136,387 135,422 Equity raised/(repaid) 0 0 0 0 0

% change Y/Y (10%) 35% (4%) 1% (1%) Debt raised/(repaid) 77,401 52,656 85,000 40,000 0

Shares outstanding 183,021 183,021 183,021 183,021 183,021 Other 49,037 -35,320 0 0 -20,000


% change Y/Y (10%) 35% (4%) 1% (1%) Beginning cash 33,150 86,925 45,709 28,394 12,160

Ending cash 86,925 45,709 28,394 12,160 24,741

DPS 0.27 0.29 0.33 0.34 0.33





Others 59,624 54,835 53,192 50,270 50,486

Current assets 294,383 286,392 261,540 231,909 245,480

Sales per share growth (5%) 44% (3%) (6%) 0%

LT investments - - - - - Sales growth (5%) 44% (3%) (6%) 0%

Net fixed assets 1,075,467 1,238,599 1,429,169 1,569,871 1,622,448 Net profit growth (10%) 35% (4%) 1% (1%)

Total Assets 1,450,288 1,656,487 1,822,205 1,933,276 1,999,423 EPS growth (10%) 35% (4%) 1% (1%)

Liabilities Interest coverage (x) 61.82 69.38 36.96 34.46 50.48

Short-term loans 148,851 102,268 102,268 102,268 82,268

Payables 204,739 270,191 261,622 246,392 247,518 Net debt to equity 17% 20% 29% 32% 27%






Shareholders' equity 847,223 938,926 1,013,196 1,088,209 1,162,691

BVPS 4.63 5.13 5.54 5.95 6.35


238



Petronet LNG Ltd.: Summary of FinancialsIncome Statement Cash flow statement

Rs in millions, year end Mar FY10 FY11 FY12E FY13E FY14E Rs in millions, year end Mar FY10 FY11 FY12E FY13E FY14E

Revenues 106,029 131,057 209,410 273,089 336,878 EBIT 6,856 10,316 15,379 17,519 22,313

% change Y/Y 25.8% 23.6% 59.8% 30.4% 23.4% Depr. & amortization 1,609 1,847 1,848 3,819 3,819Gross Margin 8.9% 10.0% 9.1% 8.6% 8.4% Change in working capital 2,791 -395 3,749 -3,292 -2,470EBITDA 8,465 12,163 17,227 21,338 26,131 Taxes -1410 -2650 -3907 -4402 -5394

% change Y/Y -6.1% 43.7% 41.6% 23.9% 22.5% Others 2,391 2,858 3,483 3,713 3,938EBITDA Margin 8.0% 9.3% 8.2% 7.8% 7.8% Cash flow from operations 8,985 7,866 19,126 11,846 15,218

EBIT 6,856 10,316 15,379 17,519 22,313% change Y/Y NM 50.5% 49.1% 13.9% 27.4% Capex -10,461 -8,887 -17,041 -11,500 -6,500

EBIT Margin 6.5% 7.9% 7.3% 6.4% 6.6% Disposal/(purchase) - - - - -

Net Interest -1,612 -1,649 -2,160 -2,605 -3,938 Free cash flow -1,476 -1,022 2,085 346 8,718Earnings before tax 5,995 9,064 13,953 15,721 19,263

% change Y/Y -22.6% 51.2% 53.9% 12.7% 22.5% Equity raised/(repaid) -0 -0 - - -

Tax -1,950 -2,868 -4,688 -5,282 -6,472 Debt raised/(repaid) 2,181 7,163 5,339 7,500 -2,500as % of EBT 32.5% 31.6% 33.6% 33.6% 33.6% Other -2,391 -2,858 -3,483 -3,713 -3,938

Net income (reported) 4,045 6,196 9,264 10,439 12,791 Dividends paid -1,606 -1,939 - - -% change Y/Y -22.0% 53.2% 49.5% 12.7% 22.5% Beginning cash 6,578 3,405 1,540 1,255 4,758

Shares outstanding 750 750 750 750 750 Ending cash 3,405 1,540 1,255 4,758 5,849

EPS (reported) 5.39 8.26 12.35 13.92 17.05 DPS 1.75 2.00 3.50 3.50 4.25% change Y/Y (22.0%) 53.2% 49.5% 12.7% 22.5%

Balance sheet Ratio AnalysisRs in millions, year end Mar FY10 FY11 FY12E FY13E FY14E Rs in millions, year end Mar FY10 FY11 FY12E FY13E FY14E

Cash and cash equivalents 3,405 1,540 1,255 4,758 5,849 EBITDA margin 8.0% 9.3% 8.2% 7.8% 7.8%

Accounts receivable 5,035 8,472 10,327 13,467 16,613 Operating margin 6.5% 7.9% 7.3% 6.4% 6.6%Inventories 2,223 2,480 5,164 9,352 13,844 Net margin 3.8% 4.7% 4.4% 3.8% 3.8%

Others 1,554 1,383 1,450 1,520 1,593Current assets 12,216 13,875 18,195 29,098 37,900


LT investments - - - - - Sales growth 25.8% 23.6% 59.8% 30.4% 23.4%Net fixed assets 42,012 49,053 64,246 71,928 74,609 Net profit growth -22.0% 53.2% 49.5% 12.7% 22.5%Total Assets 50,609 62,443 74,766 90,524 98,177 EPS growth (22.0%) 53.2% 49.5% 12.7% 22.5%

Liabilities Interest coverage (x) 5.25 7.38 7.98 8.19 6.64Short-term loans - - - - - Net debt to total capital 36.0% 35.7% 36.2% 33.6% 23.8%

Payables - - - - - Net debt to equity 72.5% 70.8% 71.0% 64.8% 42.8%Others - - - - - Sales/assets 2.21 2.32 3.05 3.30 3.57Total current liabilities 9,006 12,134 20,489 24,596 29,837 Assets/equity 2.49 2.72 2.27 2.24 1.99

Long-term debt 24,998 32,161 37,500 45,000 42,500 ROE 19.2% 25.2% 31.0% 28.4% 28.5%Other liabilities 3,262 3,480 4,261 5,142 6,220 ROCE 15.2% 19.4% 23.8% 22.5% 25.2%Total Liabilities 28,260 35,641 41,761 50,142 48,720

Shareholders' equity 22,349 26,802 33,005 40,383 49,456BVPS 29.80 35.74 44.01 53.84 65.94


239



Origin Energy: Summary of FinancialsA$ in millions, year end Jun

Income Statement FY10 FY11 FY12E FY13E FY14E Balance Sheet FY10 FY11 FY12E FY13E FY14ETotal Revenue 8,865.6 10,955.0 14,788.8 16,958.5 17,506.1 Cash & Bills 823.0 728.0 728.0 728.0 728.0Revenue Growth Y/Y 6.6% 23.6% 35.0% 14.7% 3.2% Debtors 1,381.0 2,159.0 2,180.1 2,195.5 2,202.9

EBITDA 1,304.0 1,782.0 2,399.5 2,635.5 2,736.8 Investments - - - - -Depreciation & Amortisation -408.6 -588.0 -632.3 -675.1 -677.0 Inventories 177.0 263.0 273.1 284.4 289.4

EBIT 895.4 1,194.0 1,767.2 1,960.4 2,059.8 Other Current Assets 657.0 711.0 711.0 711.0 711.0Net Interest -12.8 -143.0 -345.2 -359.5 -382.8 Current Assets 3,038.0 3,861.0 3,892.2 3,918.9 3,931.3Pre-Tax Profit 882.6 1,051.0 1,421.9 1,600.9 1,677.0 Receivables 0.0 0.0 0.0 0.0 0.0

Tax -232.0 -316.0 -455.0 -504.3 -528.3 Investments 5,395.0 5,470.0 5,470.0 5,470.0 5,470.0Minority Interests -66.0 -62.0 -80.4 -87.6 -103.0 Inventories - - - - -Preference Dividends 0.0 0.0 0.0 0.0 0.0 PP&E 9,168.0 10,313.0 11,365.6 12,288.1 14,046.1

NPAT before Abnormals 584.6 673.0 886.5 1,009.0 1,045.7 Goodwill 2,599.0 5,138.0 5,433.0 5,433.0 5,433.0NPAT after Abnormals 612.0 186.0 886.5 1,009.0 1,045.7 Other Intangibles 197.0 295.0 0.0 0.0 0.0

Normalised NPAT 584.6 673.0 886.5 1,009.0 1,045.7 Pension Fund Assets - - - - -# Shares Outstanding 878.5 1,061.8 1,102.3 1,136.2 1,136.2 Future Income Tax Benefits 88.0 0.0 0.0 0.0 0.0

Other Non Current Assets 1,349.0 1,563.0 1,539.0 1,539.0 1,539.0

Cash Flow Statement FY10 FY11 FY12E FY13E FY14E Non Current Assets 18,796.0 22,779.0 23,807.6 24,730.1 26,488.1EBIT 895.4 1,194.0 1,767.2 1,960.4 2,059.8 Total Assets 21,834.0 26,640.0 27,699.9 28,649.0 30,419.4Depreciation & Amortisation 408.6 588.0 632.3 675.1 677.0 Creditors 1,205.0 2,020.0 1,983.8 1,989.7 1,989.3

Net Interest (Paid)/Recd -165.0 -308.0 -345.2 -359.5 -382.8 Current Borrowings 113.0 595.0 595.0 595.0 595.0Tax (Paid) -791.6 -274.0 -385.5 -479.7 -516.3 Current Lease Liabilities - - - - -

Inc/(Dec) in Provisions - - - - - Current Provisions 161.0 275.0 275.0 275.0 275.0(Inc)/Dec in Working Capital 0.0 - - - - Other Current Liabilities 405.0 2,219.0 2,219.0 2,219.0 2,219.0Other Operating Items 561.6 201.0 208.3 314.1 358.0 Current Liabilities 1,884.0 5,109.0 5,072.8 5,078.7 5,078.3

Operating Cash Flow 909.0 1,401.0 1,877.0 2,110.5 2,195.8 Non Current Creditors 65.0 412.0 412.0 412.0 412.0Gross Capex -3,440.0 -4,758.0 -2,805.7 -2,468.8 -2,435.0 Non Current Borrowings 3,373.0 4,193.0 4,920.1 5,332.7 6,615.2Sale of Fixed Assets 0.0 - - - - Non Current Lease Liabilities - - - - -

Net Capex -3,440.0 -4,758.0 -2,805.7 -2,468.8 -2,435.0 Non Current Provisions 360.0 533.0 533.0 533.0 533.0Net Acquisitions -1.0 - - - - Pension Fund Liabilities 0.0 - - - -

Other Investing Items 7.0 0.0 0.0 0.0 0.0 Deferred Income Tax Liability 901.0 901.0 901.0 901.0 901.0Investing Cash Flow -3,441.0 -4,758.0 -2,805.7 -2,468.8 -2,435.0 Other Non Current Liabilities 3,813.0 1,976.0 855.3 -15.8 -15.8Equity Issued 13.0 2,385.0 546.8 457.7 0.0 Non Current Liabilities 8,512.0 8,015.0 7,621.4 7,162.9 8,445.4

Dividends Paid -409.0 -408.0 0.0 -152.6 -660.5 Total Liabilities 10,396.0 13,124.0 12,694.2 12,241.6 13,523.7Inc/(Dec) in Borrowings -143.0 1,597.0 0.0 0.0 0.0 Total Ordinary Equity 10,249.0 12,232.0 13,665.3 14,979.4 15,364.7Other Financing Items 0.0 -308.0 -345.2 -359.5 -382.8 Outside Equity Interests 1,189.0 1,284.0 1,364.4 1,452.0 1,555.0

Financing Cash Flow -539.0 3,266.0 201.6 -54.3 -1,043.3 Other Equity - - - - -Net Cash Flow -3,071.0 -91.0 -727.1 -412.6 -1,282.5 Total Equity 11,438.0 13,516.0 15,029.7 16,431.5 16,919.7

Net Debt / (Net Debt + Equity) 18.9% 15.2% 21.3% 22.6% 23.5%

Per Share Data A$ FY10 FY11 FY12E FY13E FY14E Valuation Metrics FY10 FY11 FY12E FY13E FY14E

Reported EPS 0.698 0.196 0.804 0.888 0.920 Reported P/E 19.3 68.9 16.8 15.2 14.7Normalised EPS 0.666 0.733 0.804 0.888 0.920 Normalised P/E 20.2 18.4 16.8 15.2 14.7DPS 0.50 0.50 0.52 0.55 0.58 Net Yield 3.7% 3.7% 3.8% 4.1% 4.3%

NTA 9.74 7.55 8.67 9.66 10.09 Price to Book 1.0 1.0 1.0 0.9 0.9EV/EBITDA 13.3 9.6 7.8 7.4 7.3


240



Oil Search LimitedNeutral Y/E Dec M'cap: A$7439m Price: A$6.57

Profit & Loss Statement Production

(US$ millions) CY09A CY10A CY11E CY12E CY13E (million BOE) CY09A CY10A CY11E CY12E CY13E

Total revenue 512 584 689 701 717 Kutubu 3.9 3.6 2.9 2.9 2.8

Production costs (86) (87) (92) (94) (94) Moran 2.5 2.6 2.2 2.4 2.3

Royalties (8) (10) (12) (13) (14) SE Gobe 0.4 0.3 0.2 0.2 0.1

Corporate & other costs (8) (11) (28) (23) (23) Gobe Main 0.1 0.1 0.0 0.0 0.0

Total Costs (103) (109) (132) (130) (131) SE Mananda 0.2 0.1 0.0 - -

EBITDAX 409 475 557 571 586 Hides GTE 1.1 1.0 1.1 1.1 1.1

Exploration write-off (76) (131) (78) (111) (95) PNG LNG 6.6mtpa - - - - -

EBITDA 334 344 479 460 490 Nabrajah entitlement - - - - -

Depreciation & amortisation (105) (50) (49) (49) (47) Egypt Area A - - - - -

EBIT 228 294 430 411 443 East Ras Qatara - - - - -

Net Interest Expense (3) (1) 2 5 (2) Total 8.1 7.7 6.5 6.6 6.3

Pre-Tax Profit 225 293 432 416 441 Liquids production 7.2 6.8 5.6 5.6 5.4

Tax (113) (149) (230) (232) (241) Gas production 0.9 0.9 1.0 1.0 1.0

Significant items (after tax) 21 41 - - - % liquids 89% 88% 85% 85% 85%

Reported NPAT 134 186 202 184 200

NPAT (pre-sig items) 112 144 202 184 200 Key Commodity Price Assumptions

CY09A CY10A CY11E CY12E CY13E

EBITDAX margin (%) 79.9% 81.4% 80.8% 81.4% 81.7% Aust dollar (US$) 0.792 0.921 1.033 1.003 1.040

Effective tax rate (%) 50.0% 50.8% 53.2% 55.7% 54.7% WTI Oil price US$/bbl 61.8 79.5 95.1 107.3 118.0

EPS reported (Acps) 14.5 15.3 14.8 13.8 14.3 WTI Oil price A$/bbl 78.0 86.4 92.0 107.0 113.5

EPS pre-sig items (Acps) 12.2 11.9 14.8 13.8 14.3 Tapis Oil Price US$/bbl 65.2 83.8 118.5 118.1 126.1

DPS (UScps) 4 4 4 4 5 Tapis Oil Price A$/bbl 81.6 91.0 114.7 117.8 121.3

Payout ratio (%) 42% 36% 26% 29% 34%

Franking (%) 0% 0% 0% 0% 0% Financial Ratios


Cashflow Statement PE reported (x) 45.4 42.8 44.5 47.8 46.0

(US$ millions) CY09A CY10A CY11E CY12E CY13E PE normalised (x) 54.0 55.1 44.5 47.8 46.0

Net op cash flow 284 398 368 322 474 EV/EBITDAX (x) 17.0 17.0 16.3 15.4 15.6

Capex & Exploration (470) (1,358) (1,559) (1,790) (1,231) P/GCFPS (x) 21.2 19.8 24.3 27.2 19.3

Asset Sales 88 - - - - Dividend yield (%) 0.8% 0.7% 0.6% 0.6% 0.7%

Other investing cash flows - (0) (0) - - ROE (%) 4.3% 5.2% 6.7% 5.8% 5.9%

Dividends (50) (34) (0) - - ROIC (%) 8.6% 5.8% 5.2% 3.3% 3.1%

Debt Repayment - - - - - Gearing (ND/(ND+E), %) -50.5% -33.5% -98.7% -52.6% -13.5%

Debt Proceeds - 931 848 959 870 Interest cover 68.6 355.8 (180.8) (86.8) 226.3

Equity funding 900 38 6 - -

Other financing cash flows 1 (0) (0) - - NPV Valuation at 10% WACC

Net cashflow 753 (24) (337) (509) 113 at Jun-11, LT US$90/bb l & 0.8US$/A$ A$m A$ %

GCFPS (cps) 30.9 33.1 27.0 24.2 34.0 Kutubu 779 0.59 9%

Free cashflow (185.6) (959.7) (1,190.6) (1,467.8) (757.0) SE Gobe 19 0.01 0%

FCF/share (cps) (16.0) (73.5) (90.2) (110.4) (56.5) Gobe Main 3 0.00 0%

Moran 480 0.36 5%

Balance Sheet Hides GTE 66 0.05 1%

(US$ millions) CY09A CY10A CY11E CY12E CY13E SE Mananda 0 0.00 0%

Current assets 1,461 1,416 1,218 731 713 LNG 6.6mtpa, 10tcf 7,663 5.80 85%

PP&E 714 2,383 3,741 5,307 6,340 Corporate (18) (0.01)

Exploration & Evaluation 808 282 374 437 492 Exploration 253 0.19

Other non current assets 94 207 202 202 202 PNG LNG Train 3 (risked @50%) 1,146 0.87

Total assets 3,077 4,289 5,534 6,678 7,748 Mananda-5 development (risked @ 50%) 130 0.10

Total liabilities 484 1,490 2,525 3,484 4,354 Net (Debt)/Cash (89) (0.07)

Shareholder funds 2,593 2,798 3,009 3,193 3,393 Group NPV 10,432 7.90

Total debt - 930 1,778 2,737 3,607 Valuation prem/(disc) to share price 20.2%

Cash 1,288 1,264 926 418 531

Net debt (1,288) (334) 851 2,319 3,076

Operational working capital (36) (72) (147) (125) (256)

Ave diluted shares (m) 1,159 1,307 1,320 1,330 1,339

Source: J.P. Morgan Estimates and Company data

241



Santos LimitedOverweight Y/E Dec Shares: 932.5m M'cap: A$11889m Price: A$12.75

Profit & Loss Statement Production Volumes

(A$ millions) CY09A CY10A CY11E CY12E CY13E (million BOE) CY09A CY10A CY11E CY12E CY13E

Sales revenue 2,181

2,228

2,527

3,005

3,119

Cooper 19.5

16.0

16.5

15.6

16.1 Other revenue 68

109

83

65

66

Surat/Denison (incl GLNG) 5.6

6.0

4.4

5.4

5.8

Total revenue 2,249

2,337

2,611

3,070

3,185

Amadeus 2.0

0.4

0.3

0.2

0.2 Production costs (530)

(540)

(556)

(557)

(540)

Otway 3.5

3.3

3.5

3.6

3.4

Gas purchase costs (117)

(162)

(250)

(330)

(196)

John Brookes/East Spar 7.9

8.6

8.3

8.9

8.9 Pipeline tariffs (91)

(95)

(98)

(77)

(83)

Jabiru/Challis and Legendre 0.4

0.3

-

-

-

Royalties, excise (61)

(51)

(52)

(54)

(54)

Mutineer/Exeter 1.0

0.6

0.7

0.9

0.2 Movt in stock (10)

(22)

42

-

-

Thevenard 0.3

0.3

0.2

0.2

0.2

SG&A operating expense (87)

(94)

(100)

(101)

(104)

Barrow 0.6

0.6

0.5

0.5

0.5 Other -

-

-

-

-

Stag 1.6

1.4

1.7

1.5

1.3

Total Operating Costs (897)

(964)

(1,014)

(1,119)

(976)

Bayu-Undan (DLNG) 5.0

4.5

4.6

4.3

4.7 EBITDAX 1,352

1,373

1,597

1,951

2,209

Indonesia (Oyong/Wortel/Maleo) 5.8

7.2

6.6

5.2

5.3

Exploration write-off (202)

(129)

(139)

(129)

(99)

SE Gobe (PNG) 0.1

0.1

0.1

0.1

0.1 EBITDA 1,150

1,244

1,458

1,821

2,109

Vietnam -

-

0.4

2.1

1.7

Depreciation & amortisation (619)

(600)

(598)

(628)

(639)

Bangladesh 1.0

0.7

0.6

0.2

- EBIT 531

644

859

1,193

1,470

Reindeer -

-

0.0

3.1

6.8

Net Interest Expense (13)

7

34

-

-

Greater East Spar -

-

0.2

0.8

1.7 Pre-Tax Profit 518

651

893

1,193

1,470

Kipper -

-

-

-

3.4

Corporate Tax (185)

(224)

(282)

(391)

(466)

PNG LNG -

-

-

-

- PRRT post tax (78)

(51)

(108)

(184)

(184)

Total 54.2

49.9

48.5

52.5

60.0

Significant items (after tax) 177

124

509

-

- Reported NPAT 432

500

1,012

618

820

Key Commodity Price Assumptions

NPAT (pre-sig items) 255

376

504

618

820

CY09A CY10A CY11E CY12E CY13ENPAT (pre-sig, post prefs) 246

376

504

618

820

Aust dollar (US$) 0.792

0.921

1.033

1.003

1.040

WTI Oil (US$/bbl) 61.8

79.5

95.1

107.3

118.0 EBITDAX margin (%) 60.1% 58.7% 61.2% 63.5% 69.3% Tapis Oil (US$/bbl) 65.2

83.8

118.5

118.1

126.1

Effective tax rate (%) 35.7% 34.4% 31.6% 32.8% 31.7% East Coast gas (A$/Gj) 3.80

4.48

4.42

4.63

4.72 EPS reported post prefs (cps) 54.7

59.1

114.6

69.0

90.9

West Coast gas (A$/Gj) 4.29

4.36

4.62

4.72

4.81

EPS pre-sig post prefs (cps) 31.8

44.4

57.0

69.0

90.9

LNG price (Bayu, US$/t fob) 234

277

459

460

491 DPS (cps) 42

37

30

30

30

LPG price (A$/kt) 676

820

893

909

935

Payout ratio (%) 132% 83% 53% 43% 33%Franking (%) 100% 100% 100% 100% 100% Financial Ratios

CY09A CY10A CY11E CY12E CY13ECashflow Statement PE reported (x) 23.2

21.5

11.1

18.4

14.0

(A$ millions) CY09A CY10A CY11E CY12E CY13E PE normalised (x) 40.1

28.7

22.4

18.5

14.0 Net op cash flow 1,155

1,267

1,421

1,241

1,472

EV/EBITDAX (x) 8.6

8.5

7.3

6.0

5.3

Acquisitions (380)

(4)

(43)

-

-

P/GCFPS (x) 8.5

8.5

7.9

9.2

7.8 Exploration & Evaluation (98)

(156)

(249)

(225)

(125)

Dividend yield (%) 3.3% 2.9% 2.4% 2.4% 2.4%

Capex (1,285)

(1,544)

(3,135)

(3,435)

(1,843)

ROE (%) 6.2% 6.6% 11.9% 6.9% 8.6%Asset Sales 12

-

424

-

-

ROIC (%) 6.6% 7.8% 11.5% 5.2% 6.2%

Other investing cash flows (660)

693

163

-

-

Gearing (ND/(ND+E), %) -6.5% -18.0% 4.1% 25.0% 27.7%Dividends (297)

(316)

(79)

(187)

(189)

Interest cover 40.9

(92.0)

n/c n/c n/c

Debt Proceeds/(Repayment) (1,868)

1,596

246

174

181 Equity funding 3,003

490

4

-

-

DCF Valuation at 9%

Other financing cash flows 1,116

60

-

-

-

cashflows from Jul-11, LT US$90/bbl & 0.8US$/A$ A$m A$Net cashflow 698

2,086

(1,248)

(2,432)

(505)

Cooper Basin (excl shale gas) 1,406

1.51

GCFPS (cps) 150.1

150.2

161.3

139.0

163.6

Surat/Denison excl GLNG 261

0.28 Free cashflow (227.9)

(433.0)

(1,962.6)

(2,419.2)

(496.7)

Amadeus 55

0.06

FCF/share (cps) (29.6)

(51.3)

(222.8)

(270.9)

(55.2)

Otway 248

0.27 John Brookes 670

0.72

Balance Sheet Jabiru/Challis/Legendre -

- (A$ millions) CY09A CY10A CY11E CY12E CY13E Mutineer/Exeter 90

0.10

Current assets 3,519

5,271

4,594

2,237

1,655

Thevenard 32

0.03 Exploration & Development 923

962

1,062

1,964

2,292

Barrow 278

0.30

Propert, Plant & Eqp. 6,517

6,914

8,760

10,761

11,663

Stag 278

0.30 Other non current assets 402

622

499

499

499

Bayu-Undan 1,351

1.45

Total assets 11,361

13,769

14,915

15,462

16,108

Kipper 347

0.37 Total liabilities 4,394

6,166

6,443

6,560

6,575

SE Gobe (PNG) 17

0.02

Shareholder funds 6,967

7,603

8,471

8,902

9,533

Oyong / Wortel (Indonesia) 150

0.16 Total debt 1,813

3,157

3,408

3,582

3,763

Maleo (Indonesia) 66

0.07

Cash 2,240

4,319

3,046

614

109

Reindeer 949

1.02 Net debt (427)

(1,162)

362

2,968

3,654

Greater East Spar 313

0.34

Operational working capital 481

166

577

711

798

Vietnam 607

0.65 Ave diluted shares (m) 769

843

881

881

881

PNG LNG 4,418

4.74

GLNG (risked) 3,217

3.45 Production by Product Other (80) (0.09) (million BOE) CY09A CY10A CY11E CY12E CY13E Corp & Unallocated (634) (0.68) Gas 38.0 36.3 34.4 37.6 45.2 Pre-FID projects incl PNGLNG T3 (risked) 1,052

1.13

Oil 8.4 6.5 6.9 8.3 7.0 Exploration 360

0.39 Condensate 3.0 2.7 2.7 2.5 3.3 Gunnedah CSG (80% of PEL238 etc) 708

0.76

LPG 2.0 1.8 1.8 1.5 1.7 Bonaparte LNG (40% interest) 163

0.17 LNG 2.8 2.6 2.7 2.6 2.9 Asset sale proceeds (net) 491

0.53

Total 54.2

49.9

48.5

52.5

60.0

Asset EV 16,814

18.03 Net Debt 390

0.42

Equity value 17,204

18.45 Source: J.P. Morgan Estimates and Company Data Equity valuation prem/(disc) to share price 44.7%

242



Woodside Petroleum LimitedUnderweight Y/E Dec Shares: 793.2m M'cap: A$25253m Price: A$32.37

Profit & Loss Statement Production Volumes

(US$ millions) CY09A CY10A CY11E CY12E CY13E (million BOE) CY09A CY10A CY11E CY12E CY13E

Sales revenue 3,722

4,193

4,824

5,451

6,645

NWSJV 50.9

51.8

46.8

45.4

48.2 Other revenue 37

53

60

62

63

Laminaria 3.6

2.3

1.6

1.2

0.4

Total revenue 3,759

4,246

4,885

5,513

6,708

Legendre -

-

-

-

- Production costs (477)

(459)

(467)

(547)

(718)

Ohanet 2.3

2.3

1.8

-

-

Royalties & Excise (275)

(419)

(488)

(441)

(509)

Mutineer/Exeter 0.2

0.1

0.2

0.1

- Other Costs (156)

(132)

(141)

(133)

(139)

US GoM 1.9

1.3

0.3

-

-

EBITDAX 2,850

3,236

3,789

4,392

5,341

Chinguetti entitlement -

-

-

-

- Exploration write-off (252)

(329)

(353)

(273)

(273)

Otway 4.6

0.9

-

-

-

EBITDA 2,601

2,907

3,436

4,119

5,069

Enfield 6.3

5.7

4.2

3.5

2.7 Depreciation & amortisation (856)

(749)

(570)

(748)

(963)

Neptune 1.3

0.9

0.8

0.7

0.6

EBIT 1,745

2,158

2,865

3,371

4,106

Stybarrow 5.7

2.1

4.1

3.4

2.7 Net Interest Expense (12)

18

(92)

(344)

(302)

Vincent 4.0

5.1

4.3

5.1

4.4

Pre-Tax Profit 1,733

2,176

2,773

3,027

3,804

Pluto-1 -

-

-

17.0

34.9 PRRT pre-tax (post08) (79)

(165)

(195)

(478)

(528)

Total 80.9

72.7

63.9

76.5

93.9

Corporate Tax (537)

(602)

(835)

(845)

(1,058) Significant items (after tax) 414

157

(6)

-

-

Key Commodity Price Assumptions

Minority interests -

(2)

-

-

-


Reported NPAT 1,531

1,564

1,737

1,703

2,218

Aust dollar (US$) 0.792

0.921

1.033

1.003

1.040 NPAT (pre-sig items) 1,117

1,407

1,744

1,703

2,218

Brent Oil price US$/bbl 62.1

80.2

111.8

112.5

121.3

1,395

1,539

1,879

1,713

2,031

Brent Oil price A$/bbl 78.4

87.2

108.2

112.2

116.6 EBITDA margin (%) 69.2% 68.5% 70.3% 74.7% 75.6% WTI Oil price US$/bbl 61.8

79.5

95.1

107.3

118.0

Effective tax rate (%) 31.0% 27.7% 30.1% 27.9% 27.8% WTI Oil price A$/bbl 78.0

86.4

92.0

107.0

113.5 EPS reported (Acps) 274.8

221.4

212.0

207.4

257.8

Domestic gas price (A$/Gj) 4.28

3.71

4.24

3.95

4.03

EPS pre-sig items (Acps) 198.3

199.2

212.7

207.4

257.8

LNG price (US$/t) 325

515

597

553

557 DPS (UScps) 94

105

112

104

134

Payout ratio (%) 55% 58% 51% 50% 50% Financial Ratios

Franking (%) 100% 100% 100% 100% 100% CY09A CY10A CY11E CY12E CY13E

PE reported (x) 11.8

14.6

15.3

15.6

12.6 Cashflow Statement PE normalised (x) 16.3

16.3

15.2

15.6

12.6

(US$ millions) CY09A CY10A CY11E CY12E CY13E EV/EBITDAX (x) 13.2

10.0

7.6

6.8

5.4 Net op cash flow 1,531

2,104

2,729

2,821

3,658

P/GCFPS (x) 11.8

10.9

9.7

9.4

7.6

Acquisitions -

-

-

-

-

Dividend yield (%) 3.7% 3.5% 3.3% 3.2% 4.0%

Capex & Exploration (4,755)

(3,649)

(4,118)

(1,806)

(2,431)

ROE (%) 13.4% 12.3% 13.1% 10.6% 11.8%

Asset Sales 1

-

-

-

-

ROIC (%) 9.6% 9.0% 9.4% 8.5% 9.4%

Other investing cash flows 14

742

43

-

-

Gearing (ND/(ND+E), %) 28.7% 25.3% 28.2% 22.0% 18.7%

Dividends (291)

(547)

(1)

-

(782)

Interest cover 135.6

(118.7)

26.6

7.8

7.9 Debt Repayment -

(42)

(291)

-

(721)

Debt Proceeds 2,810

-

1,236

200

-

NPV Valuation at 9%

Equity funding 1,353

1,078

-

-

-

cashflows from Jul-11, LT US$90/bbl & 0.8US$/A$ A$m A$ %

Other financing cash flows 291

119

8

-

-

NWSJV ex-oil 11,471

14.46

36%

Net cashflow 953

(195)

(394)

1,215

(276)

Cossack oil 589

0.74

2%

GCFPS (cps) 218

272

344

346

442

Laminaria 150

0.19

0%

Free cashflow (3,225)

(1,545)

(1,389)

1,015

1,227

Ohanet 10

0.01

0%

FCF/share (cps) (458.5)

(199.9)

(175.1)

124.3

148.3

Enfield 673

0.85

2%

Mut/Exeter 18

0.02

0%Balance Sheet Neptune 116

0.15

0%

(US$ millions) CY09A CY10A CY11E CY12E CY13E US GoM (10)

(0.01)

0%

Current assets 2,419

1,579

1,272

2,606

2,406

Stybarrow 438

0.55

1%

Oil & Gas Properties 13,857

16,517

19,512

19,479

20,926

Vincent 1,531

1.93

5%

Exploration & Evaluation 1,158

1,801

2,097

2,188

2,279

Pluto-1 16,650

20.99

53%

Other non current assets 319

299

309

309

309

Group & Unallocated (295)

(0.37)

Total assets 17,753

20,196

23,190

24,582

25,920

Other Fields / Projects (risked) 6,905

8.71

Total liabilities 8,485

8,510

9,703

9,391

9,293

Exploration 700

0.88

Shareholder funds 9,268

11,686

13,487

15,190

16,626

Asset sale proceeds -

-

Total debt 4,939

4,915

5,870

6,070

5,349

Other Value & Investments 617

0.78

Cash 1,207

963

579

1,793

1,517

Net Debt (4,209)

(5.31)

Net debt 3,732

3,952

5,291

4,277

3,832

Group NPV 35,353

44.57

Operational working capital (574)

(677)

(449)

372

74

Share price prem/(disc) to NPV -27%

Ave diluted shares (m) 703

773

793

816

827

Source: J.P. Morgan Estimates and Company data

243



244



245



Disclosures

Analyst Certification: The research analyst(s) denoted by an “AC” on the cover of this report certifies (or, where multiple research analysts are primarily responsible for this report, the research analyst denoted by an “AC” on the cover or within the document individually certifies, with respect to each security or issuer that the research analyst covers in this research) that: (1) all of the views expressed in this report accurately reflect his or her personal views about any and all of the subject securities or issuers; and (2) no part of any of the research analyst's compensation was, is, or will be directly or indirectly related to the specific recommendations or views expressed by the research analyst(s) in this report.

Important Disclosures

Lead or Co-manager: J.P. Morgan acted as lead or co-manager in a public offering of equity and/or debt securities for BP, Repsol YPF, Statoil, TOTAL, Chevron Corp, Gazprom, CNOOC, Sinopec Corp - H, Origin Energy within the past 12 months.

Client: J.P. Morgan currently has, or had within the past 12 months, the following company(ies) as clients: BG Group, BP, Royal Dutch Shell B, ENI, Repsol YPF, Statoil, TOTAL, Chevron Corp, Exxon Mobil Corp, Gazprom, Novatek, Oil Search, Santos Limited,Woodside Petroleum, Inpex Corporation, CNOOC, Sinopec Corp - H, PetroChina, Petronet LNG Ltd., Origin Energy.

Client/Investment Banking: J.P. Morgan currently has, or had within the past 12 months, the following company(ies) as investment banking clients: BG Group, BP, Royal Dutch Shell B, Repsol YPF, Statoil, TOTAL, Chevron Corp, Exxon Mobil Corp, Gazprom, Santos Limited, CNOOC, Sinopec Corp - H, Origin Energy.

Client/Non-Investment Banking, Securities-Related: J.P. Morgan currently has, or had within the past 12 months, the following company(ies) as clients, and the services provided were non-investment-banking, securities-related: BG Group, BP, Royal Dutch Shell B, ENI, Repsol YPF, Statoil, TOTAL, Chevron Corp, Exxon Mobil Corp, Gazprom, Novatek, Santos Limited, Woodside Petroleum, Inpex Corporation, CNOOC, Sinopec Corp - H, Origin Energy.

Client/Non-Securities-Related: J.P. Morgan currently has, or had within the past 12 months, the following company(ies) as clients, and the services provided were non-securities-related: BG Group, BP, Royal Dutch Shell B, ENI, Repsol YPF, Statoil, TOTAL, Chevron Corp, Gazprom, Novatek, Santos Limited, Woodside Petroleum, Sinopec Corp - H, Origin Energy.

Investment Banking (past 12 months): J.P. Morgan received in the past 12 months compensation for investment banking BG Group, BP, Royal Dutch Shell B, Repsol YPF, Statoil, TOTAL, Chevron Corp, Exxon Mobil Corp, Gazprom, Santos Limited, CNOOC, Sinopec Corp - H, Origin Energy.

Investment Banking (next 3 months): J.P. Morgan expects to receive, or intends to seek, compensation for investment banking services in the next three months from BG Group, BP, Royal Dutch Shell B, ENI, Repsol YPF, Statoil, TOTAL, Chevron Corp, Exxon Mobil Corp, Gazprom, Santos Limited, Inpex Corporation, CNOOC, Sinopec Corp - H, PetroChina, Origin Energy.

Non-Investment Banking Compensation: J.P. Morgan has received compensation in the past 12 months for products or services other than investment banking from BG Group, BP, Royal Dutch Shell B, ENI, Repsol YPF, Statoil, TOTAL, Chevron Corp, Exxon Mobil Corp, Gazprom, Novatek, Santos Limited, Woodside Petroleum, Inpex Corporation, CNOOC, Sinopec Corp - H, Origin Energy.

Broker: J.P. Morgan Securities Ltd. acts as Corporate Broker to BG Group.

Company-Specific Disclosures: Important disclosures, including price charts, are available for compendium reports and all J.P. Morgan–covered companies by visiting https://mm.jpmorgan.com/disclosures/company, calling 1-800-477-0406, or emailing [email protected] with your request.

Explanation of Equity Research Ratings and Analyst(s) Coverage Universe: J.P. Morgan uses the following rating system: Overweight [Over the next six to twelve months, we expect this stock will outperform the average total return of the stocks in the analyst's (or the analyst's team's) coverage universe.] Neutral [Over the next six to twelve months, we expect this stock will perform in line with the average total return of the stocks in the analyst's (or the analyst's team's) coverage universe.] Underweight [Over the next six to twelve months, we expect this stock will underperform the average total return of the stocks in the analyst's (or the analyst's team's) coverage universe.] In our Asia (ex-Australia) and UK small- and mid-cap equity research, each stock’s expected total return is compared to the expected total return of a benchmark country market index, not to those analysts’ coverage universe. If it does not appear in the Important Disclosures section of this report, the certifying analyst’s coverage universe can be found on J.P. Morgan’s research website, www.morganmarkets.com.

Coverage Universe: Lucas, Frederick G: BG Group (BG.L), BP (BP.L), Royal Dutch Shell A (RDSa.L), Royal Dutch Shell B (RDSb.L)

Sharma, Nitin: ENI (ENI.MI), Essar Energy (ESSR.L), Galp Energia (GALP.LS), OMV (OMVV.VI), Repsol YPF (REP.MC), Statoil (STL.OL), TOTAL (TOTF.PA)


https://mm.jpmorgan.com/disclosures/company

246



Wilson, Benjamin: AWE Limited (AWE.AX), Beach Energy Ltd. (BPT.AX), BlueScope Steel (BSL.AX), Oil Search (OSH.AX), OneSteel Limited (OST.AX), ROC Oil Company Limited (ROC.AX), Santos Limited (STO.AX), Sims Metal Management Ltd (SGM.AX), Woodside Petroleum (WPL.AX)

Bustnes, Brynjar Eirik: CNOOC (0883.HK), China BlueChemical Ltd (3983.HK), China Oilfield Services Limited (2883.HK), Inpex Corporation (1605.T), MIE Holdings Corporation (1555.HK), PetroChina (0857.HK), S-Oil Corp (010950.KS), SK Innovation Co Ltd (096770.KS), Sinopec Corp - H (0386.HK)

Mirchandani, Pradeep: Bharat Petroleum Corporation (BPCL) (BPCL.BO), Cairn India Limited (CAIL.BO), Essar Oil Ltd. (ESRO.BO), Gas Authority of India Limited (GAIL.BO), Gujarat Gas Ltd (GGAS.BO), Gujarat State Petronet Ltd. (GSPT.BO), Hindustan Petroleum Corporation (HPCL) (HPCL.BO), Indian Oil Corporation (IOC.BO), Indraprastha Gas (IGAS.BO), Oil India Ltd.(OILI.BO), Oil and Natural Gas Corporation (ONGC.BO), Petronet LNG Ltd. (PLNG.BO), Reliance Industries Ltd (RELI.BO)

Kazakova, Nadia Y: C.A.T. Oil (O2C.F), Eurasia Drilling Company (EDCLq.L), Gazprom (GAZP.RTS), HMS Group (HMSGq.L), MOL (MOLB.BU), Novatek (NVTKq.L), PKN ORLEN (PKNA.WA), Rosneft (ROSNq.L), Surgutneftegaz (SNGS.RTS), Surgutneftegaz Prefs (SNGS_p.RTS)

Minyard, Katherine L: Baytex Energy (BTE.TO), Canadian Natural Resources (CNQ.TO), Cenovus Energy (CVE.TO), Chevron Corp (CVX), ConocoPhillips (COP), Exxon Mobil Corp (XOM), Hess (HES), Husky Energy (HSE.TO), Lone Pine Resources (LPR), MEG Energy (MEG.TO), Marathon Oil (MRO), Murphy Oil (MUR), Nexen (NXY.TO), Occidental Petroleum (OXY), Penn West Exploration (PWT.TO), Suncor Energy (SU.TO), Talisman Energy (TLM.TO)

J.P. Morgan Equity Research Ratings Distribution, as of January 6, 2012

Overweight(buy)

Neutral(hold)

Underweight(sell)

J.P. Morgan Global Equity Research Coverage 47% 42% 12%IB clients* 52% 45% 36%

JPMS Equity Research Coverage 45% 47% 8%IB clients* 72% 62% 58%

*Percentage of investment banking clients in each rating category.For purposes only of FINRA/NYSE ratings distribution rules, our Overweight rating falls into a buy rating category; our Neutral rating falls into a hold rating category; and our Underweight rating falls into a sell rating category.

Equity Valuation and Risks: For valuation methodology and risks associated with covered companies or price targets for covered companies, please see the most recent company-specific research report at http://www.morganmarkets.com , contact the primary analyst or your J.P. Morgan representative, or email [email protected].

Equity Analysts' Compensation: The equity research analysts responsible for the preparation of this report receive compensation based upon various factors, including the quality and accuracy of research, client feedback, competitive factors, and overall firm revenues, which include revenues from, among other business units, Institutional Equities and Investment Banking.

Registration of non-US Analysts: Unless otherwise noted, the non-US analysts listed on the front of this report are employees of non-US affiliates of JPMS, are not registered/qualified as research analysts under NASD/NYSE rules, may not be associated persons of JPMS, and may not be subject to FINRA Rule 2711 and NYSE Rule 472 restrictions on communications with covered companies, public appearances, and trading securities held by a research analyst account.

Other Disclosures

J.P. Morgan ("JPM") is the global brand name for J.P. Morgan Securities LLC ("JPMS") and its affiliates worldwide. J.P. Morgan Cazenove is a marketing name for the U.K. investment banking businesses and EMEA cash equities and equity research businesses of JPMorgan Chase & Co. and its subsidiaries.

Options related research: If the information contained herein regards options related research, such information is available only to persons who have received the proper option risk disclosure documents. For a copy of the Option Clearing Corporation's Characteristics and Risks of Standardized Options, please contact your J.P. Morgan Representative or visit the OCC's website at http://www.optionsclearing.com/publications/risks/riskstoc.pdf

Legal Entities Disclosures U.S.: JPMS is a member of NYSE, FINRA, SIPC and the NFA. JPMorgan Chase Bank, N.A. is a member of FDIC and is authorized and regulated in the UK by the Financial Services Authority. U.K.: J.P. Morgan Securities Ltd. (JPMSL) is a member of the London Stock Exchange and is authorized and regulated by the Financial Services Authority. Registered in England & Wales No. 2711006. Registered Office 125 London Wall, London EC2Y 5AJ. South Africa: J.P. Morgan Equities Limited is a member of the Johannesburg Securities Exchange and is regulated by the FSB. Hong Kong: J.P. Morgan Securities (Asia Pacific) Limited (CE number AAJ321) is regulated by the Hong Kong Monetary Authority and the Securities and Futures Commission in Hong Kong. Korea: J.P. Morgan Securities (Far East) Ltd, Seoul Branch, is regulated by the Korea Financial Supervisory Service. Australia: J.P. Morgan Australia Limited (ABN 52 002 888 011/AFS Licence No: 238188) is regulated by ASIC and J.P. Morgan Securities Australia Limited (ABN 61 003 245 234/AFS Licence No: 238066) is a Market Participant with the ASX and regulated by ASIC. Taiwan: J.P.Morgan Securities (Taiwan) Limited is a participant of the Taiwan Stock Exchange (company-type) and regulated by the Taiwan Securities and Futures Bureau. India: J.P. Morgan India Private

http://www.optionsclearing.com/publications/risks/riskstoc.pdf


http://www.morganmarkets.com/

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Limited, having its registered office at J.P. Morgan Tower, Off. C.S.T. Road, Kalina, Santacruz East, Mumbai - 400098, is a member of the National Stock Exchange of India Limited (SEBI Registration Number - INB 230675231/INF 230675231/INE 230675231) and Bombay Stock Exchange Limited (SEBI Registration Number - INB 010675237/INF 010675237) and is regulated by Securities and Exchange Board of India. Thailand: JPMorgan Securities (Thailand) Limited is a member of the Stock Exchange of Thailand and is regulated by the Ministry of Finance and the Securities and Exchange Commission. Indonesia: PT J.P. Morgan Securities Indonesia is a member of the Indonesia Stock Exchange and is regulated by the BAPEPAM LK. Philippines: J.P. Morgan Securities Philippines Inc. is a member of the Philippine Stock Exchange and is regulated by the Securities and Exchange Commission. Brazil: Banco J.P. Morgan S.A. is regulated by the Comissao de Valores Mobiliarios (CVM) and by the Central Bank of Brazil. Mexico: J.P. Morgan Casa de Bolsa, S.A. de C.V., J.P. Morgan Grupo Financiero is a member of the Mexican Stock Exchange and authorized to act as a broker dealer by the National Banking and Securities Exchange Commission. Singapore: This material is issued and distributed in Singapore by J.P. Morgan Securities Singapore Private Limited (JPMSS) [MICA (P) 032/01/2012 and Co. Reg. No.: 199405335R] which is a member of the Singapore Exchange Securities Trading Limited and is regulated by the Monetary Authority of Singapore (MAS) and/or JPMorgan Chase Bank, N.A., Singapore branch (JPMCB Singapore) which is regulated by the MAS. Malaysia: This material is issued and distributed in Malaysia by JPMorgan Securities (Malaysia) Sdn Bhd (18146-X) which is a Participating Organization of Bursa Malaysia Berhad and a holder of Capital Markets Services License issued by the Securities Commission in Malaysia. Pakistan: J. P. Morgan Pakistan Broking (Pvt.) Ltd is a member of the Karachi Stock Exchange and regulated by the Securities and Exchange Commission of Pakistan. Saudi Arabia: J.P. Morgan Saudi Arabia Ltd. is authorized by the Capital Market Authority of the Kingdom of Saudi Arabia (CMA) to carry out dealing as an agent, arranging, advising and custody, with respect to securities business under licence number 35-07079 and its registered address is at 8th Floor, Al-Faisaliyah Tower, King Fahad Road, P.O. Box 51907, Riyadh 11553, Kingdom of Saudi Arabia. Dubai: JPMorgan Chase Bank, N.A., Dubai Branch is regulated by the Dubai Financial Services Authority (DFSA) and its registered address is Dubai International Financial Centre - Building 3, Level 7, PO Box 506551, Dubai, UAE.

Country and Region Specific Disclosures U.K. and European Economic Area (EEA): Unless specified to the contrary, issued and approved for distribution in the U.K. and the EEA by JPMSL. Investment research issued by JPMSL has been prepared in accordance with JPMSL's policies for managing conflicts of interest arising as a result of publication and distribution of investment research. Many European regulators require a firm to establish, implement and maintain such a policy. This report has been issued in the U.K. only to persons of a kind described in Article 19 (5), 38, 47 and 49 of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (all such persons being referred to as "relevant persons"). This document must not be acted on or relied on by persons who are not relevant persons. Any investment or investment activity to which this document relates is only available to relevant persons and will be engaged in only with relevant persons. In other EEA countries, the report has been issued to persons regarded as professional investors (or equivalent) in their home jurisdiction. Australia: This material is issued and distributed by JPMSAL in Australia to "wholesale clients" only. JPMSAL does not issue or distribute this material to "retail clients". The recipient of this material must not distribute it to any third party or outside Australia without the prior written consent of JPMSAL. For the purposes of this paragraph the terms "wholesale client" and "retail client" have the meanings given to them in section 761G of the Corporations Act 2001. Germany: This material is distributed in Germany by J.P. Morgan Securities Ltd., Frankfurt Branch and J.P.Morgan Chase Bank, N.A., Frankfurt Branch which are regulated by the Bundesanstalt für Finanzdienstleistungsaufsicht. Hong Kong: The 1% ownership disclosure as of the previous month end satisfies the requirements under Paragraph 16.5(a) of the Hong Kong Code of Conduct for Persons Licensed by or Registered with the Securities and Futures Commission. (For research published within the first ten days of the month, the disclosure may be based on the month end data from two months prior.) J.P. Morgan Broking (Hong Kong) Limited is the liquidity provider/market maker for derivative warrants, callable bull bear contracts and stock options listed on the Stock Exchange of Hong Kong Limited. An updated list can be found on HKEx website: http://www.hkex.com.hk. Japan: There is a risk that a loss may occur due to a change in the price of the shares in the case of share trading, and that a loss may occur due to the exchange rate in the case of foreign share trading. In the case of share trading, JPMorgan Securities Japan Co., Ltd., will be receiving a brokerage fee and consumption tax (shouhizei) calculated by multiplying the executed price by the commission rate which was individually agreed between JPMorgan Securities Japan Co., Ltd., and the customer in advance. Financial Instruments Firms: JPMorgan Securities Japan Co., Ltd., Kanto Local Finance Bureau (kinsho) No. 82 Participating Association / Japan Securities Dealers Association, The Financial Futures Association of Japan, Type II Financial Instruments Firms Association and Japan Securities Investment Advisers Association. Korea: This report may have been edited or contributed to from time to time by affiliates of J.P. Morgan Securities (Far East) Ltd, Seoul Branch. Singapore: JPMSS and/or its affiliates may have a holding in any of the securities discussed in this report; for securities where the holding is 1% or greater, the specific holding is disclosed in the Important Disclosures section above. India: For private circulation only, not for sale. Pakistan: For private circulation only, not for sale. New Zealand: This material is issued and distributed by JPMSAL in New Zealand only to persons whose principal business is the investment of money or who, in the course of and for the purposes of their business, habitually invest money. JPMSAL does not issue or distribute this material to members of "the public" as determined in accordance with section 3 of the Securities Act 1978. The recipient of this material must not distribute it to any third party or outside New Zealand without the prior written consent of JPMSAL. Canada: The information contained herein is not, and under no circumstances is to be construed as, a prospectus, an advertisement, a public offering, an offer to sell securities described herein, or solicitation of an offer to buy securities described herein, in Canada or any province or territory thereof. Any offer or sale of the securities described herein in Canada will be made only under an exemption from the requirements to file a prospectus with the relevant Canadian securities regulators and only by a dealer properly registered under applicable securities laws or, alternatively, pursuant to an exemption from the dealer registration requirement in the relevant province or territory of Canada in which such offer or sale is made. The information contained herein is under no circumstances to be construed as investment advice in any province or territory of Canada and is not tailored to the needs of the recipient. To the extent that the information contained herein references securities of an issuer incorporated, formed or created under the laws of Canada or a province or territory of Canada, any trades in such securities must be conducted through a dealer registered in Canada. No securities commission or similar regulatory authority in Canada has reviewed or in any way passed judgment upon these materials, the information contained herein or the merits of the securities described herein, and any representation to the contrary is an offence. Dubai: This report has been issued to persons regarded as professional clients as defined under the DFSA rules.

General: Additional information is available upon request. Information has been obtained from sources believed to be reliable but JPMorgan Chase & Co. or its affiliates and/or subsidiaries (collectively J.P. Morgan) do not warrant its completeness or accuracy except with respect to any disclosures relative to JPMS and/or its affiliates and the analyst's involvement with the issuer that is the subject of the research. All pricing is as of the close of market for the securities discussed, unless otherwise stated. Opinions and estimates constitute our judgment as of the date of this material and are subject to change without notice. Past performance is not indicative of future results. This material is not intended as an offer or solicitation for the purchase or sale of any financial instrument. The opinions and recommendations herein do not take into account individual client circumstances, objectives, or needs and are not intended as recommendations of particular securities, financial instruments or strategies to particular clients. The recipient of this report must make its own

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independent decisions regarding any securities or financial instruments mentioned herein. JPMS distributes in the U.S. research published by non-U.S. affiliates and accepts responsibility for its contents. Periodic updates may be provided on companies/industries based on company specific developments or announcements, market conditions or any other publicly available information. Clients should contact analysts and execute transactions through a J.P. Morgan subsidiary or affiliate in their home jurisdiction unless governing law permits otherwise.

"Other Disclosures" last revised January 6, 2012.

Copyright 2012 JPMorgan Chase & Co. All rights reserved. This report or any portion hereof may not be reprinted, sold or redistributed without the written consent of J.P. Morgan. #$J&098$#*P

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