Bernstein - Global Gas Decoupling, the Rising Marginal Cost of LNG and the Asian Gas Premium...

8/7/2019 Bernstein - Global Gas Decoupling, the Rising Marginal Cost of LNG and the Asian Gas Premium 06.10.10

1/23

Asia-PacificOil&Gas

October 6, 2010

Nei l Beveridge, Ph.D. (Senior Analyst) [email protected] +852-2918-5741

Angus Chan, CA [email protected] +852-2918-5740

See Disclosure Appendix of this publication for important disclosures and analyst certifications.

Bernst ein Asia-Pac Energy: Global Gas Dec oupl ing , the Rising

Marginal Cost of LNG and t he Asian Gas Premium

Ticker Rating CUR

10/5/2010ClosingPrice

TargetPrice

TTMRel.Perf.

EPS P/E

2009A 2010E 2011E 2009A 2010E 2011E Yield

WPL.AU O AUD 44.48 55.00 -31.1% 2.71 1.53 3.95 16.4 29.1 11.3 2.5%

STO.AU O AUD 12.58 17.00 -34.3% 0.34 0.36 0.66 37.0 34.9 19.1 3.3%

OSH.AU O AUD 6.16 7.50 -19.3% 0.09 0.14 0.18 68.4 44.0 34.2 0.8%

857.HK O HKD 9.48 10.50 -8.9% 0.64 0.84 1.04 14.8 11.3 9.1 3.0%

PTR O USD 121.41 135.50 -1.8% 8.25 10.84 13.42 14.7 11.2 9.0 3.1%

RIL.IN M INR 1017.85 1160.00 -22.3% 53.40 68.60 81.40 19.1 14.8 12.5 0.6%

MXAPJ 453.67 23.63 31.02 35.63 19.2 14.6 12.7 2.7%

SPX 1137.03 61.70 83.42 95.36 18.4 13.6 11.9 2.0%

O Outperform, M Market-Perform, U Underperform, N Not Rated

High l ights

Asian gas prices are trading at a significant premium to other international markets. We believe this will

continue given the structural supply deficit and the rising marginal cost of LNG imports which will push

prices higher. Within the sector we favor low cost LNG exporters, domestic gas producers and quality CBM

players as a long term play.

Natural gas prices in Asia are trading at a premium to the US in both regulated and unregulatedgas markets. The US is experiencing a glut in gas supply from shale gas drilling and relatively weak

demand growth has pushed gas prices to historic lows; Asian markets in contrast remain tight as demandcontinues to grow rapidly with supply struggling to keep pace and the rising marginal cost of gas whichis pushing prices higher.

To meet growing demand, LNG imports to Asia will grow strongly; Australia will be the mainbeneficiary. Regas capacity in non-OECD Asia is set to more than double in the next 5 years which webelieve will benefit Australian LNG exporters. The decline in SE Asian LNG projects coupled with themoratorium in new LNG projects in Qatar means that Australia will be the main supplier of incrementalLNG to the Pacific basin over the next decade.

Australian LNG wont be cheap however. Rising project costs will mean that the price linkagebetween LNG and oil will remain firmly intact. Despite the current oversupply in LNG we believe thatthe supply-demand balance will significantly tighten over the coming 3 years. Although some believe

that competition between projects could drive prices lower, the high marginal cost of Australian LNGprojects will require contract prices to be close to oil parity in order for projects to be developedeconomically.

The increase in the marginal cost of gas through LNG imports mean that regulated gas prices inAsia will continue to rise. Although Indian (APM) gas prices doubled and Chinese wellhead gas pricesincreased by 25% this year, domestic gas pricing remains at a significant discount to imported gas. Webelieve that further price increases are required to accelerate the development of domestic gas productionwhich in the long run is preferable to imports.


2/23

Asia-PacificOil&Gas

October 6, 2010

Nei l Beveridge , Ph.D. (Senior Analyst) [email protected] +852-2918-5741

2

The main risks to our thesis is that unconventional gas makes a significant impact to the supplydemand balance in Asia in the near to medium term but we think this is unlikely. While Asia hassignificant CBM and Shale gas potential, development of these reserves will take time. The industrystructure in China and India is not the same as in the US where there are large numbers of small cap E&P

companies with unrestricted access. In Asia development is likely to be much slower given theconsolidated nature of the industry and access restrictions to foreign companies.

Companies which will benefit from the rising marginal cost of gas are those which are lower down

the cost curve. These are low cost (high liquid) LNG exporters, domestic gas producers (which willbenefit from regulatory price increases) and quality small cap CBM producers.Within the Asiangas sector our favorite picks are Oil Search, Woodside and Petrochina which we believe will enjoy stronggas volume growth and benefit from the Asian gas premium.

Investment Conc lus ion

Despite a prevailing negative sentiment on global gas given the oversupply in capacity, Asia continues to bethe one bright spot with gas prices in Asia trading at a substantial premium to the US and Europeanmarkets. This should be good for Asian domestic producers and LNG exporters alike. While the surge in

unconventional gas drilling continues to sustain anomalously low gas prices in the US and Europeanmarkets mop up excess global LNG capacity; markets in Asia remain tight. Strong demand growth in Chinaand India, limitations in infrastructure capacity and misguided regulatory pricing policies means that supplyremains unable to keep pace with demand. In more mature markets of Japan and Korea, the decline oftraditional projects in SE Asia means that large gaps in long term supply need to be plugged over thecoming years with new supply.

A beneficiary of supply deficient Asian gas markets is Australia. Australia has large gas reserves but thecosts of development are high. In our view Australian LNG effectively sets the marginal gas price in Asia.Given the enormous development costs, Australian LNG projects require pricing close to oil parity to beeconomic. We therefore believe that the marginal price of gas in Asia will remain oil linked and at apremium to other markets. Increases in gas import costs will further encourage the increase of regulateddomestic gas prices in China and India as governments attempt to stimulate domestic gas production overimports. Although unconventional gas is a potential game changer, the above ground challenges in Asiasuggests that this is still some way off.

The beneficiary of continued high gas pricing in Asia are low cost LNG exporters, domestic producers inChina and India (which benefit from regulatory reform) and quality small cap companies developing coalbed methane projects where pricing is unregulated. We favor E&P companies which have LNG projectswith high liquids content or are lower cost brown field developments such as PNG LNG and Plutoexpansion. Our top picks in Australia remain Woodside and Oil Search. We also believe that the Indian andChinese gas producers such as Reliance and Petrochina will benefit from further pricing reform, amongwhich we believe Petrochina offers best value at present.

Detai ls

Over the past 10 years, the marginal cost of producing a barrel of crude has risen significantly from around$20/bbl to between $70 -80/bbl. This has been driven by declining reserves and production per well as wehave reached the end of era of easy oil. Oil prices have responded to the increasing marginal cost of supplyand cycled around the marginal cost.

We believe the same phenomenon is happening with LNG. In the 1990's and early part of this decade theLNG industry focused on the development of low cost 'easy' gas fields with relatively high liquids yields inSouth East Asia and more recently in Qatar. Given the moratorium on new development of LNG in Qatarand the decline of projects in SE Asia producers have been forced to develop projects in more remote places


3/23


4/23

Asia-PacificOil&Gas

October 6, 2010


4

Exhibit 2Gas Prices are starting to decouple between east and west

Oil, LNG and Spot Gas Prices in UK and US

0

5

10

15

20

25

Ja

n-00

Jul-00

Ja

n-01

Jul-01

Ja

n-02

Jul-02

Ja

n-03

Jul-03

Ja

n-04

Jul-04

Ja

n-05

Jul-05

Ja

n-06

Jul-06

Ja

n-07

Jul-07

Ja

n-08

Jul-08

Ja

n-09

Jul-09

Ja

n-10

Jul-10

$/mmbtu

Japan LNG Import HH UK NBP WTI

Source: Bloomberg

Exhibit 3Pricing discount to crude has never been as high for USmarkets while Asia markets remain close to oil

Exhibit 4Price premium of Asia markets over US markets remainsstrong

Ratio of Gas to Oil Prices in US and Asia

0

1

2

Jan-00

Jan-01

Jan-02

Jan-03

Jan-04

Jan-05

Jan-06

Jan-07

Jan-08

Jan-09

Jan-10

Gas/OilPrice

US HH Japan

Japan Price Premium Realtive to US and UK

-10

-8

-6

-4

-2

0

2

4

6

8

10

Jan-00

Jan-01

Jan-02

Jan-03

Jan-04

Jan-05

Jan-06

Jan-07

Jan-08

Jan-09

Jan-10

$/mmbtu

Japan minus HH Japan minus UK NBP

Source: Bloomberg, Bernstein Est. Source: Bloomberg, Bernstein Est.

In contrast to the US demand for gas in Asia has been surging with supply struggling to keep up. Japan andKorea LNG demand looks set to grow by 7% and 31% respectively this year. In China total gas demandgrowth is likely to average 20% and in India we expect demand growth to be over 30%. This compares with


5/23

Asia-PacificOil&Gas

October 6, 2010


5

4% growth which is likely in the US. To meet growing demand needs, Asia needs increasing quantities ofimports. In traditional LNG markets of Japan and Korea the demand for LNG will be driven by the need tobackfill supply from mature fields such as Arun and Bontang where supply will continue to decline.

Exhibit 5Japan requires significant LNG to backfill a decline insupply

Exhibit 6Korea has a bigger supply deficit problem which it needsto address

Japan LNG Supply-Demand

0

10

2030

40

50

60

70

80

90

100

2000

2002

2004

2006

2008

2010

2012

2014

2016

2018

2020

mtpa

Contracted Supply Demand

Korea LNG Supply-Demand

0

5

10

15

20

25

30

35

40

2000

2002

2004

2006

2008

2010

2012

2014

2016

2018

2020

mtpa

Contracted Supply Demand

Source: Bernstein Est. Source: Bernstein Est.

Where new demand growth for LNG will be most strong is in emerging markets in Asia. In China, Indiaand other South East Asian markets such as Singapore, Thailand, Malaysia and Indonesia new regasterminals projects being built. We expect regas capacity to double over the next 3 years to 70mtpa as new

capacity is brought on stream (Exhibit 7). Over the next 5 years we expect the Asia-Pacific region to be themain consumer of global LNG which means that LNG pricing will be important in gas price setting in theregion.


6/23

Asia-PacificOil&Gas

October 6, 2010


6

Exhibit 7LNG regas volumes in non-OECD Asia will grow strongly

Growth In Regas Capacity in Non-OECD Asia

0

10

20

30

40

50

60

70

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

mtpa

China India Other Asia

Source: Bernstein Est.

Exhibit 8Asia Pacific Region Will Continue to be the Main Consumer for Global LNG

Global LNG Imports by Region

0

50

100

150

200

250

300

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

mtpa

N. America Europe Asia-Pacific

Source: Bernstein Est, Bloomberg


7/23

Asia-PacificOil&Gas

October 6, 2010


7

Austral ia - The Marginal Gas Suppl ier in the Paci f ic Bas in

Incremental supply of LNG can only come from one place in our view Australia (Exhibit 9). With SouthEast Asia projects at the point of maturity (Arun, Bontang) and domestic demand for gas in Indonesia andMalaysia picking up, export cargoes from this region are likely to decline. In Qatar there is a moratorium onnew supply, not to mention the shortage of gas within the region as evidenced by emirates of Kuwait andDubai which are starting to import LNG. While Nigeria, Venezuela and Russia also have potential to boostexports we see a number of potential hurdles which makes it unlikely that we will see significantincremental supply growth in the near future.

Given the lack of alternatives, Australia will be the main supplier of incremental LNG in our view.Although Australia accounts for less than 10% of current LNG production it accounts for one third ofincremental new LNG and 50% of possible new LNG projects (on a capacity basis) which are underconsideration worldwide (Exhibit 10, Exhibit 11 and Exhibit 12).

Exhibit 9Australia has the largest source of liquefaction capacity yet to be developed

Liquefaction Capacity by Country

0

20

40

60

80

100

120

140

Australia

Qatar

Nigeria

Indonesia

Algeria

Russia

Malaysia

Egypt

T&T

Venezuela

PNG

Brunei

Oman

AbuDhabi

EG

Yemen

Angola

Canada

Peru

Norway

(mtpa)

Existing Capacity Under Construction Capacity Planned Capacity



8/23

Asia-PacificOil&Gas

October 6, 2010


8

Exhibit 10Australia has less than 10% ofcurrent capacity

Exhibit 11One third of capacity underconstruction

Exhibit 12More than 50% of planned projects

Global LNG Capacity In Operation mtpa

263mtpa

8%

92%

Australia Other

Global LNG Capacity In Construction mtpa

60mtpa

33%

67%

Australia Other

Global LNG Capacity Planned mtpa

203mtpa

49%51%

Australia Other

Source: Bernstein Est. Source: Bernstein Est. Source: Bernstein Est.

What is the Marginal Cost of Gas in Asia?

We believe that Australian LNG effectively defines the marginal cost of Asia given that it is the highestcost supply of gas within the region. Globally, There is a large difference in the marginal cost of gas supply,which we define at the FOB price required to generate a project 12% IRR(Exhibit 13). While oilcompany's seek an integrated 15% IRR on major oil and gas developments, 12% IRR represents the lowend of the range at which companies would be willing to approve LNG projects. LNG within the MiddleEast has the lowest marginal cost of supply given the large low cost gas fields and high liquids contents.The Australian projects (marked in red) are at the high end of the cost scale given their high costs, remotelocations and lower liquids content.

Exhibit 13Australian LNG projects have the highest cost of supply globally

FOB Gas Price to Yield 12% IRR

Sakhalin2

Gorgon

Pluto

PNGLNG

QCLNG

Snohvit

Kenai

AngolaLNG

NorthWestShelf

PeruLNG

MLNGDua

YemenLNG

MLNGSatu

B

rassLNG

Tangguh

ML

NGTiga

OLN

G

Brun

eiLNG

Darwin

ELNG

1

Damietta

ELNG2

EGLNG

AtlanticLNG4

QalhatLNG

Atlantic

LNG2&3

Qatargas

Bontang

AtlanticLN

G1

QatarGas-3

Arun

Qatargas-4

Adgas

0

2

4

6

8

10

12

- 20 40 60 80 100 120 140 160 180 200 220

Cumulative capacity, mmtpa

US$/mmbtu

Source: Bernstein Est., Woodmac


9/23

Asia-PacificOil&Gas

October 6, 2010


9

The marginal cost of LNG is not only dependent on project location. The marginal cost of LNG productionhas been increasing over time (Exhibit 14). Prior to 2004 the FOB price of LNG project ranged from $2 to$4/mmbtu. Over the past 5 years the marginal cost of LNG has increased substantially along with oil price.The marginal cost of new LNG projects (mostly located in Australia) requires an $8 to $10/mmbtu FOB

price to deliver a 12% IRR. Assuming a typical LNG contract relationship with oil (0.145) this implies oilprices of $55bbl to $70/bbl to deliver a break even return.

Exhibit 14The marginal cost of LNG supply continues to rise with oil prices

Oil Price and LNG Marginal Cost of Supply

0

2

4

6

810

12

14

16

18

1975 1980 1985 1990 1995 2000 2005 2010 2015

$/mmb

tu

LNG Marginal Costs (ex-Australia) WTI LNG Marginal Cost (Australia)

Oil price has been converted from $/bbl to

$/mmbtu be multiplying by 0.166

Source: Bernstein Est., Woodmac

Underlying the increase in the marginal cost of LNG is the increasing costs of developing new LNG

projects. Exhibit 15 lists a number of major LNG projects which have been developed, including their costand the estimated marginal cost of supply based on an integrated 12% project IRR.


10/23

Asia-PacificOil&Gas

October 6, 2010


10

Exhibit 15Capex, capacity, cost per ton and marginal cost of supply for existing LNG projects

MTPA USD $bn $/MTPA Marginal LNG

Project FID Start Up Capacity Total Total FOB $/mmbtu

Gorgon 2009 2014 15 37 2467 8.8

PNG LNG 2009 2014 6.7 15 2239 7.5

Angola LNG 2008 2012 5.2 9 1731 3.6

Pluto-1 2007 2011 4.8 10.5 2188 7.7

Pluto 1 2007 2011 4.8 10.5 2188 7.7

Peru LNG 2008 2010 4.45 3.8 854 3.4

Qatargas-2 2004 2009 15.6 8.1 519 1.5

Yemen LNG 2005 2009 6.8 4.5 662 2.9

Tangguh 2005 2009 7.6 5 658 2.6

Sakhalin 2 2004 2009 9.6 25 2604 11.2

NWS T5 2005 2008 4.8 7.9 1646 5.9

Snohvit 2003 2007 4.3 6.3 1465 6.1

ELNG 1 2003 2007 3.4 1.4 412 1.7

Darwin 2002 2006 3.4 2.7 794 2

NWS T4 2002 2004 4.3 7.8 1814 6.5

RasGas 1 1995 1999 6.6 3 455 1.5

NWS T1-3 1985 1989 7.7 8.3 1078 3.6

Assumes USD:AUD exchange rate of 1.15 for future projects

Estimated LNG FOB Prices required for 12% IRR on integrated project


Three factors have the greatest impact the marginal cost in our view. Overall project cost, liquid content ofthe project and country taxation regime. While each of these factors plays a role in determining price, thecost per ton has the largest impact on setting the overall marginal cost of LNG supply given the globalvariation in project costs (Exhibit 16).

Exhibit 16

LNG project costs are the fundamental driver of the marginal cost of LNG supply

LNG Project Costs vs. Marginal Cost

Angola LNG

Gorgon

PNG LNG

Pluto-1

Peru LNGYemen LNG

Tangguh

Sakhalin 2

Snohvit

Darwin LNGELNG 1

NWS T1-3

Ras GasR

2= 0.8901

0

2

4

6

8

10

12

0 500 1000 1500 2000 2500 3000

Capex per Ton

MarginalLNGCost$/mmbtu

Project Data Linear (Project Data)



11/23

Asia-PacificOil&Gas

October 6, 2010


11

In recent years the price of developing a new LNG project in Australia and worldwide has increasedsignificantly. Liquefaction costs (which account for 30% to 40% over LNG project developments) haveincreased from less that $400/ton to over close to $1000/ton for new liquefaction plants. Global upstreamcosts continue to increase with 3 year average reserve replacement costs close to $15/boe (Exhibit 18).

Total integrated project costs have historically varied from less than $500/t to more than $2500/t.

Exhibit 17LNG plant costs continue to increase

Exhibit 18as do upstream cost

LNG Plant Liquifaction Costs

0

200

400

600

800

1000

1200

1400

1600

1990 1995 2000 2005 2010

$/mtpa

Global Upstream F&D Costs

0

5

10

15

20

25

30

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

$/boe

Source: Corporate Reports Source: Bernstein Est.

With higher development costs, the marginal cost of LNG has to rise. In our view Australian LNG projectsneed a minimum real gas price of $8-10/mmtbu and oil price of $60/bbl to $70/bbl deliver a minimum IRRof 12%. Given the trend towards increasing costs, we believe that LNG prices will continue to rise.


12/23

Asia-PacificOil&Gas

October 6, 2010


12

Exhibit 19Oil price of close to $70/bbl is required for an LNG project with a marginal cost of $8-10/mmbtu

Oil Price Required for Breakeven LNG Price

$0

$2

$4

$6

$8

$10

$12

$14

$16

$18

0 10 20 30 40 50 60 70 80 90 100

JCC Price

LNGCIFPrice($/mmbtu)

Crude Recent Contracts (0.145 x Crude)

Marginal Cost


Marginal Cost of New LNG Projec t

So what is the marginal cost of the next wave of developments likely to be? A number of LNG projects arelikely to reach FID over the next 2 to 3 years (Exhibit 20). We have taken the most recent estimates forcapex and capacity to calculate the capex per ton and estimated the marginal cost of new LNG supply basedon a 12% IRR (Exhibit 21).

Exhibit 20

Capex, capacity, cost per ton and marginal cost of supply for planned LNG projects

MTPA USD $bn $/MTPA Marginal LNG

Project Company FID Start Up Capacity Total Total FOB $/mmbtu

PNG LNG T4 OSH, STO 2013 2018 3.3 5.5 1667 6.0

Browse WPL, RDS 2013 2018 12 35.0 2917 10.2

PNG LNG T3 OSH, STO 2013 2017 3.3 4.0 1212 4.5

Pluto 3 WPL 2012 2016 4.3 10.0 2326 8.1

Icthys INPEX 2011 2016 8.4 25.0 2976 10.7

Wheatstone CVX 2011 2017 8.6 21.0 2442 8.5

Pluto 2 WPL 2011 2015 4.3 9.0 2093 7.4

GLNG STO 2010 2014 7.2 15.0 2083 7.3

QCLNG BG 2010 2014 8.0 16.0 2000 7.1


Not surprisingly, we find that projects which are brown field expansions with high liquids content have thelowest marginal cost of supply. Assuming gas reserves can be confirmed through further exploration andappraisal drilling in 2011, expansion of the PNG LNG project looks likely to go ahead given the highreturns and low marginal costs. On current capex estimates, coal bed methane to LNG projects look to becompetitive versus dry gas projects in Western Australia, although capex estimates for green field CBMprojects remain uncertain and could be higher than we currently anticipate. Icthys and Browse have thehighest capex per ton and the highest marginal cost. We believe that an LNG price of $10/mmbtu which isequivalent to an oil price of $70/bbl will be required to generate a marginal return on these projects. Given


13/23

Asia-PacificOil&Gas

October 6, 2010


13

that companies will be seeking a higher IRR than 12% given the risks of cost overrun these projects lookfairly marginal even under current oil price assumptions.

Exhibit 21Cost of Supply curve for new Australian LNG projects

Marginal Cost of Proposed Australian LNG Projects

Icthys

Browse

Gorgon

Wheatstone

PlutoT3

PlutoT2

GLNG

QCLNG

PNGLNGT4

PNGL

NGT3

0

2

4

6

8

10

12

- 20 40 60

Cumulative capacity, mmtpa

US$/mmbtu

oil parity at USD70/bbl


The one mitigating factor for these projects is the liquids content. Icthys has one of the highest liquids ofany LNG project and Browse is also thought to be relatively liquids rich compared to some of the other drygas developments which are taking place in Western Australia such as Pluto and Gorgon (Exhibit 22).Taking the liquids benefit into account may mean that the gas price (FOB) required to generate anintegrated 12% IRR is likely to be slightly lower than we estimate here.


14/23

Asia-PacificOil&Gas

October 6, 2010


14

Exhibit 22Liquids content may mean that some projects have a lower breakeven price

QCLNGGLNG

GorgonWhatstone

Pluto

Browse

PNG

Icthys

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

0 10 20 30 40 50

Condensate Gas Ratio (bbls/mmscf)

DiscounttoLNGMarginalCostforLiquids

$/mmbtu


Conclusions

Our take-away from this analysis is that Australian LNG will play a major role not only in gas supply toAsia but in price setting in Asia. Australian LNG is high cost and will require oil linked pricing to bedeveloped economically. As such, we expect that the marginal cost of gas in the region will remain linkedto oil prices. This will continue to put upwards pressure on gas prices in the region and result in gas pricestrading at a premium to the US and Europe. Competition between projects in Australia is unlikely to lead toa decoupling to oil prices or substantial discounts as this would require developers to sell LNG at price

which did not deliver a marginal return on investment.

The key risk to this thesis is the development of unconventional gas which could be lower cost than LNG orincreased supply of low cost LNG from the Middle East. We think both are unlikely. While the potential forunconventional gas in Asia is clear, above ground issues mean that development of unconventional gas islikely to take much longer relative to the US.

The high marginal cost of gas in Asia will ultimately benefit companies which are lower cost and can takeadvantage of higher Asian gas prices. These include low cost LNG suppliers who can develop projectssubstantially below the marginal cost of supply. It will also benefit unregulated gas suppliers such asoffshore gas producers and onshore CBM companies in China and India where prices are unregulated.

Ultimately, we also believe that the high marginal cost of gas will benefit regulated gas producers in China

and India (Exhibit 23). While there are historical reasons to regulate the gas price, the policy is provingcounter productive and limiting rather than stimulating domestic supply. In India for example, offshore gasdiscoveries are not being developed in a timely way on account of the gas price being too low ($4-5/mmbtu) to allow economic development.

In China there are similar problems, where the wellhead gas price needs to be increased to accelerate thedevelopment of domestic gas reserves. Given the cost of imports, we believe it makes sense that regulatorsraise gas prices to encourage development of domestic gas. In China we expect gas prices to be raised by10% per year over the next 5 years to incentivize the development of domestic gas over more expensive gas


15/23

Asia-PacificOil&Gas

October 6, 2010


15

imports. In India we expect that offshore gas prices will be increased to $5-6/mmbtu in the next 12 monthsto further encourage development offshore supply.

Exhibit 23Domestic gas prices will have to increase in response to higher import prices

China City Gate and Well Head Gas Prices

0

2

4

6

8

10

12

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

$/mcf

Domestic Gas (Citygate) Domestic Gas (Wellhead)

Wellhead prices:

2009-15E CAGR 10%

City gate: 2000-09 CAGR of 9%

Wellheads: 2000-09 CAGR of 6%

City gate gas prices:

2009-15E CAGR 9%

price of LNG imports



16/23

Asia-PacificOil&Gas

October 6, 2010


16

Disclosure Appendix

Valuat ion Methodology

Within our E&P coverage, we value Woodside based on our 2011 cashflow per share estimates, to whichwe apply a target price to cashflow multiple based on historical trading ranges and the expected recycleratio (the ratio of cashflow per barrel and the average F&D cost per barrel of reserves added). We havefound a strong correlation between the recycle ratio and forward P/CF multiples for international E&Pcompanies (Exhibit 24). Our price targets are also sanity checked against NAV based valuation (Exhibit25), though we prefer the use of the use of the PCF valuation methodologies as it can be back-tested andbuilds in fewer assumptions in today's more uncertain cost and commodity environment.

Exhibit 24Woodside price target

Company Currency RR 2009-11E SCB Target Fwd P/CF SCB 2011 CFPS SCB Price Target

Woodside AUD 270% 5.5 10.0 55.0

Source: Bernstein estimates

Exhibit 25Woodside Net Asset Value

Woodside NAV Valuation At $80 (Real) Oil At $100 (Real) Oil

Country Field/Prospect

Equity

(%)

Risk

(%) Total NPV

Risked NPV/

share

Risked NPV/

share

M Boe $M AUD AUD

Corporate

Net Debt (3,633) (5.9) (5.9)

Central SG&A (534) (0.9) (0.9)

Fields in Production

Australia

NWS LNG 460 8,131 13.3 15.6Domestic Oil 121 2,597 4.2 5.3

Domestic Gas 132 1,081 1.8 1.9

Algeria 15% 54 60 0.1 0.1

US* 10 291 0.5 0.9

Fields being developed

Australia Pluto 1 90% 784 12,433 20.3 21.5

NAV

Production 777 12,161 19.9 23.8

Development 784 12,433 20.3 21.5

Base NAV (incl. Corporate) 1,561 20,427 33.4 38.4

Upside

Pluto 2 75% 100% 654 5,692 9.3 13.6

Pluto 3 50% 100% 436 2,939 4.8 7.4

Browse 50% 1,167 2,333 3.8 3.8Sunrise 33% 319 638 1.0 1.0

International** 500 0.8 0.8

Contingent Resources*** 375 749 1.2 1.2

Total NAV (Risked) 4,511 33,279 54.4 66.3



17/23

Asia-PacificOil&Gas

October 6, 2010


17

For Santos and Oil Search, we believe an NAV approach is appropriate given a significant portion of theirsvalues are attached to future LNG projects (PNG LNG for OSH, GLNG and PNG LNG for Santos). On thisbasis, we set our price targets for Santos and Oil Search at AUD17.00 and AUD7.50 (Exhibit 26 and

Exhibit 27).

Exhibit 26Santos Net Asset Value

Santos NAV Valuation At $80 (Real) Oil $100 (Real) Oil


Equity

(%)

Risk

(%)

Total

Res. NPV

Risked NPV per

share

Risked NPV per

share

M Boe US$M AUD AUD

Corporate

Net Cash 371 0.5 0.5

Farm-out Proceeds (20% GLNG) 957 1.4 1.4

Central SG&A (609) -0.9 -0.9

Production

Australia

Eastern AustraliaCooper Basin 60-75% 274 2,238 3.3 3.9

Other E. Australia 53 318 0.5 0.5

Western Australia and NT

Bayu-Undan 11% 44 453 0.7 0.8

John Brookes 45% 71 414 0.6 0.6

Barrow Island 29% 12 166 0.2 0.3

Other WA and NT 38 313 0.5 0.6

Indonesia Maleo/ Oyong 15 78 0.1 0.1

Development

PNG PNG LNG 13.5% 220 2,743 4.0 5.3

Australia* 98 689 1.0 1.1

Indonesia Peluang/ Wortel 15 78 0.1 0.1

Vietnam Chim Sao/ Dua 38% 14 113 0.2 0.3

NAV

Production 508 3,980 5.9 6.8

Development 348 3,622 5.3 6.8

Contingent Resources 1074 702 1.0 1.0

Base NAV (incl. Net Cash) 1929 9,023 13.3 15.7

Upside

GLNG T1 40% 100% 538 1,837 2.7 3.7

GLNG T2 40% 25% 538 1,600 0.6 0.8

PNG LNG T3 13.5% 25% 138 952 0.4 0.5

Total NAV 3,144 13,412 17.0 20.7

* Includes Kipper, Reindeer, Henry, Halyard



18/23

Asia-PacificOil&Gas

October 6, 2010


18

Exhibit 27Oil Search Net Asset value

Oil Search NAV Valuation At $80 (Real) Oil $100 (Real) Oil


Equity

(%)

Risk

(%)

Total

Res. NPV

Risked NPV/

share Risked NPV/share

M Boe $M AUD AUD

Corporate

Net Cash 325 0.29 0.29

Central SG&A -182 -0.16 -0.16

Production

PNG

Kutubu Area 60% 21.6 525 0.46 0.55

Moran PDL 2 60% 12.2 137 0.12 0.15

Moran PDL 5 41% 10.4 145 0.13 0.15

Moran PDL 6 73% 0.3 13 0.01 0.01

Gobe PDL 3 36% 0.7 12 0.01 0.01

Gobe PDL 4 10% 0.3 6 0.01 0.01

Hides GTE Project 100% 9.8 39 0.03 0.04

SE Mananda 72% 0.8 35 0.03 0.04

Development

PNG PNG LNG T1&T2 29% 591.5 5,945 5.26 6.95

NAV

Production 56 911 0.81 0.96

Development 591 5,945 5.26 6.95

PNG exploration upside 579 289 0.26 0.26

International* (2C Resources) 125 150 0.13 0.13

Base NAV (incl. Net Cash) 1,351 7,438 6.58 8.42

Upside

PNG LNG Train 3 (2017) 29% 50% 296 2,019 0.89 1.22

PNG LNG Train 4 (2018) 29% 0% 296 1,613 - -

Total NAV 1,943 11,070 7.48 9.65

Source:

We value large cap integrated oil and gas companies by identifying the forward price to book multiples theyshould trade at based on returns on equity, long term earnings growth expectations, dividend payout ratioand cost of equity. Our starting point is that Fwd P/B = (ROE x PO) / (Ke g), where is our estimates ofROE for 2011, PO is the dividend payout ratio, Ke is the cost of equity, and g is the long term growth rates.We set our price for PTR and RIL at HKD10.50 and INR1160 respectively (Exhibit 28).

Exhibit 28Summary of price targets

Summary of price targets 2011E

Company Cur Ke Payout Ratio LT Growth rates 2011E ROE 2011E BVPS x P/B = Price Target

PTR HKD 8.5% 45% 4% 17.2% 6.1 1.7 10.5

RIL INR 8.5% 20% 7% 16.0% 540.6 2.1 1160

Source:


19/23

Asia-PacificOil&Gas

October 6, 2010


19

Risks

Woodside: Risks to our Woodside price target include a decline in oil price as given the high correlationand beta with oil or delays in the construction of Pluto 1. Upside risk will be a major discovery in theCarnarvon basin over the next 6 months which transforms their ability to deliver the Pluto 2 LNG project.

Santos: Risks to our Santos price target include a significant change in oil prices given the high correlationand beta with oil or delays to its GLNG project where we expect FID at the end of 2010 due to failure tosecuring LNG offtake agreements. The possibility of cost overruns on this project also represents a possiblerisk.

Oil Search: Risks to our Oil Search price target include a decline in oil prices given the high correlation andbeta with oil, or failure to progress their PNG LNG project in a timely way due to political or social unrest,for which a significant amount of value is already embedded within the share price. Given the position ofXOM in the project we believe that cost overruns and delays will be avoided.

PetroChina: downside risks to our PetroChina price target include a decline in oil prices given the highcorrelation and beta with oil, accelerated production decline at Daqing oil field and larger than expectedlosses in their refining division as a result of government fuel price subsidies. The introduction of resourcetax is a further downside risk. Better than expected refining margins and domestic gas prices as a result ofpolicy changes represent an upside risk to our price target.

Reliance: Risks to our Reliance price target include a decline in oil prices given the high correlation andbeta with oil and operational problems relating to Reliance as it ramps up Dhirubhai which result in asignificantly lower than expected production output. Sustained weakness in refining and petrochemicalmargins could be a further downside risk if economic recovery is slower than expected and demand growthremains weak.


20/23

SRO REQUIRED DISCLOSURES

References to "Bernstein" relate to Sanford C. Bernstein & Co., LLC, Sanford C. Bernstein Limited, and Sanford C. Bernstein, a unit ofAllianceBernstein Hong Kong Limited, collectively.

Bernstein analysts are compensated based on aggregate contributions to the research franchise as measured by account penetration,productivity and proactivity of investment ideas. No analysts are compensated based on performance in, or contributions to, generatinginvestment banking revenues.

Bernstein rates stocks based on forecasts of relative performance for the next 6-12 months versus the S&P 500 for stocks listed on theU.S. and Canadian exchanges, versus the MSCI Pan Europe Index for stocks listed on the European exchanges (except for Russiancompanies), versus the MSCI Emerging Markets Index for Russian companies and stocks listed on emerging markets exchanges outsideof the Asia Pacific region, and versus the MSCI Asia Pacific ex-Japan Index for stocks listed on the Asian (ex-Japan) exchanges - unlessotherwise specified. We have three categories of ratings:

Outperform: Stock will outpace the market index by more than 15 pp in the year ahead.

Market-Perform: Stock will perform in line with the market index to within +/-15 pp in the year ahead.

Underperform: Stock will trail the performance of the market index by more than 15 pp in the year ahead.

Not Rated: The stock Rating, Target Price and estimates (if any) have been suspended temporarily.

As of 09/28/2010, Bernstein's ratings were distributed as follows: Outperform - 45.0% (1.7% banking clients) ; Market-Perform - 47.8%(1.0% banking clients); Underperform - 7.2% (0.0% banking clients); Not Rated - 0.0% (0.0% banking clients). The numbers in parenthesesrepresent the percentage of companies in each category to whom Bernstein provided investment banking services within the last twelve(12) months.

Neil Beveridge maintains a long position in BP PLC (BP).

Accounts over which Bernstein and/or their affiliates exercise investment discretion own more than 1% of the outstanding common stock ofthe following companies STO.AU / Santos Ltd, OSH.AU / Oil Search Ltd.

In the next three (3) months, Bernstein or an affiliate expects to receive or intends to seek compensation for investment banking servicesfrom WPL.AU / Woodside Petroleum Ltd, STO.AU / Santos Ltd, OSH.AU / Oil Search Ltd, 857.HK / PetroChina Co Ltd, PTR / PetroChinaCo Ltd, RIL.IN / Reliance Industries Ltd.

12-Month Rating History as of 10/04/2010

Ticker Rating Changes

857.HK O (IC) 06/29/09

OSH.AU O (IC) 06/29/09

PTR O (IC) 06/29/09

RIL.IN M (RC) 04/27/10 O (IC) 06/29/09

STO.AU O (RC) 07/12/10 M (RC) 04/09/10 O (IC) 06/29/09

WPL.AU O (RC) 11/17/09 M (IC) 06/29/09

Rating Guide: O - Outperform, M - Market-Perform, U - Underperform, N - Not Rated

Rating Actions: IC - Initiated Coverage, DC - Dropped Coverage, RC - Rating Change


21/23


22/23

OTHER DISCLOSURES

A price movement of a security which may be temporary will not necessarily trigger a recommendation change. Bernstein will advise as andwhen coverage of securities commences and ceases. Bernstein has no policy or standard as to the frequency of any updates or changes to itscoverage policies. Although the definition and application of these methods are based on generally accepted industry practices and models,please note that there is a range of reasonable variations within these models. The application of models typically depends on forecasts of arange of economic variables, which may include, but not limited to, interest rates, exchange rates, earnings, cash flows and risk factors that aresubject to uncertainty and also may change over t ime. Any valuation is dependent upon the subjective opinion of the analysts carrying out this

valuation.

This document may not be passed on to any person in the United Kingdom (i) who is a retail client (ii) unless that person or entity qualifies as anauthorised person or exempt person within the meaning of section 19 of the UK Financial Services and Markets Act 2000 (the "Act"), or qualifiesas a person to whom the financial promotion restriction imposed by the Act does not apply by virtue of the Financial Services and Markets Act2000 (Financial Promotion) Order 2005, or is a person classified as an "professional client" for the purposes of the Conduct of Business Rules ofthe Financial Services Authority.

To our readers in the United States: Sanford C. Bernstein & Co., LLC is distributing this publication in the United States and acceptsresponsibility for its contents. Any U.S. person receiving this publication and wishing to effect securities transactions in any security discussedherein should do so only through Sanford C. Bernstein & Co., LLC.

To our readers in the United Kingdom: This publication has been issued or approved for issue in the United Kingdom by Sanford C. BernsteinLimited, authorised and regulated by the Financial Services Authority and located at Devonshire House, 1 Mayfair Place, London W1J 8SB, +44(0)20-7170-5000.

To our readers in member states of the EEA: This publication is being distributed in the EEA by Sanford C. Bernstein Limited, which isauthorised and regulated in the United Kingdom by the Financial Services Authority and holds a passport under the Investment ServicesDirective.

To our readers in Hong Kong: This publication is being issued in Hong Kong by Sanford C. Bernstein, a unit of AllianceBernstein Hong KongLimited. AllianceBernstein Hong Kong Limited is regulated by the Hong Kong Securities and Futures Commission.

To our readers in Australia: Sanford C. Bernstein & Co., LLC and Sanford C. Bernstein Limited are exempt from the requirement to hold anAustralian financial services licence under the Corporations Act 2001 in respect of the provision of the following financial services to wholesaleclients:

providing financial product advice;

dealing in a financial product;

making a market for a financial product; and

providing a custodial or depository service.

Sanford C. Bernstein & Co., LLC, Sanford C. Bernstein Limited and AllianceBernstein Hong Kong Limited are regulated by, respectively, theSecurities and Exchange Commission under U.S. laws, by the Financial Services Authority under U.K. laws, and by the Hong Kong Securitiesand Futures Commission under Hong Kong laws, all of which differ from Australian laws.

One or more of the officers, directors, or employees of Sanford C. Bernstein & Co., LLC, Sanford C. Bernstein Limited, Sanford C. Bernstein, aunit of AllianceBernstein Hong Kong Limited, and/or their affiliates may at any time hold, increase or decrease positions in securities of anycompany mentioned herein.

Bernstein or its affiliates may provide investment management or other services to the pension or profit sharing plans, or employees of anycompany mentioned herein, and may give advice to others as to investments in such companies. These entities may effect transactions that aresimilar to or different from those recommended herein.


23/23

Bernstein Research Publications are disseminated to our customers through posting on the firm's password protected website,www.bernsteinresearch.com. Additionally, Bernstein Research Publications are available through email, postal mail and commercial researchportals. If you wish to alter your current distribution method, please contact your salesperson for details.

Bernstein and/or its affiliates do and seek to do business with companies covered in its research publications. As a result, investors should beaware that Bernstein and/or its affiliates may have a conflict of interest that could affect the objectivity of this publication. Investors shouldconsider this publication as only a single factor in making their investment decisions.

This publication has been published and distributed in accordance with Bernstein's policy for management of conflicts of interest in investment

research, a copy of which is available from Sanford C. Bernstein & Co., LLC, Director of Compliance, 1345 Avenue of the Americas, New York,N.Y. 10105, Sanford C. Bernstein Limited, Director of Compliance, Devonshire House, One Mayfair Place, LondonW1J 8SB, United Kingdom, orSanford C. Bernstein, a unit of AllianceBernstein Hong Kong Limited, Director of Compliance, Suite 3401, 34th Floor, One IFC, One HarbourView Street, Central, Hong Kong.

CERTIFICATIONS

I/(we), Neil Beveridge, Ph.D., Senior Analyst(s), certify that all of the views expressed in this publication accurately reflect my/(our) personalviews about any and all of the subject securities or issuers and that no part of my/(our) compensation was, is, or will be, directly orindirectly, related to the specific recommendations or views in this publication.

pproved By: NK

Copyright 2010, Sanford C. Bernstein & Co., LLC, Sanford C. Bernstein Limited, and AllianceBernstein Hong Kong Limited, subsidiaries of AllianceBernstein L.P. ~ 1345 Avenue oAmericas ~ NY, NY 10105 ~ 212/756-4400. All rights reserved.

his publication is not directed to, or intended for distribution to or use by, any person or entity who is a citizen or resident of, or located in any locality, state, country or other jurisdiction where such distribution, pvailability or use would be contrary to law or regulation or which would subject Bernstein or any of their subsidiaries or affiliates to any registration or licensing requirement within such jurisdiction. This publication is basublic sources we believe to be reliable, but no representation is made by us that the publication is accurate or complete. We do not undertake to advise you of any change in the reported information or in the opinihis publication was prepared and issued byBernstein for distribution to eligible counterparties or professional clients. This publication is not an offer to buy or sell any security, and it does not constitute investment, dvice. The investments referred to herein may not be suitable for you. Investors must make their own investment decisions in consultation with their professional advisors in light of their specific circumstances. Tvestments may fluctuate and investments that are denominated in foreign currencies may fluctuate in value as a result of exposure to exchange rate movements Information about past performance of an investm

Bernstein - Global Gas Decoupling, the Rising Marginal Cost of LNG and the Asian Gas Premium...

Documents

Transcript of Bernstein - Global Gas Decoupling, the Rising Marginal Cost of LNG and the Asian Gas Premium...