Australian LNG outlook - Macquarie€¦ · Squeezing through the closing window the surviving LNG projects but it looks like too little, too late. 7 Sep 2010 A building threat from

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AUSTRALIA

Australian LNG - Related Research

Research Date

Sticker shocks drive bargain hunting 10 Sep 2012

Capacity constraints bite as activity rises

4 May 2012

Buyer bonanza 16 April 2012

Beware the false dawn 26 Oct 2011

Catching the last wave 23 June 2011

Japan likely to look to LNG 15 Mar 2011

Backlogs, bottlenecks and budget blowouts

1 Feb 2011

Squeezing through the closing window 7 Sep 2010

A building threat from Russia 15 June 2010

Chinese gas reform may encourage domestic production of LNG imports

2 June 2010

Less of a one-way bet 12 Jan 2010

Australian LNG rescued by delays 15 Sep 2009

Source: Macquarie Research, December 2012

Recommendation and price targets

Price NAV % disc. Target Rec

WPL 34.04 41.06 17% 37.50 Neutral

STO 10.88 17.98 39% 16.00 Outperform

ORG 11.12 17.20 35% 15.50 Outperform

OSH 7.04 9.96 29% 9.00 Outperform

Source: Factset, Macquarie Research, December 2012

7 December 2012 Macquarie Securities (Australia) Limited

Australian LNG outlook Strangling the golden goose Event

With blow-outs recently announced at PNG LNG, QCLNG, GLNG & Gorgon,

the anticipated cost pressures that we wrote about two years ago are hitting

the headlines thick and fast (see „Backlogs, bottlenecks & budget blowouts‟).

As a result, we are growing increasingly confident that Ichthys could turn out

to be Australia‟s last greenfield LNG project (a view we presented in „Catching

the last wave‟ – June 2011). Indeed, this view is supported by the growing

suggestion that Browse – Australia‟s largest remaining undeveloped resource

– will struggle to yield acceptable returns going to James Price Point.

Impact

From bad to worse: Australia‟s five most advanced LNG developments are

already an average of 32% over budget and 6 months late despite being only

~60% complete. This has seen forecast project IRRs fall from 14.9% to 11.7%

providing scant reward for the considerable development risks endured.

In sight of the peak: We continue see aggregate Australian LNG capex

peaking in 2013 suggesting the worst may yet lie ahead. However, taking a

wider look across the economy, pull backs in other sectors means it appears

overall investment spending could fall next year.

Survival of the biggest: With the oil price remaining high while commodity

prices have seen sharp falls, miners have pulled back capex more

aggressively than the LNG industry which has firm delivery commitments and

oil-linked contracts. At the margin, this could ease development pressures on

the surviving LNG projects but it looks like too little, too late.

Outlook

Stuck in the middle: Costs are trending higher just as buyers grow more

price-sensitive. As a result, LNG project returns are seemingly being

squeezed from both sides meaning either Australian operators will have to

contain local cost pressures or buyers will have to accept higher prices.

Not out of the woods…: Now approaching the business end of several

developments, LNG construction risks are set to rise into 2013. However with

WPL, STO, ORG and OSH having collectively already raised a massive

A$44bn since 2009, most available funding levers have been exploited

meaning any further overruns are likely to be equity rather than debt financed.

…but possibly out of their depth: LNG has historically been the realm of

the largest industry players better placed to absorb development pressures.

Instead, local operators, with all development eggs typically in just one

basket, are disproportionately exposed if and when things go wrong.

Options expiring out-of-the-money: Given our view that Australia‟s LNG

market window is closing fast, we believe investors should be willing to pay

less for unsanctioned LNG developments that look increasingly unlikely to

progress. That said, given the heavy development discounts already priced in,

such options are typically already footnotes to current valuations.

Oil Search still the best placed in a competitive world: Being outside

Australia and being Exxon-operated, PNG LNG was meant to be immune

from local development pressures. That said, we continue to believe PNG

LNG offers the lowest cost expansion potential which would be competitive

with any new-build LNG project despite growing supply-side competition.

Macquarie Private Wealth Australian LNG outlook

7 December 2012 2

Strangling the golden goose Australia‟s well documented development bottlenecks are driving cost pressures and slowing

progress. Compounding the issue is growing supply side competition in LNG markets which is

handing buyers more choice and greater negotiating power meaning they are increasingly finding

quicker, cheaper and lower-risk supplies elsewhere.

Australia’s falling competitiveness to hurt the next wave

The last couple of years have witnessed a rapid deterioration in Australia‟s relative standing as a coal

producer and the fear is that the same may now be happening in LNG given that several current

developments look challenged to yield acceptable returns.

Our analysis of the LNG cost curve supports this view with Australia‟s current batch of

sanctioned and proposed projects consistently needing among the highest gas prices to

breakeven. This rising cost base is all the more concerning given the anticipated influx of LNG

tanker capacity over coming years which looks set to erode Australia‟s locational advantages

into the Asian market.

Shell recently presented estimates calling for further Australian cost inflation of between 20-

40% over the next five years. If this plays out, in the absence of a high liquids yield, it

suggests local LNG projects sanctioned in 2014 could require gas prices of over U$16/mmBtu

merely to deliver a 12% return. Such a high breakeven gas price requirement is likely to be

too high for the buyers and too risky for the sellers meaning future LNG developments in

Australia may simply not be good business.

What‟s more, with so much Australian LNG sold over recent years and with Australia

seemingly set to be the world‟s largest LNG producer by the end of the decade, there is a risk

that buyers may look to diversify supply sources. This means Australia could simply have hit

its acceptable market share limits for the time being.

In order to remain viable, Australia‟s LNG producers will grow increasingly reliant on the

survival of oil-linked prices. However, linking the price of LNG (which has numerous

substitutes - particularly when used in power generation) to the price of oil (which has virtually

no substitutes when used as a transport fuel) means these two energy sources have

significantly different elasticities of demand. As a result, the persistently high oil price coupled

with slowing global GDP growth is acting to expose these fundamental differences.

The net result is that while it has been an exciting few years in the Australian LNG industry, we

nevertheless believe the country‟s market window may be closing quickly and therefore life would

appear to be getting harder for Australia‟s unsanctioned projects.

Against this backdrop, it is perhaps noteworthy that it has now been 10 months since FID at Ichthys -

this is Australia‟s longest period without a green-field LNG project approval since Gorgon got the ball

rolling back in September 2009, perhaps suggesting the anticipated slow-down in future LNG project

sanctions may already have started.

Darkest before dawn

Despite these ongoing development pressures, with many projects still at an early stage, we continue

see aggregate Australian LNG capex peaking in 2013 suggesting the worst may yet lie ahead. That

said, taking a wider look across the economy more broadly, it increasingly looks like overall,

economy-wide investment spending peaked in 2012 and will see a modest fall next year.

This lower and earlier peak than we were expecting two years ago reflects both a drop-off in

non-resources spending (perhaps partly crowded out by the resources sector and the ensuing

high AUD) and the growing headwinds facing the local mining industry.

Capex plans in the mining industry have been hit harder than those of the LNG producers.

This reflects both the contractual nature of LNG supply (making it difficult to scale back even if

operators wanted to) but also the fact that the oil price has remained high. This contrasts to

the miners where the outlook for bulk commodities has deteriorated.

While falling mining capex plans over the next couple of years could free up labour and ease

development pressures, this is likely to be too little, too late. This is because the specialised

skills of LNG plant construction are not easily transferrable from the mine site and because

many LNG project operators have signed fixed-priced contracts in order to preserve margins.


7 December 2012 3

Difficult LNG developments - not new and not solely Australia’s problem

Keeping up 40 years of exponential LNG demand growth with arithmetic capacity additions is proving

increasingly challenging as the market grows, especially as so much or the world‟s LNG engineering

expertise is concentrated in just six companies. So while much of the local cost pressure witnessed

over recent years is undoubtedly driven by Australia-specific factors, a significant part also reflects

the wider challenges of an over-stretched industry around the world.

The lure of legacy assets takes precedence over shareholder value

The fact that greenfield LNG projects offering such modest returns have been sanctioned in Australia

against the backdrop of considerable development risks, falling returns, an increasingly price

sensitive customer base and ultimately falling margins perhaps points to an alternate management

motivation in place of shareholder value. Indeed, rather than focusing on investment returns alone,

we believe some companies may be tempted by current windfall profits (the spot oil price is higher

than the long run marginal cost – and has been for some time) to build long-life legacy assets to

cement their respective futures rather than drive shareholder value or improve ROIC metrics.

Funding pressures building – but have to spend money to grow

In total, we estimate that WPL, STO, ORG and OSH combined have raised a massive A$44bn since

2009 via equity raisings, DRPs, hybrids, corporate debt, project finance and asset sales – this

compares to their combined market caps at ~A$55bn. As a result, having already exploited most

available funding levers, in many cases the local operators do not have the balance sheet capacity to

absorb further cost blow outs given the scale of LNG projects and the budgets involved which in

many cases dwarf current operations.

How are the local players placed?

Woodside – Neutral rating & A$37.50/sh price target: Having exploited the LNG

opportunity ahead of its Australian-listed peers, WPL has already developed a significant

proportion of its LNG asset base offering infrastructural advantages and lower development

exposure. That said, with over 10% of our WPL valuation derived from unsanctioned LNG

projects, WPL is perhaps also the most exposed to Australia‟s closing market window. Against

this backdrop and following the cost pressures at Gorgon, we believe it would be a brave CEO

that takes on a James Price Point development in this environment. Consequently, as

demonstrated by the recent Israel and Myanmar deals, this predicament is pushing WPL

down the acquisition path, even if this comes at the cost of significant political risk.

Santos – Outperform rating & A$16/sh price target: Since the end of 2009, STO has

sanctioned two LNG projects which have driven a doubling of the company‟s core NAV and a

40% increase in its 2P reserves while also underpinning an expected 42% increase in

production over the next five years. Despite this and the U$60/bbl rise in the oil price, STO‟s

shares have fallen 23% over this period (admittedly not helped by two equity raisings)

demonstrating the market‟s lack of faith in the deliverability these projects and perhaps also

wider concerns around the underlying economics of CSG.

Origin Energy – Outperform rating & A$15.50/sh price target: The overall impression is

that the APLNG development is going well and the relative advantages that APLNG enjoys

over its peers are materialising as expected. That said, with over three years still to go until

start-up at train 2, there is still a long way to go. So overall, while we see little obvious near

term upside in the utilities business and a long development road ahead at APLNG, we

nevertheless believe ORG is close to the end of the de-rating cycle and think that by the end

of 2013, the ORG outlook should have improved significantly.

Oil Search – Outperform rating & A$9.00 price target: Being outside Australia and being

Exxon-operated, PNG LNG was meant to be immune from local development pressure and

therefore the recent over-run was particularly disappointing. However, after the subsequent

pull-back, OSH is back trading slightly below core NAV which we see as a good entry point

given its low risk upside from greater clarity around the Taza discovery, the ongoing near field

appraisal programme and the growing potential for a third train in due course. Indeed, we

think there is no other stock in the sector that can match OSH‟s rich vein of catalysts and

medium-term production growth.


7 December 2012 4

Too much of a good thing Gifted with a brief market window, Australian operators have sanctioned a massive 61mtpa of green-

field LNG capacity in just three years. To put this into perspective, this is equivalent to almost 70% of

all capacity sanctioned globally over this period and accounts for approximately 25% of current global

demand. Such a flurry of activity against the backdrop of a generational mining boom has predictably

driven considerable development bottlenecks. These bottlenecks are driving considerable cost

pressures and slow progress, meaning that buyers are increasingly finding quicker, cheaper and

lower risk routes to market elsewhere. Consequently, while Australia‟s LNG flame is burning brightly,

the local industry is also struggling with a broader credibility issue over the deliverability its large,

capital intensive LNG projects which threatens to tarnish the premium Australian LNG brand.

Excluding APLNG, Wheatstone, Prelude and Ichthys (where work remains at an early stage)

the remaining five current Australian LNG developments are already an average of 32% over

budget and six months late despite being only ~60% complete. This has seen forecast project

IRRs fall from 14.9% to 11.7%, providing scant reward for the considerable development risks.

This environment of rising risks and falling returns is likely to weigh on future project

sanctions. On the demand side this is because high costs are getting increasingly difficult to

pass on to consumers. Meanwhile, on the supply side, Australia‟s high costs are eroding

returns, which is likely to see operators looking to invest elsewhere in their portfolios.

Compounding Australia‟s cost pressures is the growing supply-side competition which is

handing LNG buyers more choice and greater negotiating power. Indeed, while much remains

highly speculative, we nevertheless count a massive ~150mtpa of newly proposed capacity

that has been announced over the past 18 months alone, which is equivalent to more than

60% of current global demand. Here we particularly note the growing momentum behind US

exports which look set to cost around a quarter of Australia‟s brownfield projects enabling US

operators to offer greater pricing flexibility. As a result, every incremental tonne out of the US

is likely to result in one less tonne out of Australia.

These current development pressures reinforce our view that Ichthys is likely to be Australia‟s last

greenfield project (a view we first presented back in 2010 and which is apparently supported by the

growing suggestion that Browse – Australia‟s largest remaining undeveloped resource – will struggle

to yield acceptable returns as a greenfield, shore-base development). Going forward, in order to

remain competitive, we expect any growth in Australia‟s liquefaction capacity to be driven by

brownfield expansions, floating LNG or small-scale plants which could circumvent many of the local

development bottlenecks. Here we note recent comments from Shell‟s Ann Pickard suggesting

floating LNG would be “the saviour of the Australian LNG industry over the next decade or so”.

Against this backdrop, it is perhaps noteworthy that it has now been 10 months since FID at Ichthys -

this is Australia‟s longest period without a green-field LNG project approval since Gorgon got the ball

rolling back in September 2009 perhaps suggesting the slow-down may already have started.

Fig 1 Although it remains early days for many developments, cost pressures have already seen estimated returns on Australia’s current batch of LNG projects fall from 14.4% to 11.9%

Project

Complete

Budget at

FID (US$bn)

Current budget

(US$bn)

Official %

overrun since FID

Macquarie estimated

cost (US$bn)

Macquarie estimated % overrun

Original build

period (months)

Estimated

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IRR on

old budget

IRR on

new budget

Macquarie estimated

IRR

Pluto 100% $11.2 $14.1 26% $14.1 26% 41 15 13.0% 10.2% 10.2% PNG LNG 70% $15.0 $19.0 27% $20.0 33% 54 4 22.4% 19.2% 18.6%

Gorgon 55% $37.0 $52.0 41% $52.0 41% 64 3 13.5% 10.5% 10.5%

QCLNG 45% $15.0 $20.4 36% $20.8 39% 44 3 13.5% 9.8% 9.7%

GLNG 40% $16.0 $18.5 16% $23.4 46% 48 6 13.3% 11.3% 9.4%

APLNG 22% $20.0 $20.0 0% $25.2 26% 47 3 11.7% 11.7% 10.4%

Wheatstone 7% $29.0 $29.0 0% $33.5 16% 57 0 14.9% 14.9% 12.8%

Prelude* 10% $12.0 $12.0 0% $13.2 10% 67 0 13.1% 13.1% 12.7%

Ichthys 5% $34.0 $34.0 0% $42.0 24% 60 0 14.4% 14.4% 13.8%

Total/avg 39% $189.2 $219.0 16% $244.1 29% 53 4 14.4% 12.8% 11.9%



7 December 2012 5

Capacity constraints starting to bite

Even before the current development pressures, Australia did not have a good record of project

delivery. Indeed, we estimate of the ~22 projects over A$2bn to have been sanctioned locally since

2000, only one (Darwin LNG) was delivered on time and on budget. We estimate that the rest were

an average of 44% more expensive and seven months later than anticipated. This sets a worrying

precedent given the ramp-up in investment expected over coming years.

Against this backdrop, the return erosion witnessed at Pluto could be a sign of things to come (here

we estimate the IRR fell from ~12% at FID to only 3.8% by first production under our longer term oil

price assumption at the time of FID in July 2007 of U$57/bbl). Surely the industry cannot work on the

assumption that oil prices continue to rise faster than project costs in order to justify expensive

developments both because, with an oil price already above U$100/bbl, this is unlikely to be the case

indefinitely but also because such an environment would likely accelerate any move away from oil-

indexed LNG contracts.

Fig 2 Australia’s mining capital cost inflation has averaged 5.1% over the past decade

Fig 3 Over the past decade, Australia’s major capital projects (>U$2bn) have, on average, been delivered 44% over budget and 7 months late

Source: IPA, Rio Tinto, Macquarie Research, December 2012 Source: Macquarie Research, December 2012

The specific drivers of these local cost pressures are well documented with the strong local currency,

unrealistic union demands, high-cost local manufacturing, falling labour productivity and excessive

political red tape all hampering progress. These issues however all stem from the overwhelming

development backlog – Australia has seemingly bitten off more than it can chew.

Strong appreciation of the AUD: While it varies between projects, we estimate that 57% of

the aggregate budgets across the current batch of Australian LNG developments is exposed

to the local currency. On this simplistic basis, the move from initial fx assumptions to spot

adds ~U$10bn or an average of 6% to current USD budgets.

Remote locations: At 15.5tcf, Browse is Australia‟s largest undeveloped gas resource – this

compares to emerging supply-side competitors such as Canada and East Africa which each

have ~100tcf basically in a single location. So while initial greenfield developments in these

countries may be expensive – both will have considerably more subsequent brownfield

opportunities, potentially making them more attractive longer term bets.

Higher taxes: Australia‟s largest foreign investor, Chevron, recently said: “Industry confidence

in making major capital investments is being affected by the current fiscal environment. This

increases business costs, erodes international competitiveness and diminishes investor

confidence. These costs add to the growing list of disincentives to invest here.” Ironically

however, the nature of Australia‟s PRRT means that the government is sharing in current

development pressures providing at least some protection from ongoing cost escalation.

Labour shortages: The local contractor market is simply not sufficiently deep to cope with

current activity levels – this lack of competition is driving up costs and improving the unions‟

negotiating position – but there are early signs this could now perhaps be starting to change.

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7 December 2012 6

Increasing regulatory burden: The duplication between State and Federal regulations, the

growing costs of environmental compliance and painstakingly slow government approvals

processes have been unanimously cited by project operators as an impediment to progress.

Scope changes: In many cases, the rush to exploit Australia‟s brief market window saw

planning processes squeezed. With such planning so crucial to ultimate successful project

delivery, rushed engineering studies appears to now be taking their toll.

Despite these ongoing development pressures, with many developments still at an early stage, we

continue see LNG capex peaking in 2013 suggesting the worst may yet lie ahead. However, without

further project sanctions (which are looking increasingly challenged) we expect spending to fall away

sharply beyond this peak.

Fig 4 Two years ago we saw committed LNG capex peaking at under US$15bn in 2013…

Fig 5 …however, subsequent FIDs and cost pressures have seen this estimate more than double to over U$30bn – but will fall sharply after this

Source: WoodMac, Macquarie Research, December 2012 Source: WoodMac, Macquarie Research, December 2012

Australia’s falling competitiveness to hurt the next wave…

The last couple of years have witnessed a rapid deterioration in Australia‟s relative standing as a coal

producer and the fear is that the same may now be happening in LNG given that several current

developments look challenged to yield acceptable returns.

A recent Port Jackson study on the mining industry found that only five years ago, 63% of

Australia‟s thermal coal production was in the bottom half of the cost curve. Today however

this has fallen to 28% (or only 15% if we look at new mines) which has seen several older

mines closed and proposed expansions postponed.

On the coking coal side, recent comments by US producer, Alpha Natural Resources, points

to Australia‟s falling competitiveness “The fact is that their (Australian) cost inflation has been

so rapid that it is actually improving the US‟s relative position in the global seaborne

metallurgical market”.

Current conditions are also taking their toll on Australia‟s unsanctioned LNG projects

(particularly Browse, Arrow and several of the proposed brownfield expansions). Here we note

recent comments from Ann Pickard at Shell saying “the Australian LNG industry has probably

the highest cost base now anywhere in the world” while Woodside‟s Peter Coleman

suggested “Australia can‟t compete dollar for dollar with international competitors”. Such a

high cost base puts significant pressure on the quality of the resource to compensate however

on this front, much of the low-hanging fruit has already been picked.

Our analysis of the LNG cost curve supports this view with Australia‟s current batch of sanctioned

and proposed projects consistently needing among the highest gas prices to breakeven. This rising

cost base is all the more concerning given the anticipated influx of LNG tanker capacity over coming

years which looks set to lower transport costs and thereby bringing down the friction of distance in

LNG markets. This will erode Australia‟s locational advantages into the Asian market and bring local

producers into more direct competition with typically lower cost global peers.

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7 December 2012 7

Fig 6 The LNG cost curve – local cost pressures are seeing Australia’s LNG projects drifting up the cost curve to now be among the least competitive

Source: WoodMac, Macquarie Research, December 2012

Somewhat alarmingly, although local projects already appear increasingly uncompetitive, the industry

apparently expects local cost pressures to persist over the medium term. As a result, in the absence

of increasingly unlikely hikes in Asian LNG prices, this environment looks set to further erode the

returns profile of Australia‟s next batch of proposed LNG projects.

Back in 2005, Gorgon was expected to cost just U$11bn for a 10mtpa development equating

to U$1,100/t, which compares to the recently revised budget of U$52bn or U$3,333/t. What‟s

more, we note that despite leveraging considerable brownfield benefits, Chevron is flagging

an anticipated budget for train 4 of over U$10bn or ~U$2,000/t, suggesting the next wave of

Australian expansion projects will not be cheap either.

Shell recently cited Australia as „a particular concern on cost inflation‟ pointing to IHS/Cera

estimates calling for further local cost inflation of between 20-40% over the next 5 years. If this

plays out, in the absence of a high liquids yield, it suggests local LNG projects sanctioned in

2014 could require gas prices of over U$16/mmBtu merely to deliver a 12% IRR – this

compares to US exports which at current Henry Hub prices can deliver similar returns at a

price under U$10/mmBtu. Such a high breakeven gas price requirement is likely to be too high

for the buyers and too risky for the sellers meaning future LNG developments in Australia may

simply not be good business.

Fig 7 Since 2000, Australian LNG development costs have risen faster than global upstream costs (and this trend looks set to continue)

Fig 8 Shell expects local development costs to rise a further 20-40% from 2010 to 2014, suggesting the next wave of local LNG projects will struggle

Source: IHS Cera, Macquarie Research, December 2012 Source: IHS Cera, Shell, Macquarie Research, December 2012

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7 December 2012 8

…but Australia had to move quickly and perhaps took its eye off costs

Since 2008 there have been few LNG projects outside Australia that were able to hit what appears to

be a tight medium-term market window from ~2013-2017. What‟s more, the obvious threat that there

was during this period came from Qatar, however even this threat was mitigated by Qatar‟s

unwillingness to lower prices. This created the perverse situation where Australia (the high-cost

producer) was consistently able to undercut Qatar (the low-cost producer) and steal market share.

Recognising this was clearly an unsustainable situation. Australia had to move quickly to exploit

market conditions to get its expensive green-field projects developed, meaning that speed, rather

than cost, has been the primary focus over recent years.

While this environment made for an exciting period for the Australian LNG industry, we believe this

country‟s market window may be closing quickly, and therefore life would appear to be getting harder

for Australia‟s unsanctioned projects.

First there is growing competition from the raft of newly proposed LNG supply from around the

world which is creating intense competition for buyers. What‟s more, with so much of this

proposed capacity coming from within the OECD (such as the US and Canada), Australia is

arguably no longer such a relative standout from a geo-political perspective.

Second, Australia‟s unprecedented project backlog is driving cost pressures and extending

development timelines meaning, in many cases, Australia can no longer get its gas to market

as cheaply or as quickly as its competitors.

And finally, with so much Australian LNG sold over recent years and with Australia seemingly

set to be the world‟s largest LNG producer by the end of the decade, there is a risk that

buyers may look to diversify supply sources. This means Australia could simply have hit its

acceptable market share limits for the time being.

So overall, while Australia unquestionably remains on of the world's most reliable LNG suppliers, the

premium Australian brand is perhaps less of a differentiator today than it was previously.

Darkest before dawn

Despite the bleak outlook presented above, we note that there are perhaps tentative signs that, at

the margin, local development pressures could be starting to ease. Specifically here we point to our

analysis of spending across the Australian economy rather than merely looking at the LNG industry

in isolation (Figs 9 & 10 show our forecasts of the domestic proportion of Australia capex spend back

in late 2010 versus our current forecasts).

Fig 9 2 years ago, peak domestic Australian capex was forecast at ~US$140bn in 2013…

Fig 10 …today the peak looks lower and earlier at ~US$120bn in 2012 while more projects have moved into the ‘speculative’ category

Source: ABS, BREE, Macquarie Research, December 2012 Source: ABS, BREE, Macquarie Research, December 2012

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7 December 2012 9

The conclusion here is that it increasingly looks like overall, economy-wide investment spending

peaked in 2012 and overall spend will see a modest fall next year (although as discussed above, in

isolation, LNG capex still looks set to peak in 2013 merely due to work phasing).

This lower and earlier peak than we were expecting predominately reflects a drop-off in non-

resources spending (perhaps partly crowed out by the mining boom and the ensuing high AUD) and

the growing headwinds facing the local mining industry. Here we refer to the scrapping or deferral of

large mining development proposals (such as Olympic Dam, Outer Harbour, Peak Downs, Mt

Pleasant, Solomon and South Downs), the closure of Queensland coal mines (Gregory, Norwich

Park, Blair Athol, New Oakleigh, Sunnyside) and headcount reductions across the Queensland coal

districts and the Pilbara. All this is freeing up labour which has been a key development constraint

over recent years.

From these graphs, it is noticeable how capex plans in the mining industry have been hit harder than

those of the LNG producers. This reflects both the contractual nature of LNG supply (making it

difficult to scale back even if operators wanted to) but also the fact that the oil price has remained

high (and local producers typically sell on an oil-linked basis). This contrasts to the miners where

while the outlook for bulk commodities has deteriorated (to which the miners have magnified their

exposure through recent cost inflation).

This apparently collapsing project backlog on the mining side could reduce contractor

bargaining power, which at the margin could alleviate some cost pressures.

Falling mining activity is also freeing up historically scarce labour which could ease pressures

on the LNG developments. That said, we note that with many of these LNG projects entering

the second half of the development, it is typically highly skilled, specialised labour that is

required which may not be easily transferrable from the mine site.

What‟s more, while improving access to labour can clearly help to preserve schedule, it is

likely to have less of a direct read-through on the cost side given existing enterprise

agreements with the unions and the fact that many LNG project operators signed fixed priced

contracts in order to preserve margins. Clearly these contracts work both ways, suggesting

that in many cases it could be the contractor, rather than the operator, that benefits from

falling labour costs at this late stage.

Finally, it is also worth noting that the costs of several raw materials are either rising less

quickly or falling which again acts limit cap cost pressures (here we note Asian steel prices

are down ~7% y/y) however given our bullish iron ore forecasts, this could be short-lived.

Difficult LNG developments are not new and are not solely an Australian problem...

Since 2000, global LNG demand has grown at ~8% per annum (from 141mt to an anticipated 268mt

this year). Keeping up with this exponential demand growth with arithmetic capacity additions is

proving increasingly challenging as the market grows, especially as so much or the world‟s LNG

engineering expertise is concentrated in just six companies (Chiyoda, KBR, Bechtel, JGC, Foster

Wheeler and Technip account for the overwhelming majority of trains built to date).

The stresses created by this exponential demand growth are clear. Until recently, the industry

in its entirety had not attempted to build more than 7 trains at one time – this compares to the

current environment which sees Bechtel alone attempting 11 (including Angola LNG).

What‟s more, this level of activity is expected to persist for several more years with Shell

recently estimating that the LNG industry will need to invest ~U$700bn over the next 15 years

in order to meet forecast demand growth. Interestingly, under our forecast of LNG demand in

2027 (of ~480mtpa) this equates to an implied all-in construction cost of ~U$3,300/t which

compares to the current Australian projects at ~U$3,000/t.

So while much of the local cost pressure witnessed over recent years is undoubtedly driven by

Australia-specific factors, a significant part also reflects the wider challenges of keeping up with such

significant demand growth. This environment has predictably driven industry-wide LNG construction

costs higher.

In the early 2000s there was a trend of falling unit costs as train sizes grew and the industry

witnessed scale benefits. Against this backdrop, BG‟s ALNG train 4 was delivered in 2006,

three months early and within budget at an all-in cost of only U$230/t.


7 December 2012 10

This trend however was soon reversed by changes in raw materials and contracting costs as

well as rising activity levels across the industry. As a result, by the end of the decade, both

Shell‟s Sakhalin II and Statoil‟s Snohvit were eventually delivered close to double the original

budgets. Indeed, over this period Australia‟s own Gorgon project witnessed similar inflation

prior to its eventual sanction in 2009 (in 2003 Gorgon was expected to cost only U$11bn for a

10mpa facility – this compares to current guidance of ~U$52bn – albeit for a larger 15.6mtpa

facility).

The net result is that within a decade, unit LNG construction costs have risen by a massive

~950% from ~U$200/t to over U$2,000/t for the current batch of developments.

Fig 11 The overwhelming focus on Australia has merely exacerbated LNG’s existing trend of rising costs which dates back to ~2005

Source: WoodMac, Macquarie Research, December 2012

It’s getting harder to pass on the industry’s rising costs

In an environment of intensifying supply-side competition (from the likes of the US, Canada, East

Africa, Israel and Russia to name a few) Australia‟s high construction costs are growing increasingly

difficult to pass on to the buyers. What‟s more, even on the demand side, live is getting tough with

buyers growing increasingly price sensitive – indeed, even Japan can seemingly no longer afford

LNG.

As a result, LNG sellers find themselves in the awkward position where costs are trending higher just

as increasingly price-sensitive buyers are seemingly spoilt for choice. All this suggests project returns

are being squeezed from both sides meaning either Australian operators will have to contain local

cost pressures or buyers will have to accept higher prices if the next wave of unsanctioned Australian

projects are to succeed.

As we recently argued in “Australia LNG outlook - Sticker Shocks Drive Bargain Hunting” –

(September 2012), we do not expect LNG prices to collapse simply because the cost of

supply is high while strong demand growth will require new capacity to be built.

That said, high LNG prices could however impact rates of demand growth – this is because as

the LNG market grows, more marginal projects are being sanctioned and the supply cost

curve steepens. Meanwhile in contrast, at these higher levels of production, the demand curve

flattens out as demand moves towards emerging markets where price subsidies and alternate

energy supply options often limit LNG‟s competitiveness.

Therefore, if LNG construction costs continue to rise, emerging demand centres will be

encouraged to stay with coal, especially as ongoing improvements in the efficiency of coal

fired generators (which is driving lower emissions) erodes the relative benefits of LNG as a

cleaner burning fuel.

5mtpa Capacity

Browse

PNG LNG t3

Ichthys

APLNG t1&2

PNG LNG t1&2

Scarborough

Gorgon

Pluto t2

Pluto t1

Darwin LNG

NWS Train 4

NWS Train 5

0

500

1,000

1,500

2,000

2,500

1990 1995 2000 2005 2010 2015 2020

$/tonne per annum (2010 real)


7 December 2012 11

In order to remain viable, the LNG industry‟s high construction costs will grow increasingly

reliant on the survival of oil-linked prices. However, linking the price of LNG (which has

numerous substitutes - particularly when used in power generation) to the price of oil (which

has virtually no substitutes when used as a transport fuel) means these two energy sources

have significantly different elasticity‟s of demand. As a result, the persistently high oil price

coupled with slowing global GDP growth is acting to expose these fundamental differences.

Against this backdrop, Australian operators must be careful not to grow complacent with the

country‟s recent success by merely extrapolating recent trends into the future rather than recognising

the significant changes taking place on the demand side. This is because it is increasingly clear that

buyers no longer see LNG as the marginal fuel source or Australia as the marginal source of LNG

supply.

The lure of legacy assets takes precedence over shareholder value

The fact that greenfield LNG projects offering such modest returns have been sanctioned in Australia

against the backdrop of considerable development risks, falling returns, an increasingly price

sensitive customer base and ultimately falling margins perhaps points to an alternate management

motivation in place of shareholder value. Indeed, rather than focusing on investment returns alone,

we believe some companies may be tempted by current windfall profits (the spot oil price is higher

than the long run marginal cost – and has been for some time) to build long life legacy assets to

cement their respective futures rather than drive shareholder value or improve ROIC metrics.

While not directly related, but nevertheless supporting this view, Wood Mackenzie recently published

a study into corporate exploration performance. One of the study‟s findings was that companies

adding discovered volumes tended to be recognised above those creating value (i.e. the materiality

or size of a discovery was found to be the biggest driver of performance while return on investment

was regarded at the least relevant criteria). From an LNG perspective, this analogy implies that the

larger the reserve implications from sanctioning a project, the lower the acceptable project return.

Fig 12 Wood Mackenzie’s study suggests return on investment is slipping down the priority list in assessing the industry’s exploration performance – could the same be true for new LNG project sanctions?

Source: Wood Mackenzie, Macquarie Research, December 2012

We estimate that cost blow-outs and delays have eroded Pluto‟s IRR to only 10.2% (assuming

U$104/bbl). However, under Macquarie‟s July 2007 oil price assumption of U$57/bbl (when

Pluto was sanctioned) and incorporating what we now know about this difficult development,

we estimate that Pluto had an IRR of just 3.8% at FID. In other words the project was worth

negative A$6/sh to WPL at this time and has since been bailed out by subsequent reserve

additions and the rising oil price.

Given the recent experience at Pluto (and other ongoing developments such as Gorgon), we

believe the market may look for a greater margin for error on new greenfield projects. As a

result, a proposed IRR of ~13% if all goes well is unlikely to be met favourably by investors for

technically, environmentally and politically challenging, remote projects in Australia which are

disproportionately exposed to the development challenges.

0%

10%

20%

30%

40%

50%

Materiality Value creation Success rate F&D costs Return on

investment


7 December 2012 12

Which projects can withstand the increasingly inevitable capex inflation?

Examining this idea of falling returns across the Australian LNG industry, in the tables below we

assess which projects are best positioned to withstand the increasingly inevitable cost inflation by

employing the six screening criteria used by WPL for new LNG investments, namely:

NPV – the present values of future cash flows (in this analysis we use a 10% discount rate)

IRR – WPL looks for IRRs near 15% for brownfield developments but will accept lower than

this on a greenfield project

VIR or PIR – this is essentially the project NPV divided by the initial capex and WPL uses a

hurdle rate of 0.25x.

Payback – WPL looks for project payback in the first 6 to 8 years

Cumulative cash flow – over the first 20 years of a project‟s life, WPL likes to see cumulative

cash flow equal to at least twice the original investment

In the tables below, we highlight in grey the projects that do not meet WPL‟s criteria in the event of

25% and 50% cost over-runs which based on announcements to date appears to be a reasonable

frame of reference. This analysis highlights both the obvious advantages of brownfield over

greenfield developments (with PNG LNG trains 1,2 & 3 the most insulated from blow outs) but also

how easily the thin returns from the CSG projects can be eroded by development hiccups.

Fig 13 How are LNG project economics affected by capex inflation?

NPV (using a flat 10% discount rate) IRR (near 15% for brownfield) VIR or PIR (0.25x hurdle rate)

Project Base +25% cost blow out

+50% cost blow out Base

+25% cost blow out


+25% cost blow out

+50% cost blow out

PNG LNG t3 6,436 5,959 5,499 26.2% 22.9% 20.5% 1.85 x 1.37 x 1.05 x

PNG LNG t1&2 15,875 14,460 12,565 21.0% 19.1% 17.4% 1.18 x 1.01 x 0.82 x

Pluto t2 7,522 5,734 3,964 18.4% 15.5% 13.4% 0.78 x 0.48 x 0.27 x

Sunrise 3,831 2,049 1,444 14.8% 12.3% 10.4% 0.38 x 0.16 x 0.00 x

Browse - JPP 4,624 1,641 -1,342 12.6% 11.1% 9.8% 0.20 x 0.06 x -0.04 x

Browse - NWS 7,778 6,426 5,080 19.5% 16.9% 14.9% 0.91 x 0.61 x 0.40 x

Browse - FLNG 5,834 2,886 -55 14.8% 12.3% 10.4% 0.36 x 0.15 x 0.00 x

APLNG t1&2 5,130 1,252 -2,669 11.4% 9.4% 7.8% 0.27 x 0.05 x -0.10 x

GLNG t1&2 3,239 346 -2,548 12.9% 10.8% 9.1% 0.23 x 0.02 x -0.12 x

NPV/initial capex (must be >20%) Payback (6-8yr target) CCF/Initial capex (looking for >2x)

Project Base +25% cost blow out


+25% cost blow out


+25% cost blow out

+50% cost blow out

PNG LNG t3 99% 73% 56% 6.75 7.00 7.50 5.62 x 4.62 x 3.98 x

PNG LNG t1&2 84% 61% 44% 8.25 8.75 9.25 4.82 x 3.94 x 3.19 x

Pluto t2 68% 42% 24% 6.75 7.75 8.50 5.05 x 4.18 x 3.64 x

Sunrise 29% 13% 7% 8.50 9.50 10.25 3.86 x 3.23 x 2.74 x

Browse - JPP 12% 3% -2% 9.25 10.25 11.50 3.33 x 2.69 x 2.26 x

Browse - NWS 32% 21% 14% 9.00 9.75 10.50 5.39 x 4.46 x 3.86 x

Browse - FLNG 15% 6% 0% 7.50 7.75 9.25 2.72 x 2.20 x 1.87 x

APLNG t1&2 26% 5% -9% 10.00 11.50 12.50 3.74 x 3.00 x 2.50 x

GLNG t1&2 18% 1% -9% 10.25 11.75 12.75 3.63 x 2.91 x 2.42 x



7 December 2012 13

Funding pressures building – but have to spend money to grow

In total, we estimate that WPL, STO, ORG and OSH combined have raised a massive U$44bn since

2009 via equity raisings, DRPs, hybrids, corporate debt, project finance and asset sales – this

compares to their combined market caps at ~A$60bn. As a result, having already exploited most

available funding levers, in many cases the local operators do not have the balance sheet capacity to

absorb further cost blow outs given the scale of LNG projects and the budgets involved which in

many cases dwarf current operations. Consequently we see fresh equity issuances would appear to

be the most obvious way of dealing with further cost pressures.

Fig 14 Local LNG players have raised over U$44bn since 2009 via asset sales, project finance, corp. debt, DRP’s and equity – this compares to their combined market caps at ~A$60bn…

Fig 15 …however these funds will be spent quickly with STO and ORG in particular set to spend between 20-30% of their market capitalisations annually during the development period

Source: Macquarie Research, December 2012 Source: Macquarie Research, December 2012

WPL: With Pluto on-stream, WPL has a strong, sustainable cash flow base. However in

Browse, Sunrise, Leviathan and the Pluto expansions, WPL also has numerous capital

intensive development options. In this context we note comments from Moody‟s suggesting

management‟s recent move into Israel is “credit negative” as it reduced funds to reduce debt

or to fund the existing large portfolio of LNG projects. Indeed, we estimate that Browse alone

would stretch WPL‟s funding metrics under S&P criteria for BBB+ rated companies.

Meanwhile, if Browse, Sunrise, Pluto expansions and Leviathan were all sanctioned on

current timelines (clearly unrealistic) WPL could need up to ~U$13bn in fresh equity. As a

result, any hike in the medium term dividend could be seen as a vote of no confidence in at

least one of WPL‟s LNG growth options.

STO: STO remains confident in its „robust funding position‟ but is also adopting a „rigorous

focus on cost reduction‟ suggesting the funding position is getting tighter (a view further

supported by this week‟s job cuts announcement). What‟s more, while management points to

more than A$6bn of available liquidity, we note the Board‟s commitment to a „strong

investment grade credit rating‟ means this does not necessarily translate into funding capacity.

Indeed, we estimate that if STO is to retain its BBB+ credit rating, surplus funds have shrunk

from A$1,100m to only A$200m over the past 12 months reflecting the capex acceleration at

GLNG, the cost overruns at PNG LNG and S&P‟s move to allocate only 50% equity credit to

STO‟s hybrids. That said, we would expect the board to allow the credit rating to slip to BBB

during the development phase which could free up ~A$600m of additional debt drawdown

capacity – but either way, there is limited capacity to cope with further cost overruns.

-5,000

0

5,000

10,000

15,000

20,000

25,000

30,000

WPL STO ORG OSH

Net asset sales Project Finance

Debt/ECA Hybrid

DRP Equity

Mkt CAp

U$m

0.00 x

0.05 x

0.10 x

0.15 x

0.20 x

0.25 x

0.30 x

0.35 x

0.40 x

2010 2011 2012 2013 2014 2015 2016

WPL

STO

ORG

OSH

Capex/Mkt Cap


7 December 2012 14

OSH: With no credit rating to protect and access to considerable project financing on

attractive terms under the Exxon umbrella, OSH perhaps has greater funding flexibility than

some of its peers. As a result, in the absence of success at either Taza or the Gulf of Papua

(which could require material funding during the development period) we continue to see OSH

remaining comfortably funded over the development period with an estimated ~U$800m of

surplus liquidity. That said, this overrun nevertheless perhaps leaves less funds available for a

third train (both for OSH and the PNG government) but given that the majority of any cash

calls here will likely fall due after PNG LNG start-up, this is unlikely to be material (what‟s

more, we note that the PNG government recently secured significant long dated funding from

the Chinese which could remove this potential drag on future developments).

ORG: With A$5.2bn of cash and undrawn debt, ORG does not have a liquidity issue but there

appears to be limited room to move within the confines of the BBB+ credit rating. In this

context, we estimate slipping to BBB would free up ~A$600m of valuable debt capacity at an

incremental annual interest cost of ~A$60m (but this would leave a limited funding buffer to

cope with the growing uncertainties facing the Energy Markets business). Against this

backdrop, management has nevertheless effectively ruled out an equity raising and remains

determined to preserve an investment grade credit rating, meaning there is growing pressure

(but also perhaps growing confidence) in securing a good price for the APLNG stake sale.

Fig 16 WPL – Pluto cash flow will help to fund the next wave of growth, but WPL seemingly cannot afford to do all projects on current time-lines

Fig 17 STO – Over the past 12 months, STO’s funding cushion has shrunk from U$1.2 down to only U$200m suggesting a ratings downgrade can no longer be ruled out

Fig 18 ORG - Assuming hybrids of ~A$1.8bn are given equity credit of 50% by S&P, we see ORG struggling to hold on to its current BBB+ rating even with a reduced equity stake in APLNG

Fig 19 OSH - We see OSH as comfortably funded over the PNG LNG development period (however success at Taza or the Gulf of Papua drilling could require external funding)

Source: Company data, Macquarie Research, December 2012

0%

50%

100%

150%

200%

250%

300%

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

+ Browse

+ Browse, Leviathan

+ Browse, Leviathan, Pluto

+ Browse, Leviathan, Pluto, Sunrise

FFO/Total Debt

FFO/TD must stay

above 35%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2008 2009 2010 2011 2012 2013 2014 2015 2016

This Year Last Year

FFO/TD

BBB+ credit rating TD/FFO < 3.3x

0%

10%

20%

30%

40%

50%

60%

Dec-10 Dec-11 Dec-12 Dec-13 Dec-14 Dec-15

37.5% equity stake 30% equity stake

FFO/TD

S&P likely to show short-term leniency;

BBB+ credit rating TD/FFO > 35%0

500

1,000

1,500

2,000

2,500

3,000

Dec-1

1

Jun-1

2

Dec-1

2

Jun-1

3

Dec-1

3

Jun-1

4

Dec-1

4

Jun-1

5

Dec-1

5

Jun-1

6

Macq (new facility) Macq (old facility) OSH

U$bn


7 December 2012 15

How are the local players placed? LNG has historically been the realm of only the largest industry players that typically have

many ongoing developments which dilutes their exposure to any single project. This is

typically not the case for the local operators who tend to have all their development eggs in

one, or perhaps two, development baskets. This means that if and when things do go wrong,

the local players are disproportionately exposed. What‟s more, in many cases local LNG

projects are set to return only a thin margin above the cost of capital meaning there is little

room for error during the precarious development period. Indeed, with the current batch of

Australian greenfield LNG projects offering returns of ~12-13%, even a small change in

project costs can have a large impact on value (anticipated return erosion could see

Australian greenfield projects lose over 80% of their value).

These development risks are perhaps heightened further as we enter the riskiest period for

many of the local LNG players as we approach the business end of several developments.

This is because we continue to believe development risk is back end loaded. That is, while the

issues that drive subsequent cost inflation and schedule slippage may occur early on (often in

the design phase) operators tend to believe they can find work-around solutions as with so

much time remaining nothing is yet deemed to be on the critical path. This contrasts with the

final stages of the development where everything is on the critical path at which point

companies have to report the slow progress to the market (here we note the first cost over-run

announcement on Pluto came when 83% complete while PNG LNG was 70% done when it

announced its recent over-run).


7 December 2012 16

AUSTRALIA

WPL AU Neutral

Price (at 05:10, 06 Dec 2012 GMT) A$34.08

Volatility index Low

12-month target A$ 37.50

12-month TSR % +13.5

Valuation A$ 41.06 - DCF (WACC 10.0%, beta 1.1, ERP 5.0%, RFR 6.1%)

GICS sector Energy

Market cap A$m 28,079

30-day avg turnover A$m 51.7

Number shares on issue m 823.9

Investment fundamentals

Year end 31 Dec 2011A 2012E 2013E 2014E

Revenue m 4,802.0 6,124.1 6,269.5 7,386.0 EBIT m 2,475.0 3,212.4 3,194.2 4,044.1 Reported profit m 1,507.0 2,953.2 1,952.4 2,490.4 Adjusted profit m 1,655.0 2,013.2 1,952.4 2,490.4 Gross cashflow m 2,885.0 3,465.2 3,572.4 4,335.6 CFPS ¢ 363.5 423.4 433.6 526.2 CFPS growth % 12.1 16.5 2.4 21.4 PGCFPS x 9.8 8.4 8.2 6.8 PGCFPS rel x 1.16 0.93 0.90 0.86 EPS adj ¢ 208.7 246.0 237.0 302.3 EPS adj growth % 13.6 17.9 -3.7 27.6 PER adj x 17.1 14.5 15.0 11.8 PER rel x 1.29 1.04 1.06 0.94 Total DPS ¢ 110.0 128.0 121.7 150.0 Total div yield % 3.1 3.6 3.4 4.2 Franking % 100 100 100 100 ROA % 11.5 13.2 12.3 15.5 ROE % 13.9 14.5 12.5 14.9 EV/EBITDA x 9.0 7.3 7.1 5.8 Net debt/equity % 38.1 11.9 8.8 -3.5 P/BV x 2.2 1.9 1.8 1.7

WPL AU vs ASX 100, & rec history

Note: Recommendation timeline - if not a continuous line, then there was no Macquarie coverage at the time or there was an embargo period.

Source: FactSet, Macquarie Research, December 2012

(all figures in USD unless noted)

Macquarie Securities (Australia) Limited

Woodside Petroleum

Both the least and most exposed to development risk

Dealt with significant development risk…: Having exploited the LNG

opportunity ahead of its Australian-listed peers, WPL has already developed a

significant proportion of its LNG asset base offering obvious infrastructural

advantages and reduced development exposure going forwards.

…and yet still has the most unsanctioned projects yet to develop: With

over 10% of our WPL valuation derived from unsanctioned LNG projects

(namely Browse, Sunrise, Pluto expansions and Leviathan) WPL is perhaps

the most exposed to Australia‟s closing market window. Indeed, given our

view that growing supply-side competition is conspiring against Australia‟s

higher cost projects, slow progress across WPL‟s growth portfolio may come

at a heavy price if the market window has simply been missed.

Swapping development risk for acquisition and political risk: Slow

progress on WPL‟s Australian growth portfolio coupled with a growing Pluto

cash pile and a closing market window are leaning on management to find the

next leg of production growth. Indeed, as demonstrated by the recent Israel

and Myanmar deals, this predicament is pushing WPL down the acquisition

path, even if this comes at the cost of significant political risk. Moreover,

recent comments from Coleman suggest there may be more to come with

management currently running the ruler over US downstream liquefaction

opportunities (but with no upstream exposure these are likely to yield utility

type returns which could struggle to cover WPL‟s cost of capital).

Stuck in the middle at Browse: Browse is arguably the single biggest driver

of the near-term investment case at WPL and yet here the company

increasingly looks like a pawn stuck between the WA Premier and Shell‟s

divergent development aspirations. Our view is that in light of the cost

pressures at Gorgon, it would be a brave CEO that takes on a James Price

Point development in this environment. This is because we see Browse as

arguably the project most exposed to cost inflation and schedule slippage

courtesy of its remoteness, technical challenges and environmental concerns

which perhaps explains the JV‟s growing nervousness.

FLNG seems like the way to go: We estimate an IRR of a Browse floating

LNG development at 14.8%. This compares to backfill at the North West Shelf

at 19.5% and James Price Point at only 12.6%. What‟s more, despite its

higher returns, we also see floating LNG as a lower risk development (albeit

perhaps coming at the cost of heightened off-shore operational risk). What‟s

more, the flexibility of phasing multiple FLNG vessels could prove more

capital efficient compared to the large upfront investment required for an

onshore plant at James Price Point.

Government may have to give ground to get its way: Having already

condoned floating LNG at Prelude and having lost Ichthys to the Northern

Territory, we suspect the WA government will struggle to push the Browse JV

into a marginal development at James Price Point without offering significant

tax breaks (which would require Federal support). Indeed, the very things that

Barnett wants from Browse (jobs, taxes, Aboriginal concessions, domestic

gas supplies) are exactly the things that the JV are presumably looking to

circumvent by considering floating LNG.

Maintain Neutral rating and A$37.50/sh price target: WPL is increasingly

looking like a growth company with no near-term growth - albeit more

reasonably priced today than in the past. We suspect this predicament merely

stiffens management resolve to go after its capital intensive, longer-term

growth options and therefore, despite its improving balance sheet, we do not

expect any capital returns above the company‟s already generous 4% yield.

We also do not expect any near-term Shell sell down as Shell may be keen to

hold on to its remaining 23% stake and two board seats in the Browse

operator in order to ensure the greatest influence over this development plan.


7 December 2012 17

Fig 20 Woodside Petroleum financials


Woodside Petroleum (WPL-AU) Share Price: A$34.08

Neutral Shares: 823.9m

Profit & Loss 1H12A 2H12E 2011A 2012E 2013E 2014E Price assumptions 1H12A 2H12E 2011A 2012E 2013E 2014E

Sales Revenue US$m 2,601 3,523 4,802 6,124 6,270 7,386 US$/A$ ¢ 1.05 0.99 1.02 1.05 1.04 1.02

add other income US$m 64 85 55 149 178 192 Domestic gas A$/GJ 4.14 4.18 4.30 4.16 4.16 4.29

Total revenue US$m 2,665 3,608 4,857 6,273 6,448 7,577 Oil-Brent US$/bbl 114.22 107.10 111.15 110.66 106.25 115.50

less operating costs US$m (731) (880) (1,200) (1,611) (1,649) (1,705)

EBITDAX US$m 1,934 2,728 3,657 4,662 4,799 5,873 Production 1H12A 2H12E 2011A 2012E 2013E 2014E

less exploration expensed US$m (130) (107) (587) (237) (360) (592) Natural gas PJ 40.8 43.0 87.2 83.8 85.7 85.7

EBITDA US$m 1,804 2,621 3,070 4,425 4,439 5,281 Crude mmbbl 8.1 9.7 16.8 17.7 13.5 14.1

less dep. & amort. US$m (444) (718) (627) (1,162) (1,244) (1,236) Condensate mmbbl 4.0 5.3 9.1 9.4 10.2 9.5

less other non-cash costs US$m (50) - 32 (50) - - LPG k tonnes 65 64 232 129 128 128

EBIT US$m 1,310 1,902 2,475 3,212 3,194 4,044 LNG m tonnes 1.7 3.2 2.5 4.8 6.2 6.4

less net interest US$m (42) (95) (26) (137) (167) (112) Sub total boe mmboe 33.5 50.8 62.9 84.9 94.1 95.9

Pre-tax operating profit US$m 1,268 1,807 2,449 3,075 3,028 3,932 Ohanet mmboe 0.7 - 1.8 - - -

less tax expense US$m (391) (542) (775) (933) (908) (1,180) Total production mmboe 34.2 50.8 64.7 84.9 94.1 95.9

less PRRT US$m (27) (90) (17) (117) (151) (245)

Net operating profit US$m 850 1,175 1,657 2,025 1,968 2,507

add non-recurring items US$m (34) 974 (148) 940 - -

Reported profit US$m 812 2,141 1,507 2,953 1,952 2,490

Adjusted profit US$m 846 1,167 1,655 2,013 1,952 2,490

EPS (Adjusted) Acps 101.3 132.4 204.0 233.7 227.7 297.9

EPS Growth % 3% 36% 14% 18% -4% 28%

DPS (Ordinary & Special) UScps 65 63 110 128 122 150

DPS (Ordinary & Special) Acps 63 59 108 122 117 148

Franking % 100% 100% 100% 100% 100% 100%

EFPOWA shares on issue m 811 824 799 824 824 824

Cashflow Analysis 1H12A 2H12E 2011A 2012E 2013E 2014E Reserves 2011A 2012E 2013E 2014E

Reported Profit US$m 812 2,141 1,509 1,991 1,968 2,507 Natural gas Tcf 7.3 6.9 6.5 6.0

add non-cash adj US$m 1,085 1,553 1,827 2,638 2,830 3,365 Condensate mmbbl 128 119 108 99

add working capital adj US$m 32 - (270) 32 - - Oil mmbbl 98 81 67 53

add interest & div received US$m 5 3 14 8 34 51 Total 2P reserves mmboe 1,717 1,632 1,538 1,442

less interest paid & other US$m (140) (98) (342) (238) (200) (163) Contingent resources mmbbl 2,137 2,137 2,137 2,137

less tax paid US$m (303) (559) (496) (862) (1,140) (1,479) Total reserves & resources mmboe 3,853 3,768 3,674 3,578

Operating cashflow US$m 1,491 3,041 2,242 3,569 3,492 4,281

less exploration & evaluation US$m (1,329) (564) (3,584) (1,893) (1,411) (1,046) 2P Reserves / production years 26.55 19.21 16.34 15.03

less acq./inv. US$m - - - - - - EV / 1P reserves US$/boe 25.50 28.29 30.68 33.58

add other US$m 2 2,000 51 2,002 (696) - EV / 2P reserves US$/boe 22.22 20.94 22.22 23.69

less dividends US$m (325) (536) (652) (861) (986) (1,129) EV / Total resources US$/boe 9.90 9.07 9.30 9.55

add debt movements US$m 404 (429) 366 (25) (733) (1,183)

add equity movements US$m 320 - 648 320 - - Per bbl statistics 1H12A 2H12E 2011A 2012E 2013E 2014E

Net cashflow US$m 567 2,546 (929) 3,113 (334) 924 Sales Revenue / boe US$/boe 76.13 69.39 74.26 72.10 66.61 77.02

add exchange rate adj. US$m 3 - 7 3 - - EBIT / boe US$/boe 38.34 37.47 38.28 37.82 33.94 42.17

Increase in cash US$m 570 2,546 (922) 3,116 (334) 924 Profit / boe US$/boe 24.77 22.99 25.59 23.70 20.74 25.97

Net debt at period end US$m 4,844 1,869 5,061 1,869 1,470 (637) Opex/boe US$/boe 8.78 9.25 7.81 9.06 9.18 9.68

Capex/boe US$/boe 38.90 11.10 55.43 22.28 14.99 10.90

Balance sheet 1H12A 2H12E 2011A 2012E 2013E 2014E DDA/boe US$/boe 12.82 13.57 9.51 13.27 12.81 12.40

Cash & cash eq. US$m 611 3,157 41 3,157 2,823 3,747 Cash flow/boe US$/boe 12.82 13.57 34.67 42.02 37.10 44.64

Current assets US$m 1,462 4,008 1,014 4,008 3,674 4,598

Fixed assets US$m 22,996 21,880 21,726 21,880 22,382 21,599 NPV @ WACC of 10.0%

Total assets US$m 24,458 25,888 22,740 25,888 26,056 26,197 Producing assets A$m A$ps %

Current liabilities US$m 2,422 2,239 2,412 2,239 1,507 1,452 North West Shelf 10,401 15.40

Total liabilities US$m 10,327 10,144 9,471 10,144 9,330 8,093 Laminaria 184 0.27

Shareholder equity US$m 14,131 15,744 13,269 15,744 16,726 18,104 Stybarrow 261 0.39

Vincent 1,018 1.51

Ratio analysis 1H12A 2H12E 2011A 2012E 2013E 2014E Enfield 528 0.78

ND/ND+E % 26% 11% 28% 11% 8% -4% Neptune 257 0.38

Interest cover x 29.8 x 19.4 x 68.8 x 22.6 x 16.0 x 24.8 x Mutineer / Exeter 5 0.01

Dividend payout ratio % 65% 24% 58% 36% 51% 50% Pluto (train 1) 15,704 23.24

ROA % 6% 8% 12% 13% 12% 15% Static assets & exploration

ROE % 6% 8% 14% 15% 13% 15% Pluto (train 2) risked valuation @ 15% 766 1.13

ROIC % 5% 7% 10% 12% 12% 15% Pluto (train 3) risked valuation @ 15% 385 0.57

Effective tax rate % 31% 30% 32% 30% 30% 30% Browse risked valuation @ 60% 1,102 1.63

EBITDA margin % 69% 74% 64% 72% 71% 71% Sunrise risked valuation @ 20% 212 0.31

EBIT margin % 50% 54% 52% 52% 51% 55% Leviathan risked valuation @ 30% 411 0.61

Free cash flow A$m -136 3,622 -957 3,486 1,784 3,647 Exploration portfolio 1,094 1.62

Financial assets

Valuation 1H12A 2H12E 2011A 2012E 2013E 2014E Cash & Investments 1,718 2.00

EV/EBITDAX ratio x 17.4 x 17.2 x 10.2 x 7.3 x 7.1 x 5.8 x Debt (5,455) (8.07)

P/E ratio x 34.3 x 33.5 x 19.4 x 14.6 x 15.0 x 11.4 x Base business carbon (22) (0.03)

P/CEPS ratio x 18.8 x 19.3 x 11.3 x 8.5 x 8.2 x 6.6 x Corporate costs (462) (0.68)

FCF yield % nmf nmf nmf 11.6% 6.1% 12.8% Risked NPV 28,107 41.06

Dividend yield % 1.6% 1.9% 2.7% 3.6% 3.4% 4.3% Shareprice prem/(disc) to NPV -17%

- core NPV per share (A$) 35.19

Sensitivities (Adjusted earnings) NPV 2011A 2012E 2013E 2014E - risked NPV per share (A$) 41.06

Oil price (+US$1/bbl) A$m 41.65 1,655 2,017 1,977 2,532 - unrisked NPV per share (A$) 61.75

delta 0.58 0 4 25 41

1.4% 0.0% 0.2% 1.3% 1.7%

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Gas Crude Condensate LPG LNGmmboe


7 December 2012 18

Fig 21 Woodside Petroleum NAV breakdown


Producing Assets Interest Unrisked Unrisked Risk Risked Risked USD/boe Aps Aps % NPV Sensitivity

mmboe USD (m) mmboe USD (m) risked unrisked -$10 Base +$10

North West Shelf gas 16.7% 529.0 9,536 100% 529 9,536 18.0 14.11 14.11 34% 13.08 14.11 15.65

North West Shelf oil 33.3% 28.2 866 100% 28 866 30.7 1.28 1.28 3% 1.15 1.28 1.42

Laminaria 66.5% 6.2 184 100% 6 184 29.7 0.27 0.27 1% 0.25 0.27 0.30

Stybarrow 50.0% 11.4 261 100% 11 261 22.8 0.39 0.39 1% 0.34 0.39 0.44

Vincent 60.0% 27.9 1,018 100% 28 1,018 36.4 1.51 1.51 4% 1.38 1.51 1.64

Enfield 60.0% 18.8 528 100% 19 528 28.1 0.78 0.78 2% 0.71 0.78 0.87

Neptune & Powerplay 20.0% 7.3 257 100% 7 257 35.2 0.38 0.38 1% 0.37 0.38 0.43

Mutineer / Exeter 8.2% 0.2 5 100% 0 5 24.8 0.01 0.01 0% 0.01 0.01 0.01

Pluto train 1 90.0% 809 15,704 100% 809 15,704 19.4 23.24 23.24 57% 21.34 23.24 25.41

Sub Total 1,438 28,359 1,438 28,359 19.7 41.98 41.98 102% 38.64 41.98 46.16

Static Assets & Exploration

Pluto train 2 (WPL gas) 90.0% 943 5,106 15% 141 766 5.4 1.13 7.56 3% 0.90 1.13 1.37

Pluto train 3 (3rd party gas) 50.0% 512 2,565 15% 77 385 5.0 0.57 3.80 1% 0.43 0.57 0.71

Browse 31.3% 818 1,837 60% 491 1,102 2.2 1.63 2.72 4% 0.73 1.63 2.53

Sunrise 30.1% 303 1,059 20% 61 212 3.5 0.31 1.57 1% 0.21 0.31 0.42

Leviathan (domgas + LNG) 30.0% 892 1,369 30% 268 411 1.5 0.61 2.03 1% 0.63 0.61 0.60

Greater Laverda 60.0% 60 1,140 50% 30 570 19.1 0.84 1.69 2% 0.74 0.84 0.95

Lady Nora 16.7% 7 169 50% 3 85 25.4 0.13 0.25 0% 0.11 0.13 0.14

Cimatti 60.0% 8 144 50% 4 72 19.2 0.11 0.21 0% 0.10 0.11 0.12

Innsbruck 15.0% 15 150 10% 2 15 10.0 0.02 0.22 0% 0.02 0.02 0.02

Asterix 12.5% 31 234 10% 3 23 7.5 0.03 0.35 0% 0.03 0.03 0.03

Panoramix 12.5% 13 125 50% 6 63 10.0 0.09 0.19 0% 0.09 0.09 0.09

Vampira 12.5% 13 125 50% 6 63 10.0 0.09 0.19 0% 0.09 0.09 0.09

Leviathan (oil) 30.0% 402 3,922 7.5% 30 204 10.0 0.30 5.81 1% 0.30 0.30 0.30

Sub Total 4,015 17,946 1,121 3,969 3.5 5.88 26.56 14% 4.38 5.88 7.39

Financial Assets

Cash & Investments 1,718 2.00 2.00 5% 2.00 2.00 2.00

Base business carbon (22) (0.03) (0.03) 0% (0.03) (0.03) (0.03)

LNG projects carbon (143) (143) (0.21) (0.21) -1% (0.21) (0.21) (0.21)

Debt (5,455) (8.07) (8.07) -20% (8.07) (8.07) (8.07)

Corporate costs (462) (0.68) (0.68) -2% (0.68) (0.68) (0.68)

Sub Total (4,221) (6.79) (6.79) -17% (6.79) (6.79) (6.79)

Overall total 5,453 mmboe 28,107 USDm 41.06 61.75 100% 36.24 41.06 46.76

- core NPV per share (A$) 35 35.19 31.85 35.19 39.37

- risked NPV per share (A$) 5,453 41.06 36.24 41.06 46.76

- unrisked NPV per share (A$) 41,963 61.75 46.76 46.76 46.65

Ordinary Shares on Issue (m) 824

Exchange Rate 0.82

WACC (post tax) 10.0%

Share Price 34.08

Price premium (discount) to NPV -17%

Proportion of NAV from LNG 98%

Franking credits (risked at 50% - A$ps) 1.56


7 December 2012 19

AUSTRALIA

STO AU Outperform

Price (at 05:10, 06 Dec 2012 GMT) A$10.88

Volatility index Low/Medium




GICS sector Energy



Number shares on issue m 961.2


Year end 31 Dec 2011A 2012E 2013E 2014E

Revenue m 2,530.0 3,195.9 3,747.9 4,267.3 EBIT m 773.0 970.7 1,211.5 1,540.0 Reported profit m 753.0 572.0 655.9 736.9 Adjusted profit m 453.0 593.0 655.9 736.9 Gross cashflow m 1,259.0 1,553.9 1,768.2 1,927.6 CFPS ¢ 139.9 162.8 181.1 194.0 CFPS growth % 6.3 16.4 11.2 7.2 PGCFPS x 7.8 6.7 6.0 5.6 PGCFPS rel x 0.92 0.74 0.66 0.71 EPS adj ¢ 50.5 62.1 67.2 74.1 EPS adj growth % 12.5 23.0 8.1 10.4 PER adj x 21.5 17.5 16.2 14.7 PER rel x 1.63 1.26 1.14 1.17 Total DPS ¢ 30.0 30.0 30.0 30.0 Total div yield % 2.8 2.8 2.8 2.8 Franking % 100 100 100 100 ROA % 5.2 5.9 6.7 7.7 ROE % 5.5 6.4 6.6 6.9 EV/EBITDA x 6.0 5.1 4.3 3.7 Net debt/equity % -15.8 4.9 25.7 34.5 P/BV x 1.1 1.1 1.0 1.0

STO AU vs ASX 100, & rec history



(all figures in AUD unless noted)


Santos

The market can’t see past GLNG

The market doesn’t believe: Since the end of 2009, STO has sanctioned

two LNG projects which have driven a doubling of the company‟s core NAV

and a 40% increase in its 2P reserves while also underpinning an expected

42% increase in production over the next 5 years. Despite this and the

U$60/bbl rise in the oil price, STO‟s shares have fallen 23% over this period

(admittedly not helped by two equity raisings) demonstrating the market‟s lack

of faith in the deliverability these projects and perhaps also wider concerns

around the underlying economics of CSG.

GLNG’s headline numbers are reassuring…: GLNG is now apparently 40%

complete, suggesting it has closed the gap with QCLNG while extending its

lead over APLNG. However, if instead we use the anticipated arrival date of

the first module as a proxy for progress it tells a different story. Specifically

APLNG is expected to take ~600 days from FID to first module, QCLNG took

660 days while GLNG looks set to take ~760 days perhaps suggesting some

relative slippage (but with only 111 modules at GLNG compared to 168 at

APLNG, STO may be able to claw back any lost time).

…but the detail points to development pressures: STO recently

confirmed the late delivery of the MOF, pointed to modest resource bookings

in 2012, underlying well flow rate assumptions appear to be falling, the shift to

a tunnel to Curtis Island is likely to add schedule pressures while the delay in

JV sign-off for the revised capex budget is unnerving.

GLNG gas supply continues to evolve: With 250-300TJ/d now expected

from third-party gas, with Roma storage contributing to the initial flow and gas

savings from the move to electrification, gas supply plans at GLNG continue

to evolve, even at this late stage. With the goal posts apparently moving in

terms of gas supply, the market is understandably nervous about the

deliverability of Roma gas, especially given that the flow rates at Fairview

continue to improve.

The tight tunnel timeline is perhaps the biggest risk: The most concerning

scope change is the move to tunnel across to Curtis Island. This is a

significant scope of work and clearly on the critical path given that current

plans call for commissioning gas to be sent into the plant in mid-2014. Here

we note BG expects to complete its Narrows Crossing by June next year, this

is 18 months before first exports are due - it increasingly appears STO will

have significantly less time than this. What‟s more, such a late adjustment

means STO is unable to capitalise on many of the benefits of a tunnel –

namely tapping into shore-based utilities such as power and water.

GLNG is unlocking STO’s East Australian gas portfolio: Despite initial

guidance of 11-14%, we now estimate GLNG‟s IRR at only 9.7% - comfortably

below STO‟s WACC. However, as GLNG returns fall, management

increasingly points to the tightening effect that LNG exports will have on the

east coast market in order to justify the project from a wider portfolio

perspective. With this in mind, STO continues to secure acreage, book

resources, invest in Moomba infrastructure and lower production costs - all

against the backdrop of rising east coast gas prices and falling political

opposition to CSG operations. As a result, STO is uniquely positioned to profit

from the tight gas market that LNG exports will create on the east coast.

Maintain Outperform rating and A$16/sh: STO has an aspirational net LNG

production target of ~5.25mtpa by 2020 which implies considerable exposure

to development risks given current capacity of only 0.4mtpa. While STO will

unquestionably face cost and schedule pressures along with the rest of the

sector, given the current share price, we believe management will be hard

pushed to disappoint against the market‟s unrealistically low expectations.


7 December 2012 20

Fig 22 Santos financials


Santos (STO-AU) Share Price: A$10.88

Outperform Shares: 958.8m

Profit & Loss 1H12A 2H12E 2011A 2012E 2013E 2014E Price Assumptions 1H12A 2H12E 2011A 2012E 2013E 2014E

Sales revenue A$m 1,493 1,703 2,530 3,196 3,748 4,267 US$/A$ ¢ 1.03 1.07 1.02 1.05 1.04 1.02

add other income A$m 30 39 111 69 82 87 Domestic gas A$/Gj 5.06 5.34 4.74 5.20 5.81 6.49

Total revenue A$m 1,523 1,742 2,641 3,265 3,830 4,354 Oil-Brent US$/bbl 114.22 107.10 111.15 110.66 106.25 115.50

less operating costs A$m (649) (694) (1,060) (1,343) (1,506) (1,624)

EBITDAX A$m 874 1,049 1,581 1,923 2,324 2,731 Production 1H12A 2H12E 2011A 2012E 2013E 2014E

less exploration expensed A$m (86) (85) (167) (171) (260) (240) Natural gas PJ 101.3 107.8 190.4 209.1 219.1 229.4

EBITDA A$m 788 964 1,414 1,752 2,064 2,491 Crude mmbbl 4.6 4.9 7.2 9.4 9.8 9.0

less dep. & amort. A$m (377) (413) (641) (790) (852) (951) Condensate mmbbl 1.5 1.6 2.9 3.1 3.7 4.1

less other non-cash costs A$m 9 - - 9 - - LPG k tonnes 100.7 104.3 209.5 205.0 269.5 279.3

EBIT A$m 420 551 773 971 1,211 1,540 LNG k tonnes 106.5 161.0 256.7 267.6 343.8 499.4

less net interest A$m 45 35 91 80 16 (35) Total production mmboe 25.3 27.4 47.0 52.6 56.6 59.5

Pre-tax operating profit A$m 465 585 864 1,050 1,228 1,505 Third party sales mmboe 5.2 5.3 10.8 10.5 14.5 14.4

less tax expense (incl PRRT) A$m (182) (275) (413) (457) (572) (768) Total sales mmboe 29.0 33.3 57.2 62.3 71.2 73.9

Net operating profit A$m 283 310 451 593 656 737

add non-recurring items A$m (21) - 300 (21) - -

Reported profit A$m 262 310 753 572 656 737

add (goodwill amm - pref div) A$m - - - - - -

Adjusted profit A$m 283 310 453 593 656 737

EPS (Adjusted) Acps 29.8 32.3 50.5 62.1 67.2 74.1

EPS Growth % 26% 8% 12% 23% 8% 10%

DPS (Ordinary & Special) Acps 15 15 30 30 30 30

Franking % 100% 100% 100% 100% 100% 100%

EFPOWA shares on issue m 948 960 898 954 976 993


Cash receipts from operations A$m 3,397 3,518 3,067 3,518 3,900 4,398 Natural gas PJ 3,458 3,249 3,029 2,800

less operating costs A$m (1,572) (1,543) (1,263) (1,543) (1,506) (1,624) Oil mmbbl 47 38 28 19

less gross interest paid A$m (96) (27) (175) (123) (54) (79) Condensate mmbbl 31 28 25 21

less tax paid A$m (42) (248) (357) (290) (495) (603) LPG k tonnes 2,070 1,865 1,596 1,316

Cashflow from operations A$m 712 818 1,234 1,530 1,801 2,043 Total 2P reserves mmboe 1,364 1,311 1,255 1,195

less development & exploration A$m (1,434) (2,012) (2,915) (3,446) (3,968) (3,202) Contingent resources mmbbl 2,162 2,162 2,162 2,162

less acq./inv. A$m (73) - (60) (73) - - Total reserves & resources mmboe 3,526 3,473 3,417 3,357

add divestment A$m 133 - 852 133 - -

less dividends paid A$m (78) (143) (155) (221) (291) (298) 2P reserve life years 29.0 24.9 22.2 20.1

add debt movements A$m 247 225 (31) 472 1,359 658 EV/ 1P reserves A$/boe 16.63 18.50 20.44 22.97

add equity movements/other A$m 82 143 96 225 291 298 EV / 2P reserves A$/boe 7.92 8.43 8.81 9.24

Net cashflow A$m (411) (970) (979) (1,381) (808) (501) EV / Total resources A$/boe 3.06 3.18 3.23 3.29

add exchange rate adj. A$m (6) - (8) (6) - - EV/ 1P reserves US$/boe 17.02 18.49 20.43 22.96

Increase in cash A$m (417) (970) (987) (1,387) (808) (501) EV / 2P reserves US$/boe 8.11 8.42 8.80 9.24

Net debt at year end A$m 616 1,811 (71) 1,811 3,978 5,138 EV / Total resources US$/boe 3.14 3.18 3.23 3.29

Balance Sheet 1H12A 2H12E 2011A 2012E 2013E 2014E Per Barrel Statistics 1H12A 2H12E 2011A 2012E 2013E 2014E

Cash & cash eq. A$m 2,915 1,945 3,332 1,945 1,137 636 Sales revenue / boe US$/boe 59.10 62.20 55.13 63.74 69.02 72.83

Current assets A$m 4,123 3,153 4,752 3,153 2,345 1,844 EBIT / boe US$/boe 16.62 20.11 16.84 19.36 22.31 26.29

Fixed assets A$m 12,451 13,983 11,062 13,983 16,883 18,944 Profit / boe US$/boe 11.20 11.32 9.87 11.83 12.08 12.58

Total assets A$m 16,574 17,136 15,814 17,136 19,228 20,788 Opex/boe US$/boe 15.70 14.07 14.49 14.86 14.22 14.05

Current liabilities A$m 1,362 1,389 1,524 1,389 1,466 1,631 Capex/boe US$/boe 6.52 7.35 7.23 6.94 8.56 5.12

Total liabilities A$m 7,284 7,536 6,851 7,536 8,972 9,795 DDA/boe US$/boe 14.92 15.10 13.97 15.76 15.69 16.23

Shareholder equity A$m 9,290 9,600 8,963 9,600 10,256 10,993 Cash flow/boe US$/boe 28.18 29.86 26.89 30.51 33.16 34.87

Ratio Analysis 1H12A 2H12E 2011A 2012E 2013E 2014E NPV @ WACC of 10.6%

ND/ND+E % 6% 16% -1% 16% 28% 32% Producing assets A$m A$ps %

Interest cover x 9.9 x 10.6 x 9.3 x 10.3 x 11.2 x 9.7 x Cooper Basin Area 2,507 2.60

Dividend payout ratio % 50% 46% 36% 50% 45% 40% Onshore Queensland CSG Assets 113 0.12

ROA % 3% 3% 5% 6% 7% 8% Otway Gas 215 0.22

ROE % 3% 3% 5% 6% 7% 7% WA Gas 2,720 2.82

ROIC % 3% 3% 5% 5% 5% 5% WA Oil 261 0.27

Effective tax rate % 30% 37% 37% 34% 33% 34% South East Asia 1,140 1.18

EBITDA margin % 53% 57% 56% 55% 55% 58% Bayu-Undan 1,189 1.23

EBIT margin % 28% 32% 31% 30% 32% 36% Developing assets

Free cash flow A$m (401) (1,212) (1,050) (1,613) (2,140) (1,074) Kipper risked valuation @ 100% 467 0.48

Glastone LNG train 1&2 risked valuation @ 100% 777 0.81

Valuation 1H12A 2H12E 2011A 2012E 2013E 2014E Cooper Basin - 2C risked valuation @ 50% 1,235 1.28

EV/EBITDAX ratio x 15.0 x 10.5 x 6.8 x 5.7 x 4.8 x 4.0 x Cooper Basin/GLNG gas supply risked valuation @ 100% 852 0.88

EV/DACF ratio x 18.7 x 14.0 x 9.3 x 7.4 x 6.3 x 5.6 x Fletcher/Finucane risked valuation @ 100% 166 0.17

P/E ratio x 44.3 x 33.7 x 21.5 x 17.5 x 16.2 x 14.7 x PNG LNG trains 1 & 2 risked valuation @ 100% 3,305 3.43

P/CEPS ratio x 33.6 x 25.9 x 7.8 x 6.7 x 6.0 x 5.6 x Static assets & exploration

FCF yield % nmf nmf nmf nmf nmf nmf PNG LNG train 3 risked valuation @ 50% 437 0.45

Dividend yield % 1.1% 1.4% 2.8% 2.8% 2.8% 2.8% Discoveries 1,110 1.15

Exploration 892 0.92

Sensitivities (Adjusted Earnings) Valuation 2011A 2012E 2013E 2014E Financial assets

Oil price (+US$1/bbl) A$m 18.18 453 591 647 728 Corporate/tariffs/other (324) (0.41)

delta -17.98 0 -2 -9 -9 Cash & Investments 2,915 3.02

0.0% 0.0% -0.2% -1.0% -0.9% Debt (2,557) (2.65)

Currency (+1c) A$m 17.79 453 591 647 728 Risked NPV 17,419 17.98

delta -17.98 0 -2 -9 -9 Shareprice prem/(disc) to NPV -39%

0.0% 0.0% -0.2% -0.9% -0.9% - core NPV per share (A$) 16.20

- risked NPV per share (A$) 17.98

- unrisked NPV per share (A$) 25.08

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7 December 2012 21

Fig 23 Santos NAV breakdown


Producing Assets Interest Unrisked Unrisked Risk Risked Risked USD/boe A$ps A$ps % NPV Sensitivity

mmmboe AUD (m) mmmboe AUD (m) risked unrisked -$10 Base +$10

Cooper Basin - 2P 63.0% 188 2,507 100% 188 2,507 10.9 2.60 2.60 14% 2.38 2.60 2.86

Surat / Denison various 7 98 100% 7 98 10.9 0.10 0.10 1% 0.10 0.10 0.10

Fairview 30.0% 3 15 100% 3 15 4.5 0.02 0.02 0% 0.02 0.02 0.02

Casino & Henry 50.0% 19 201 100% 19 201 8.6 0.21 0.21 1% 0.21 0.21 0.21

Minerva 10.0% 1 14 100% 1 14 10.3 0.01 0.01 0% 0.01 0.01 0.01

Bayu-Undan 11.5% 55 1,189 100% 55 1,189 17.7 1.23 1.23 7% 1.09 1.23 1.40

John Brookes 45.0% 69 1,266 100% 69 1,266 15.0 1.31 1.31 7% 1.30 1.31 1.33

Spar/Halyard (Aus) 45.0% 37 497 100% 37 497 11.1 0.52 0.52 3% 0.51 0.52 0.53

Reindeer/Carabou 45.0% 40 957 100% 40 957 19.6 0.99 0.99 6% 0.95 0.99 1.08

Thevernard Island 35.7% 1 20 100% 1 20 33.0 0.02 0.02 0% 0.02 0.02 0.02

Barrow Island 28.6% 2 103 100% 2 103 45.6 0.11 0.11 1% 0.10 0.11 0.12

Stag 66.7% 2 94 100% 2 94 33.6 0.10 0.10 1% 0.09 0.10 0.11

Mutineer / Exeter 33.4% 1 44 100% 1 44 46.9 0.05 0.05 0% 0.04 0.05 0.05

Maleo & Pelung 67.5% 10 182 100% 10 182 14.5 0.19 0.19 1% 0.19 0.19 0.19

SE Gobe 9.4% 0 7 100% 0 7 37.0 0.01 0.01 0% 0.01 0.01 0.01

Chim Sao & Dua (Vietnam) 31.9% 17 812 100% 17 812 39.9 0.84 0.84 5% 0.83 0.84 1.02

Bangladesh 75.0% 1 19 100% 1 19 15.2 0.02 0.02 0% 0.02 0.02 0.02

Oyong & Wortel 45.0% 14 121 100% 14 121 6.9 0.13 0.13 1% 0.13 0.13 0.13

Sub Total 467 8,144 467 8,144 14.3 8.44 8.44 47% 8.00 8.44 9.20

Developing Assets

Kipper 35.0% 48 467 100% 48 467 8.0 0.48 0.48 3% 0.47 0.48 0.51

Glastone LNG train 1&2 30.0% 407 777 100% 407 777 1.6 0.81 0.81 4% 0.12 0.81 1.40

Cooper Basin - 2C 63.0% 461 2,469 50% 231 1,235 4.4 1.28 2.56 7% 1.20 1.28 1.37

Cooper Basin/GLNG gas supply 66.6% 92 852 100% 92 852 7.6 0.88 0.88 5% 0.74 0.88 1.05

PNG LNG trains 1 & 2 13.5% 235 3,305 100% 235 3,305 11.5 3.43 3.43 19% 2.95 3.43 3.84

Fletcher/Finucane 44.0% 6 166 100% 6 166 22.3 0.17 0.17 1% 0.15 0.17 0.19

Mereenie - 2P 100.0% 30 141 100% 30 141 3.8 0.15 0.15 1% 0.14 0.15 0.15

Gunnedah Basin (3P) 80.0% 386 1,158 50% 193 579 3.0 0.60 1.20 3% 0.60 0.60 0.60

Sub Total 1,665 9,335 1,241 7,522 5.0 7.80 9.68 43% 6.38 7.80 9.11

- - -

Static Assets

PNG LNG train 3 (hides upside) 13.5% 88 873 50% 44 437 8.2 0.45 0.91 3% 0.38 0.45 0.52

Mereenie - 2C 100.0% 21 36 25% 5 9 2.8 0.01 0.04 0% 0.01 0.01 0.01

Caldita/Barossa 25.0% 108 291 75% 81 218 2.2 0.23 0.30 1% 0.23 0.23 0.23

Bonaparte LNG 40.0% 147 650 25% 37 163 3.6 0.17 0.67 1% 0.17 0.17 0.17

Sub Total 363 1,850 167 826 4.1 0.86 1.92 5% 0.79 0.86 0.93

Exploration

Ichthys N (Aus) 30.0% 30 102 20% 6 20 3.0 0.02 0.11 0% 0.02 0.02 0.02

Zola (Contingent) 24.8% 21 51 50% 10 26 3.0 0.03 0.05 0% 0.03 0.03 0.03

Zola (Prospective) 24.8% 96 328 25% 24 82 3.0 0.08 0.34 0% 0.08 0.08 0.08

Burnside-1 (Aus) 47.8% 120 391 25% 30 98 3.0 0.10 0.40 1% 0.10 0.10 0.10

Winchester-1 (Aus) 75.0% 167 565 10% 17 56 3.0 0.06 0.59 0% 0.06 0.06 0.06

Crown-1 (Aus) 30.0% 93 309 50% 46 155 3.0 0.16 0.32 1% 0.16 0.16 0.16

Dufresne-1 (Aus) 30.0% 67 215 10% 7 21 3.0 0.02 0.22 0% 0.02 0.02 0.02

Bassett West-1 (Aus) 30.0% 67 215 10% 7 21 3.0 0.02 0.22 0% 0.02 0.02 0.02

Hon Khoai-1 (Viet) 65.0% 49 531 10% 5 53 10.0 0.06 0.55 0% 0.06 0.06 0.06

Beam-1 (Aus) 45.0% 23 70 10% 2 7 4.0 0.01 0.07 0% 0.01 0.01 0.01

Gunnedah Basin (2C) 80.0% 497 1,788 15% 75 268 3.0 0.28 1.85 2% 0.28 0.28 0.28

Cooper Basin - Shale 63.0% 138 336 25% 34 84 2.0 0.09 0.35 0% 0.09 0.09 0.09

Sub total 1,366 4,901 263 892 2.8 0.92 5.08 5% 0.92 0.92 0.92

Financial & Corporate

Cash & investments 2,915 3.02 3.02 17% 3.02 3.02 3.02

Debt & hybrid (2,557) (2.65) (2.65) -15% (2.65) (2.65) (2.65)

Potential Mudflows Liability 18.0% 10% (74) (0.08) (0.08) 0% (0.08) (0.08) (0.08)

Base business carbon (457) (0.47) (0.47) -3% (0.47) (0.47) (0.47)

LNG projects carbon (144) (144) (0.15) (0.15) -1% (0.15) (0.15) (0.15)

ORR, Tariffs 416 0.43 0.43 2% 0.43 0.43 0.43

Third Party Sales 286 0.30 0.30 2% 0.28 0.30 0.31

Corporate overheads (569) (0.59) (0.59) -3% (0.59) (0.59) (0.59)

Sub Total (40) (0.04) (0.04) 0% (0.05) (0.04) (0.03)

Overall total 1,741 mmboe 17,345 AUDm 17.98 25.08 100% 16.04 17.98 20.13

-core NPV per share (A$) 1,302 16.20 14.33 16.20 18.28

-risked NPV per share (A$) 2,138 17.98 16.04 17.98 20.13

-unrisked NPV per share (A$) 3,861 25.08 22.98 25.08 27.38

Diluted number of shares (m) 964.5

Ordinary Shares on Issue (m) 958.8

In-the-money options outstanding (m) 4.9

Exchange Rate 0.82


Share Price 10.88





7 December 2012 22

AUSTRALIA

ORG AU Outperform

Price (at 05:10, 06 Dec 2012 GMT) A$11.12




Valuation A$ 17.20 - DCF (WACC 9.3%, beta 1.2, ERP 5.0%, RFR 6.0%, TGR 2.0%)

GICS sector Energy



Number shares on issue m 1,094


Year end 30 Jun 2012A 2013E 2014E 2015E

Revenue m 12,935 13,372 14,435 15,008 EBIT m 1,598 1,692 1,948 2,110 Reported profit m 980 802 892 947 Adjusted profit m 893 848 974 1,046 Gross cashflow m 1,580 1,555 1,709 1,805 CFPS ¢ 146.1 142.2 155.2 162.8 CFPS growth % 9.9 -2.7 9.2 4.9 PGCFPS x 7.6 7.8 7.2 6.8 PGCFPS rel x 0.84 0.86 0.91 0.93 EPS adj ¢ 82.6 77.6 88.5 94.4 EPS adj growth % 17.9 -6.1 14.1 6.6 PER adj x 13.5 14.3 12.6 11.8 PER rel x 0.97 1.01 1.00 1.01 Total DPS ¢ 50.0 50.0 53.5 56.6 Total div yield % 4.5 4.5 4.8 5.1 Franking % 100 100 100 100 ROA % 5.9 5.9 6.4 6.6 ROE % 7.1 6.4 7.1 7.4 EV/EBITDA x 8.1 7.8 7.3 7.1 Net debt/equity % 38.2 48.2 55.2 54.2 P/BV x 0.9 0.9 0.9 0.9

ORG AU vs ASX 100, & rec history



(all figures in AUD unless noted)


Origin Energy

All eyes on the APLNG sales process in 1Q13

Off to a strong start: APLNG is clearly off to a strong start. That said, solid

progress to date should be seen in the context of the project only being ~22%

complete meaning it remains very early days (we note PNG LNG‟s recent cost

over-run was announced when the project was 70% complete while news of

Pluto‟s first cost over-run came when it was 83% complete).

Getting on the front foot: It appears APLNG is possibly ahead of schedule

on several critical path items prompting management to suggest the project

could even finish ahead of GLNG (although given the embarrassment this

would likely cause Bechtel, we suspect that barring any project specific

disasters, the projects will finish in the order they started). What‟s more,

looking further afield, we note the commissioning issues currently being faced

at Angola LNG (a Bechtel built Cascade plant) suggesting this process or this

contractor are not totally risk free.

Free kick from BG: As with GLNG, we see the crossing over to Curtis Island

as key to all developments and on this front, APLNG conveniently has BG

doing much of the heavy lifting on the Narrows Crossing given its greater

schedule urgency. This not only takes this scope of work of APLNG‟s critical

path but also de-risks the overall development significantly.

Expansion plans back in vogue: Despite management having all but

dropped plans for a fourth train this time last year (indeed even a third looked

like a long-dated option well out of the money) it appears APLNG‟s expansion

plans are (at least somewhat) back on the table – which is perhaps a function

of the ongoing project equity sales process. We however believe that both

LNG buyers and sellers are growing increasingly reluctant to take the required

resource risk on expansion trains and so we continue to think management

remains more likely to sell any excess gas into the other two projects and

potentially look to invite Arrow to share its Curtis Island site in order to share

collaboration benefits (although given that both QCLNG and GLNG also

appear to be wooing Arrow, ORG may have limited bargaining power here).

Australia’s cost pressures unlikely to support APLNG sales process:

The long list of cost pressures and delays facing Australian LNG

developments will not support the ongoing APLNG sales efforts, especially

given that APLNG has no gas to sell. Without off-take, this deal merely offers

the buyer relatively thin returns against the backdrop of considerable

development risks. What‟s more, without off-take, this deal will offer a

transparent look-though valuation for the project (as opposed to the two

previous Sinopec deals which were obscured by confidential gas sales

agreements).

Limited pricing power: We suspect the APLNG JV may struggle to lure a

buyer by offering discounts without upsetting Sinopec. Meanwhile attracting

high prices without off-take may also be difficult. However, with this stake sale

being key to ORG‟s medium-term funding plans, it is imperative that not only a

decent price is agreed, but also that an accommodating partner is found.

Maintain Outperform rating & A$15.50/sh target: The overall impression is

that the APLNG development is going well and the relative advantages that

APLNG enjoys over its peers are materialising as expected. That said, with

over three years still to go until start-up at train 2, there is still a long way to

go. So overall, while we see little obvious near term upside in the utilities

business and a long development road ahead at APLNG, we nevertheless

believe ORG is close to the end of the de-rating cycle and think that by the

end of 2013, the ORG outlook should have improved significantly.


7 December 2012 23

Fig 24 Origin Energy financials


Origin Energy (ORG-AU) Share Price: A$11.12


Profit & Loss 2H12A 1H13E 2012A 2013E 2014E 2015E Assumptions 2H12A 1H13E 2012A 2013E 2014E 2015E

Total Revenue $m 6,436 6,400 12,935 13,372 14,435 15,008 USD/AUD c 0.75 0.79 1.01 1.06 1.02 1.01

less operating costs $m (5,382) (5,328) (10,752) (11,111) (11,999) (12,501) AUD/NZD c 1.14 1.12 1.28 1.25 1.13 1.13

EBITDA $m 1,054 1,073 2,183 2,261 2,436 2,507 WTI oil prices US$/bbl 75.32 62.05 93.96 89.28 97.31 105.69

less dep. & amort. $m (306) (315) (614) (634) (647) (659)

EBIT $m 748 758 1,569 1,628 1,790 1,848 E&P Production 2H12A 1H13E 2012A 2013E 2014E 2015E

less net interest expense $m (110) (166) (217) (344) (419) (467) Natural gas (inc Ethane) PJ 32.0 35.3 65.0 70.3 69.2 71.5

add share in associates (inc. APLNG) $m 18 34 29 64 158 262 Crude kbbls 279.9 305.5 590.5 570.7 475.3 407.2

Profit before tax $m 656 626 1,381 1,348 1,529 1,643 Condensate kbbls 748.7 810.6 1,614.6 1,622.5 1,581.7 1,608.8

less tax expense $m (188) (199) (415) (427) (466) (497) LPG ktonnes 58.4 64.7 120.4 131.5 132.1 138.5

Net profit $m 468 427 966 921 1,062 1,146 APLNG PJe 23.7 22.4 46.3 48.2 74.2 120.9

less minorities $m (41) (36) (73) (73) (88) (100) Total production (inc APLNG) PJe 64.3 67.1 129.4 137.1 161.3 210.3

Adjusted profit $m 427 391 893 848 974 1,046

add net abnormals $m (218) (21) 87 (46) (82) (99) E&P Reserves 2H12A 1H13E 2012A 2013E 2014E 2015E

add amortisation of goodwill $m - - - - - - 1P Reserves PJe 1,054 965 878 788

Reported profit $m 209 371 980 802 892 947 2P Reserves PJe 6,037 5,948 5,861 5,772

3P Reserves PJe 9,817 9,728 9,641 9,551

EPS (Adjusted) Acps 39.2 35.8 82.6 77.6 88.6 94.5 2P reserves life yrs 52.8 49.3 40.3 30.0

EPS Growth % 7.4% -17.3% 16.2% -6.0% 14.2% 6.7% Generation 4.23

Retail 7.91

EPS (Reported) c 19.2 34.0 90.9 73.3 81.1 85.6 Contact 2.10

DPS (Ordinary & Special) Acps 25.0 25.0 50.0 50.1 53.5 56.7 E&P 2.35

Franking % 100% 100% 100% 100% 100% 100% APLNG 4.44

EFPOWA shares on issue m 1,087.7 1,091.1 1,081.5 1,092.8 1,099.7 1,106.7 Other 0.99

Cash Flow Statement 2H12A 1H13E 2012A 2013E 2014E 2015E

Total revenue $m 6,436 6,400 12,935 13,372 14,435 15,008

less operating expenses $m (5,382) (5,328) (10,752) (11,111) (11,999) (12,501)

less net interest expense $m (192) (195) (366) (410) (537) (609)

less tax payable $m (26) (203) (39) (437) (467) (471)

Total payments $m (5,600) (5,726) (11,157) (11,958) (13,003) (13,581)

Gross cash flow $m 836 675 1,778 1,415 1,432 1,427

add proceeds from sales $m 36 44 41 44 - -

add capital raisings/debt drawdowns $m 2,813 1,167 7,579 1,591 1,515 2,535

less debt repaid $m (2,120) (150) (6,330) (158) (150) (2,320)

less capital expenditure $m (1,030) (1,771) (1,556) (1,253) (627) (731)

less dividends paid $m (249) (272) (411) (546) (550) (614)

add change in working capital 52 (70) (307) (140) (82) (35)

add other $m (818) 865 (1,161) (1,237) (1,578) (250)

Net cash flow $m (480) 487 (367) (284) (38) 12

Cash at Beginning of Period $m 837 357 724 357 73 35

Cash at end of period $m 357 844 357 73 35 47

Balance Sheet 2H12A 1H13E 2012A 2013E 2014E 2015E

Cash 357 844 357 73 35 47

Fixed Assets 10,895 11,313 10,895 11,470 11,450 11,523

Exploration Assets 838 838 838 838 838 838

Intangibles 625 625 625 625 625 625 Valuation 2H12A 1H13E 2012A 2013E 2014E 2015E

Other 15,266 15,349 15,266 16,673 18,551 19,182 EV/EBITDA ratio x 7.9 x 7.6 x 7.7 x 7.2 x 6.4 x 5.8 x

Total Assets 27,981 28,969 27,981 29,679 31,499 32,215 EV/EBIT ratio x 11.1 x 10.8 x 10.7 x 10.1 x 8.6 x 7.9 x

Senior Debt 4,296 5,275 4,296 5,653 6,941 7,074 P/E ratio x 16.8 x 15.5 x 16.5 x 14.3 x 12.6 x 11.8 x

Total Liabilities 13,523 14,339 13,523 14,816 16,128 16,329 P/CEPS ratio x 8.0 x 8.5 x 10.0 x 8.1 x 9.2 x 8.8 x

Total S/Holders Funds 14,458 14,630 14,458 14,863 15,370 15,886 FCF yield x -10.91% -2.36% -4.98% -6.60% 0.61% 11.96%

Dividend yield x 3.78% 4.50% 3.66% 4.50% 4.81% 5.10%

Key Ratios 2H12A 1H13E 2012A 2013E 2014E 2015E

Net Debt/Equity % 28% 29% 28% 33% 36% 35% NPV @ WACC of 9.3%

Net Debt/(Net Debt+Equity) % 38% 41% 38% 48% 55% 54% Base business A$m A$ps %

Debt Coverage Ratio % 6.0 x 4.4 x 6.2 x 4.6 x 4.3 x 3.9 x Generation 4,597 4.23

Enterprise Value $m 19,918 18,166 20,368 19,333 20,737 20,937 E&P 2,549 2.35

Effective tax rate % 28% 31% 30% 31% 30% 30% Retail 8,589 7.91

EBITDA margin % 16.4% 16.8% 16.9% 16.9% 16.9% 16.7% Contact 2,285 2.10

EBIT margin % 11.6% 11.8% 12.1% 12.2% 12.4% 12.3% Developing assets

ROA % 5.8% 5.9% 6.0% 6.1% 6.8% 7.3% APLNG Domgas risked valuation @ 100% 379 0.35

ROE % 7.3% 6.6% 7.4% 6.9% 7.7% 8.0% APLNG tr 1 risked valuation @ 100% 1,363 1.26

ROIC % 4.1% 3.1% 4.6% 3.5% 3.6% 3.6% APLNG tr 2 risked valuation @ 100% 2,871 2.64

Free cash flow $m (784) (143) (740) (803) 75 1,472 APLNG tr 3 risked valuation @ 15% 213 0.20

ATP 788P risked valuation @ 50% 356 0.33

Segmental EBITDA 2H12A 1H13E 2012A 2013E 2014E 2015E GLNG supply contract risked valuation @ 75% 204 0.19

E&P 150 161 329 325 384 388 Trefoil (T/18P - Bass Gas) risked valuation @ 50% 58 0.05

Energy Markets 742 767 1,562 1,635 1,670 1,701 Redback South-1 (Perth) risked valuation @ 75% 12 0.01

Contact Energy 218 204 400 421 503 546 Redback South-2 (Perth) risked valuation @ 75% 12 0.01

APLNG 31 48 47 96 244 429 Mbawa-1 (L8 - offshore Kenya) risked valuation @ 10% 128 0.12

Corporate (43) (43) (81) (87) (88) (89) Static Assets

Total EBITDA (inc. associates) 1,098 1,137 2,257 2,390 2,712 2,975 Generation options risked valuation @ 12% 374 0.34

Underlying EBITDA growth -5.3% 3.5% 27.2% 5.9% 13.5% 9.7% Financial Assets

Cash 401 0.37

Debt (5,546) (5.11)

Solar Power 56 0.05

Corporate overheads (226) (0.21)

Risked NPV 18,903 17.20

Shareprice prem/(disc) to NPV -35%

NPV breakdownGeneration

19%

Contact

10%E&P

11%

APLNG

20%

Other

4%

Retail

36%

Segmental Capex

-

500

1,000

1,500

2,000

2,500

3,000

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

Exploration and Production Contact Energy Corporate Energy Markets APLNG

A$m

Segment EBITDA

-

1,000

2,000

3,000

4,000

5,000

6,000

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

20

14

20

15

20

16

20

17

20

18

20

19

20

20

Exploration and Production Energy Markets Contact Energy Networks APLNG

A$m

RoFe by division

0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

20%

2006 2008 2010 2012 2014 2016

E&P Energy Markets Contact

RoFe


7 December 2012 24

Fig 25 Origin Energy NAV breakdown


Base Business Interest Unrisked Unrisked Risk Risked Risked USD/boe A$ps A$ps % NPV Sensitivity

mboe AUD (m) mboe AUD (m) risked unrisked -$10 Base +$10

E&P 100% 489 2,549 100% 489 2,549 4.3 2.35 2.35 14% 2.23 2.35 2.56

SA & SWQ Cooper 50 418 100% 50 418 6.9 0.38 0.38 2% 0.36 0.38 0.42

Perth Basin 4 38 100% 4 38 6.9 0.03 0.03 0% 0.03 0.03 0.04

Surat - - 100% - - - - 0% - - -

Bass Basin 25 423 100% 25 423 13.8 0.39 0.39 2% 0.36 0.39 0.43

Otway Basin 64 936 100% 64 936 12.1 0.86 0.86 5% 0.83 0.86 0.92

Onshore Taranaki 4 95 100% 4 95 20.5 0.09 0.09 1% 0.08 0.09 0.10

Kupe 50% 35 446 100% 35 446 10.5 0.41 0.41 2% 0.37 0.41 0.48

Third Party 100% 307 194 100% 307 194 0.5 0.18 0.18 1% 0.18 0.18 0.18

Generation 100% 4,597 100% 4,597 na 4.23 4.23 25% 4.23 4.23 4.23

Darling Downs 100% 1,015 100% 1,015 0.93 0.93 5% 0.93 0.93 0.93

Uranquinty 100% 851 100% 851 0.78 0.78 5% 0.78 0.78 0.78

Worsley 50% 62 100% 62 0.06 0.06 0% 0.06 0.06 0.06

Bulwer Island 50% 65 100% 65 0.06 0.06 0% 0.06 0.06 0.06

Osborne 50% 67 100% 67 0.06 0.06 0% 0.06 0.06 0.06

Mt Stuart 100% 76 100% 76 0.07 0.07 0% 0.07 0.07 0.07

Quarantine 100% 105 100% 105 0.10 0.10 1% 0.10 0.10 0.10

Ladbroke 100% 60 100% 60 0.06 0.06 0% 0.06 0.06 0.06

Roma 100% 27 100% 27 0.02 0.02 0% 0.02 0.02 0.02

Mortlake 100% 929 100% 929 0.86 0.86 5% 0.86 0.86 0.86

Cullerin Ridge 100% 187 100% 187 0.17 0.17 1% 0.17 0.17 0.17

Eraring Gentrader 100% 1,153 100% 1,153 1.06 1.06 6% 1.06 1.06 1.06

Retail 100% 8,589 100% 8,589 na 7.91 7.91 46% 7.69 7.91 7.98

15 Year Cashflow (less Gen) 4,309 100% 4,309 3.97 3.97 23% 3.80 3.97 4.00

Terminal Value 4,280 100% 4,280 3.94 3.94 23% 3.90 3.94 3.98

Contact 51.4% 2,285 100% 2,285 na 2.10 2.10 12% 2.10 2.10 2.10

Sub Total 489 18,020 489 18,020 30.2 16.59 16.59 96% 16.26 16.59 16.88

Developing Assets

APLNG - Domgas 30.0% 142 379 100% 142 379 2.2 0.35 0.35 2% 0.33 0.35 0.37

APLNG - tr 1 30.0% 244 1,363 100% 244 1,363 4.6 1.26 1.26 7% 1.00 1.26 1.66

APLNG - tr 2 30.0% 220 2,871 100% 220 2,871 10.7 2.64 2.64 15% 2.28 2.64 3.15

APLNG - tr 3 30.0% 269 1,419 15% 40 213 4.4 0.20 1.31 1% 0.16 0.20 0.25

ATP 788P (Iron Bark) 100% 192 713 50% 96 356 4.0 0.33 0.66 2% 0.33 0.33 0.33

GLNG supply contract 100% 61 272 75% 46 204 3.7 0.19 0.25 1% 0.10 0.19 0.38

Trefoil (T/18P - Bass Gas) 39% 19 116 50% 10 58 5.0 0.05 0.11 0% 0.05 0.05 0.05

Redback South-1 (onshore Perth) 67% 3 16 75% 2 12 5.0 0.01 0.02 0% 0.01 0.01 0.01

Redback South-2 (onshore Perth) 67% 3 16 75% 2 12 5.0 0.01 0.02 0% 0.01 0.01 0.01

Mbawa-1 (L8 - offshore Kenya) 20% 140 1,280 10% 14 128 7.5 0.12 1.18 0% 0.12 0.12 0.12

Sub Total 1,292 8,447 816 5,597 5.6 5.15 7.78 29% 4.39 5.15 6.35

- - -

Static Assets & Exploration

Contracted Wind Capacity 100% 355 25% 89 0.08 0.33 0% 0.08 0.08 0.08

Gas Options 100% 1,099 10% 110 0.10 1.01 1% 0.10 0.10 0.10

Wind Options 100% 1,756 10% 176 0.16 1.62 1% 0.16 0.16 0.16

Sub Total - 3,210 - 374 0.34 2.96 2% 0.35 0.34 0.35


Cash 401 0.37 0.37 2% 0.37 0.37 0.37

Debt & Hybrid (5,546) (5.11) (5.11) -30% (5.11) (5.11) (5.11)

Transform Solar, Geothermal 56 100% 56 0.05 0.05 0% 0.05 0.05 0.05


Sub Total - 56 - (5,315) (4.89) (4.89) -28% (4.89) (4.89) (4.89)

Overall total 1,781 29,733 1,304 18,677 17.20 22.43 100% 16.10 17.20 18.69

-core NPV per share (A$) 15.94 14.97 15.94 17.18

-risked NPV per share (A$) 17.20 16.10 17.20 18.69

-unrisked NPV per share (A$) 22.43 21.10 22.43 24.31

-ORG ex APLNG 12.75

Ordinary Shares on Issue (m) 1,086

Exchange Rate 0.82


Share Price 11.12




7 December 2012 25

AUSTRALIA

OSH AU Outperform

Price (at 05:10, 06 Dec 2012 GMT) A$7.04





GICS sector Energy



Number shares on issue m 1,335


Year end 31 Dec 2011A 2012E 2013E 2014E

Revenue m 703.3 680.9 677.5 1,086.0 EBIT m 473.8 330.3 330.4 605.3 Reported profit m 202.5 183.0 150.8 379.0 Adjusted profit m 235.7 149.7 150.8 379.0 Gross cashflow m 357.9 340.4 323.1 624.4 CFPS ¢ 27.0 25.5 24.1 46.4 CFPS growth % 9.2 -5.3 -5.6 92.3 PGCFPS x 27.3 28.8 30.5 15.9 PGCFPS rel x 3.22 3.18 3.36 2.01 EPS adj ¢ 17.8 11.2 11.3 28.2 EPS adj growth % 62.0 -36.7 0.2 150.0 PER adj x 41.4 65.5 65.3 26.1 PER rel x 3.13 4.69 4.59 2.09 Total DPS ¢ 4.0 4.0 4.0 6.0 Total div yield % 0.5 0.5 0.5 0.8 Franking % 0 0 0 0 ROA % 9.5 5.1 4.3 7.1 ROE % 8.1 4.8 4.6 10.7 EV/EBITDA x 18.8 21.7 22.6 13.4 Net debt/equity % 23.2 71.6 102.3 99.1 P/BV x 3.2 3.1 2.9 2.7

OSH AU vs ASX 100, & rec history



(all figures in USD unless noted)


Oil Search

No one is immune to LNG development pressures

Still a great project at U$19bn…: With the new PNG LNG budget standing

at U$19bn, this project is now 27% over-budget driven by adverse fx swings,

community issues and inclement weather. At this stage, however, the project

apparently remains on-track for a timely 2014 start-up. Here we note that

given its advantageous project financing terms, PNG LNG‟s valuation is

almost twice as sensitive to schedule versus cost and therefore we see this

cost blow-out as the lesser of two evils. The net result is that with a still

healthy IRR of 18.6%, PNG LNG continues to provide the most downside

protection should costs rise further from here (although we recognise

investments in PNG may also understandably require a higher hurdle rate).

…and still the most easily expandable: PNG LNG also offers the lowest

cost brown-field expansion potential which would be competitive with any

new-build LNG project despite the growing supply-side competition that we

expect. As a result, while we believe Australia‟s market window is closing fast,

we continue to believe in PNG expansion trains.

Time is of the essence: Progress on expansion trains has been slower than

expected and Exxon is showing less urgency than we would like (Exxon

recently suggested that it expected to be producing at least 10mtpa in PNG by

2025 – this is some eight years after we currently expect train 3 to start up). In

light of growing supply-side competition, the LNG market is only getting

tougher and as a result, further delays could impact future pricing terms on

train 3 off-take. What‟s more, given the government‟s growing assertiveness,

we suspect such delays may also result in more onerous fiscal terms, greater

state ownership or larger domestic supply obligations.

Upstream – soil composition, clouds and community costing at Komo:

Exxon now expects the first Antinov to arrive in mid-February, some 6 months

later than originally planned. Management however believes much of this lost

time can be recovered by increasing truck deliveries and re-scheduling work

and so remains confident that Hides gas will be sent down to the LNG plant in

2Q14. From here it is then expected to take ~45 days to first LNG exports.

Downstream tracking well – now over 60% complete: Exxon is confident

of plant delivery close to the original U$4bn budget with the facilities ready to

receive commissioning gas from Kutubu in April/May 2013, as scheduled.

Meanwhile, with ~180 of 297kms of on-shore pipe now welded and with the

off-shore component already finished, the pipeline is making good progress.

Benefits sharing – a simmering medium-term risk: The biggest risk to

PNG LNG is perhaps the urgent need for a robust and equitable benefits

sharing package as community expectations of the project‟s benefit streams

are clearly growing. With the recent political in-fighting and subsequent

election, we suspect this important issue has not received its due attention.

OSH however stress that there is still sufficient time but by the same token

there is also little time to waste (we note this is the one aspect of the

development that is not directly within the JV‟s control).

Maintain Outperform rating & A$9/sh price target: Being outside Australia

and being Exxon operated, PNG LNG was meant to be immune from local

development pressure and therefore the recent over-run was particularly

disappointing. However, after the subsequent pull-back, OSH is back trading

slightly below core NAV which we see as a good entry point given its low risk

upside from greater clarity around the Taza discovery, the ongoing near field

appraisal programme and the growing potential for a 3rd

train in due course.

Indeed, there is no other stock in the sector that can match OSH‟s rich vein of

catalysts and medium-term production growth.


7 December 2012 26

Fig 26 Oil Search financials


Oil Search (OSH-AU) Share Price: A$7.04


Profit & Loss 1H12A 2H12E 2011A 2012E 2013E 2014E Price Assumptions 1H12A 2H12E 2011A 2012E 2013E 2014E

Sales revenue US$m 379 302 703 681 678 1,086 US$/A$ c 1.03 1.07 1.02 1.05 1.04 1.02

add other income US$m 20 14 30 34 30 30 Oil-Brent US$/bbl 114.22 107.10 111.15 110.66 106.25 115.50

Total revenue US$m 399 316 733 715 708 1,116

less operating costs US$m (94) (100) (137) (194) (205) (266) Production 1H12A 2H12E 2011A 2012E 2013E 2014E

EBITDAX US$m 304 217 596 521 503 851 Natural gas bcf 2.6 2.7 5.6 5.3 5.4 5.4

less exploration expensed US$m (56) (78) (61) (134) (108) (135) Crude mmbbl 2.8 2.6 5.6 5.3 5.7 5.2

EBITDA US$m 248 139 535 387 395 716 Condensate mmbbl 0.1 0.1 0.1 0.1 0.1 0.8

less dep. & amort. US$m (23) (23) (50) (46) (54) (100) LNG m tonnes - - - - - 0.3

less other non-cash costs US$m (16) (11) (12) (11) (10) (10) Total production mmboe 3.3 3.1 6.7 6.3 6.7 9.9

EBIT US$m 219 111 474 330 330 605

less net interest US$m (1) (1) (1) (2) (5) (7)

Pre-tax operating profit US$m 218 110 473 328 325 598

less tax expense US$m (111) (68) (237) (179) (174) (219)

Net operating profit US$m 107 42 236 150 151 379

add non-recurring items US$m - 33 (33) 33 - -

Reported profit US$m 107 76 202 183 151 379

Adjusted profit US$m 107 42 236 150 151 379

EPS (adjusted) Acps 7.8 3.0 17.4 10.8 10.8 27.8

EPS Growth % 783% 296% 62% -37% 0% 150%

DPS (Ordinary & Special) Uscps 2.0 2.0 4.0 4.0 4.0 6.0

DPS (Ordinary & Special) Acps 1.9 1.9 3.9 3.8 3.8 5.9

Franking % 0% 0% 0% 0% 0% 0%

EFPOWA shares on issue m 1,332 1,333 1,338 1,333 1,341 1,346


Cash receipts from operations US$m 741 684 732 684 690 1,096 Natural gas bcf (0) (0) (0) (1)

less operating costs US$m (84) (89) (114) (173) (182) (243) Oil mmbbl - - - -

less interest paid US$m (3) (4) (3) (4) (5) (60) Total 2P reserves mmboe - - - -

less tax paid US$m (69) (68) (178) (138) (174) (219) Contingent resources mmbbl 104 98 93 87

Cashflow from operations US$m 219 151 436 370 328 575 Total reserves & resources mmboe 104 98 93 87

less expl & devlp US$m (1,012) (994) (1,469) (2,006) (1,468) (790)

less PP&E US$m (2) - (7) (2) - - 2P reserve life years 87.3 81.7 54.6 19.1

less acq./inv. US$m (5) - - (5) - - EV / 1P reserves US$/boe 29.97 30.55 31.20 32.20

add divestments US$m - 44 - 44 - - EV / 2P reserves US$/boe 17.90 18.11 18.33 18.68

less dividends US$m (15) (27) (37) (41) (53) (54) EV / Total Resources US$/boe 11.37 11.37 11.37 11.37

add equity/other US$m 18 27 43 45 53 27

add debt movements US$m 602 514 818 1,116 878 279

Increase in cash US$m (195) (286) (216) (481) (262) 37

Net debt at year end (cash) US$m 1,496 2,296 700 2,296 3,436 3,678

Balance Sheet 1H12A 2H12E 2011A 2012E 2013E 2014E Per Barrel Statistics 1H12A 2H12E 2011A 2012E 2013E 2014E

Cash & cash eq. US$m 853 567 1,047 567 305 341 Sales Revenue / boe 116.20 98.39 105.17 107.55 101.35 109.82

Current assets US$m 1,228 931 1,295 931 669 706 EBIT / boe 67.30 36.13 70.85 52.17 49.42 61.21

Fixed assets US$m 5,374 6,267 4,407 6,267 7,573 8,182 Profit / boe 32.98 13.75 35.25 23.65 22.56 38.32

Total assets US$m 6,601 7,198 5,702 7,198 8,242 8,888 Opex/boe 16.65 18.56 15.24 17.58 18.42 17.28

Current liabilities US$m 596 596 528 596 596 596 DDA/boe 7.01 7.57 7.44 7.28 8.12 10.15

Total liabilities US$m 3,468 3,989 2,685 3,989 4,882 5,176 Cash flow/boe 67.22 48.98 65.21 58.36 49.08 58.13

Shareholder equity US$m 3,134 3,209 3,017 3,209 3,360 3,712

Ratio analysis 1H12A 2H12E 2011A 2012E 2013E 2014E NPV @ WACC of 11.0%

ND/ND+E % 32% 42% 19% 42% 51% 50% Producing assets US$m A$ps %

Interest cover x 3.8 x 2.6 x 4.2 x 3.3 x 3.3 x 5.3 x Kutubu - PDL 2 649 0.59

Dividend payout ratio % 25% 35% 8% 5% 5% 11% Moran - PDL 2/5 573 0.52

ROA % 3% 2% 9% 5% 4% 7% Gobe Main/SE Gobe 23 0.02

ROE % 3% 1% 8% 5% 5% 11% Hides GTE 111 0.10

ROIC % 4% 2% 8% 3% 3% 5% SE Mananda 12 0.01

Effective tax rate % 51% 62% 50% 54% 54% 37% Developing assets

EBITDA margin % 80% 72% 85% 77% 74% 78% PNG LNG Train 1 & 2 risked valuation @ 100% 5,775 5.29

EBIT margin % 58% 37% 67% 49% 49% 56% Train 3 (Hides upside) risked valuation @ 50% 645 0.59

Free cash flow US$m -725 -597 -676 -1,321 -863 76 Discovered gas in PNG risked valuation @ 15% 28 0.03

Appraisal 1,171 1.07

Valuation 1H12A 2H12E 2011A 2012E 2013E 2014E Exploration & Appraisal upside

EV/EBITDAX ratio x 35.5 x 45.6 x 16.1 x 19.0 x 19.7 x 11.6 x Exploration Portfolio 1,193 1.09

EV/DACF ratio x 56.3 x 67.1 x 29.2 x 30.6 x 15.8 x 5.8 x Financial assets

P/E ratio x 87.0 x 237.6 x 40.5 x 65.2 x 65.1 x 25.3 x Cash & Investments 897 0.75

P/CEPS ratio x 48.6 x 67.8 x 26.7 x 28.8 x 30.4 x 15.4 x Debt - -

FCF yield % -7.8% -5.9% -7.1% -13.4% -8.7% 0.8% Drilling Rigs 70 0.06

Dividend yield % 0.3% 0.3% 0.5% 0.5% 0.8% 1.1% Capitalised G & A (187) (0.17)

Risked NPV 10,959 9.96

Sensitivities (Adjusted Earnings) NPV 2011A 2012E 2013E 2014E Shareprice prem/(disc) to NPV -29%

Oil price (+US$1/bbl) US$m 10.07 236 151 154 385 - core NPV per share (A$) 7.18

delta 0.10 - 1 3 6 - risked NPV per share (A$) 9.96

% 1.0% 0.0% 0.5% 1.8% 1.6% - unrisked NPV per share (A$) 16.46

0.0

5.0

10.0

15.0

20.0

25.0

30.0

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020



7 December 2012 27

Fig 27 Oil Search NAV breakdown


Producing Assets Interest Unrisked Unrisked Risk Risked Risked USD/boe A$ps A$ps % NPV Sensitivity

mmboe USD (m) mmboe USD (m) risked unrisked -$10 Base +$10

Kutubu - PDL 2 60% 14.8 649 100% 15 649 44.0 0.59 0.59 6% 0.53 0.59 0.66

Moran - PDL 2 60% 10.2 306 100% 10 306 30.2 0.28 0.28 3% 0.25 0.28 0.31

Moran - PDL 5 41% 8.0 267 100% 8 267 33.2 0.24 0.24 2% 0.22 0.24 0.27

SE Gobe 26% 0.5 16 100% 0 16 33.8 0.01 0.01 0% 0.01 0.01 0.02

Gobe Main/Saunders 10% 0.2 7 100% 0 7 38.2 0.01 0.01 0% 0.01 0.01 0.01

Hides GtE 100% 9.7 111 100% 10 111 11.4 0.10 0.10 1% 0.09 0.10 0.11

SE Mananda 72% 0.5 12 100% 0 12 25.8 0.01 0.01 0% 0.01 0.01 0.01

Sub Total 43.8 1,368 44 1,368 31.2 1.25 1.25 13% 1.13 1.25 1.39

.

Development Assets

PNG LNG trains 1 & 2 29% 505 5,775 100% 505 5,775 11.4 5.29 5.29 53% 4.54 5.29 5.93

Sub Total 505 5,775 505 5,775 11.4 5.29 5.29 53% 4.54 5.29 5.93

Appraisal upside

Hides upside (train 3) 25% 163 1,289 50% 81 645 7.9 0.59 1.18 6% 0.50 0.59 0.68

Associated gas upside 60% 75 406 50% 38 203 5.4 0.19 0.37 2% 0.16 0.19 0.21

P'nyang (PRL 3) 39% 193 1,041 75% 144 781 5.4 0.72 0.95 7% 0.60 0.72 0.83

Discovered gas in PNG 100% 34 184 15% 5 28 5.4 0.03 0.17 0% 0.02 0.03 0.03

Mananda-5 71% 18 249 75% 13 187 15.0 0.17 0.23 2% 0.17 0.17 0.17

Sub Total 482 3,169 58% 282 1,843 6.5 1.69 2.90 17% 1.45 1.69 1.92

Exploration upside

Near field exploration 100% 125 1,225 30% 38 368 10.0 0.34 1.12 3% 0.34 0.34 0.34

Huria 53% 88 378 10% 9 38 4.5 0.03 0.35 0% 0.03 0.03 0.04

North Angore 53% 88 378 10% 9 38 4.5 0.03 0.35 0% 0.03 0.03 0.04

Tagari 53% 88 378 10% 9 38 4.5 0.03 0.35 0% 0.03 0.03 0.04

Flinders 45% 75 317 10% 8 32 4.5 0.03 0.29 0% 0.02 0.03 0.03

Pandora 24% 40 173 10% 4 17 4.5 0.02 0.16 0% 0.01 0.02 0.02

Manada-6 71% 14 196 10% 1 20 15.0 0.02 0.18 0% 0.02 0.02 0.02

Gulf of Papua 40% 533 2,384 15% 80 358 4.5 0.33 2.18 3% 0.28 0.33 0.38

Taza Block - Taza-1 60% 180 888 25% 45 222 5.0 0.20 0.81 2% 0.20 0.20 0.20

Tajerouine - Semda 100% 55 525 10% 6 53 10.0 0.05 0.48 0% 0.05 0.05 0.05

Al Meashar - Block 7 Yemen 34% 9 57 10% 1 6 7.5 0.01 0.05 0% 0.01 0.01 0.01

Jebel Milh - Block 7 Yemen 34% 9 57 10% 1 6 7.5 0.01 0.05 0% 0.01 0.01 0.01

Sub Total 1,302 6,957 17% 209 1,193 5.7 1.09 6.37 11% 1.02 1.09 1.17


Cash & Investments 897 0.75 0.75 8% 0.75 0.75 0.75

Corporate debt - - 0% - - -

PNG LNG project debt (not included in NPV as field equity valuation) (2,349) (2.15) (2.15) -22% (2.15) (2.15) (2.15)

Drilling rigs 70 0.06 0.06 1% 0.06 0.06 0.06


Sub Total 780 0.64 0.64 6% 0.64 0.64 0.64

Overall total 2,333 mmboe 10,959 USDm 9.96 16.46 100% 8.78 9.96 11.05

- core NPV per share (A$) 44 7.18 6.31 7.18 7.96

- risked NPV per share (A$) 758 9.96 8.78 9.96 11.05

- unrisked NPV per share (A$) 1,851 16.46 14.59 16.46 18.23

Ordinary Shares on Issue (m) 1,331

Exchange Rate 0.82


Share Price 7.04



Mkt Cap 9,373


7 December 2012 28

Important disclosures:

Recommendation definitions

Macquarie - Australia/New Zealand Outperform – return >3% in excess of benchmark return Neutral – return within 3% of benchmark return Underperform – return >3% below benchmark return Benchmark return is determined by long term nominal GDP growth plus 12 month forward market dividend yield

Macquarie – Asia/Europe Outperform – expected return >+10% Neutral – expected return from -10% to +10% Underperform – expected return <-10%

Macquarie First South - South Africa Outperform – expected return >+10% Neutral – expected return from -10% to +10% Underperform – expected return <-10%

Macquarie - Canada Outperform – return >5% in excess of benchmark return Neutral – return within 5% of benchmark return Underperform – return >5% below benchmark return

Macquarie - USA Outperform (Buy) – return >5% in excess of Russell 3000 index return Neutral (Hold) – return within 5% of Russell 3000 index return Underperform (Sell)– return >5% below Russell 3000 index return

Volatility index definition*

This is calculated from the volatility of historical price movements. Very high–highest risk – Stock should be expected to move up or down 60–100% in a year – investors should be aware this stock is highly speculative. High – stock should be expected to move up or down at least 40–60% in a year – investors should be aware this stock could be speculative. Medium – stock should be expected to move up or down at least 30–40% in a year. Low–medium – stock should be expected to move up or down at least 25–30% in a year. Low – stock should be expected to move up or down at least 15–25% in a year. * Applicable to Australian/NZ/Canada stocks only

Recommendations – 12 months Note: Quant recommendations may differ from Fundamental Analyst recommendations

Financial definitions

All "Adjusted" data items have had the following adjustments made: Added back: goodwill amortisation, provision for catastrophe reserves, IFRS derivatives & hedging, IFRS impairments & IFRS interest expense Excluded: non recurring items, asset revals, property revals, appraisal value uplift, preference dividends & minority interests EPS = adjusted net profit / efpowa* ROA = adjusted ebit / average total assets ROA Banks/Insurance = adjusted net profit /average total assets ROE = adjusted net profit / average shareholders funds Gross cashflow = adjusted net profit + depreciation *equivalent fully paid ordinary weighted average number of shares All Reported numbers for Australian/NZ listed stocks are modelled under IFRS (International Financial Reporting Standards).

Recommendation proportions – For quarter ending 30 Sept 2012

AU/NZ Asia RSA USA CA EUR Outperform 50.00% 56.85% 61.54% 41.38% 63.19% 44.15% (for US coverage by MCUSA, 7.35% of stocks covered are investment banking clients)

Neutral 36.62% 25.14% 27.69% 52.13% 30.77% 30.57% (for US coverage by MCUSA, 9.31% of stocks covered are investment banking clients)

Underperform 13.38% 18.02% 10.77% 6.49% 6.04% 25.28% (for US coverage by MCUSA, 0.00% of stocks covered are investment banking clients)

Company Specific Disclosures: Macquarie and its affiliates collectively and beneficially own or control 1% or more of any class of Woodside Petroleum Limited's equity securities. Macquarie Bank Limited makes a market in the securities in respect of Woodside Petroleum Limited. Macquarie Bank Limited makes a market in the securities in respect of Santos Limited. Macquarie and its affiliates collectively and beneficially own or control 1% or more of any class of Santos Limited's equity securities. Macquarie and its affiliates collectively and beneficially own or control 1% or more of any class of Origin Energy Limited's equity securities. Macquarie acted as Joint Lead Manager to Origin Energy Limited for an offer of dated, unsecured, subordinated, cumulative notes to raise $500 million with the ability to raise more or less. The Macquarie Group acted as financial advisor to Origin Energy in relation to its acquisition of the retail businesses of Integral Energy and Country Energy as announced on 15 December 2010. The Macquarie acted as joint lead manager, underwriter and joint bookrunner to Origin Energy Limited on a pro-rata renounceable entitlement offer as announced on 15 March 2011. Within the last 12 months, Macquarie Group has received compensation for investment advisory services from Origin Energy Limited. Macquarie Bank Limited makes a market in the securities in respect of Origin Energy Limited. Macquarie Bank Limited makes a market in the securities in respect of Oil Search Limited. Macquarie and its affiliates collectively and beneficially own or control 1% or more of any class of Oil Search Limited's equity securities. Important disclosure information regarding the subject companies covered in this report is available at www.macquarie.com/disclosures.

Analyst Certification: The views expressed in this research reflect the personal views of the analyst(s) about the subject securities or issuers and no part of the compensation of the analyst(s) was, is, or will be directly or indirectly related to the inclusion of specific recommendations or views in this research. The analyst principally responsible for the preparation of this research receives compensation based on overall revenues of Macquarie Group Ltd (ABN 94 122 169 279, AFSL No. 318062) (“MGL”) and its related entities (the “Macquarie Group”) and has taken reasonable care to achieve and maintain independence and objectivity in making any recommendations. General Disclosure: This research has been issued by Macquarie Securities (Australia) Limited (ABN 58 002 832 126, AFSL No. 238947) a Participant of the Australian Securities Exchange (ASX) and Chi-X Australia Pty Limited. This research is distributed in Australia by Macquarie Equities Limited (ABN 41 002 574 923, AFSL No. 237504) ("MEL"), a Participant of the ASX, and in New Zealand by Macquarie Equities New Zealand Limited (“MENZ”) an NZX Firm. Macquarie Private Wealth‟s services in New Zealand are provided by MENZ. Macquarie Bank Limited (ABN 46 008 583 542, AFSL No. 237502) (“MBL”) is a company incorporated in Australia and authorised under the Banking Act 1959 (Australia) to conduct banking business in Australia. None of MBL, MGL or MENZ is registered as a bank in New Zealand by the Reserve Bank of New Zealand under the Reserve Bank of New Zealand Act 1989. Any MGL subsidiary noted in this research, apart from MBL, is not an authorised deposit-taking institution for the purposes of the Banking Act 1959 (Australia) and that subsidiary‟s obligations do not represent deposits or other liabilities of MBL. MBL does not guarantee or otherwise provide assurance in respect of the obligations of that subsidiary, unless noted otherwise. This research is general advice and does not take account of your objectives, financial situation or needs. Before acting on this general advice, you should consider the appropriateness of the advice having regard to your situation. We recommend you obtain financial, legal and taxation advice before making any financial investment decision. This research has been prepared for the use of the clients of the Macquarie Group and must not be copied, either in whole or in part, or distributed to any other person. If you are not the intended recipient, you must not use or disclose this research in any way. If you received it in error, please tell us immediately by return e-mail and delete the document. We do not guarantee the integrity of any e-mails or attached files and are not responsible for any changes made to them by any other person. Nothing in this research shall be construed as a solicitation to buy or sell any security or product, or to engage in or refrain from engaging in any transaction. This research is based on information obtained from sources believed to be reliable, but the Macquarie Group does not make any representation or warranty that it is accurate, complete or up to date. We accept no obligation to correct or update the information or opinions in it. Opinions expressed are subject to change without notice. The Macquarie Group accepts no liability whatsoever for any direct, indirect, consequential or other loss arising from any use of this research and/or further communication in relation to this research. The Macquarie Group produces a variety of research products, recommendations contained in one type of research product may differ from recommendations contained in other types of research. The Macquarie Group has established and implemented a conflicts policy at group level, which may be revised and updated from time to time, pursuant to regulatory requirements; which sets out how we must seek to identify and manage all material conflicts of interest. The Macquarie Group, its officers and employees may have conflicting roles in the financial products referred to in this research and, as such, may effect transactions which are not consistent with the recommendations (if any) in this research. The Macquarie Group may receive fees, brokerage or commissions for acting in those capacities and the reader should assume that this is the case. The Macquarie Group„s employees or officers may provide oral or written opinions to its clients which are contrary to the opinions expressed in this research. Important disclosure information regarding the subject companies covered in this report is available at www.macquarie.com/disclosures.


7 December 2012 29

Australian LNG outlook - Macquarie€¦ · Squeezing through the closing window the surviving LNG projects but it looks like too little, too late. 7 Sep 2010 A building threat from

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