A Bank of Japan decision not to follow up a $1.4-trillion
stimulus programme announced in April rekindled fears that other
central banks, including the U.S. Federal Reserve, could scale
back stimulus efforts, and also hurt investor sentiment.

Brent crude futures had dropped 60 cents to $102.36
a barrel by 0649 GMT, while U.S. oil fell 76 cents to
$94.62.

U.S. oil stockpiles rose 9 million barrels last week, data
from the American Petroleum Institute showed on Tuesday.

“U.S. inventories are still relatively high, well above
five-year averages anyway, for this time of year,” said Natalie
Rampono, commodity strategist at ANZ in Melbourne.

U.S. oil inventories would normally be expected to start
dropping at this time of year, when the summer driving season
causes fuel demand to spike.

Both the Organization of the Petroleum Exporting Countries
(OPEC) and the U.S. Energy Information Administration (EIA) cut
their demand forecasts on Tuesday.

“The fact that they are making ongoing downgrades, I think
that’s also weighing on sentiment,” said Rampono, adding that
the cuts of 10,000 and 20,000 barrels per day were not much.

OPEC trimmed its forecast for 2013 world oil demand growth
by 10,000 barrels per day (bpd) to 780,000 bpd.

But it expects demand to grow more quickly during the rest
of the year than in the first half, boosted by economic recovery
and higher seasonal consumption, the cartel said in a monthly
report.

The EIA also cut both its 2013 and 2014 world oil demand
growth forecasts by 20,000 barrels per day.

Oil demand in developing countries in April surpassed that
of wealthy nations for the first time ever, the EIA reported.

(Editing by Clarence Fernandez and Joseph Radford)

Estimated global reserves of oil in shale rock deposits will
boost total world crude resources by 11 percent, the U.S.
government said in a report on Monday.

U.S. oil production has soared as new drilling techniques
have unlocked shale deposits countrywide. The Energy Information
Administration now estimates such shale oil reserves at 58
billion barrels, up from 32 billion in 2011.

“The gains seem to be hitting a ceiling simply because there
is a broad market recognition that supply is racing ahead of
demand,” said Victor Shum, managing director of downstream
energy consulting, at IHS in Singapore.

Brent crude fell 14 cents at $103.81 a barrel by
0651 GMT, while U.S. oil rose 8 cents to $95.85.

Increasing oil supplies and waning demand in China, the
world’s number two oil consumer, are likely to hold down prices.

Data from China showed a slowdown in the economy of the
world’s biggest energy consumer, with May exports weak and
domestic activity struggling to pick up.

Implied oil demand rose in May at its lowest annual rate
since September 2012, Reuters calculations show.

A Reuters poll of analysts expects U.S. commercial crude oil
stockpiles to have risen last week on higher imports, in a
counterseasonal increase that may squeeze prices.

The North Sea Buzzard oil field, which produces 200,000
barrels per day, returned to full production capacity on Monday,
weighing on Brent prices.

The Organization of the Petroleum Exporting Countries (OPEC)
and the West’s energy adviser, the International Energy Agency
(IEA), will release monthly reports of global oil demand on
Tuesday.

OPEC is expected to confirm that production rose slightly in
May, Citi analyst Tim Evans said in a note.

Also helping to keep a lid on prices is continued oil supply
from South Sudan, despite threats from Sudan that it would stop
cross-border flows in a row over alleged support for rebels.

In the latest conflict, Sudan had said it would close the
two export pipelines with its African neighbour within two
months unless Juba halted support for insurgents operating
across the shared border.

Turning off the tap from South Sudan would hit supplies to
Asian buyers, such as China National Petroleum Corp (CNPC)
, India’s ONGC Videsh, and Malaysia’s
Petronas, which run the oilfields in both countries.

“The market continues to regard tensions between Sudan and
South Sudan as more noise than a credible threat that oil
exports are about to be interrupted,” Citi’s Evans said.

Oil prices had risen in early trade on the U.S. jobs data
that showed a slight improvement, indicating that while the
economy of the world’s top oil consumer was healthier, it was
also still in need of the Federal Reserve’s monetary support.

“Oil prices are rising too much and then the reality sets in
that the overall, worldwide demand is not all that great,” Tony
Nunan, oil risk manager with Mitsubishi Corp in Tokyo. “I think
now we’re going to swing back and focus on China.”

Data over the weekend showed that China’s economy is losing
momentum, with May exports and domestic activity struggling to
pick up.

Brent oil dropped 44 cents to $104.12 a barrel by
0818 GMT, after climbing to $104.76 earlier. U.S. oil
dropped 37 cents to $95.66 per barrel.

The market is looking well supplied later in the year, said
Victor Shum, managing director, downstream energy consulting, at
IHS in Singapore.

“There is broad market recognition that oil supply is racing
ahead of demand with strong non-OPEC supply growth,” Shum said,
adding that Brent will probably trade below $100 on average in
the second half.

The Organization of the Petroleum Exporting Countries, which
pumps more than a third of the world’s oil, has little room to
pump more due to a U.S. oil boom that has sparked competition
for market share in Asia and set off a rivalry between the
OPEC’s top two producers Saudi Arabia and Iraq.

But oil price losses may be limited by the stronger U.S. job
number and hopes the U.S. Federal Reserve would hold off on
tapering its massive stimulus.

The U.S. employers stepped up hiring by a little more than
expected in May, but the jobless rate remained well above
pre-recession levels and May marked the third straight month
that payrolls rose by less than 200,000.

The report showed an economy still in need of the Fed’s
monetary support, but one which could be strong enough by
September for the U.S. central bank to ease up on its
bond-buying stimulus, many economists said.

Prices also drew support from concerns about Sudan cutting
oil exports from South Sudan, said IHS’ Shum.

Sudan edged back from a day-old order to block all oil
exports from South Sudan on Sunday, saying it could reverse its
decision if its neighbour stopped backing rebels.

The standoff is a stark reminder of the unpredictability of
this small but, for China and other Asian buyers and producers,
still significant corner of the crude industry.

(Additional reporting by Manash Goswami in Singapore; Editing
by Himani Sarkar)

Seoul has warned of power shortages and rolling blackouts
due to the closure of two reactors and the extended shutdown of
a third to replace parts supplied using fake documents.

Traders and suppliers of LNG, gas super chilled into liquid
for shipping, see the extra South Korean demand boosting prices
already being supported by additional Japanese needs after the
Fukushima crisis two years ago crippled its nuclear industry.

South Korea, the world’s No.2 liquefied natural gas importer
after Japan, is due to detail its plans on Friday on how it
intends to cope with a loss of power just as demand peaks in the
summer when air conditioning use spikes. Meteorologists are
forecasting this summer could be unusually hot.

Korea Gas Corp (KOGAS), the world’s largest
corporate buyer of LNG, has already said it will raise stock
levels to 70 percent of its capacity of 3.96 million tonnes from
about 60 percent now. That will mean an additional requirement
of 396,000 tonnes of LNG, which is mainly supplied in Asia by
plants in Australia and Indonesia.

“If the South Koreans start buying right now to add to their
inventories, it could support prices,” said a LNG trader in
Singapore. “A lot will depend on the summer, on the temperatures
and LNG consumption.”

Asian spot LNG prices LNG-AS have traded in a tight range
recentlyas the influence of steady Japanese demand was capped by
weak demand from Europe, particularly UK purchases.

ASIAN PRICES

Prices have held around $14 to $14.50 per million British
Thermal Units (BTU) for the last few weeks, and more South
Korean purchases could take them up to $15-$16 per MBTU. But
they are unlikely to rise back to highs of nearly $20 per MBTU
earlier this year, traders said, citing ample supply and weak
European demand.

“If they need more LNG this year, they shouldn’t have a
problem getting it,” said Tony Regan, an analyst at energy
consultancy Tri-Zen. “We might see prices come up a bit but it
shouldn’t be too dramatic.”

South Korea’s energy ministry sees power supply this summer
at about 77,000 megawatts, down 3,000 MW after the closure of
the nuclear plants and short of demand projection of 79,000 MW.

To have a big impact on Asian prices, 5,000 MW or more would
have to go offline, the Singapore-based trader said.

The problems at the South Korean reactors mark a fresh blow
to authorities after the country previously halted the
operations of some of its 23 reactors last November after a
scandal emerged over parts being supplied using fake documents.

The reactors, which each have a capacity of 1,000 MW, would
remain closed for about four months, the government said.

Reflecting the sensitivities of the closure, South Korean
Energy Minister Yoon Sang-jick cut short a trip to the United
Arab Emirates, where he attended the ground-breaking for a South
Korean-built reactor, to deal with the power situation.

South Korea has a lot to lose. It plans to add another 11
nuclear reactors in the country by 2024 to lessen its dependence
on fossil fuels.

The country also wants to play a growing role in the global
nuclear industry, and aims to export scores of nuclear reactors.
A $20 billion deal with the UAE has already been signed.

POWER MIX

Coal and nuclear power plants together account for 55
percent of South Korea’s total generating capacity of 83,465
megawatts, according to Korea Power Exchange.

Most of the coal power plants are already running at full
capacity, which means South Korea can’t step up imports of the
fuel to meet the shortfall, an industry source said.

Gas-based power stations, which can generate 23,220 MW,
accounting for 28 percent of the country’s total capacity, offer
the best potential to increase power.

The timing of the nuclear closures comes at time when gas
consumption would normally turn lower after winter when heating
facilities run for 24 hours.

“Unless spot prices are low, we don’t plan to buy a lot
more,” said a second source at KOGAS. “According to our
calculations, we are not in any dangerous situation as LNG
demand will only be half or a third of what it would have been
in winter.”

The biggest Asian – and global – buyer of LNG is still
Japan. Its LNG imports are likely to stay at record highs as 48
of the country’s 50 reactors remain shut awaiting safety checks
under new rules that will be finalized in July.

Japan imported 7.05 million tonnes of the fuel last month,
up 2.1 percent from a year earlier. In the year ended in March,
imports came to a record 87 million tonnes, more than a third of
global supply of 240 million tonnes during 2011.

(Additional reporting by Aaron Sheldrick in Tokyo; Writing by
Manash Goswami; Editing by Ed Davies)

Stiff competition in the energy and mining sectors driven by
an infrastructure building spree to meet Asian demand has led to
shortages of some workers and driven up wages in recent years.

Australia has seven LNG projects under construction,
involving firms such as Royal Dutch Shell, Chevron Corp
and Inpex, but more than half have announced
cost blowouts partly blamed on labour costs.

Soaring costs in Australia, also linked to a strong local
dollar and stringent environmental rules, have become a hot
issue and led to some in the industry warning that $100 billion
of future LNG projects could be scrapped.

LNG projects in Australia are currently 20 to 30 percent
more expensive than their rivals in North America and East
Africa, according to the consulting firm McKinsey & Company.

Chevron Corp, whose $52 billion Gorgon LNG plant in
Western Australia is the largest gas export facility under
construction, said is already seeing more interest in LNG jobs.

“We were a little bit worried that as we got into the big
ramp up that we might be caught short,” said Roy Krzywosinski,
managing director of Chevron Australia.

“When we need an incremental 100 people, we are finding
them,” he added, speaking on the sidelines of an industry
conference where costs have been a big talking point.

Gorgon LNG and Chevron’s $29 billion Wheatstone LNG
development have together created 14,000 jobs across Australia.

Companies with LNG operations near Australia’s coal sector
on the eastern seaboard may be reaping even more benefits.

With coal miners cutting output and staff, more workers were
now available, said Grant King, managing director of Origin
Energy.

“The great news is there’s jobs for those people in (the LNG
industry),” King said.

While the supply of more labour may take some pressure off
LNG projects, it was unlikely to drive down costs on Origin’s
A$24.7 billion ($23.77 billion) Australia Pacific LNG plant.

“I don’t think anybody is saying these projects are going to
get cheaper, but I think the availability of labour takes some
of the risks away from these projects,” King said.

MORE DRILLING RIGS, GEOLOGISTS

The easing of pressures for some LNG and gas producers goes
beyond labour.

“Resources have been relatively available – anything from
trucking to drilling rigs to geologists and engineers,” said
Brad Lingo, managing director of oil and gas explorer
Drillsearch.

Drillsearch, which expects to supply gas to LNG export
projects, has seen a 10 to 20 percent cost saving in its
operations at the exploration stage, Lingo said.

While cost improvements can be chalked up partly to the
mining downturn, engineering and oil and gas services companies
were also having to cut fees to win work in Australia, said
David Knox, chief executive of Santos, Australia’s
second-biggest energy firm.

Australian LNG projects currently on the drawing board could
provide a A$320 billion windfall for the Australian economy from
2015 to 2025, according to McKinsey.

But given Australia’s higher costs some fear the projects
won’t get built.

Although Australia is on a path to becoming the world’s top
producer with it share of global LNG supply set to jump from 7
percent in 2000 to 25 percent in 2018, Wood Mackenzie said it
expected fewer new LNG plants to be approved due to higher costs
and competition from U.S. LNG exports tied to a shale gas boom.

“U.S. supply has become the most favourable near-term
option, that is for deals where supply is expected to start pre
2020,” Andrew McManus, Wood Mackenzie’s head of Australia
Upstream Consulting, said.

But some in the industry are less gloomy, even with costs
20 to 30 percent more expensive than the competition.

“That is a concern, we’ve got to work on that. It doesn’t
mean that everything is off,” said Santos’ Knox, who expects
cheaper ways of building LNG projects to help the situation.

Faced by the higher expense of building on-shore plants,
firms such as Woodside Petroleum and Royal Dutch Shell
are also looking at floating LNG platforms to save
cash.($1 = 1.0389 Australian dollars)

(Editing by Ed Davies)

Prices have slumped around 30 percent since their peak two
years ago as coal flooded global markets, especially from the
United States where cheap gas has cut domestic demand and led to
a nearly 50 percent jump in thermal coal exports last year. Even
robust Chinese and Indian demand growth is failing to soak up
the plentiful supply.

To boost their thinning margins, miners in Australia such as
BHP Billiton, Rio Tinto, Glencore Xstrata
and Peabody have trimmed output and laid off
thousands. Clinging to barely profitable operations, coal
producers now face the prospect of further cost-cutting, which
they fear could benefit rivals when the market recovers.

“Everyone is waiting to see who blinks first,” said Tom
Sartor, an analyst with Morgans Stockbroking in Brisbane. “You
don’t want to be the one curtailing production knowing that it’s
going to benefit your competitor.”

Australia’s coal industry has become a victim of its own
success. In its rush to meet growing Chinese demand, producers
churned out more and more coal, and miners are now stuck with
more than they can sell.

This has been compounded by the dramatic ascent of shale gas
production in the United States, whose displaced coal has headed
to the rest of the world.

About a fifth of the United States’ 56 million tonnes of
thermal coal exports in 2012 went to Asia, Australia’s main
market, according to the U.S. Energy Information Administration.

Australian thermal coal exports could even fall this year
and growth rates are likely to remain weak in the next few
years. UBS expects Australian coal exports to drop around 5
percent to around 162 million tonnes, after increasing 31
percent to 171 million tonnes in 2012.

“The market is chronically oversupplied at the moment …
current supply capacity is adequate enough to take care of
demand growth over the next couple of years,” said Prakash
Sharma, Wood Mackenzie’s senior coal markets analyst for Asia
Pacific.

As a result, analysts estimate Australian thermal coal
prices through the end of the decade to range from
around $90 per tonne now to $105 per tonne, with a $130 per
tonne record high in 2011 seen as an anomaly.

TOUGH FOR JUNIORS

While top miners have big balance sheets to help them
weather the storm, junior miners face a bleaker outlook, with
the funding environment the worst in a generation.

“The market’s pretty much dead. For many of the small coal
companies, it’s just not going to happen unless you have very
deep pockets and even then nothing is certain,” said Warwick
Grigor, executive chairman of Canaccord BGF, a stockbroker
specialising in the emerging mining sector.

Aquila Resources was dealt a blow last month when
Japan’s Sumitomo Corp pulled out of their coal
exploration partnership, in one of the latest examples of a
setback for smaller miners.

And global companies are bracing for more cutbacks as well,
with BHP last week announcing its capital and exploration
expenditure would be slashed, while Glencore Xstrata stopped
work on a planned 35 million tonnes-per-year Australian coal
export terminal.

Rio Tinto is looking sell of part of its stake in
its Coal & Allied subsidiary, which produces mostly thermal
coal, as well as several other mines.

According to the Australian Coal Association, the country’s
coal industry directly employs 50,000, and the downturn is
already clear in its eastern coal towns.

Just a year ago it was nearly impossible to rent an
apartment in Queensland’s Blackwater, whose name had become
synonymous with the boom in coal as workers rushed there for
jobs in mines run by firms such as BHP.

But rents have since plummeted around 75 percent after the
wave of miners and contractors receded, leaving the boom years a
fast-fading memory to many of the permanent residents of the
town of 5,000.

‘TAKE OR PAY’

Efforts to reduce supply and slash costs have been hampered,
however, with some producers locked into long-term contracts
with port and rail companies.

Under ‘take-or-pay’ agreements, miners must either ship a
minimum amount of coal or pay a hefty fine.

“I don’t see the supply-demand dynamic changing quickly,
particularly in Australia with so many companies with
take-or-pay commitments with ports,” Whitehaven Coal Managing
Director Paul Flynn told Reuters in an interview last month.

“That really is an impediment to a rebalancing of the
supply-demand equation in the short term … You’d have to be
losing more than your take-or-pay commitments to shut a mine
down.”

The good news for miners is that appetite in China and
India, the two biggest drivers of global coal demand growth,
will cushion the sector’s decline.

The two nations currently account for around 30 percent of
the world’s global coal demand, with that figure remaining
relatively steady through the latter part of the decade,
according to a UBS forecast.

“We’ll never really go back to the bad old days because
(China and India) are two new kids on the block that aren’t
going away,” said Tom Price, an analyst with UBS in Sydney.

But as substantial producers of coal themselves, the two may
also add volatility to the market as they swing between domestic
supplies and imports, depending on price differences.

China, the world’s largest producer as well as consumer of
coal, dug a whopping 3.1 billion tonnes of thermal coal in 2012,
and had to import more to meet demand.

“People forget just how much coal China produces. You’re not
getting that continuing stream of buyer demand,” said Don
Barnett, whose AustCoal consultancy has worked with numerous
Australian coal producers.

By the end of the decade half a dozen or so floating gas
processing plants, some weighing as much as six aircraft
carriers and half-a-kilometre (0.3 miles) long, could be
deployed on the world’s oceans.

But what is being pushed by oil firms and ship builders as a
blueprint that will transform the offshore gas sector and cut
costs by up to a quarter is seen by critics as an untested and
controversial technology that could hit jobs and investment.

The technology should enable gas to be got at in fields too
far off land for pipes, allowing previously uneconomic reserves
to be exploited, but there has been controversy over plans to
use floating LNG platforms closer to shore instead of building a
plant on land.

In Australia, where the first floating liquefied natural gas
plant is due to launch by 2017, unions are fighting what they
see as the risk of cheap foreign labour being used on a floating
LNG platform in a remote area that could simply pull up anchor
and go elsewhere once a gas field is depleted.

Royal Dutch Shell says that its $12.6 billion
floating Prelude plant being built in South Korea to sit off
Australia would mainly use local labour, denying media reports
suggesting it would be “full” of low paid foreign workers.

“It’s not. It’s going to be full of Australians,” Shell
Australia country chair Ann Pickard told reporters in Perth,
adding that 80 to 85 percent of jobs would be local jobs.

Unions say that local workers could not only lose out on
construction work for onshore plants, but once in operation a
floating plant could skirt local labour laws.

In a case that could shed light on how labour laws apply to
rigs or floating platforms, a lawsuit has been filed on behalf
of four Filipinos in a Western Australian court alleging they
were paid the equivalent of about A$3 ($3.10) per hour while
working on an offshore oil rig, less than a fifth of Australia’s
minimum wage of A$15.96.

The lawsuit centres on an argument over whether anchors or
other lines attaching rigs and other floating production vessels
to the seabed mean all workers should be subject to local labour
laws.

JOBS FLOATING AWAY?

A series of floating LNG projects are underway or planned
globally including a second involving Exxon Mobil and a
third being considered by Woodside Petroleum, also in
Australia.

Others are also planned off Indonesia and Colombia, and are
being considered for Papua New Guinea, Israel and Mozambique.

The economic stakes are high. Woodside had said its plans
for an onshore site for its Browse LNG project would have
created about 8,000 construction jobs and created up to $50
billion in gross domestic product for Australia’s economy.

Woodside CEO Peter Coleman said after a decision to shelve
the onshore option and consider floating LNG that more long-term
jobs would be generated by the latter than at an onshore plant.

But unions are sceptical over moves away from onshore
processing.

“We must not allow local jobs to float away,” said
Australian Manufacturing Workers’ Union State Secretary Steve
McCartney.

East Timor’s government also opposes plans by Woodside for
another floating plant in the Timor Sea and is pressing for an
onshore site that it says would bring more jobs and investment
to the impoverished nation.

COST SAVINGS

Pressure to address the escalating costs of onshore plants
has become a major issue in Australia, which aims to become the
world’s No. 1 LNG exporter by the end of the decade with $190
billion of projects underway.

Of seven LNG plants under construction, more than half have
announced cost blowouts ranging from 15 to 40 percent. Companies
blaming a high local dollar, expensive labour and tough
environmental rules for the rise.

Analysts estimate floating LNG could shave 20 to 25 percent
off LNG plant development costs, with savings coming primarily
from the lack of a need for a pipeline to shore and less labour.

While labour makes up 30 to 35 percent of the cost of an
onshore plant, it only makes up 20 to 25 percent of an offshore
plant, according to Deutsche Bank.

More savings could come from whittling down the development
time. Land-based LNG plants currently take a minimum of four to
five years to construct, according to developer Exmar,
while floating plants could take less than three years.

“This leads to earlier monetization of the gas field, which
is highly attractive from an investment point of view,” said
Bart Lavent, managing director of Exmar’s LNG Infrastructure
division.

UNTRIED TECHNOLOGY?

Gas from floating plants in Australia will supply Asian
nations such as China where demand is set to jump four-fold by
2035, according to International Energy Agency data.

“Asian companies are mostly looking at FLNG investment as a
means of securing access to more LNG,” said Oivin Iversen,
Senior Vice President at Norwegian shipping company Hoegh FLNG,
adding that the firm expected to have orders within two years
for small-scale to mid-size floating LNG vessels.

Western Australia’s Premier Colin Barnett, who has opposed
floating LNG due to the threat to jobs and investment, said the
technology was untested and could be at risk from cyclones.

Shipbuilders, however, are licking their lips at the
prospect of fat contracts. South Korea’s largest – Daewoo
Shipbuilding & Marine Engineering, Hyundai Heavy
Industries and Samsung Heavy Industries
- are all involved in building LNG platforms.

“I personally think the time has passed for worries about
whether floating LNG is untested,” said an official at Daewoo
Shipbuilding, adding that the components had been tested and the
technology was backed by leading energy firms.

Australian LNG projects have seen a series of huge cost
overruns as the country ramps up production on its way to
becoming the world’s largest exporter of the clean burning
energy source.

Some analysts believe the decision on Browse spells an end
to new onshore gas projects in Australia in favour of offshore
plants that can be built more cheaply and face fewer
environmental and landower hurdles.

“This decision will surprise few as the proposed onshore
development always looked too economically, technically,
environmentally and socially risky for too little reward,”
analysts at Macquarie said in a note.

“While the JV appears to have finally seen sense, this
decision probably also calls an end to green field onshore
projects in Australia.”

Browse LNG was to be Woodside’s biggest LNG development yet,
but has been plagued by controversy over its proposed location
at James Price Point on the northwest coast, coming under fire
from environmentalists and some Aboriginal landowners.

Woodside said it would immediately begin evaluation of other
options including a floating LNG plant, pipelines to existing
facilities elsewhere in the region or a smaller onshore plant.

“Woodside firmly believes that the Browse resource is world
class,” Woodside CEO Peter Coleman said on Friday. “We are
working to underpin this value by bringing forward the earliest
possible development of Browse.”

Woodside owns a 31 percent stake in Browse, which it is
developing with partners Royal Dutch Shell, BP Plc
, PetroChina, Mitsui & Co and
Mitsubishi Corp.

Estimates of the cost of the onshore plant option vary, but
some analysts estimate that if it is on par with other LNG
plants underway, such as Chevron Corp’s Gorgon plant, it
could be as high as $48 billion.

Of seven LNG plants under construction in Australia, all of
which are due to come online in 2014 or later, four have already
announced cost blowouts ranging from 15 to 40 percent.

CHEAPER FLOATING

Shares in Woodside, which is worth around $30 billion, rose
3 percent on expectations the company will develop a cheaper
option or free up more cash for shareholders.

Building a floating plant in Asia and towing it into place
off the Western Australia coast is likely to save billions of
dollars in construction costs.

Earlier this month, Exxon Mobil and BHP Billiton
revealed plans to build the world’s largest floating
LNG vessel offshore northwestern Australia, producing 6-7
million tonnes per annum (mtpa) of LNG from 2020-2021.

Woodside’s Browse project had been targeting 12 mtpa.

A person with knowledge of the joint venture partner
discussions said Shell had been pushing the partnership to go
with a floating LNG option given the high costs of an onshore
plant.

Shell, which owns 24 percent of Woodside, has not publicly
supported a floating LNG plant for Browse, but Ann Pickard,
Shell Australia’s chairman has, pointed to floating LNG as a
good solution for Australia’s problems with high costs.

Pickard has also championed floating LNG as a way for
Australia to make revenues faster.

POLITICAL BLOW

However, the decision to shelve the project is a blow to
West Australia’s premier, Colin Barnett, who won reelection last
month and has been a vocal proponent of establishing a gas
export hub at James Price Point, with Browse LNG as the
cornerstone project.

Another option for the plant would be for it to be delayed
until construction costs ease, something some analysts expect to
occur once the existing plants under construction in Australia
come online.

“If Shell were to persuade Woodside that they need to take
more time on this, I don’t think Shell would be criticized. I
think that would be seen as a sensible decision at this point,”
Tony Regan, an analyst with Tri-Zen International in Singapore
said.

Shell has delayed its Arrow LNG development in eastern
Australia and has said it is in no hurry to proceed with an
expansion of Gorgon LNG, in which it is a stakeholder, leading
some to believe that the company would prefer to wait for costs
to decrease before making more large investments in Australia.

Prime Minister Julia Gillard said the decision was a
commercial one and did not mark the end of the country’s near
decade-long boom in resources.

“We haven’t seen the peak of the investment phase into
resources yet. And we are yet to see the peak of the production
phase,” Gillard told reporters in Sydney.

“So we will be seeing the resources boom at work in our
economy for a long time to come.”

Economic growth in China, the world’s top buyer of iron
ore, is expected to slow to a rate of around 7 percent a year
for the rest of the decade, but its demand for resources will
continue to fuel growth in Western Australia, Barnett said in an
interview.

Even so, a number of iron ore infrastructure projects
backed by the premier’s government have been frozen.

Aquila Resources Ltd put its A$7.4 billion ($7.8
billion) West Pilbara Iron Ore project on ice in February due to
funding difficulties after it failed to agree on a budget with
its partners.

Japan’s Mitsubishi also put on hold plans to
develop the A$5.9 billion Oakajee port and rail project in the
state’s Midwest region as it had not been able to line up a
partner to help fund the project.

“The view that Oakajee is not happening is not correct,”
Barnett said, pointing out that a mine in the Midwest region,
Gindalbie Metals Ltd’s A$3 billion Karara mine, had
already started production, and that others would follow.

The state government is still working closely with China’s
National Development Reform Commission, as well as individual
steel mills in China to smooth the way for investment in Western
Australia, Barnett said.

“I’m confident we’ll get there,” he said, adding that the
West Pilbara Iron Ore project’s Anketell port would be next in
line after the ports used by Rio Tinto and BHP Billiton
run out of capacity.

“Once the existing facilities, even with their expansions,
reach capacity, (Anketell) is the next port,” Barnett said.

The state accounts for 73 percent of Australia’s exports to
China, and receives 80 percent of Chinese investment in
Australia, Barnett said.

“While everyone talks about the Asian century, from a West
Australian perspective, it’s really the Asian decade. This is
the decade of greatest opportunity,” Barnett said, adding that
the state will likely double its production of iron ore by the
end of the decade.

“There’s enough investment that’s going to take this state
through this decade.”

Western Australia has a land area about the size of India
with a population equal to that of Paris, and is home to the
largest iron ore deposit on earth.

The state has led Australia’s resources boom, with its No. 1
export earner, iron ore, raking in $62 billion in 2011.

As of late last year, the state had A$167 billion of
resource projects under construction or committed and a further
A$151 billion under consideration.

TAPER OFF

Barnett said China’s growth – and thus hundreds of billions
in dollars of investment in Western Australia – would likely
taper off after 2020, but still saw ample opportunities even in
the face of a Chinese slowdown.

“If China settles down in the 2020s and grows at five or six
percent, that’ll do me. That’s going to be absorbing a huge
amount of natural resources from Western Australia,” the Premier
said.

“There will be volatility. Commodity prices always bounce
around – West Australia has had a 100 years of that, we
understand that,” Barnett said.

At around $135 .IO62-CNI=SI a tonne currently, iron ore
has rebounded more than 50 percent from three-year lows seen
late last year, but prices are still shy of the $200 per tonne
record price seen in early 2011.

More global supply coming through and slower Chinese demand
may pressure prices again from the second half of 2013 and
beyond, with some analysts looking at an average price of below
$100 a tonne by 2015.($1 = 0.9536 Australian dollars)

(Additonal reporting by Manolo Serapio in SINGAPORE; Editing by
Ed Davies)

At around half a kilometer (0.3 miles) long, the vessel would be nearly as long as five football fields laid end-to-end and would be the largest floating facility in the world.

The plant would bump up Australia’s current LNG production by nearly 30 percent, producing 6 million to 7 million metric tons (6.62 million to 7.71 million tons) per annum (mtpa), enough to fuel the LNG needs of Japan, the world’s largest importer of the gas, for about a month.

Exxon and BHP’s decision to develop the Scarborough field using floating LNG is another vote of confidence in the as yet untried technology, which energy companies hope will help cut down on the ballooning costs of developing gas.

Exxon, which detailed the plan in a filing with Australia’s environment department on Tuesday, did not give a cost estimate for the plant.

Australia currently has $190 billion worth of LNG projects under way and is on track to replace Qatar as the world’s largest LNG exporter by the end of the decade.

But the country has been plagued by cost inflation, and of seven LNG plants under construction there that are due to come online in 2014 or later, four have already announced cost blowouts ranging from 15 to 40 percent.

FITCH BEARISH

High costs and competition from other LNG producing regions such as North America and East Africa have led some industry analysts to predict that Australia’s growth potential as an LNG producer is increasingly limited.

Fitch Ratings was the latest to forecast lower growth for the Australian LNG sector, saying in a report on Tuesday that increased costs had eroded the country’s competitive advantage.

Royal Dutch Shell (RDSa.L: Quote, Profile, Research, Stock Buzz), considered the industry leader in floating LNG, has touted floating technology as a way to circumvent Australia’s rising costs and cut down on construction time.

“Floating (LNG) is actually very good for the federal government in terms of getting the tax revenues out faster and quicker,” Ann Pickard, Shell’s country chairman in Australia, said earlier this year.

An added advantage of floating LNG vessels is that they can be redeployed to another location once a gas field is depleted.

The Scarborough LNG plant would start production in 2020-2021 and be moored 220 kilometers (137 miles) from the Australian coast, Exxon said in the government filing.

If the Scarborough gas field were developed using floating LNG, the plant would be about double the capacity of Shell’s Prelude LNG, also off the cost of Australia, which will have a capacity of 3.6 mtpa when it comes online in 2017 and be the world’s first floating LNG plant.

Shell indicated that its Prelude LNG project was expected to cost in the range of $10.8 to $12.6 billion. With a similar cost structure, Scarborough LNG would cost $18 billion to $24.5 billion, according to Reuters’ calculations.

The Scarborough floating LNG plant would be built offshore, likely in South Korea, which is already in talks to build similar facilities.

Exxon and BHP, which are 50-50 joint venture partners in the Scarborough development, expect to make a final investment decision on the plant in 2014-2015, Exxon said.

(Editing by Muralikumar Anantharaman)