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US shale derails Australian CBM LNG plans

US LNG exporters are using cheap shale gas to undercut Australia’s coal-bed methane, threatening billions of dollars in infrastructure investment

Cheap US shale gas is pulling investors and liquefied natural gas (LNG) consumers away from Australia, threatening to derail the country’s plan to be the world’s largest LNG exporter.

Australia was expected to overtake Qatar as the top LNG producer in the coming decade, with more than A$175 billion ($184 billion) in investments set to boost LNG output capacity beyond 100 million tonnes a year (t/y). This compares with Qatar’s 77 million t/y LNG production capacity.

But the US has signalled its intention to become an LNG exporter, as it pushes to monetise its abundant shale-gas production. US unconventional gas output has grown quickly in the past five years, depressing domestic gas prices. US gas now trades at below $2.25 per million British thermal units (Btu), its lowest level in a decade. And US gas prices have stayed relatively flat at around $4/million Btu for the last three years, while global oil prices have almost tripled since the 2008 financial crisis, remaining over $100 a barrel.

Crucially, due to the disconnection between US gas and oil prices, Asian buyers want US LNG because it is linked to the US Henry Hub gas price, making it cheaper than the oil-linked contracts that other LNG producers insist on signing.

Lucky country losing out?

And while interest in US LNG rises, Australia is losing out. Rising raw material prices for huge infrastructure construction, labour shortages, and a strengthening dollar have all added to the cost of Australian LNG export projects.

This, combined with higher Australian gas prices, could give some stakeholders in Australia’s LNG projects cold feet, possibly giving them cause to invest elsewhere.

BG Group is already looking to sell up to 20% of its stake in the $15 billion Queensland Curtis LNG (QCLNG) development in eastern Australia. First shipments from the 8.5 million t/y QCLNG project are expected in 2014. At present, BG Group has a 93.75% operating stake in the project, while China National Offshore Oil Corporation has 5%, with Tokyo Gas owning the remaining 1.25%.

“We would read this move by BG Group as part of a portfolio re-balancing effort that also, we believe, was the impetus for BG [entering supply agreements for] the Cheniere Sabine Pass LNG project,” Zach Allen, president of LNG consultancy Pan EurAsian, said. “While we believe that LNG can be delivered to northeast Asian customers from QCLNG at a lower cost than from Sabine Pass, it does have a significantly different risk profile.”

Calculated in terms of capital investment versus liquefaction capacity, QCLNG is one of the cheapest Australian LNG developments under construction, EnergyQuest, a consultancy, said, but these calculations do not factor in the price of natural gas.

Most of Australia’s gas is sold on bilateral, long-term contracts, with a small spot market in the state of Victoria. Hubs are slowly being developed in Sydney, Adelaide, and Brisbane. The Australian gas market is roughly divided into two – east and west – with both regions experiencing soaring gas prices.

In the east, the Queensland government expects gas prices to rise around 20% to A$6 a gigajoule (GJ) ($6.65/million Btu) by 2015 in its medium-demand scenario. Its high-demand scenario sees prices almost doubling to A$8/GJ in the same timeframe. This is around 30-100% higher than the US Henry Hub gas contracts for June 2015 delivery which are trading around $4.10/million Btu.

On the rise

“In the high scenario, new contract prices are expected to rise substantially from 2013, to over $8/GJ in most (Queensland gas) markets. This level is maintained until growth in LNG stops in the mid-2020s, at which point prices temporarily fall by $1–2/GJ, but then rise back to former levels owing to reserves depletion,” the government’s Gas Market Report 2011 said.

The medium scenario assumes global LNG demand will increase 4.5% a year and one train of 3.5 million t/y capacity to be built on Curtis Island every two years, while the high scenario assumes demand will grow 6.5% and one train to be built a year.

Queensland is home to five planned coal-bed methane (CBM) to LNG export facilities. If all five go ahead, the state’s CBM-LNG production capacity will be 36.3 million t/y from 14 production trains.

In the report, the government estimated liquefaction plus shipping costs to Asian customers at between A$5.35-9.19/GJ or $5.90-9.65/million Btu, with LNG costs varying on the strength of the Australian dollar to US dollar exchange rates. It also calculated CBM and Gippsland basin gas production at $3.50/GJ and assumes CBM producers will not sell below A$4.50/GJ.

In Western Australia, gas prices are forecast to climb even higher than those on the east coast. Average wholesale gas prices have already more than doubled to between A$5.55-9.25/GJ in 2011, according to a government report into Western Australia gas prices last year. For the past 20 years or so, gas prices were around A$2-3/GJ on long-term “legacy contracts”.

EnergyQuest noted that west coast long-term gas contracts were around A$7-8/GJ, more than double US Henry Hub gas contracts for 2015. The consultancy added Western Australian gas contracts were increasingly linked to oil prices, as diesel is often the alternative fuel for customers, with a much higher energy equivalent price of A$20/GJ.

Wholesale gas prices were expected to rise as the cheap legacy contracts discouraged upstream and infrastructure investment, creating a squeeze in gas supply thanks to additional demand from LNG projects.

In Western Australia, the Pluto, Gorgon, and Wheatstone LNG export terminals are all either under construction or have reached the final investment decision stage. The three projects have a combined production capacity of 27.9 million t/y. A final investment decision on the 12 million t/y Browse project is expected next year.

Risky business?

With the price of gas from Queensland and Western Australia expected to be at least a third more expensive than US gas by 2015, Australian LNG producers have to sign oil-linked contracts or risk making a loss. Brent crude contracts for delivery in 2015 are priced at around $100/b, which indicates Australian producers will charge between $13-14/million Btu for oil-linked LNG.

Using Cheniere’s Henry Hub price formula, US LNG could be delivered to Asia in 2015 at under $10/million Btu at present forward gas prices. As an LNG buyer, the choice is obvious.

Australian gas prices are unlikely to fall as long as domestic demand continues to increase, unlike US gas consumption which is expected to stay relatively flat. The US Energy Information Administration sees a 5% rise in domestic demand, to 273 billion cubic metres a year, in the five years to 2015. But the Queensland gas report expects eastern Australian gas demand – which includes the states of New South Wales, Victoria, South Australia, and Tasmania – to rise by 14% to 800 PJ (21.36 billion cm/y) by 2015 and up to 62% to 1,850 PJ by 2030. This includes additional demand from LNG projects, which are expected to need 62.5 PJ of gas a year (1.67 billion cm/y) per tonne of LNG.

Western Australian demand is also set to nearly double from 514 PJ to around 960 PJ by 2019/2020, according to a study for DomGas Alliance, an Australian association of gas consumers, published in 2010.

If Australian LNG stakeholders cannot get the economics to work, projects may be delayed or downsized – giving the US the opportunity to race past Australia and Qatar to become the world’s largest LNG exporter.

So far, seven US terminals have filed applications to export LNG. If all are approved and built, US export capacity would total 102 million t/y, catapulting it ahead of Qatar’s 77 million t/y capacity. If all of the Australian projects go ahead, its capacity will be over 110 million t/y. North American exports gain an extra boost if the 10 million t/y LNG export potential from Apache’s Kitimat terminal in Canada is taken into account.

US on the rise

In its latest strategic outlook, BG Group said the US could be producing up to 45 million t/y by 2020, well above Indonesia’s expected 38.99 million t/y. This would make the US the world’s second-largest exporter, according to the LNG Insight databank. And others are even more optimistic, forecasting the US to reach the top spot by 2020.

“Australia’s need to sell its LNG under an oil-linked formula could delay the final investment decision on some projects, as buyers might prefer to opt for Henry Hub spot-based US LNG,” Thierry Bros, LNG analyst at investment bank Société Générale, said. “We therefore believe that US LNG supply could grow quickly in the 2016-2020 period, possibly overtaking Qatar (and Australia) as the number one producer.”

Since the start of January, Cheniere has signed 16 million t/y of supply deals from its 18 million t/y Sabine Pass LNG export project. BG Group, Spain’s Gas Natural Fenosa, India’s Gail and South Korea’s Kogas are all signed up with contracts linked to the US Henry Hub gas prices.

Cheniere has also signed a $2 billion investment deal with US private equity firm Blackstone towards building Sabine Pass’ first two liquefaction trains, with estimated costs at $9.5 billion.

"We expect to obtain the remaining financing needed to fund the first two trains by the end of the first quarter and to commence construction in the first half of 2012," Cheniere’s chief executive officer Charif Souki, said.

And Asian buyers are still queuing up to buy US over Australian. Japanese officials are in talks with the US government to import up to 17 million t/y LNG, with first shipments as early as 2015, according to Japanese newspaper Yomiuri. Mitsubishi, Chubu Electric Power, and Tokyo Gas are also believed to be interested in participating in US export projects.

Although most of the US LNG export projects have Department of Energy approval to ship to Free Trade Agreement (FTA) countries, only Sabine Pass has permission for non-FTA destinations. Japan, which is not a signatory to the FTA, could ask the US government to approve more projects to export to non-FTA countries or perhaps to provide a waiver for some importers.

Making up for lost capacity

After the Fukushima meltdown last year, Japan, which is the world’s largest LNG importer, is expected to consume even more gas to offset lost nuclear capacity. Fifty two out of 54 nuclear reactors were shut down, either due to the tsunami or for routine maintenance, and, as yet, none have restarted. The country’s two operational plants are due to shut down for maintenance by May, which will increase Japanese LNG demand, at least in the short term.

“Japan imported a record 78.4 million tons of LNG in 2011, up 12% from 2010, which helped to push up Asian demand and Asian spot LNG prices,” US bank Merrill Lynch said. “However, if none of the [nuclear power] capacity was to be re-started, Japanese LNG import demand could spike by an additional 2.3 million tonnes. In that scenario, imports would increase by a total of 11.0 million tonnes to 89.4 million tonnes in 2012.”

Indonesia is also interested in importing US LNG. The southeast Asian country is turning from an LNG exporter to importer to meet domestic gas needs as its own gasfields deplete. “We’re basically very interested in importing LNG from the US, however we need the gas from next year, while most of the US producers will only start deliveries in 2018,” Suryadi Mardjoeki, gas division head of state utility PLN, told the Jakarta Post in an interview.

Fearing the introduction of Henry Hub-linked LNG contracts from 2016 onwards, Qatar, at present the world’s leading exporter, has rushed to sign long-term, oil-linked contracts with Asian customers. Recent Qatar LNG deals include two supply contracts with Kogas and Taiwan’s CPC signed in February 2012 and December 2011 respectively. Both will deliver 2 million t/y of LNG over 20 years.

Qatar’s energy minister Mohammed Bin Saleh Al-Sada also signed a memorandum of understanding with Pakistan petroleum and natural resource minister Asim Hussain to supply 3.5 million t/y of LNG, but the Asian country has since baulked at the $18/million Btu LNG asking price.

The world’s gas demand is going to grow, and LNG is an increasingly important part of that supply. For a long time, Australia was expected to become the global LNG supermarket, but the US is threatening to open shop, offering cheaper alternatives.

And they fear that once consumers get the first taste of hub-linked prices, they will probably never go back. And that fear is not only real, but likely to happen, forcing Australia’s LNG plans on to the buffers.

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