No plain sailing for Australian LNG
The country will shortly become the world's largest exporter
Since the nation's eight new liquefied natural gas export projects were sanctioned—most of which are now operational—oil prices have near halved and the dynamics of the market have changed significantly, rapidly and unpredictably. Australia's high-priced exporters face a raft of uncertainties. These have shaken the foundations of the project-financing and long-term, oil-indexed, bilateral-contract structure on which the large-scale projects were sanctioned.
While views differ on the size and duration of a global LNG supply surplus, the availability of more varied supplies is spurring the entry of trading entities. At the same time, the development of trading hubs offers a more transparent and visible way in which to buy LNG.
Independent commodity trading entities are circling the Asian LNG market to exploit new market dynamics. According to consultancy Wood Mackenzie, Trafigura, Vitol, Gunvor and Glencore were responsible for trading 27m tonnes of LNG in 2017, equivalent to 9% of total volumes sold worldwide. The four now dominate the LNG trading landscape. "As these four trading houses enter the market alongside large buyers and portfolio players, they start to resemble mini-portfolio players," says consultancy Wood Mackenzie.
As a result, one of the outstanding risks that Australian LNG exporters face is in marketing their product. "On the international spot market, the battle is raging between producers, as each of them wants to secure a footprint. Geographical proximity is no longer a guarantee to make business," says Jean-Christian Heintz, founder of advisory firm Wideangle LNG. "So far, Australia has had an easy job selling to legacy Asia [Japan, South Korea], also because these customers would usually evolve very slowly. But the mindsets are changing, and Asian buyers themselves are seeking more flexibility and gearing up their trading skills," Heintz adds.
'Australia's LNG sector has been plagued by high labour costs and will face competition from producers such as Qatargas and Cheniere'—Heintz, Wideangle LNG
To manage marketing risk, Australian producers must look at developing their own trading arms or partner with traders or portfolio players, as Woodside recently did with RWE. "They will have to carefully price their spot LNG, maybe not on a pure netback value, but more on a marketing basis," Heintz says.
The continued expansion of supply into an oversupplied market by low-cost producers, especially Qatar and Russia, and the resurgence of the US shale industry create substantial competiton for Australian LNG in Asia.
While Australia is at a geographical distance from Atlantic markets, the mistake would be not to follow them, says Heintz: "Keeping an eye on European LNG and gas prices is vital to understand the dynamics of global LNG and take action before it's too late. Even if Australia will remain de facto a Pacific player, it has to consider the bigger picture at all times".
What happens in the US should be of particular focus for Australian LNG exporters, says Bruce Robertson at the Institute for Energy Economics and Financial Analysis. "With higher prices the US is seeing a resurgence of activity. Exports will become a focus, placing further pressure on global gas prices," Robertson notes. He adds that "the result of more supply and more ways of buying LNG means the power balance between suppliers and customers has now fundamentally shifted in favour of LNG customers".
A supply surplus and availability of new ways of sourcing LNG are putting pressure on the use of oil indexation in LNG contracts. This is a historical anachronism based on the need to produce power in the days when electricity was generated from oil. "Contracts will increasingly be linked to gas markets, not to oil. This will place further pressure on long-term contract prices," says Robertson.
For Queensland LNG exporters, which source their gas from onshore coal-seam gas (CSG) fields, a business which requires ongoing capital expenditure on drilling, this is of particular concern. "Long-term LNG contracts are priced with reference to oil prices," says Robertson. "The percentage of the oil price—the pricing slope—has fallen from 13.5-14% to 11% for long-term contracts. This will place tremendous pressure on high cost producers such as the east coast Australian onshore gas industry."
Choppy waters: Australia's LNG sector faces domestic and international challenges
In the wider marketplace, the move to Asian LNG spot pricing "will present challenges to capital-intensive long-life projects like ones in Australia in terms of planning and forecasting," says Gero Farruggio, managing director of Rystad Energy Australia, a consultancy.
When it comes to expansions, some Australian LNG projects could find it harder to secure finance than before. "Most of the projects were signed off when oil prices were over $100 per barrel," says Farruggio noting that the lower oil price could present particular economic challenges.
The knock-on effect is rising investment risk. "Australia's LNG sector has been plagued by high labour costs and will face competition from producers such as Qatargas and Cheniere who can easily scale up production by incrementally growing existing trains," sayz Heintz.
Competition will also come from new producers, Russia and Mozambique, which are eager to secure a slice of the action. Compared to these latter producers, Australia's main asset is the fact that it has "very low country risk," Heintz adds.
In addition to supply and demand challenges, Australian LNG operators must confront the changing nature of their business from a technical perspective, something which Heintz terms innovation risk: "The LNG market is changing towards new uses of the fuel—small-scale, bunkering. Australia shouldn't neglect the potential to deliver smaller parcels of LNG to small, neighbouring countries or islands and/or to become a bunkering alternative for vessels cruising in the area."
For Farruggio, the technical challenges facing Australian LNG operators are largely project specific, such as "securing supply for backfill feed gas, or technical challenges facing projects such as Prelude. This revolutionary approach was once seen as the future but runs the risk of being an isolated approach. Performance will determine this over the coming months".
Within the wider energy marketplace, there's also the emerging risk of new technologies, such as the ever-increasing competition from renewables combined with batteries for electricity production. "With the falling costs of wind, solar and batteries, renewables are providing genuine competition to new gas plants. The relentless falls in cost for renewables is placing ever increasing pressure on the medium-term demand for gas," says Robertson.
Australia's regulatory and political environment is throwing up new challenges for LNG operators. On the east coast, Queensland's three export projects; APLNG, QCLNG and GLNG, are now subject to a temporary gas reservation mechanism put in place to ensure adequate supply to the domestic market.
Long rejected as a concept by the federal government, their application of this mechanism last year in the face of rising local gas prices has raised the spectre of sovereign risk for investors for the first time. It has ramifications further afield, too, Darwin LNG and Ichthys in the Northern Territory will be subject to the new mechanism once the state's network is connected to the east coast market through the new Northern Gas Pipeline, which is due to start up later this year.
"Many LNG exporters [Indonesia, Algeria, Egypt] have been facing, or are facing, increasing gas and power demand, leading to conflict between export and domestic policies. Australia is probably not immune to this risk," says Heintz, but "should coal or oil become persona non grata in the energy landscape, then Australia may need much more gas for its own needs".
11%—Rate of oil price indexed to long-term LNG contracts
When it comes to sourcing CSG for Queensland's LNG projects, there are emerging risks around the social licence to operate. "Whilst the industry forges ahead with its plans to open up the Northern Territory and New South Wales to CSG and shale gas operations it would appear it has so far failed to bring the people along with it. There is still widespread opposition to the industry and it is failing to gain a social licence to operate onshore in these new gas provinces," says Robertson.
Neil Pollock, operations manager for Australia, New Zealand and Papua New Guinea at risk manager DNV GL concurs: "The social licence to operate issues for east coast gas explorers is presently being impacted by a negative public perception that makes the social licence vulnerable," he said. "This may be compromised further if the perception of benefit to Australia verses the consequences and risk is adjusted. Industry needs to continue to engage with environmental NGOs and the public to ensure a continued social licence to operate."
As a result, Australian LNG exports, primarily on the east coast, could be hampered by longer-term onshore gas supply issues. "These could come from the lower-than-expected CSG yields, uneconomic complex CSG wells as well as constraints resulting from restrictions placed on accessing domestic pipeline gas from non-Queensland states," says Pollock, adding that the restrictions on onshore fracking in Victoria, NSW and the Northern Territory will compound this.