BRISBANE, Australia – Australia may have captured the lion’s share of new liquefied natural gas (LNG) projects approved since 2010, and be set to overtake Qatar as the world’s #1 supplier of LNG. But the outlook for a further round of Australian LNG projects is clouded by increasing international competition and ongoing concerns over escalating costs.
This was the message that attendees of Hart Energy’s DUG Australia conference heard in Brisbane last week from Tri-Zen Principal Consultant, Tony Regan, who reminded the conference that the long-term development of shale gas in Australia would depend on the competitive ability of the country’s LNG projects to access international LNG markets.
Regan recalled that in 2010 there were some 74 million tonnes per annum (tpa) of new capacity in LNG projects that were planned to reach final investment decision (FID) that year.
But, in the wake of the 2008-2009 financial crisis, most of these projects “fell by the wayside,” leaving Australia’s three coal seam gas to LNG projects on Curtis Island—Gladstone LNG, Queensland Curtis and Australia Pacific—as the only projects actually to go ahead. Australia was “the only show in town,” with the three projects collectively comprising some 25.3 million tpa of new capacity.
Today, LNG capacity under construction amounts to a “very impressive” total of just over 100 million tpa. The Australian contribution makes up 60% of all new capacity and—in addition to the three Curtis Island projects—comprises Gorgon, Wheatstone, Prelude and Ichthys. Elsewhere, there are projects underway in Algeria, Colombia, Malaysia, Papua New Guinea and the U.S.
These projects will result in “dramatic changes” in regional LNG productive capacity. Assuming the projects come online as scheduled, Australia will rise from a “mid-ranked” producer behind Indonesia and Malaysia to become the world’s largest LNG producer, potentially overtaking Qatar, by 2017.
But what is the outlook for a further round of Australian LNG projects?
“We have probably just as much tonnage being offered in the next round in Australia as in the last round,” said Regan. “The real issue is: Can any of that go ahead?”
With the domestic market for natural gas still limited in size, the development of shale gas remains dependent on international demand for LNG, noted Regan. Here he offered a “very rosy” forecast, with global LNG demand projected to double in the decade to 2020 to 464 million tpa.
On the positive side, Regan projects that, assuming global liquefaction capacity of 287 million tpa at August 2013, and liquefaction capacity under construction totaling 102 million tpa, some 126 million tpa of additional capacity is needed to meet a demand forecast of 464 million tpa in 2020 (assuming liquefaction plants have an average capacity utilization of 90%).
“We have a very big shortfall. We may have 100 million tpa under construction at the moment, but it’s not nearly enough,” said Regan. “We need another 126 million tpa to meet that demand forecast for 2020. That’s 10 to perhaps 16 new projects that have to come on by 2020, depending on their size.”
As a “big reality check,” however, Regan said “Australia has a huge problem with cost inflation.” He noted that Gorgon had seen costs go up by 40%, while Queensland Curtis had seen costs rise by 36%--cost increases that were “absolutely unprecedented.” In addition, Ichthys was expected to come in at $34 billion, he said.
“Australia has priced itself out of the market,” said Regan, expressing skepticism “how any of the next round of LNG projects can go ahead in Australia.”
Regan cited a “mixed bag” of projects making up some 57.6 million tpa in Australia’s next round of LNG capacity. Of these, the Browse project “might” be able to reach FID, according to Regan, in the wake of Woodside’s decision to no longer pursue it as an onshore project and instead develop it as a floating LNG (FLNG) project, which should reduce costs by some 30% or possibly more.
“But even if it is an FLNG project, it is not a slam dunk,” said Regan. “And if Browse does go to FLNG, almost everything in Western Australia will go to FLNG. It will be the way to go. We may not see any more deepwater offshore production coming onshore for liquefaction.”
Another that “might” make it to FID is Arrow LNG if it were to “piggy back” off another existing LNG project, with Origin/ConocoPhillips’ LNG project being a likely candidate. “But I don’t think it can go ahead as a standalone project,” said Regan.
Even with brownfield projects at Gorgon and Wheatstone, project sponsors are now getting “rather cautious about talking about brownfield expansion there and the timing of it.”
In addition to the cost issue, the “big gorilla in the room” is the array of competing international projects, principally in the U.S. and Canada, but also in East Africa, Russia and elsewhere. Regan listed LNG projects totaling 210 million tpa in the U.S. and 68 million tpa in Canada.
The “reality check” for U.S. projects was the need to locate buyers.
“The biggest challenge is still going to be to get the buyers,” said Regan. “At the moment there are probably buyers for no more than 25% of that potential U.S. production.”
And what’s holding buyers back?
Traditionally, LNG supply from the U.S. Gulf Coast has served European markets, but “demand has crashed there,” said Regan. “The big LNG market is northeast Asia. That is a very long way from the U.S. Gulf Coast. The Canadian Pacific coast is a lot closer.”
Australian LNG v. the World
However, from a cost perspective, the U.S. situation is “dramatically different” from that of Australia.
For example, Regan cited Cheniere Energy’s trains #1 and #2 Sabine Pass as costing $5.6 billion, and recently Cheniere reached FID for trains #3 and #4 at a projected cost of $3.8 billion. By comparison, said Regan, analysts’ estimates for the Browse project at James Price Point were $44-50 billion, so two trains at Sabine Point would come in at “about one-tenth of the price of Australia.”
Similarly, in Canada, the LNG Canada project sponsored by Royal Dutch Shell and PetroChina has the same design capacity—12 million tpa—as that of Browse. The budget estimate for LNG Canada is cited at $20 billion—“half” that of Browse, based on analysts’ estimates.
“We’re not talking about a need for Australia to knock off 10 per cent of its costs. Here we have this Canadian project looking as if it will cost half, with the same volume, as the cost of Browse. So there’s a huge problem facing Australia on costs.”
Regan described Canada as looking “pretty intimidating,” with almost 70 million tpa of potential production that is advantaged by British Columbia being “so much closer” to major Asian markets.
Outside North America, Regan cited Russia as having projects with a potential collective capacity of some 50 million tpa. In east Africa—viewed as “an extremely interesting area with very high potential”—Mozambique is estimated to have some 20 million tpa of capacity, while Tanzania has some 10 million tpa of capacity. In the eastern Mediterranean, LNG also has potentially attractive economics.
In sum, said Regan, Australia today faces “far more competition. Australia was the only show in town in 2010; it is definitely not in 2013.” Today, U.S. projects are “in with a vengeance that wasn’t mentioned in 2010.” And with new LNG projects arising in Canada, East Africa and elsewhere with attractive economics, “there is huge competition for Australia that didn’t exist in 2010.”
As for shale development, Regan advised participants “to be cautious about rushing to shale. Because if shale can be developed in a big way in Australia, the bulk of it is going to have to look for export markets as LNG. And someone has got to address the Australian cost issue to make sure it can come out as LNG.”