Dr Bethune said the Australia Pacific, Gladstone, and Queensland Curtis LNG projects near Gladstone had successfully silenced the naysayers with successful developments and, since Santos announced plans to push ahead with the unprecedented plan to turn CSG into LNG, around $60 billion has been spent in the state, almost one third of Australia’s $200 billion gas boom.

“Ten or 15 years ago there were plenty of sceptics about CSG for domestic use, much less LNG exports, and now, 10 years later, we have three LNG projects up and running and a completely new gas sources that was commercialised very quickly,” Dr Bethune told Energy News.

He said the LNG plants would settle into the markets, but the journey had just begun, and the hungry plants need to be fed and exports need to be sent into the world seamlessly to Australia can maintain its reputation for reliable supply.

“Churchill said it not the beginning of the end, but the end of the beginning,” he said.

He told a Queensland Petroleum Exploration Association function last week that each of the three plants needs to be maintained and fed, and that will require an annual investment of around $2 billion.

Of the projects, Santos and its partners have has 7.8 million tonnes per annum of capacity on Curtis Island, based around reserves of 5.2 trillion cubic feet. The plant’s trains have undertaken a slow ramp up, with Train 1 producing just 1MMtpa in the second quarter.

Santos’ project lacks coverage and needs third party gas to keep turning over, but even then the shortfall appears to be deep.

The project has 2-3 years to meet its contracts, which are dispersed, and that fact will take some of the pressure off the fact that those reserves only cover around a dozen years of production.

Queensland Curtis LNG, which is operated by Shell, has two trains with a capacity of 8.5MMtpa. It has contracts for 5.2MMtpa and is selling primarily to Japan, China and Singapore.

It has reserves coverage of 11.3Tcf, and has a favourable third party gas contract with the upstream Australia Pacific LNG project being run by Origin Energy, ConocoPhillips and Sinopec.

APLNG is the largest development with 8.6MMtpa of capacity. It has reserves cover of 12.8Tcf and sells primary to China’s Sinopec, with some contracted gas to Japan and some available for spot sales.

The fact that drilling for the plants peaked between 2013 and 2015 was not necessarily a bad sign, Bethune told Energy News, because after the initial crop of development CSG wells the rate of new wells was expected to decline.

While he said there was a minimum level of new production the three projects need to add each year to replace declining CSG rates, it was concerning that Santos had recently failed to hit its targets.

“Both APLNG and QCLNG are drilling the number of number of wells they said they were going to, which is around 300 each per year but the issue is with GLNG because they are not drilling anything like that,” he said.

“There are concerns about future reserves and they have been drilling below the levels they need.”

Dr Bethune said it was clear that there needs to be an increase in drilling rates, at least in Queensland but most likely in other states, to ensure the domestic and export markets are supplied.

There are now some 7400 wells drilled across the Bowen and Surat basins, including 500 fracced wells.

Dr Bethune speculated that Santos may be trying to push out costs and focus on reduce desk.

Santos has reassured markets that it believes it has sufficient reserves coverage for the life of its contracts, although it is relying on Cooper Basin portfolio and third party gas contracts to achieve that aim.

What each of the three projects will need to struggle with are the challenging economics.

APLNG, for example, needs around $1.4 billion in capital just to sustain operations, and operating expenses are around $1.3 billion, Dr Bethune said.

Once the income from domgas sales is stripped out, APLNG needs to make around $2.4 billion per annum just to break even or $US27/bbl.

In order to turn a profit, after debt payments, APLNG needs to make $3.8 billion, or enjoy an oil price of $42/bbl, which most forecasts say is likely to be achieved out to 2024, even if margins are a little skinny in the near future.

The good news for Queensland’s LNG sector is that spot prices for LNG have been improving since March.

In terms of breakeven levels, Dr Bethune said the figures were “not too bad”, and prices have recovered recently, trading as high as $50/bbl in recent weeks, so he would expect the three plants were at least covering costs and allowing debt repayments, potentially generating some income for their owners.

Dr Bethune said the fact that the oil price is below where predictions would have pegged it at project sanction, and the increasing interest in short-cycle contracts, would probably not be major issues given the long-term contracts entered into at FID, aside from any production set aside for the spot market.

He believed Queensland’s LNG sector should be relatively robust.

The projects have also impacted on the domestic gas market and east coast gas prices, which are already converging on LNG prices between $6-10/GJ up from $2-4/GJ in late 2014.

He said it was too early to predict what the impact of possible LNG imports could have into an east coast location, such as Sydney or Newcastle, as has been talked about this week by AGL Energy.

“There are a lot of things that need to fall into place before we could know the impact of something like that,” Dr Bethune said.

“You would need to know domgas prices, LNG spot prices, the level of imports, the cost of the FGSU, and of course we have seen spot prices going up, rather than coming down in recent times, so that makes it harder to justifying an import project, but it is early days.”

China is the largest buyer of gas from Queensland, with 76 cargoes between January 2015 and October 2016, followed by Korea (28), Japan (24) and Singapore (16), with other sales to places such as Indonesia, Mexico, Argentina, Pakistan and Egypt.