A knock-on effect from the oil market plunge, if prices stay low, could be that huge shale gas reserves in South Australia’s Cooper Basin remain unexplored.

The Cooper Basin had been Australia’s best chance of replicating the American shale gas boom; over there, production of gas from coal seams was quickly overtaken by extraction of gas — and oil — from deeper shales, unlocked by directional drilling and hydraulic fracturing, otherwise known as “fracking”.

In 2011, the US Energy Information Administration (EIA) set the cat among the pigeons with an estimate there could be 396 trillion cubic feet of shale gas in the Cooper Basin — bigger than our conventional gas off Western Australia and double Australia’s total identified coal seam gas reserves. If even a fraction of that Cooper gas proved economically recoverable, the east coast boom in CSG — fuelling construction of three great new liquefied natural gas (LNG) export facilities at Gladstone worth $70 billion, and vaulting us over Qatar to become the world’s largest LNG exporter by 2018 — would be followed by an even bigger shale gas boom. Unlike our CSG fields, unhappily spread under some of our most fertile farmlands like Queensland’s Darling Downs and the Liverpool Plains of NSW, the Cooper Basin was an established oil and gas province in the remote desert, connected to the east coast market by an existing pipeline, with processing at Moomba.

Geoscience Australia was more cautious; it has never backed the US EIA number, and its 2014 Energy Resource Assessment notes simply that Australia’s shale gas resource “remains to be defined” and the Cooper Basin is “being explored for thick basin-centred gas accumulations”.

Nevertheless, the interest of US oil majors was piqued and in 2013 as Chevron entered a joint venture with established Cooper Basin player Beach Energy and junior Icon Energy.

Fast forward two years, and as the The Australian Financial Review has reported, results have been disappointing, with worries about the rapid decline in gas flow-rates from the exploration wells drilled so far. And drilling costs have been higher than expected, with each well costing $20 million. A similarly disappointing experience led ConocoPhillips and PetroChina to pull out of exploring another onshore shale gas target, WA’s Canning Basin.

Outgoing Beach managing director Reg Nelson was still talking up the potential a fortnight ago, telling the AFR last month that the Cooper Basin could hold up to 600 trillion cubic feet of gas?—?of which 10%-20% could be recoverable?—?leading to speculation that Chevron might pull out of the joint venture by March. In the market fallout since last Thursday’s OPEC meeting that possibility only looms larger, and this is reflected in the share price of the Cooper Basin players, which have fallen in line with the rest of the energy sector: Beach, which was trading over $1.70 in August, is now trading at $1; junior Drillsearch’s shares have halved since late July and were down by a quarter by Monday’s close, at 83 cents; partner Senex plunged over 30% and is now at 28 cents. Tuesday’s AFR predicts a long-awaited consolidation of the Cooper Basin players.

Biggest player of all in the Cooper Basin is Santos, which has decades experience and drilled the first producing shale well there in October 2012, announcing the “historic milestone” touted by the South Australian Premier Jay Weatherill. Since then, it has turned around Cooper Basin production — which had been declining — and invested in increasing the capacity of the Moomba by 30%. Massive new drill rigs capable of drilling as deep as six kilometres have been brought in, but commercial development seems to remain permanently two to three years away. There might be a large amount of gas, but as Santos’ James Baulderstone told the company’s investor day only a week ago, getting to it is a matter of cost:

“[The] talk obviously recently about the NT pipeline gives renewed push for those Central Australian assets … these are massive gas deposits here, we’re talking [tens of trillions of cubic feet] in these opportunities. The real challenge is … you can find the gas, but at what cost can you bring it out of the ground? [In the Cooper] we’ve got these massive amounts of gas all in place, lots of different plays, 3000 foot continuous columns of gas, all those areas, we now need to work out how we can quickly move from this into defining those appraisal areas and then moving on into execution. So how are we going? … We’re actually pretty happy where we are at the moment … what’s really unlocked these plays in the US is actually how you actually increase your flow rates over time. It is important to realise that US is 10 years ahead of us, they’re right in the development phase, we’re in [the] ‘crack the code’ phase.”

Santos shares have been cut by a quarter to $9.20 in the space of the last few days — see Tuesday’s Chanticleer column  — amid fears for its balance sheet strength (it is raising capital in London) and the impact of lower oil prices on future cash flows right when it has to spend some $2.5 billion to finish the Gladstone LNG (GLNG) project by the end of next year.

Santos’ investor seminar presentation highlighted how sensitive future cash flows from GLNG are to a falling oil price (the LNG we export to Asia is sold at a proportion of the oil price, known as the “slope”, generally somewhere around 0.15). Previously Santos had forecast cash flows to double to around US$3.2 billion in 2016, once GLNG was up and running. But that assumed an average oil price of US$100 a barrel. If oil were to trade at an average US$90 a barrel in 2016, Santos told investors, cash flows would only rise by 65% to some US$2.6 billion. In round figures, that’s half a billion dollars cash flow evaporating each year based on a US$10 per barrel drop in the oil price. Right now, of course, oil is trading much lower than that, below US$70 a barrel, and analysts are tipping it will fall further.

Santos was keen to stress last week that the so-called “slope” was not linear under most LNG contracts, which include out-clauses for market volatility. Once built, LNG plants are prodigious cash cows and lower prices could paradoxically underpin Australian export competitiveness, but there is no doubt some fundamental assumptions are being redrawn and Santos and our other exporters will be pinning their hopes on an oil rebound, sooner rather than later.

Put simply, the appetite for remote, expensive, longer-dated shale gas exploration programs could be disappearing fast. It has been widely observed that the Saudis’ objective at last week’s OPEC meeting was to undermine US shale oil production, whatever the cost. Our own shale gas boom could be so much collateral damage.

Paddy Manning is Crikey’s business editor.