TiP

There are so many hares running on gas in Australia now that even the professionals are finding it hard to keep up.

While coal seam gas and its host of detractors hold a lot of media attention, the potential gas shortage plight of New South Wales mid-decade is starting to emerge as a major issue and the argument about whether or not gas should be reserved for domestic use remains a very live topic.

The LNG developments, both in Australia’s north and north-west and in Queensland, are a dominant discussion point and their fate, especially those still waiting a final investment decision, now that the US is poised to enter the export market, is a matter of some controversy.

For me, one of the most interesting issues is whether we are on the cusp of adding shale gas to our resources wealth in a substantial way, when this might happen, what the gas will cost and how it will impact on the east coast energy market.

Federal Coalition energy spokesman Ian Macfarlane summed things up succinctly at the APPEA conference in Adelaide this week when he said: “The big sleeper (in resources development) is if the shale gas industry gets off the ground in the next two or three years. Then we’re never going to have a domestic gas supply issue.”

A paper released by Geoscience Australia at the conference says the shale resources could double this country’s gas reserves.

Standing on the floor of the APPEA trade exhibition this week, looking at a map on the Beach Energy stand (one of 150 firms pursuing the attention of more than 3,000 delegates), I was struck by the proximity of its tenements and others nearby in the Cooper Basin (crossing the South Australia/Queensland borders) to major east coast markets, not least NSW, and to the existing Moomba-based infrastructure.

Talking to Beach Energy CEO Reg Nelson later in the day, I am also struck by his quiet confidence that shale gas will be in the market somewhat sooner than others believe.

This is also the day that KPMG releases its global shale gas commentary at the conference – you can find the paper (“Shale gas – a global perspective”) on the consultants’ website – listing a litany of reasons to be cautious about Australian prospects.

The biggest issues for shale gas here, KPMG says, are the cost of extraction, the lack of infrastructure, ongoing community and environmental concerns over fraccing and the competition it will face from coal seam methane.

One of its key points holds equally good for coal seam gas. Development, it says, will “hinge on the industry’s ability to control reputational risk and manage public opinion.”

This was perhaps the biggest theme running through the APPEA conference, with the upstream petroleum industry now hard up against the realisation that the heady early “let it rip” years of the coal seam boom have backfired in a big way, creating problems that can’t be quickly or easily fixed.

In one respect, KPMG states the bleeding obvious when it points out that the local shale gas industry needs to import global skills and technology to optimise the opportunities.

This has been the story of upstream petroleum development in Australia for a half century. Upstream petroleum exploration and production is a global business and the skills, equipment and techniques migrate across international borders, carried by the major companies and picked up by the smaller local players.

One of the interesting aspects to emerge from the APPEA conference is that the major companies are now interested in Australia’s domestic gas markets as well as the first prize of using our gas in international trade.

Santos executive James Baulderstone told journalists that the big overseas firms are taking an interest in the Melbourne, Sydney and Brisbane markets.

This is not so hard to understand.

Although our east coast is a much smaller consumption area than, say, western Europe, a sales potential of 21,000 PJ cumulatively over the next two decades – it’s an EnergyQuest estimate used by the Energy Supply Association in its energy white paper submission – is not to be sneezed at.

For companies like Beach Energy, overseas interest opens the way for joint venturers with deep-ish pockets.

“You always listen to what people might be inclined to offer,” says Nelson.

He hopes that Beach may be selling shale gas via Moomba late this year or early next year.

Much now rests on the gas flow rates when horizontal drilling is undertaken in its tenements in the months ahead.

Interestingly, the amount of oil available from the shale plays may be a deciding factor in how far and how fast things progress.

This is the perspective of consultants Wood Mackenzie, who expressed the view this week that shale explorers here may be a decade away from large-scale production – citing a lack of drilling rigs, labor costs and infrastructure barriers – unless the initial drillings prove to be liquids-rich, pushing up the value proposition for development.

(There are about 30 onshore drilling rigs available in Australia today versus about 1,600 operating in the United States.)

The Wood Mackenzie thinking is supported by ConocoPhillips, whose Australian president, Todd Creeger, told Bloomberg news agency: “If you have liquids, the economics are much, much better right now than a pure gas play.”

While current attention is most strongly on the Cooper Basin, there are also shale opportunities in the Georgina Basin, straddling the border of the Northern Territory and Queensland, and in Western Australia’s Canning Basin, which covers a big area of the State’s north and extends offshore.

Santos, which is committed to large-scale export of coal seam gas through Gladstone and seeks to be the major player in developing the industry in NSW, where there are already 1.1 million residential and business gas customers and opportunities for gas to supplant coal in baseload generation,
is another expressing caution about shale’s immediate prospects.

Baulderstone quotes production costs for shale gas at $6 per gigajoule, up to 30 per cent more expensive than CSG, and has the view that, taking in to account technology and capital constraints, it is unlikely to be economic this decade.

(Conventional Cooper Basin gas sells at between $3 and $4 per GJ at present.)

For Santos, NSW is a significant domestic opportunity, with its coal seam methane tenements close to the largest market in the country and a 2015-25 window of opportunity to cash in.

Its managing director, David Knox, finds himself in the interesting position this year of wearing two hats – he is also chairman of APPEA.

Wearing both, he told “Business Spectator” at the end of a busy week that the key to realising the full potential of our gas resources is “to get the drill bit out – to unlock these resources.”

Ominously for those – politicians, manufacturers, householders, small business – who worry about energy costs, Knox noted that the upstream industry needs rising prices to drive major investment.

“Then,” he said, “as we are successful, as we unlock the continent, the gas prices will start to come down (as they have in America).”

He adds the interesting point that, when this country finds it has very large proven resources, an opportunity also opens to turn the gas in to transport fuel – it can provide superior quality diesel – and this will contribute to lowering the national carbon footprint along with a substantial use of gas for electricity generation.

The key, Knox argues, is to allow the market to work, as he says the Americans have done.

How willing politicians, especially State policymakers, are to let the market work, with an eye to long-term national economic benefits, is the $64 billion question.

The problem is that, politically, in the long run they know they are all dead – the nearer horizons are where their focus lies.

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