Published in the June/July 2014 edition of RESOURCESTOCKS

Analysts remain concerned about the commerciality of Australia’s unconventional hydrocarbon projects that have attracted many millions of dollars from global majors, and of the staying power of said majors.

Amidst all this, that old chestnut, the thing that built many of these big companies, is looming as the saviour of the industry: conventional hydrocarbons, with its more identifiable geology, known basins and ease of commercialisation.

All eyes are on the Cooper Basin as the next likely candidate in the world to replicate the United States’ success with shale gas and oil, but could it all fall in a heap?

Such a thought is an anathema to companies developing projects in the Cooper and elsewhere such as Buru Energy, Santos, Beach Energy, Drillsearch and Senex, but the question has been raised.

Surely, super-majors – such as ConocoPhillips ($109.5 million with New Standard Energy), Mitsubishi ($152.4m with Buru Energy in Western Australia’s Canning basin); and Chevron ($101m with Drillsearch) and BG ($349m with Beach) in the Cooper – would not sink in of all that unless they are serious and in for the long haul?

Make no mistake, there are huge upsides here. Late last year a leading investment bank in Houston, Texas – Tudor Pickering Holt – issued a report following healthy initial flow rates from most hydraulically fractured wells in the Cooper and declared the basin had one of the best shale prospects outside North America. It cited strong gas pricing and existing infrastructure as prime draws there.

Meanwhile Minelife.com.au founder Gavin Wendt and IFM Investors listed equities investment director Jim Copland were part of a panel at an oil and gas investment forum in Sydney recently where some honest soul-searching was being done by companies and investors, rather than the usual spruik-fest that these conferences can often become.

Some of the work done in the Canning is more mature, in areas where there has traditionally been conventional activity, and much has been made of Buru’s $550 million, 550km Broome to Port Headland Great Northern Pipeline project to connect the Canning Basin with the existing domestic gas transmission system.

However, at $1 million per kilometre, Wendt said some analysts he had spoken to had serious doubts as to whether the pipeline would be a commercial reality due to the large cap-ex numbers.

He said the basin was remote, though it was advanced due to conventional oil extraction that had taken place previously. Wendt said the resource might be big, but there was no real potential market up there and getting it to Singapore for processing was more easily said than done.

“There’s also going to be more competition in Asia for exports,” Wendt said.

“So which will be economic? There will be no shortage in Asia for potential gas. So conceptually, ok, you may be able to export it, but what are you going to get for it and what’s it going to cost you?”

Copland told RESOURCESTOCKS the unconventional gas hype was “tremendously exciting, and there have been some great steps forward on the technology front over the past 20 years that has pioneered an amazing turnaround in domestic oil production in the US, but it’s just not obvious how it translates to Australia”. Referring to central Australia opportunities he said: “One of the challenges on the gas side is that the domestic price is currently coming off legacy contracts of $2-3/GJ, which worked for the period, but they were long-term contracts and are all rolling off now.

“So prices are not going up domestically – maybe $6-7/GJ on the east coast, or heading that way – but in order to underpin the economics of some of these shale gas plays then you probably need prices closer to double digits, certainly in the early days, to justify what is inefficient drilling, fraccing and completion.

“You probably need someone to make a loss for a while to get this thing established, and hopefully to bring the costs down – and these wells in Australia cost twice what they do in the US – $18-20 million a well in Australia, so there’s just no return there. It’s just a big black hole.

“You need the big boys to do it. They are all out there, they’ve pegged strategic positions in JVs with locals, but they don’t need to be there in the next five years. They may be just positioning themselves for some future opportunity, which may be 10-20 years down the track.

“That’s too long a time frame for the juniors to be part of that, and they can’t see any returns in the short-term.”

Wendt said that if the Chinese conniptions over iron ore were anything to go by, investors should not take these majors’ commitments as set in stone.

He said the majors in central Australia were effectively doing in the unconventional space what the Chinese were doing in the resource space generally – putting their feet on a whole bunch of assets, then looking to see which ones stacked up.

“These sorts of companies in the petroleum space are doing this all over the world in potential farm-ins in spending up to ‘x’ amount,” Wendt said. “Whether they get there or not remains to be seen. They’re part of multi-year funding deals, and after maybe a year or two they may decide to pull out. It’s effectively giving them a seat at the table. They’ve been doing this in Europe, Africa, all over the place. So Aussie companies shouldn’t think that they’re particularly special.

“Then they’ll take a step back and say which ones look like being the most commercial and doable.

“One of the complaints in the hard rock space among juniors who have Chinese farm-in partners is ‘they came in and now they’re not doing anything’ because they’ve got their fingers in a lot of pies, and what might have been high priority for them two years ago is now not necessarily so and the smaller companies are stuffed because they’re not in charge of the JV, the Chinese farm-in partner is.

“I’m not necessarily saying that’s how it’s going to pan out, but when you analyse some of these unconventional deals, none of these projects are close to being commercial.

“A lot of [shale projects] are far away from having reserves. It sounds good to have a multinational involved with you, but it doesn’t mean the project is going to stack up in terms of commerciality.”

CLARIFYING CONUNDRUMS

Everyone talks about unconventional, but the reality is that the US experience has shown that tight sands appear more economic to develop than shales – indeed, the tight sands were the first to be developed in the US. Senex certainly subscribes to this view, but its peers in the Cooper do not seem to share it – hence their massive investment in shale.

Understandably so. It has been on for young and old since Beach Energy booked 2 trillion cubic feet of gas from its first two shale gas wells (Holdfast-1 and Encounter-1) in the Cooper – it did not expect such a prize from them. That is a third of the conventional gas the Cooper has produced over 40 years.

With existing nearby infrastructure and a willing east coast market, not to mention three needy LNG projects up in Gladstone, it made sense for majors to move in.

But infrastructure and market is not the issue.

Analysis by Senex mid-last year showed that of the Gladstone LNG projects that had reached final investment decision, there would be a shortfall of about 280PJ in 2017 that was going to have to be met by Cooper Basin or other third-party supply.

Given the concerns Wendt and Copland highlighted – and they are not the only ones saying it – Senex is taking a different strategy, with a substantial land position across the Cooper-Eromanga Basin. Senex told Excellence in Oil and Gas Conference delegates in March that tight sands in the Cooper had moderate flow rates, low to moderate condensate and 10s to 1000s of billion cubic feet per field, while shale gas had low to moderate flow rates, dry gas and multiple trillion cubic feet per field.

“Tight sands in the Cooper Basin will likely have better economics than shales due to key geological differences,” a Senex spokesman told RESOURCESTOCKS.

“The key inputs to an economic analysis include temperature, pressure, CO2 content, condensate volume and composition, depth, porosity, permeability, availability of infrastructure and processing and access to market.”

Senex believes the western flank of the main trough in the Cooper will be shallower, with lower temperatures and therefore be more likely to contain liquids – the key ingredient, because it is easier to commercialise and fund future operations.

Its recent deal with vertically integrated Australian major Origin Energy suggests there is also substantial investment interest in tight sands. The Senex/Origin Energy joint venture will invest up to $252 million in a two stage work program involving the drilling of at least 15 wells and substantial 2D and 3D seismic acquisition programs, with Senex free carried for the first $185 million of that program.

“If you’re drilling to shallower depths – for example, our Hornet stratigraphic tight sands-type field – it’s only down at about 2500m,” the Senex spokesman said.

“If you go into the middle of the Nappamerri trough where some of the wells are being drilled to 4-4500m, there’s obviously a difference in the physical cost of doing drilling. It’s more technically difficult.”

While he takes Copland’s point about the costs of commercialisation, he said other factors would come into play to alleviate this.

“Our view is that over time you will refine your drilling techniques, well completion techniques and ‘production enhancement’ techniques, which will reduce costs,” the spokesman said. “You’ll also drill more of these wells, and achieve the benefits of better equipment utilisation.

“That in itself will reduce costs, as you won’t pay for mobilisation every time you drill a well and when you’re doing a drilling campaign you can negotiate a better deal with your drilling and service contractors. In a competitive market, costs come down as equipment utilisation goes up.”

SMOKE AND MIRRORS

Another line of thinking revealed at the conference was that while the US had known about its shale for decades and achieved success that had triggered investment in shale across the globe, not all was as it seemed.

“The jury is still out in my view, and it’s been backed up by presenters recently, but the technical people at the coal face analysing this independently say there is a lot of shale gas and oil being produced in the US,” Wendt said. “But how economic is it?

“On initial inspection it looks rather cheap, but the decline of these oil and gas wells is dramatic. They’re not producing as consistently or steadily as conventional oil wells. They’re expensive to drill and have expensive drop-off in terms of production.

“Companies are currently raising lots of money, there’s a booming share market, well production is dropping off but they’re drilling new wells at a very, very rapid rate, which is disguising the overall economics and productivity of this energy.

“The bottom line is that oil and gas production is only economic if the oil price is at a certain level – ie, $US90-100/barrel. It doesn’t mean there will be cheap oil and gas. It means there could potentially be additional oil and gas if the price stays high.

“If the oil price fell to $US60/barrel, a lot of that shale oil and gas would be rendered uneconomic and wouldn’t even be produced.

“That’s the critical thing. We’ll hear a lot about the unconventional oil and gas industry economics over the next few years. About three years ago the unconventional space was the booming thing. Just about every ASX-listed oil company had jumped on the unconventional bandwagon, their share prices took off and they were flavour of the month.

“What happened? They over-promised, they under-delivered, they didn’t give investors the full picture. The unconventional space in Australia is going to take a long time to develop. They only told half the story – they talked about the potential but didn’t tell investors about how it’s a long haul.”

As discussed in the special APPEA edition of RESOURCESTOCKS in April-May, the redirection of ASX-listed junior Key Petroleum is a case in point of where the future lies in terms of what’s commercial: conventional. Key was one of those juniors Wendt mentioned that went after unconventional and courted several majors in his Perth office, but their doubts lingered so Key focused on its conventional oil.

Work done on its conventional assets will value-add the unconventional assets and help get a big farm-in partner to develop them.

“There are numerous frontier basins around the world that have never been tested, so there is significant upside in terms of what’s going to be found in conventional oil and gas, but it’s a bit like the hard rock mining space – people are going to have to go further afield in higher-risk places where they may never have contemplated going,” Wendt said.

“They’re also going to have to go into much deeper water, which is more challenging. So the cost of going further offshore for data acquisition, drilling and production will be a hell of a lot more.

“So I still think there is a strong case to be made for conventional oil and gas companies to make money out of conventional oil and gas.”

Copland said he “quite likes” the oil side because the economics in the Cooper Basin are $35-40/barrel costs, it is sold for more than $100/bbl, so there was a good margin.

“It gets a bit problematic when companies started getting to the gas side though.

“The oil coming out of the Cooper is all conventional – stuff they’ve known about for years and they’re finding it more efficiently because of 3D seismic,” he said. “But in unconventional, the Cooper is dry. There are some areas of liquids, but we don’t have any Eaglefords or Bakkens [like in the US] where we can confidently say there’s some oil there.

“The Barnett shale gas has been sub-economic for a long time because the gas price has come right down. So if we don’t have the oil, the whole thing looks really tough. Really tough.”