By Ross Verne
TUMBLING exploration expenditure, delayed projects, and serious pain for oil-focused players are the factors set to characterise Australian oil and gas in 2015.
Big cuts to exploration budgets, project deferrals, and a climate of deep uncertainty have set the industry up for a difficult 2015.
Amidst the price pressures and uncertainties afflicting the sector, the experts identified opportunities in the domestic gas sector, growth in coal seam gas, and light at the end of the tunnel for the country’s nascent shale industry.
Graeme Bethune from energy sector advisory firm EnergyQuest and Credit Suisse Australia oil and gas analyst Martin Kronborg provide further insight into what we can expect this year.
Woodside, BHP and Senex have become the latest companies to announce capex reductions for 2015, following Santos’s 25 per cent cut in December.
Credit Suisse Australia analyst Martin Kronborg said he expected cuts of 20-25% from “virtually all other producers” when they present their financial results later this month.
BHP warned of impairments of up to US$250 million for its petroleum business, and announced a 20% cut to its exploration spending, down from US$720 million to US$600 million.
Senex responded to a 30% revenue decline in the December quarter by cutting 30 staff – about 15% of its workforce – as part of a move to slash its original $100-120 million spending forecast to about $90 million.
It would defer “higher risk” exploration spending and drill only 16 of 26 wells originally planned this year.
Woodside announced impairments of between US$250 million and US$400 million for full year 2014 in mid-January, saying it would provide a further update in February.
Mr Kronborg said Santos and Origin were at risk of impairments because of their high-cost CSG-LNG projects, with Beach Energy also in danger as a result of its high-cost Cooper basin joint venture with Santos.
“On balance sheets, Santos and Origin are the most stretched of the large caps,” Mr Kronborg said.
“Although not a liquidity issue yet, their credit ratings are under pressure. “
Further to their December cuts, Santos said it was undertaking an impairment review in the context of the low-price environment, but did not provide details of expected write-downs.
Mr Kronborg said a number of companies would delay final investment decisions on major projects.
Santos and AGL’s NSW coal seam gas ambitions will be put on the backburner, Origin’s Ironbark CSG project will be delayed, and Santos and Beach’s shale gas spending will be curbed, the analyst said.
Mr Kronborg said Woodside’s Browse FLNG project was unlikely to reach a final investment decision by 2016.
“Joint venture partner Shell has little reason to sanction a new FLNG project before Prelude is online [in 2017],” Mr Kronborg said.
EnergyQuest chief executive Graeme Bethune said exploration activity would be the principal victim of the spending cuts, with the reduction in activity to be most starkly witnessed off the West Australian coast, with activity to also fall in the prospective but unproven Canning basin.
“The largest amount of exploration by value is in offshore Western Australia which is after both gas and oil – I think companies will probably pull back on exploration,” Dr Bethune said.
“You have had some of the majors farm into the Canning basin; they are all cutting expenditure and those kind of things so they might pull back.”
Director of the University of Queensland’s Centre for Coal Seam Gas Andrew Garnett said the outlook was grim for oil-focused domestic producers.
“Those domestic companies [with] high cost operations are clearly going to suffer,” Dr Garnett said.
“You’re going to see those companies with predominantly oil operations suffer, and you’re going to see them cut back for the time being on capital expenditure and a focus on basically keeping their operating cash flow healthy.
“The degree to which they have to do that is largely to do with how well cashed up they are now.
“It is probably a bit early to say – everybody has got their fright, everybody is a little afraid at the moment – it has been very quick so far.”
Dr Garnett said government and industry would need to work to promote exploration in Australia, especially given its inherently high-cost nature.
“It is as much the government as it is the industry; they really need to take the view of if this is a long downturn then what are we going to do differently so the exploration doesn’t ground to a halt,” he said.
“We are now competing against other places in the world where they have both more mature geology and lower operating costs.
“They really need to reassess how attractive we are as an exploration destination.”
Australia’s LNG projects and domestic gas
Mr Kronborg said the low-price oil environment will potentially cause Australia’s LNG players to suffer impairments.
“It is also likely also to delay any expansion trains,” he said.
Mr Kronborg said Queensland’s LNG plants may be forced into a position where they are no longer targeting full production, due to high costs and limited gas reserves.
Dr Hartley said because LNG prices were not linked to the oil price in a simplistic way – instead using an ‘s-curve’ where strong fluctuations in the oil price were managed – the effects of a low-price environment on LNG were not as pronounced as some would imagine.
“The Australian projects may remain more profitable than you would think looking at the oil price alone,” Dr Hartley said.
“The fall in LNG price may be less than the oil price fall would imply because we may have hit the bottom lower sloped portion of the ‘s-curve’,” Dr Hartley said.
Dr Hartley said another key factor was that prices were quoted in US dollars but the Australian dollar had devalued against the greenback during the period where the oil price fell.
“Since many costs are in Australian dollars, this currency rate change would also insulate the profitability of the Australian LNG projects from the oil price fall to some extent.”
Despite the negative impacts on the balance sheets of the big LNG players, Dr Hartley said the plants coming online presented new opportunities for previously uneconomical gas prospects.
Plays which were deemed unworkable at low domestic prices would now be more likely to be developed because the international price presented much better returns on investment, even with the effect of the oil slump.
“Even though the international oil price has come down, domestic gas prices are still probably higher than it was before we talked about LNG exports,” Dr Hartley said.
“A lot of this activity that we are seeing – people looking at the shale in the Cooper and some of the other coal seam gas – it was made profitable by having prices above the old domestic prices so a lot of those projects I think would still be attractive to people.”
Similarly, Dr Bethune said activity offshore Victoria would not be significantly impacted by price declines because projects were mainly geared towards developing gas for the domestic market.
“There is certainly a shortage of gas for the domestic market on the east coast, particularly for industrial buyers and some utilities,” Dr Bethune said.
“I would expect domestic gas developments [offshore Victoria] to continue to be things that are being pursued. I would expect domestic gas to remain a high priority.”
A fall in operating costs – through cheaper labour and steel prices – was one benefit producers should enjoy in 2015, Dr Hartley said.
“The big premiums that were paid in Australia were because we were getting everyone trying to develop these projects at the same time, driving up the costs so you expect some cost reductions there too.”
World market for LNG
Dr Hartley said India had a big role to play in providing a market for future LNG development but there was not enough attention paid to the possibilities in South East Asia.
“A few people talk about India, but the other one that people don’t talk about is [South East Asia],” he said.
Dr Hartley said while South East Asian countries were building their own gas extraction base, their continued economic growth would lead them to eventually become net petroleum importers.
“You get a bit of growth with a big population base, it’s really going to cut into their exports and then ultimately probably lead them to be importers so that’s the other thing we would point to that is important – not just India.”
He said it was no surprise that China “was not looking like the big market people were talking about” because of pipeline deals secured with Russia, Myanmar and Central Asia, and growing unconventional domestic extraction.
“We didn’t really see a lot of opportunity for these extra LNG projects beyond the current ones for a while, for another decade,” he said.
While activity will decline throughout the sector, the established nature of the Cooper basin will give it a relative advantage over the country’s other major petroleum basins in riding out the slump, according to the experts.
Its proximity to the burgeoning LNG and east coast domestic gas market, well understood geology and technical aspects, and its propensity for shale development makes the Cooper better positioned to weather the difficult oil price environment than other petroleum systems.
“Most of the small companies on the east coast, they’re in the Cooper basin which is much less wildcat for oil – they’re established gas and oil projects,” Dr Bethune said.
Dr Garnett said the Cooper basin was the best placed of the Australian basins for withstanding the impacts of the price plunge.
“The Cooper is much better understood, a lot of the geology and technology is better understood and it’s already plugged into the east coast gas market,” Dr Garnett said.
A future for shale
Further positives for the Cooper basin – in the form of a budding shale industry – have been flagged as a future growth area, with predictions of the sector supplying the LNG plants in the medium term.
Dr Hartley said the Cooper basin was the “most logical place” for the industry to get a foothold because of existing pipelines and available routes to the international market.
He said the Cooper’s geological and regulatory environment were similar to already-developed shale plays in the United States.
“Our Baker Institute gas model had the shale in the Cooper being developed in the medium term to help supply the LNG plant basically and I think that’s what the players in the Cooper were betting on, that they will be able to sell their gas to the LNG plants,” Dr Hartley said.
“Down the track when the oil price has recovered, and then the natural gas prices recover and so on.”
Dr Garnett said before the price plunge shale players were working on the proviso of “slow and steady”, but the new environment had decelerated development further.
“[It is] slower than it would have been if it hadn’t gone to US$50 a barrel,” he said.
“This is not the environment in which you rush ahead and really spend large amounts of money on proving reserves, given the price uncertainty as well as the geological uncertainty.
“I’ve seen companies mention five-to-ten years [for significant developments]. There is a lot of basic science and technology to get done first.”
If the Cooper was the region best set up to withstand impacts of a depressed oil price, the Canning basin falls “at the other end of the spectrum”, according to Dr Garnett.
“The Canning to me looks a difficult one to get off the ground, not that it’s impossible but it’s challenging given that people’s confidence is hit,” Dr Garnett said.
While the prospectivity of the basin is ref lected by recent interest from major explorers, it remains unproven and activity in the region in 2015 will ref lect as much.
Dr Garnett said because the region was not plugged into the domestic market or any of the west coast LNG plants, it would see little development in the near future.
“The distance to market and developing particularly a shale gas or light-tight oil play in the Canning is simply going to be tricky,” Dr Garnett said.
“Without pipeline infrastructure it is difficult and of course Canning is also not yet proven – it’s still at the stage where we’re trying to discover which technical trick is right for which geological area.
“So there is some way to go, but the Canning does look the toughest,” Dr Garnett said.
He said the activity in the Canning would likely be limited to those fulfilling tenement obligations.
Dr Hartley said the Canning basin’s shale plays had “a lot more prospectivity than all of the shale in Australia” but the lack of infrastructure and a glut of conventional gas in the region meant they would not be developed for some time.
“In decades in the future [WA’s LNG plants] will be supplied by shale gas from the Canning basin probably but you’re not going to get there for some time,” Dr Hartley said.
Dr Hartley said tight gas closer to Perth was the more prospective option for WA in the short term, but said domestic gas obligations remained a constraint to developing supplies.
He said suppliers closer to Perth would be at an advantage in supplying the domestic market compared to the big exporters further north who had to transfer the gas south at a cost.
“What they should do is allow people to contract with the domestic players to fulfil their quota at least and you might get a lot of development of the expensive infrastructure to process gas for LNG and the domestic market,” Dr Hartley said.
“Local suppliers are at an advantage for that domestic market and the problem they’ve got in Western Australia with this domestic gas is it ends up being a constraint on a lot of future LNG development.”
Dr Hartley said Perth basin developments could be used to fill the domestic quota, but ideally a hub would be developed at Dongara to build a market for the region.
“If politicians would let the market work I think there is a lot of gas in some pretty good prospects – a lot of that would be developed,” he said.
Dr Hartley said companies would ideally develop a number of tight gas projects in WA’s south west.
“It makes much more sense to have them supplying the domestic market than trying to force a lot of the big projects to keep on doing it.”