Tax uncertainty, competition cloud decision making

First gas at the final train of Chevron's Gorgon project and two potential significant Woodside-led brownfields LNG projects are positives for an offshore energy industry under pressure.

An upcoming federal government report into oil and gas producers’ taxation arrangements has heightened the uncertainty for the major energy players in a local market facing steep competition from North America.

Only one major project has achieved final investment assent in the past 12 months, the Woodside Petroleum-led $US2 billion Greater Enfield project, while a number of major producers are planning considerable future capital investments to ensure they will have enough gas to keep their expensive LNG processing facilities running at top capacity.

See more of this week's offshore oil & gas feature with articles on marine logistics, helicopter services, contract wins, and Woodside's efforts to grow gas demand.

Setting out the scope of the challenge for Western Australia, Chevron managing director of Australasia Nigel Hearne pitched the argument for a more favourable policy environment.

Mr Hearne told a recent Commitee for Economic Development of Australia breakfast the advent of shale technology had roughly doubled the amount of gas available globally, while the US, until recently an energy importer, had started shipping LNG to Japan.

“Six additional LNG plants are under construction in the US with a capacity of 60 million tons per annum, the equivalent of four Gorgon (projects),” Mr Hearne said.

That gas, which is sourced onshore, comes at a much lower cost than some of WA’s offshore operations, while lower shipping rates made transportation over long distances cheaper.

Mr Hearne said pressure placed on governments for policy interventions in the sector would send the wrong signal to investors, with the recent review of the Petroleum Resources Rent Tax one such issue.

The PRRT is levied on petroleum sale profits at a rate of 40 per cent, after a series of deductions for exploration and project spending, among others, are removed.

A report by the national auditor general suggesting some companies had been using incorrect calculations in assessing deductions prompted Treasurer Scott Morrison to announce a review of the system in November last year.

It is due to report this month.

Some bodies, such as the union-backed Tax Justice Network, have called for a royalty to operate in tandem with the profits tax.

There is a broad view in the industry, however, that changes would shake investor confidence and drive sovereign risk issues.

Mr Hearne said although he expected up to $9 billion annually of ongoing expenditure would be necessary nationally to keep processing machines running, Australia would be competing globally for capital allocations.

“As global companies look for investment opportunities with shrinking capital investment programs, (opportunities) must become more competitive,” he said.

“For Australia to be competitive at attracting future constrained capital, it needs to offer a globally competitive fiscal regime.”

Australian Petroleum Production and Exploration Association chief operating officer, Western Australia, Stedman Ellis agreed that Australia would be competing with the US, both in terms of production and winning capital investment.

“The case for change to the existing regime has not been made, it is working as it was intended to work,” Mr Ellis said.

He said the existing system had facilitated investment, and gave shareholders the opportunity to recoup that outlay.

“If Australia wants to attract further investment either in new projects or backfill (of) the existing projects, having a stable, balanced fiscal regime is going to be essential,” Mr Ellis said.

Backfilling is used to move new gas supplies into existing plants to keep them at capacity as fields are depleted.

Two projects that would need to be making decisions on backfilling in the near future would be the North West Shelf Venture and Darwin LNG, Mr Ellis said.

“Any retrospective changes after this (recent) wave of investment would really kill investor confidence and with it the the prospect for further investment,” he said.

Both Mr Ellis and Mr Hearne agreed the long-term outlook for gas was good, with demand to continue to increase in the decade ahead.

But the short-term pressure remained, Mr Ellis said, with no exploration wells drilled in WA in 2016.

Developments

One major milestone in the past year was production of first gas at train three of Chevron’s Gorgon project, which received a final investment decision in 2009 (see table).

Gorgon cost upwards of $50 billion, with Mr Hearne saying his focus would be squarely on producing cash flow and sending dividends back to the company’s US head office.

The project’s second train was shut down for maintenance around the same time as train three was up and running, however.

Other success was at the Woodside-led Julimar field at Wheatstone, which reached completion late last year. The Onslow-based LNG trains, operated by Chevron, are yet to begin production.

Meanwhile, Inpex and Shell are believed to be targeting start up at the Ichthys plant and Prelude FLNG vessel respectively in the latter half of this year.

Business News understands that timeframe would be tight, however.

An added complication for Inpex has been contractor disputes at its Darwin gas facility, including in recent weeks.

Laing O’Rourke, which was tasked with building four Ichthys storage tanks jointly with Kawasaki Heavy Industries, took 800 employees off the site after it claimed it had not been paid by Kawasaki for months.

In January, Cimic Group removed newly acquired subsidiary UGL from a power plant construction contract with JKC.

Decisions

Wood Mackenzie analyst Saul Kavonic said there would be an increase in oil and gas spending outside of LNG this year with the sanctioning of the Greater Enfield project by Woodside.

That was aided by cost deflation and re-engineering, he said.

Woodside has broader strategy questions to resolve, however.

In its most recent annual report, the company floated a medium scale brownfields expansion at the Pluto LNG plant that would add an additional 1 million tonnes per annum to production.

Mr Kavonic said a big question the company would need to answer would be finding backfill gas for the neighbouring North West Shelf Venture trains.

There would be spare capacity at the facility as early as 2021, he said.

Attempting to find replacement gas might have driven Woodside’s September purchase of BHP Billiton’s share of the Scarborough project, Mr Kavonic said.

The transaction was worth up to $US400 million.

“We think they've done that with the view to bringing it (the gas) back to the Burrup,” Mr Kavonic told Business News.

“The second option, particularly in terms of economics would be the Greater Gorgon fields, the likes of Cleo and Acme.”

Enough gas is accessible in the Gorgon fields to feed that project at its current rate for 50 years, Mr Kavonic said.

“The third and final option is Browse.

“That requires a very long pipeline, so the economics is probably the most challenging of these three options.”

Nonetheless, Woodside has confirmed that it is a live option, less than a year after a decision to build a floating plant with joint venture partner Shell was knocked back.

One option looks to be out the window, with Hess putting the Equus project on the shelf, after previously considering a gas deal with Woodside.

Whichever way it goes, Woodside would need to begin front-end engineering design in the next couple of years to be ready by 2021, Mr Kavonic said.

That might not be easy if the company opted to negotiate for third party gas, he said, often a complicated process.

In that scenario, North West Shelf would produce below capacity for a couple of years.