Australia is currently gripped by a debate about whether to institute a gas export tax (some say 25%) to cash in on high commodity prices and excessive profits in the industry. It’s a good occasion to look more closely at the fiscal arrangements governing the gas industry down under.<\/p>\n\n\n\n\n\n\n\n
I remember taking a week-long and very geeky course called “World Fiscal Systems for Oil and Gas” almost 20 years ago. The convenor, Pedro van Meurs, is a bit of a legend given that he’s run this class for more than 35 years. His efforts have made both the commercial departments of oil and gas companies and governments around the world more sophisticated in their design of revenue sharing agreements governing hydrocarbon resources. They also made the rather dry and technocratic field of fiscal systems extremely interesting politically.<\/p>\n\n\n\n
I took the course because I dealt with the complexity of these systems working on then Europe’s largest gas field, which was operated by Shell, in a joint venture with Exxon-Mobile, and a 40% state equity stake. The tax accountants and commercial analysts cut their teeth understanding this complex model (equity share, royalties, public monopsony buyer of the gas, etc.) before they went out into the world negotiating on behalf of Shell with governments possessing much lower institutional capacity than the Dutch state.<\/p>\n\n\n\n
Back to de Meurs: I wonder what he would have to say about Australia’s rather simple PRRT and the fact that investors operate under extremely generous emerging market like terms from the 1980s (when Australia was regarded as a bit of a backwater and frontier oil play), extended to some of the largest and commercially viable LNG projects on the globe situated in a AAA-rated sovereign. As someone who advises both governments and corporates, he might tactfully suggest that in Australia the pendulum has swung heavily toward private producers as the main beneficiary.<\/p>\n\n\n\n
The bone of contention in Australia’s case is that capital expenditure from exploration and development can be recovered against revenue (a standard feature of production sharing agreements, PSAs, which are more generally used in frontier and emerging markets), and that this cost is compounded at a comparatively high uplift rate, originally used to entice investors to come out here. <\/p>\n\n\n\n
Most of these projects are so phenomenally expensive that a large cost base at the outset gets inflated every year by sheer arithmetic of a high discount rate, carried over and transferable between projects, and set off against revenue that usually starts to flow only 5-10 years after the groundbreaking ceremony. High profits are therefore consistently not taxed as the producer still has a huge cost pool (sometimes growing further thanks to annual compounding) to offset against growing revenues. <\/p>\n\n\n\n
Reforms to cap the deductions at 90% leave a mere 10% of profits to be taxed at the PRRT’s 40%, giving the Australian government a trickle of what they could (and arguably should) be levying. The problem is not the design of the PRRT itself, it is the failure to reset the uplift rates over the years, as many other countries have done.<\/p>\n\n\n\n
What is more, one thing that has not been talked about so much here is that the cost pool itself could also be the subject of a more rigorous audit. <\/p>\n\n\n\n
Very often, the costs the producers report are self-assessed. External auditors usually do not have to sign off on these assessments. Records are very old and although they should be kept (as the associated costs are still being offset), they probably don’t even exist anymore. Oversight is cursory (“risk-based”) at the very best. <\/p>\n\n\n\n
All this reminded me of a recent arbitration case<\/a> involving Kazakhstan and the operators of the Kashagan\/Karachaganak oil fields, principally Italian ENI. The sovereign brought a case to the tribunal arguing that key terms of the PSA had been violated, basically the reimbursement of cost overruns and other unqualified expenditure. <\/p>\n\n\n\n This is a huge and complex<\/a> story, with an uncertain outcome, but it shares some elements with the Australian LNG developments, in that very generous cost recovery prevents the sovereign from earning what many see as its “fair” share. <\/p>\n\n\n\n Australia, the world’s third largest LNG exporter, chose not to govern these major exploration and production projects as PSAs but to codify this as statutory tax with a huge self assessment component. <\/p>\n\n\n\n But now they have ended up with a system that doesn’t even allow the government to meaningfully audit the deals that have been agreed. Needless to say, this causes significant anger in a population that is paying high prices for domestic gas, faces a full blown fuel crisis, and sees LNG exporters pay ridiculously little tax. While all of these factors are not necessarily directly related, the resentment is understandable.<\/p>\n\n\n\n My former stomping grounds Holland and Kazakhstan as well as many other (emerging) markets have a further advantage over Australia in that many of them have made their national oil companies equity partners in the consortia that are developing the fields: So whatever corporate wizardry the oil majors come up with, at least it will benefit the state indirectly through its equity stake. <\/p>\n\n\n\n Not in Australia, where the prevailing mood in the 1980s when this tax legislation was passed was one of market-based development of natural resources. At current LNG prices, this proves to be a costly ideological mishap that Australians continue to pay for. <\/p>\n","protected":false},"excerpt":{"rendered":" Australia is currently gripped by a debate about whether to institute a gas export tax (some say 25%) to cash in on high commodity prices and excessive profits in the industry. It’s a good occasion to look more closely at … Continue reading