Here is a brief background story of the growing debate about the allocation of oil royalties in select states in Malaysia.
The election that swept the former ruling coalition out of power in Malaysia three months ago was historic. Implementing the new Pakatan Harapan’s election manifesto, however, has proven a bit more challenging as populist measures have been hampered by bureaucracy and inertia. And now, a new spat is brewing – Malaysian state rights over oil royalties.
At present, Malaysia’s upstream extraction is conducted by Petronas on behalf of the federal and state governments. This unifies oil extraction under one national oil company, and has allowed Petronas to forge domestic and international pacts under the PSC system that has made it one of the best run state oil firms in the world. At present, Petronas pays a 10% royalty (based on gross production), 5% to the federal government and 5% to each state government. Of the remainder, 20% goes to cost oil to recover the cost of production, while 70% is split between Petronas and operators like Shell, Murphy Oil and Sapura Energy.
Malaysian states have long requested for their 5% royalty – paid twice yearly by Petronas regardless of field profitability – to be raised. In the past, east coast peninsula states Terengganu and Kelantan were the most vocal, particularly because they were intermittently ruled by (then) opposition parties, but East Malaysian states Sabah and Sarawak have increased their tone as well. This is particularly important given that the bulk of new finds and operations are focused on East Malaysia deepwater. Sarawak itself has gone as far as to create a state oil firm to participate in PSCs to increase its share of oil revenue. There are grouses elsewhere: in 1999, when opposition party PAS took Terengganu state, the oil royalty payment to the state stopped. In the leadup to the 14th General Election, Pakatan Harapan had promised to restore payments and increase the royalty to 20%. And now that it is in actual power, it seems to be backtracking.
New Prime Minister Mahathir Mohamed announced that the royalty would indeed be raised to 20%, but it would now be based on net profit instead of gross profit. Uproar ensued. Royalties based on gross production had always been the norm, and the new government was accused of moving the goalposts. Economic Affairs minister Azmin Ali claims that raising the royalty to 20% of gross profits would ‘destroy Petronas’ and has not given a timeframe for the implementation of the new royalty rule, citing the need to federal-state discussions and a need to change the Petroleum Development Act 1974. The states are not happy – especially because they were instrumental in toppling the previous BN government – and this could play into the fragile balance currently holding the government together under Mahathir’s sheer force of will. Opposition parties have already begun capitalising on the ‘controversy’. A state seat by-election is scheduled for August 4, and will be seen as a litmus test for the effectiveness of the new government. A new government may be in place, but issues of old are still rearing their head.
Malaysian Oil Production By Area:
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The Permian is in desperate need of pipelines. That much is true. There is so much shale liquids sloshing underneath the Permian formation in Texas and New Mexico, that even though it has already upended global crude market and turned the USA into the world’s largest crude producer, there is still so much of it trapped inland, unable to make the 800km journey to the Gulf Coast that would take them to the big wider world.
The stakes are high. Even though the US is poised to reach some 12 mmb/d of crude oil production next year – more than half of that coming from shale oil formations – it could be producing a lot more. This has already caused the Brent-WTI spread to widen to a constant US$10/b since mid-2018 – when the Permian’s pipeline bottlenecks first became critical – from an average of US$4/b prior to that. It is even more dramatic in the Permian itself, where crude is selling at a US$10-16/b discount to Houston WTI, with trends pointing to the spread going as wide as US$20/b soon. Estimates suggest that a record 3,722 wells were drilled in the Permian this year but never opened because the oil could not be brought to market. This is part of the reason why the US active rig count hasn’t increased as much as would have been expected when crude prices were trending towards US$80/b – there’s no point in drilling if you can’t sell.
Assistance is on the way. Between now and 2020, estimates suggest that some 2.6 mmb/d of pipeline capacity across several projects will come onstream, with an additional 1 mmb/d in the planning stages. Add this to the existing 3.1 mmb/d of takeaway capacity (and 300,000 b/d of local refining) and Permian shale oil output currently dammed away by a wall of fixed capacity could double in size when freed to make it to market.
And more pipelines keep getting announced. In the last two weeks, Jupiter Energy Group announced a 90-day open season seeking binding commitments for a planned 1 mmb/d, 1050km long Jupiter Pipeline – which could connect the Permian to all three of Texas’ deepwater ports, Houston, Corpus Christi and Brownsville. Plains All American is launching its 500,000 b/d Sunrise Pipeline, connecting the Permian to Cushing, Oklahoma. Wolf Midstream has also launched an open season, seeking interest for its 120,000 b/d Red Wolf Crude Connector branch, connecting to its existing terminal and infrastructure in Colorado City.
Current estimates suggest that Permian output numbered around 3.5 mmb/d in October. At maximum capacity, that’s still about 100,000 b/d of shale oil trapped inland. As planned pipelines come online over the next two years, that trickle could turn into a flood. Consider this. Even at the current maxing out of Permian infrastructure, the US is already on the cusp on 12 mmb/d crude production. By 2021, it could go as high as 15 mmb/d – crude prices, permitting, of course.
As recently reported in the WSJ; “For years, the companies behind the U.S. oil-and-gas boom, including Noble Energy Inc. and Whiting Petroleum Corp. have promised shareholders they have thousands of prospective wells they can drill profitably even at $40 a barrel. Some have even said they can generate returns on investment of 30%. But most shale drillers haven’t made much, if any, money at those prices. From 2012 to 2017, the 30 biggest shale producers lost more than $50 billion. Last year, when oil prices averaged about $50 a barrel, the group as a whole was barely in the black, with profits of about $1.7 billion, or roughly 1.3% of revenue, according to FactSet.”
The immense growth experienced in the Permian has consequences for the entire oil supply chain, from refining balances – shale oil is more suitable for lighter ends like gasoline, but the world is heading for a gasoline glut and is more interested in cracking gasoil for the IMO’s strict marine fuels sulphur levels coming up in 2020 – to geopolitics, by diminishing OPEC’s power and particularly Saudi Arabia’s role as a swing producer. For now, the walls keeping a Permian flood in are still standing. In two years, they won’t, with new pipeline infrastructure in place. And so the oil world has two years to prepare for the coming tsunami, but only if crude prices stay on course.
Recent Announced Permian Pipeline Projects
Headline crude prices for the week beginning 3 December 2018 – Brent: US$61/b; WTI: US$52/b
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