Traditionally, Iraq has been exempt from any quotas imposed on the member nations of OPEC over the past decade and a half. It is recognition of the post-war realities of Iraq, still highly dependent on its energy industry to support the country’s diversification plans. So it was a surprise that Iraq joined the rest in OPEC in agreeing to a supply freeze in November and that Iraq itself had agreed to slashing its production by 210 kb/d.
Perhaps it is a sense of shared responsibilities – even though rumblings from port loading data in January and February 2017 seem to indicate that Iraq actually increased exports – the government is maintaining rhetoric that it is sticking to implementing the cuts. It is true that Iraq has a tougher time than other OPEC members in the quotas: its economy is less diversified than say, Iran or Kuwait, and its oil industry has the highest proportion of foreign party involvement in the Middle East. And the latter have included provisions in their contracts that they will be compensated in the event that Baghdad capped output for reasons beyond the drillers’ control.
However, the toughest part of the equation for Iraq lies in its north. While Saudi Arabia has full control over its wells; the Iraqi spigot has a leak. It’s a leak that sends almost 600 kb/d of crude oil internationally overseas through Turkey. It is the Kurdistan Regional Government.
The divide between the Arabic south and the Kurdish north has been
present since before the reign of Saddam Hussein. However, since the
post-Saddam era, the Kurds in Iraq have been asserting their independence,
going as far as demanding a referendum for the creation of a separate state.
More importantly, they are a bastion against Islamic State militants, seizing
territory in the north of Iraq since 2014 and the oil fields associated with
it. This gives the Kurds oil revenue of their own, even if Baghdad does not
recognise Kurdish control over the Bai Hassan and Avana fields, claiming they
belong to the Oil Ministry’s North Oil Co instead.
This means that Baghdad has no control over what the Kurds produce
and how much they export. The Kurds oppose the quotas – their state economy is
even more dependent on oil than Iraq as a whole – and Baghdad has no mechanism
to impose cuts on the north. Under the national budget, the Kurdish north is
allocated estimated production targets of 250 kb/d; data from September to
November show the Kurds have been increasing output towards 600 kb/d, exporting
it to the Turkish oil hub of Ceyhan, where it gets sent to the wider world.
This therefore places the burden of adhering to cuts beyond the 210 kb/d agreed
on the south, where production contracts and an ailing economy complicate
matters. The Iraqi Kurds are also an effective shield against ISIS, as the
Iraqi government prepares to retake the city of Mosul from the militants.
In principle, Iraq’s agreement to the OPEC quotas is a big step
forward in its admission of responsibility to the organisation. In reality,
Iraq is really two separate countries operating two separate oil economies with
separate objectives. Iraq will most certainly be a member of OPEC that will
flout the supply cuts; and it also won’t be the last. The supply freeze, as it
always has, will now fall on the shoulders of Saudi Arabia, Kuwait and the UAE.
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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
Headlines of the week
The engine oil market has grown up around 10 to 12% in the last three years because of various reasons, mostly because of the rise of automobiles.
According to the Bangladesh Road Transport Authority (BRTA), the number of registered petrol and diesel-powered vehicles is 3,663,189 units.
The number of automotive vehicles has increased by 2.5 times in the last eight years.
The demand for engine oils will rise keeping pace with the increasing automotive vehicles, with an expected 3% yearly growths.
Mostly, for this reason, the annual lubricant consumption raised over 14% growth for the last four years. Now its current demand is around 160 million tonnes.
The overall lubricants demand has increased also for the growth of the power sector, which has created a special market for industrial lubricants oil.
The lubricants oil market size for industries has doubled in the last five years due to the establishment of a number of power plants across the country.
The demand for industrial oil will continue to rise at least for the next 15 years, as the quick rental power plants need a huge quantity of lube oil to run.
The industries account for 30% of the total lubricant consumption; however, it is expected to take over 35% of the overall demand in the next 10 years.
Mobil is the market leader with 27% market share; however, market insiders say that around 70% market shares belong to various brands altogether, which is still undefined.
It is already flooded with many global and local brands.