Oil in 2017
With OPEC defying the pessimists and actually agreeing on a
production freeze, oil prices have rallied. Will this be a good sign as we
enter into 2017? The World Bank predicts that oil prices would average
US$53-55/b over 2017, a sentiment echoed by the EIA in the US. Both have no
issued new forecasts since OPEC’s agreement to slash production by 1.2 mb/d,
but it is likely that the target range has now shifted to the a range of
With Saudi Arabia already informing its customers of cuts in their January
2017 deliveries, it seems there is will enough within OPEC to follow through on
the agreement. The issue now moved from agreement to enforcement, and therein
lies some thorns. Historically, the Gulf state – Saudi Arabia, UAE and Kuwait –
have been the most disciplined in enforcing cuts, with members elsewhere –
Venezuela, Ecuador and Angola – more likely to discreetly flout the quotas.
OPEC is also meeting with some non-OPEC producers in Vienna this week to see if
consensus can be made on non-OPEC cuts; Russia has publically agreed to a 300
kb/d cut (with caveats, of course), and OPEC says a non-OPEC cut of 600 kb/d is
This might be an issue in the US, particularly with the new Trump
administration that wishes to encourage drilling. While oil prices rose
immediately in the wake of the OPEC announcement, they fell back quickly again
as US oil production announced a weekly increase. The Baker Hughes survey of
active oil rigs in the US has risen to its highest weekly level in almost a
year, as onshore producers restarted rigs in response to higher price signal.
From US$55/b last Thursday, crude oil prices are now in the low US$50s. Donald
Trump’s provisional cabinet is full of climate skeptics and energy bulls and he
has named Scott Pruitt as the head of the new American Environmental Protection
Agency, with the fossil fuel industry ally is likely to call for further
deregulation in American hydrocarbons. With Keystone XL back as a possibility
and longer-term moves to open up drilling in new areas like the Arctic likely,
it could unleash a new wave of oil in the market depressing prices. The US
under Trump is not going to agree to any supply cuts, which may very well
defeat the entire purpose of the OPEC exercise. Saudi Arabia’s attempt to wipe
up US shale oil by keeping prices down has only kept the shale producers at
bay, who will return once prices hit a decent level. This ebb and flow will
persist, and we believe a general oversupply will endure.
Here’s our prediction. The OPEC quotas will hold, but the cuts will
not be as deep as envisioned because some members – especially Iran – will take
advantage of the situation to sneak extra sales. The big producers – Russia,
Saudi Arabia, Iraq and Iran will focus on relative pricing to defend their market
share. American production will continue to be nimbly driven by price signals,
balancing out the cuts elsewhere. Oil prices will strengthen – probably to the
US$55-60/b level – which is a good place to be, all things considered. It won’t
be the dramatic recovery that many will hope for, but it won’t be a complete
collapse either, and in this environment that’s good enough already.
Natural Gas in 2017
With OPEC and a group of major non-OPEC producers coming together to
agree on shave up to 1.8 mb/d in their oil production, it is a rising tide that
will lift all other energy commodities. This includes natural gas, once the red-headed
cousin of oil but now a crowning beauty of its own.
In the natural gas space, this will lead to higher prices for
pipeline gas, rising slightly from prices that are already relatively cheap.
With a cold winter expected, natural gas demand will be high in the northern
hemisphere as well, while domestic consumption in both Europe and the US is on
a steady growth trend. However, the bigger impact will be in the LNG space.
On the LNG side, higher crude prices means higher LNG prices. Spot
prices in Asia have already hit US$8.10/mmbtu in the last week, the highest
since mid-2015, due to the OPEC agreement and cold weather in north Asia and
Europe. LNG, though, is a contract market. It is estimated that some 80% of LNG
sold in the world in based on long-term contracts linked to oil. Typically a
function of oil, indexation may vary but the general rule of thumb is that a
US$1/b increase leads to a US$0.07-0.15/mmbtu increase in oil-indexed LNG
contract prices. But those are for existing contracts, inherited from the days
when the seller was king and could command all sorts of price structures –
S-curves, for example - to benefit them. Today, that is a thing of the past.
With the glut of LNG currently existing and more still to come – Wheatstone and
Gorgon in Australia being the two big ones in 2017 – LNG has been a buyer’s
market for the last two years And the buyers are getting bolder.
Specifically, the Japanese buyers are getting bolder. If 2015 and
2016 were the years when Japanese buyers realised that a low price environment
gave them far more clout, 2017 will be the year when they begin to assert
themselves. Moves towards this are already happening. Japan is trying to render
location destination clauses in existing long-term LNG contracts void through
anti-competitive laws, which would free Japan buyers like Tokyo Gas and Chubu
Electric to swap and re-route cargoes, instead of being locked into specific
ports. Newer contracts will probably have to do away with the clauses
altogether. This creates a more dynamic environment where buyers can move their
LNG cargoes around based on supply and demand, effectively becoming traders. It
is a step towards creating an Asia trading hub for LNG, with Singapore having
already developed its own sport LNG price assessments and agreeing to work with
Japan to possibly create a Singapore-Japan benchmark. China and Korea, both
large LNG consumers as well, have also launched attempts of their own, with the
Shanghai gas derivatives exchange starting up last month. Efforts towards this
will continue, and 2017 will see a more vibrant LNG trading market.
Looking ahead, there is so much LNG coming onto the market that it
is almost a tsunami. Canada’s projects on the BC Pacific Coast. The US Gulf of
Mexico projects, with the newly-expanded Panama Canal as a conduit. The vast
projects off Western Australia. Plenty of supply coming from Mozambique and
Papua New Guinea as well. All of these volumes will be chasing Asian clients.
LNG will be a buyer’s market for a long time to come, and 2017 will be the year
that companies, utilities and governments will step up to expand and create
infrastructure to support a gas-rich future.
Downstream Oil in 2017
The upstream portion of the oil industry is ending the year on a bit
of a cheer, with rallying crude prices. In the downstream section, however, it has
been a challenging year and 2017 repeats the same situation as 2016.
Looking specifically at Asia, refined oil product demand is slowing
down. Part of this is due to the natural decline in Japan and South Korea, and
part of this is due to a natural deceleration in China, where annual growth
rates at 9-10% could never be sustained indefinitely. Demand growth in India
and developing economies is improving, but years of high oil prices have pushed
their infrastructure in different directions, not necessarily to the benefit of
oil, even in a lower price environment.
Even if there is good demand growth, not all of it will benefit
refineries. One bright spark in the downstream arena has been petrochemicals,
with countries like China still adding capacity. Traditionally, these have
depended on naphtha as their feedstock – hence the trend over the past decade
for integrated refinery-petchem facilities. US shale gas remains a gamechanger
here. There is so much ethane (and to a lesser extent, LPG liquids propane and
butane) coming out of the US that prices are low and petrochemical operations
in Asia are reconfiguring to focus on natural gas liquids as feedstock. BP
estimates that a third of global downstream demand growth may bypass refineries
altogether, placing further pressure on refineries.
This is not good for refiners. In general, refined oil product
cracks in Asia have been at historical lows in 2016, thought there are few
bright spots like naphtha. Though this will ebb and flow depending on shortages
and seasonal demand, the overall trend is shrinking cracks. Cheap oil prices
have not caused an equivalent surge in Asian oil demand. In fact, there is
simply too much product sloshing around the market. This is been exacerbated in
2016 when Chinese independent refiners – the teapots – were granted licences to
import crude for the first time, leading to them raising runs to records levels
and lifting Chinese exports. Far from being a ‘sink’ for refined products,
China is now becoming a net exporter. However, in a move last week, China
removed export quotas for the teapots, effectively preventing them from
exporting any of their products. Their import licences may still be held
steady, but the teapots will now have to consider the limited domestic market
when planning runs. This could improve the supply glut in Asia somewhat, but
traditional product ‘sinks’ are evolving on their own.
Vietnam’s second refinery, Nghi Son, is supposed to start up in
mid-2017. It will face delays. And if Dong Quat is any precedent, Nghi Son will
face production troubles in its first year. So Vietnam will remain a reliable
product ‘sink’ in 2017, but this will dissipate when Nghi Son comes onstream.
India, where oil product growth has been strong this year, will also absorb
major amounts of products, but the Indian refiners – IOC, BPCL and HPCL – all
have extensive capacity upgrade plans over the next five years, removing this
window. Indonesia continues to claim ambitious refining plans that could
potentially eliminate the need for imports, but it has been spouting this line
for a decade now and there seems to be little movement beyond announcement in
this arena, leaving Indonesia a large ‘sink’ for the time being. But Indonesian
oil product specs are generally lower than the average Asian standards,
limiting the refineries it can buy product from. There will be growth else –
notably Myanmar and Bangladesh – but this will be unable to offset the declines
in Japan and South Korea.
This is a death knell for major export-oriented refinery projects in
Asia. Projects like Petronas’ RAPID in Malaysia, due for startup in 2019, will
go ahead, but fewer will make it off the drawing board. New refineries will be
contained to net importer countries, as they try to reduce their import burden,
as we have seen this year in Pakistan, Uganda and Middle East countries moving
up the value chain. Product demands will also continue to move up the barrel,
placing more pressure on simple, topping refineries. 2016 saw a slew of
refinery sales and closures in Europe – even low oil prices couldn’t help a
determined structural trend – and that is a likely future for Asian downstream.
There will be no major surprised downstream in 2017, just confirmation of
Corporate Oil in 2017
Rex Tillerson, head of ExxonMobil since 2006, is packing his bags
and heading to the White House to serve as Donald Trump’s Secretary of State.
As part of his job, he will be jetting around the world promoting American
interests. That’s not much different in scope from his current position, except
that corporate deal-making is very different from diplomacy.
It’s an indication that 2017 will be a pivot away from prevailing
corporate trends in the energy business. Under Tillerson, US ties with Russia
are likely to get closer, as the Trump administration places business and
capitalist interests above issues such as healthcare, environment and social
justice that have taken the forefront. Tillerson will pass his seat to Darren
Woods, the current head of refining at ExxonMobil, with the company likely to
be the only one that will pursue a diversified strategy among the supermajors.
Under Woods, ExxonMobil’s refining arm has remained strong despite low margins,
having already embarked on a divestment drive that saw the company dispose of
peripheral assets in marginal markets.
ExxonMobil, like Shell and Chevron, will remain global brands. But
the assets will no longer be controlled by them. Shell has been following
ExxonMobil’s move, selling its downstream and upstream assets globally to pay
for its pricey acquisition of the BG Group. Natural gas and chemicals are in
Shell’s future, with downstream now of lesser concern; Shell, like ExxonMobil
in Latin America, will now merely licences its name to third-party players. BP
has already done the same over the last decade, with its logo now a rarity in
retail across the world, though oddly enough it is tying up with Reliance in
India. Chevron’s divestment extends further than downstream, moving into
smaller-scale upstream assets, with its attempt to exit Bangladesh and Thailand
in recent months. 2016 has been a year of divestments and debt-paring among the
supermajors as they seek to become leaner and meaner, just like Petrobras,
though for completely different reasons. Meanwhile, France’s Total still has
ambitions of being a global behemoth that the supermajors once were, picking up
assets in Asia and Africa. This will continue in 2017, with the directions
clear. Shell to natural gas and chemicals, BP to LNG, Chevron to large-scale
upstream and ExxonMobil everywhere, with top priority to sort out its
acquisition of InterOil in PNG.
The vacuum left by the supermajors particularly in downstream has
been picked up by global traders. Players like Vitol, Glencore and Gunvor have
been extending their trading empires to actual retail participation since 2013,
and the move will continue in 2017. Some might even try to set up brands of
their own, instead of piggy-backing on existing ones (and their associated
Meanwhile, the national counterparts of the supermajors, the major
NOCs, will still find 2017 a challenging year. Oil prices have risen, but
nowhere near the level that required to balance national budgets. Saudi Aramco
and to a lesser extent Adnoc and KPC have the reserves to see through the
storm, but PDVSA is in trouble. Iraq and Iran will flout OPEC supply quotas to
sneak a few extra sales to resume what they see as their rightful position,
while Libya tries to rebuild its infrastructure and Nigeria tries its hand at
privatisation. Indonesia’s Pertamina will continue to flounder in too many
directions, Malaysia’s Petronas will remain weak and Brazil’s Petrobras will
continue its fire sale to reduce its huge debts. China’s triad – PetroChina,
Sinopec and CNOOC – will continue to extend their tendrils oversees, while
Japan’s bloated energy sector will try to consolidate. And largely fail,
resulting in a friendly informal cooperation instead. Russia has a lot of debt
issues simmering under Putin’s bluster. India’s state players are probably in
the best position, where energy demand is sprinting ahead.
Higher crude oil prices will be a good way to start off 2017 for
most energy companies; but there’s still a lot of work to be done. Much like
the global political landscape, corporate energy players will become more
insular, focusing on specific areas of profit instead of a broad-based
strategy. The notion of an integrated player with tentacles in every pie is
over. With the possible exception of ExxonMobil.
Have a productive year ahead!
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The vast Shah Deniz field in Azerbaijan’s portion of the South Caspian Sea marked several milestones in 2018. It has now produced a cumulative total of 100 billion cubic metres of natural gas since the field started up in 2006, with daily output reaching a new peak, growing by 12.5% y-o-y. At a cost of US$28 billion, Shah Deniz – with its estimated 1.2 trillion cubic metres of gas resources – has proven to be an unparalleled success, being a founding link of Europe’s Southern Gas Corridor and coming in relatively on budget and on time. And now BP, along with its partners, is hoping to replicate that success with an ambitious exploration schedule over the next two years.
Four new exploration wells in three blocks, along with a seismic survey of a fourth, are planned for 2019 and an additional three wells in 2020. The aggressive programme is aimed at confirming a long-held belief by BP and SOCAR there are more significant pockets of gas swirling around the area. The first exploratory well is targeting the Shafag-Asiman block, where initial seismic surveys suggest natural gas reserves of some 500 billion cubic metres; if confirmed, that would make it the second-largest gas field ever discovered in the Caspian, behind only Shah Deniz. BP also suspects that Shah Deniz itself could be bigger than expected – the company has long predicted the existence of a second, deeper reservoir below the existing field, and a ‘further assessment’ is planned for 2020 to get to the bottom of the case, so to speak.
Two wells are planned to be drilled in the Shallow Water Absheron Peninsula (SWAP) block, some 30km southeast of Baku, where BP operates in equal partnership with SOCAR, with an additional well planned for 2020. The goal at SWAP is light crude oil, as is a seismic survey in the deepwater Caspian Sea Block D230 where a ‘significant amount’ of oil is expected. Exploration in the onshore Gobustan block, an inland field 50km north of Baku, rounds up BP’s upstream programme and the company expects that at least one seven wells of these will yield a bonanza that will take Azerbaijan’s reserves well into the middle of the century.
Developments in the Caspian are key, as it is the starting node of the Southern Gas Corridor – meant to deliver gas to Europe. Shah Deniz gas currently makes its way to Turkey via the South Caucasus Gas pipeline and exports onwards to Europe should begin when the US$8.5 billion, 32 bcm/y Trans-Anatolian Pipeline (TANAP) starts service in 2020. Planned output from Azerbaijan currently only fills half of the TANAP capacity, meaning there is room for plenty more gas, if BP can find it. From Turkey, Azeri gas will link up to the Trans-Adriatic Pipeline in Greece and connect into Turkey, potentially joined by other pipelines projects that are planned to link up with gas production in Israel. This alternate source of natural gas for Europe is crucial, particularly since political will to push through the Nordstream-2 pipeline connecting Russian gas to Germany is slackening. The demand is there and so is the infrastructure. And now BP will be spending the next two years trying to prove that the supply exists underneath Azerbaijan.
BP’s upcoming planned exploration in the Caspian:
When it was first announced in 2012, there was scepticism about whether or not Petronas’ RAPID refinery in Johor was destined for reality or cancellation. It came at a time when the refining industry saw multiple ambitious, sometimes unpractical, projects announced. At that point, Petronas – though one of the most respected state oil firms – was still seen as more of an upstream player internationally. Its downstream forays were largely confined to its home base Malaysia and specialty chemicals, as well as a surprising venture into South African through Engen. Its refineries, too, were relatively small. So the announcement that Petronas was planning essentially, its own Jamnagar, promoted some pessimism. Could it succeed?
It has. The RAPID refinery – part of a larger plan to turn the Pengerang district in southern Johor into an oil refining and storage hub capitalising on linkages with Singapore – received its first cargo of crude oil for testing in September 2018. Mechanical completion was achieved on November 29 and all critical units have begun commissioning ahead of the expected firing up of RAPID’s 300 kb/d CDU later this month. A second cargo of 2 million barrels of Saudi crude arrived at RAPID last week. It seems like it’s all systems go for RAPID. But it wasn’t always so clear cut. Financing difficulties – and the 2015 crude oil price crash – put the US$27 billion project on shaky ground for a while, and it was only when Saudi Aramco swooped in to purchase a US$7 billion stake in the project that it started coalescing. Petronas had been courting Aramco since the start of the project, mainly as a crude provider, but having the Saudi giant on board was the final step towards FID. It guaranteed a stable supply of crude for Petronas; and for Aramco, RAPID gave it a foothold in a major global refining hub area as part of its strategy to expand downstream.
But RAPID will be entering into a market quite different than when it was first announced. In 2012, demand for fuel products was concentrated on light distillates; in 2019, that focus has changed. Impending new International Maritime Organisation (IMO) regulations are requiring shippers to switch from burning cheap (and dirty) fuel oil to using cleaner middle distillate gasoils. This plays well into complex refineries like RAPID, specialising in cracking heavy and medium Arabian crude into valuable products. But the issue is that Asia and the rest of the world is currently swamped with gasoline. A whole host of new Asian refineries – the latest being the 200 kb/d Nghi Son in Vietnam – have contributed to growing volumes of gasoline with no home in Asia. Gasoline refining margins in Singapore have taken a hit, falling into negative territory for the first time in seven years. Adding RAPID to the equation places more pressure on gasoline margins, even though margins for middle distillates are still very healthy. And with three other large Asian refinery projects scheduled to come online in 2019 – one in Brunei and two in China – that glut will only grow.
The safety valve for RAPID (and indeed the other refineries due this year) is that they have been planned with deep petrochemicals integration, using naphtha produced from the refinery portion. RAPID itself is planned to have capacity of 3 million tpa of ethylene, propylene and other olefins – still a lucrative market that justifies the mega-investment. But it will be at least two years before RAPID’s petrochemicals portion will be ready to start up, and when it does, it’ll face the same set of challenging circumstances as refineries like Hengli’s 400 kb/d Dalian Changxing plant also bring online their petchem operations. But that is a problem for the future and for now, RAPID is first out of the gate into reality. It won’t be entering in a bonanza fuels market as predicted in 2012, but there is still space in the market for RAPID – and a few other like in – at least for now.
RAPID Refinery Factsheet:
Tyre market in Bangladesh is forecasted to grow at over 9% until 2020 on the back of growth in automobile sales, advancements in public infrastructure, and development-seeking government policies.
The government has emphasized on the road infrastructure of the country, which has been instrumental in driving vehicle sales in the country.
The tyre market reached Tk 4,750 crore last year, up from about Tk 4,000 crore in 2017, according to market insiders.
The commercial vehicle tyre segment dominates this industry with around 80% of the market share. At least 1.5 lakh pieces of tyres in the segment were sold in 2018.
In the commercial vehicle tyre segment, the MRF's market share is 30%. Apollo controls 5% of the segment, Birla 10%, CEAT 3%, and Hankook 1%. The rest 51% is controlled by non-branded Chinese tyres.
However, Bangladesh mostly lacks in tyre manufacturing setups, which leads to tyre imports from other countries as the only feasible option to meet the demand. The company largely imports tyre from China, India, Indonesia, Thailand and Japan.
Automobile and tyre sales in Bangladesh are expected to grow with the rising in purchasing power of people as well as growing investments and joint ventures of foreign market players. The country might become the exporting destination for global tyre manufacturers.
Several global tyre giants have also expressed interest in making significant investments by setting up their manufacturing units in the country.
This reflects an opportunity for local companies to set up an indigenous manufacturing base in Bangladesh and also enables foreign players to set up their localized production facilities to capture a significant market.
It can be said that, the rise in automobile sales, improvement in public infrastructure, and growth in purchasing power to drive the tyre market over the next five years.