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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Headline crude prices for the week beginning 18 March 2019 – Brent: US$67/b; WTI: US$58/b
Headlines of the week
Midstream & Downstream
Risk and reward – improving recovery rates versus exploration
A giant oil supply gap looms. If, as we expect, oil demand peaks at 110 million b/d in 2036, the inexorable decline of fields in production or under development today creates a yawning gap of 50 million b/d by the end of that decade.
How to fill it? It’s the preoccupation of the E&P sector. Harry Paton, Senior Analyst, Global Oil Supply, identifies the contribution from each of the traditional four sources.
1. Reserve growth
An additional 12 million b/d, or 24%, will come from fields already in production or under development. These additional reserves are typically the lowest risk and among the lowest cost, readily tied-in to export infrastructure already in place. Around 90% of these future volumes break even below US$60 per barrel.
2. pre-drill tight oil inventory and conventional pre-FID projects
They will bring another 12 million b/d to the party. That’s up on last year by 1.5 million b/d, reflecting the industry’s success in beefing up the hopper. Nearly all the increase is from the Permian Basin. Tight oil plays in North America now account for over two-thirds of the pre-FID cost curve, though extraction costs increase over time. Conventional oil plays are a smaller part of the pre-FID wedge at 4 million b/d. Brazil deep water is amongst the lowest cost resource anywhere, with breakevens eclipsing the best tight oil plays. Certain mature areas like the North Sea have succeeded in getting lower down the cost curve although volumes are small. Guyana, an emerging low-cost producer, shows how new conventional basins can change the curve.
3. Contingent resource
These existing discoveries could deliver 11 million b/d, or 22%, of future supply. This cohort forms the next generation of pre-FID developments, but each must overcome challenges to achieve commerciality.
Last, but not least, yet-to-find. We calculate new discoveries bring in 16 million b/d, the biggest share and almost one-third of future supply. The number is based on empirical analysis of past discovery rates, future assumptions for exploration spend and prospectivity.
Can yet-to-find deliver this much oil at reasonable cost? It looks more realistic today than in the recent past. Liquids reserves discovered that are potentially commercial was around 5 billion barrels in 2017 and again in 2018, close to the late 2030s ‘ask’. Moreover, exploration is creating value again, and we have argued consistently that more companies should be doing it.
But at the same time, it’s the high-risk option, and usually last in the merit order – exploration is the final top-up to meet demand. There’s a danger that new discoveries – higher cost ones at least – are squeezed out if demand’s not there or new, lower-cost supplies emerge. Tight oil’s rapid growth has disrupted the commercialisation of conventional discoveries this decade and is re-shaping future resource capture strategies.
To sustain portfolios, many companies have shifted away from exclusively relying on exploration to emphasising lower risk opportunities. These mostly revolve around commercialising existing reserves on the books, whether improving recovery rates from fields currently in production (reserves growth) or undeveloped discoveries (contingent resource).
Emerging technology may pose a greater threat to exploration in the future. Evolving technology has always played a central role in boosting expected reserves from known fields. What’s different in 2019 is that the industry is on the cusp of what might be a technological revolution. Advanced seismic imaging, data analytics, machine learning and artificial intelligence, the cloud and supercomputing will shine a light into sub-surface’s dark corners.
Combining these and other new applications to enhance recovery beyond tried-and-tested means could unlock more reserves from existing discoveries – and more quickly than we assume. Equinor is now aspiring to 60% from its operated fields in Norway. Volume-wise, most upside may be in the giant, older, onshore accumulations with low recovery factors (think ExxonMobil and Chevron’s latest Permian upgrades). In contrast, 21st century deepwater projects tend to start with high recovery factors.
If global recovery rates could be increased by a percentage or two from the average of around 30%, reserves growth might contribute another 5 to 6 million b/d in the 2030s. It’s just a scenario, and perhaps makes sweeping assumptions. But it’s one that should keep conventional explorers disciplined and focused only on the best new prospects.
Global oil supply through 2040
Things just keep getting more dire for Venezuela’s PDVSA – once a crown jewel among state energy firms, and now buried under debt and a government in crisis. With new American sanctions weighing down on its operations, PDVSA is buckling. For now, with the support of Russia, China and India, Venezuelan crude keeps flowing. But a ghost from the past has now come back to haunt it.
In 2007, Venezuela embarked on a resource nationalisation programme under then-President Hugo Chavez. It was the largest example of an oil nationalisation drive since Iraq in 1972 or when the government of Saudi Arabia bought out its American partners in ARAMCO back in 1980. The edict then was to have all foreign firms restructure their holdings in Venezuela to favour PDVSA with a majority. Total, Chevron, Statoil (now Equinor) and BP agreed; ExxonMobil and ConocoPhillips refused. Compensation was paid to ExxonMobil and ConocoPhillips, which was considered paltry. So the two American firms took PDVSA to international arbitration, seeking what they considered ‘just value’ for their erstwhile assets. In 2012, ExxonMobil was awarded some US$260 million in two arbitration awards. The dispute with ConocoPhillips took far longer.
In April 2018, the International Chamber of Commerce ruled in favour of ConocoPhillips, granting US$2.1 billion in recovery payments. Hemming and hawing on PDVSA’s part forced ConocoPhillips’ hand, and it began to seize control of terminals and cargo ships in the Caribbean operated by PDVSA or its American subsidiary Citgo. A tense standoff – where PDVSA’s carriers were ordered to return to national waters immediately – was resolved when PDVSA reached a payment agreement in August. As part of the deal, ConocoPhillips agreed to suspend any future disputes over the matter with PDVSA.
The key word being ‘future’. ConocoPhillips has an existing contractual arbitration – also at the ICC – relating to the separate Corocoro project. That decision is also expected to go towards the American firm. But more troubling is that a third dispute has just been settled by the International Centre for Settlement of Investment Disputes tribunal in favour of ConocoPhillips. This action was brought against the government of Venezuela for initiating the nationalisation process, and the ‘unlawful expropriation’ would require a US$8.7 billion payment. Though the action was brought against the government, its coffers are almost entirely stocked by sales of PDVSA crude, essentially placing further burden on an already beleaguered company. A similar action brought about by ExxonMobil resulted in a US$1.4 billion payout; however, that was overturned at the World Bank in 2017.
But it might not end there. The danger (at least on PDVSA’s part) is that these decisions will open up floodgates for any creditors seeking damages against Venezuela. And there are quite a few, including several smaller oil firms and players such as gold miner Crystallex, who is owed US$1.2 billion after the gold industry was nationalised in 2011. If the situation snowballs, there is a very tempting target for creditors to seize – Citgo, PDVSA’s crown jewel that operates downstream in the USA, which remains profitable. And that would be an even bigger disaster for PDVSA, even by current standards.
Infographic: Venezuela oil nationalisation dispute timeline