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THE above chart shows the extent to which this year's
oil-price rally has been led by futures markets. What is significant, though,
is that futures activity seems to have plateaued.
Sure,
futures activity could easily go the other way again, driving prices
significantly above the $50/bbl level. But barring a decision by the US Federal
Reserve to once again step away from interest rate rises and China further
loosening the credit tap, it is hard to see why the speculators would want to
go deeper into bull territory. The market remains heavily distorted by the
speculators, and so first and foremost you must analyse futures activity before
you then look at physical supply.
Right
now, I would argue that the Fed looks set on raising interest rates again in
June or July. And in China, credit growth contracted again in April. I believe
this indicates that economic reforms are gathering pace again.
As for
the real supply and demand of oil, you should have been asking yourselves two
questions throughout this rally: Shortages? What Shortages?
I'll deal
with the Fed, China, and today' crude supply position in more detail later on.
First of all, though, here is some historical context behind the role that
financial markets have played in determining the oil price over the last seven
years.
China, Jobs and
Economic Stimulus
I believe
that that the 2009-2014 rally in crude prices was driven by the fall in the
value of the US dollar, thanks to the Fed's ultra-low interest rate policies.
This forced hedge funds and pension funds etc. to seek an alternative 'store of
value'. This store of value was oil and other commodities.
What
seemed to justify this alternative store of value was China's parallel decision
to conduct the biggest economic stimulus programme in global economic history,
which cushioned the country from the impact of the Global Financial Crisis. It
was all about preserving jobs for the Chinese leadership of the time. They
didn't care about anything else, including the long term fundamentals of supply
and demand as overinvestment poured into manufacturing and real estate. To give
you an idea of the scale of what I am talking about, China increased lending by
$10 trillion in 2009, when its nominal GDP was only $5 trillion. Lending was an
astonishing $18 trillion higher by 2013.The long term economic benefits of this
extraordinary rise in credit didn't worry the financial speculators. Of course
not. It is not their job be worried about the long term. But other people who
should have known better, including CEOs of some chemicals companies, who
started talking about a 'new paradigm' of a rising middle class in China who
would very soon be as rich as the middle classes in the West. This not only
justified and underpinned the rallies in oil and commodity prices - but
crucially also added further momentum to the rallies.
As this
paradigm became the new consensus, the shale-oil industry took off in the US -
aided also by the availability of cheap financing thanks to the Fed's
interest-rate policies. Petrochemicals projects in the US, and elsewhere, were
also sanctioned on the theory that China - and emerging markets growth in
general - had entered this new paradigm.
It all
went very badly wrong from September 2014, when it became apparent that Chinese
economic stimulus had, after all, been unsustainable. Crude markets belatedly woke up to the notion
that China's stimulus had left behind vast domestic oversupply in manufacturing
and real, estate, and so a serious bad debt problem. The scale of China's environment crisis, made much worse by this overinvestment, was also
recognised.
What made
people wake up to these long-standing realities was that China's new political
leaders admitted the scale of the problems - and, more importantly, they
reversed course. They started reducing credit growth, and so the Chinese bubble
began to dramatically deflate. Credit growth began to decline from January
2014. And here is another extraordinary number: In 2015, growth in credit was
no less than $4 trillion lower than in 2014.
Back To The Future:
Q1 2016
After the
January 2016 collapse in oil prices and equity markets, the US Federal Reserve
got cold feet. It began to back away from further interest rate rises, on the
belief that weak crude and equities etc. meant that US economy was in too
perilous a condition to take that risk. This was the signal sent to the oil
speculators: The dollar was going to be weaker for longer than they had
expected, and so it was time to get back into crude as an alternative store of
value. This also led to recovery in other commodity markets, including iron ore.
What once
again added further momentum to the rally was China's decision to loosen
credit, which grewby some 58% in Q1
over the first quarter of 2015. The detail didn't matter here. All that
mattered to the crude-market speculators was the wider belief that China had,
somehow, turned the corner. The renewed economic stimulus created the erroneous
idea that China could spend its way out of trouble.
Now,
though, thanks to stronger US GDP growth and continued robust jobs growth, Fed
chairman Janet Yellen has indicated that two to three interest rate rises could,
be on the cards later this year - with the first hike possibly in June or July.
And in
China, credit growth fell in April. Total social financing plunged to 751 billion yuan during
month compared with 2.34 trillion yuan in March.
Any
sensible analyst would have told you that China's Q1 rise in lending was
unsustainable - and that, of course, it was a drop in the ocean compared with
the $4 trillion of credit withdrawn from the economy in 2015.
What told
you it was unsustainable was that this represented another example of a victory
for the short-term thinkers who in China, who prefer to prop-up immediate
growth rather than deal with the longer-term issues. But you also had to bet
that the reformers would reassert control - and, indeed, this has happened. In
this particular instance, local governments temporarily gained the
upper hand because of their struggle to cover their liabilities.
The end
result - and may have already seen early signs of this in the above chart -
could well be speculators switching back to the US dollar, as is strengthens -
away from their alternative stores of value.
Actual Supply And
Demand of Oil Itself
Last is
not meant to be least. Of course, this matters. But in all the noise created by
the speculators, the sound made by the data on physical production, storage and
demand can sometimes be impossible to hear.
Take last
year's oil-price rally as an example. Remember how we kept being told that the
US rig count was falling? This took Brent from $45.19/bbl in mid-January to
$69.63/bbl on 8 May.
Meanwhile,
US shale oil producers continued to push the innovation envelope on cost
reductions. Each rig in operation had also become much more productive. The practice of 'fracklogging' - storing oil in rocks ready to be fracked when
prices recovered - also increased. And thanks to stronger futures prices, the
shale oil industry was able to take out new hedges. This put them in the
position to be able to sell at lower prices in the physical market because they
had locked higher futures returns. Saudi Arabia also stuck with its market
share strategy, whilst the global economy remained weak. This all led to the
fall in oil prices during H2 2015.
The
physical justification for today's rally is on even more shaky ground.
We were
first told that there would be a production freeze agreement at the April Doha
meeting. I never believed that
this on the cards - and, of course, it didn't happen.
We did
then, however, see a dramatic decline in production as a result of wild fires
in Canada, attacks on Nigerian pipelines and more upheavals in Iraq. But I
think that this was seized upon by markets whilst they overlooked some signs of
long supply elsewhere. And, of course, this decline could well prove to be
temporary.
Signs of
long supply elsewhere includes oil in storage. Global oil stockpiles, including
floating storage, have increased for the last ten consecutive quarters,
according to this Hellenic Shipping News article, which adds:
It is estimated that almost 9% of the global VLCC fleet is
currently booked for floating storage, which is a 40% increase in tankers by
number since December. Reuters reported that at least 40 laden VLCCs anchored
off Singapore as floating storage, storing estimated volumes of up to 47.7m
bbl, thought to be the highest level in at least five years.
Crucially,
also the contango is narrowing. Last week, the one-month arbitrage on Brent in
floating storage was -$0.48/bbl, while the 12-month arbitrage was at
-$6.11/bbl, implying there was no profit incentive to store oil on ship.
Storage costs are a minimum of $0.74/bbl, and so there has to be a risk of
destocking.
Iran is
also raising production. By the summer its exports are expected to rise a
further 200,000 bbl/day to reach 2.2m bbl/day the middle of this summer.
And
nobody should be surprised over reports that the US rig count has stopped
declining, with early signs that the rig count may actually increase.The US is
the world's new 'swing producer'. The inventory of drilled but uncompleted US
wells has been building, driven by companies with contracted drilling
services. Ccompanies have merely postponed, rather than cancelled, completion
of wells. This could add 400,000 bbl/day to supply.
Let's not
forget yesterday's OPEC meeting. There was again, of course, no agreement to freeze, never mind cut, production.
As for
demand, the summer lull season in the northern hemisphere, when many people
take their holidays, is set to occur in August and July.
If this
market turns, those who want to short oil have plenty of physical ammunition to
support their positions.
John Richardson from ICIS
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It is, obviously, unsurprising that the recently released Q2 financials for the oil & gas supermajors contained distressed numbers as the first full quarter of Covid-19 impact washed over the entire industry. It is, however, surprising how the various behemoths of the energy world are choosing to respond to the new normal, and how past strategies have exposed either inherent strengths or weakness in their operational strategy.
Let’s begin with BP. With roots that stretch back to 1908 with the discovery of commercial oil in Persia, now Iran – BP arguably coined the phrase supermajor in the late 1990s, when acquisition of Amoco, Arco and Burmah Castrol married BP’s own substantial holdings in Europe and the Middle East to create a transatlantic oil and gas giant. It was a trend mirrored across the industry, with the Seven Sisters of the 1970s becoming ExxonMobil (Esso and Mobil), Chevron (Gulf Oil, Socal and Texaco) and modern day Royal Dutch Shell. Joining them were ConocoPhillips (Conoco and Phillips) and Total (Petrofina and Elf Aquitaine). As the world’s appetite for oil and gas increased at an accelerating pace, the supermajors became among the world’s largest and highest valued companies across the next two decades.
That is now poised for a major change. With fossil fuels waning in demand and renewables becoming more investable, BP is now declaring that it will no longer be a supermajor. CEO Bernard Looney made the announcement ahead of the release of the company’s Q2 financials, seeking to reinvent the firm as ‘integrated energy company’ rather than an ‘integrated oil company’. To make this change, Looney is looking to shrink BP’s oil and gas output by 40% through 2030 and invest heavily to become the world’s largest renewable energy businesses, putting climate change firmly on the agenda and getting ahead of the curve in meeting European directives for a low-carbon future. This was, perhaps, already on the cards. But the Covid-19 effect has hastened it. With a second quarter loss of US$6.7 billion, BP is choosing this time to rebrand itself for long-term transformation rather than maximise current shareholder value; indeed, it will slash dividends in half in order to invest cash for the future.
On the European side of the Atlantic, that trend is accelerating. Shell and Total are also aiming to be carbon neutral by 2050, alongside other European majors such as Eni and Equinor. That isn’t to say that oil or gas will no longer play a huge role in their operations – indeed Total and Eni in particular have made many recent and potentially lucrative finds in Egypt, South Africa and Suriname – just that oil and gas will become a smaller percentage of a diversified business. Both Shell and Total have also displayed how past strategic decisions have paid dividends in uncertain times. Both supermajors declared profits for the quarter, escaping the trend of underlying losses with net profits of US$638 million and US$126 million respectively when a deep red colour to the numbers was expected. The saving grace in a dramatic quarter was their trading activities, where the trading divisions of Shell and Total (as well as BP) took advantage of chaos in the market to deliver strong results. But even with this silver lining, Shell and Total are scaling back on dividends, as they join BP in a drive to diversify in the age of climate change, which has strong political backing in Europe where they are based.
On the other side of the pond, the mood surrounding climate change is decidedly different. ExxonMobil and Chevron aren’t exactly ignoring a low-carbon future but they aren’t exactly embracing it wholeheartedly either. Instead, both supermajors look to be focusing on maximising shareholder value by focusing on producing oil as profitably as possible. It explains why Chevron moved to acquire Noble Energy recently after failing to buy Anadarko last year, and why ExxonMobil is still gung-ho over American shale and its new found black gold assets in Guyana. The Permian remains on their focus; with economic pressure on, there are rich pickings in the shale patch that could turn American shale from a patchwork of ragtag independent drillers to big boy-dominated. In the short-term, that promises quick returns after the panic – especially with ExxonMobil and Chevron declaring net losses of US$1.08 billion and US$8.3 billion for Q2, respectively – but the underlying assumption to that is that the energy industry will recover and continue as it is for the foreseeable future, rather than the major upheaval predicted by their European counterparts.
For shareholders, and the companies themselves, the expectation is what the future will hold once the worse is over. That Q2 2020 financials dismal performance was never in doubt. What is more revealing is where the supermajors will go from here. Will BP’s attempt to end the supermajor era pay off? Or will American optimism return us back to business as usual? It’s two different visions of the future that will either way spell a sea change for the industry.
Market Outlook:
End of Article
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It was just over five years ago that ExxonMobil discovered first oil in Guyana, transforming the sleepy South American country into the world’s upstream hotspot in just half a decade. The strike rate there has been amazing – 18 discoveries out of 20 well campaigns, and more seem to coming as new discovery efforts get underway. This made Guyana the envy of its neighbours. And why not? The Guyanese economy is projected to grow at 86% y-o-y in 2020, despite the Covid-19 pandemic, as first commercial oil from the Liza field hit the market.
Just over the Guyana border, Suriname, a former Dutch colony had all the more reason to be envious. Unlike Guyana, Suriname has an established upstream industry. Managed by the state oil firm Staastsolie, the volumes are paltry: the onshore Calcutta and Tamabredjo field collectively produce at a current rate of 17,000 b/d. Guyana’s Liza field alone is 15 times larger than Suriname’s total crude output. But the Guyanese miracle always did herald some hope that some of that golden dust could blow Suriname’s way, not least because the giant offshore discoveries in the Staebroek block were just across the maritime border.
In January 2020, this bet proved right. US independent Apache announced it had made a ‘significant oil discovery’ at the Maka-Central 1 well, the first suggestion that the Cretaceous oil formation in Guyana extended southeast to Suriname. Two more discoveries were announced by Apache in quick succession, Sapakara West and, just this week, Kwaskwasi. All three are located in the 1.4 million acre offshore Block 58, which was originally held entirely by Apache before French supermajor Total bought into a 50% stake just before the Maka Central discovery was announced. Three discoveries in six month is quite a payoff, especially with the Kwaskwasi-1 well delivering the highest net pay and confirming a ‘world-class hydrocarbon resource’. More importantly, initial findings suggest that Kwaskwasi holds oil with API gravities in the 34-43 degree range, the sort of light oil that is perfect for petrochemicals and higher-grade fuels.
With Total scheduled to take over operatorship of the block after a fourth drilling campaign, the partners are eager to extend their streak. The Sam Croft drillship is scheduled to head to Keskesi, the fourth scheduled prospect in Block 58, after operations at Kwaskwasi-1 have concluded, and an additional exploration campaign is already in the plans for 2021.
Total and Apache aren’t the only ones playing in Surinamese waters, though they are the first to hit the payday. Most of the country’s offshore blocks have been apportioned, snapped up by ExxonMobil, Kosmos, Petronas, Tullow and Equinor, and all are hoping to be the next to announce a find. ExxonMobil, with Equinor and Hess Energy, have a good position in Block 59, just next to the Caieteur block in Guyana, while Kosmos is hunting in Block 42, right next to the Canje block in Guyana. However, it is Malaysia’s Petronas that is the next likely candidate. Present in Suriname since 2016, when it drilled the exploratory Roselle-1 well in Block 52, Petronas also has interests in Block 48 and Block 53, and recently completed a farm-out sale with ExxonMobil for 50% of Block 52. Its drilling campaign for the Sloanea-1 well is scheduled to begin in Q4 2020, and will be keenly watched by all in Suriname.
Unlike Guyana that had no state oil company, Suriname has existing national oil infrastructure. Staatsolie currently controls onshore and shallow water areas in the country. However, all wells drill in offshore Block A, B, C and D have turned out dry so far. That leaves Staatsolie in a situation: its own areas are not prolific as discoveries by Total, Apache, Petronas et al. For now, Staatsolie is looking to gain rights to 10-20% of any oil discovery within Suriname, but the framework for this is weak and it must navigate carefully to not antagonise the oil majors that are powering the discoveries in its waters. It will do well to avoid the confrontational attitude that is jeopardising LNG development in Papua New Guinea with ExxonMobil and Total, but Staatsolie does have a claim to Suriname’s oil riches for itself.
For now, it is exhilarating to observe the progress in this previously quiet corner of South America. It is the closest thing to frontier oil exploration in the 21st century, with each new discovery generating more and more excitement. Who would have thought there was so much oil left undiscovered? Guyana has shot into the spotlight, Suriname is starting its own ascent and… who knows… could French Guiana be next?
End of Article
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Source: U.S. Energy Information Administration, Annual Coal Report
In 2019, U.S. coal production totaled 706 million short tons (MMst), a 7% decrease from the 756 MMst mined in 2018. Last year’s production was the lowest amount of coal produced in the United States since 1978, when a coal miners’ strike halted most of the country’s coal production from December 1977 to March 1978. Weekly coal production estimates from the U.S. Energy Information Administration (EIA) show the United States is on pace for an even larger decline in 2020, falling to production levels comparable with those in the 1960s.
Source: U.S. Energy Information Administration, Annual Coal Report
Wyoming produces more coal than any other state, representing 39% of U.S. coal production in 2019, at 277 MMst, which is 9% lower than its coal production in 2018. Coal production in West Virginia, the state with the second-highest coal output, fell by a relatively smaller 2% in 2019. West Virginia is a primary producer of metallurgical coal, which saw sustained demand for exports in 2019. Coal production recently stopped in two states, Kansas in 2017 and Arkansas in 2018. Arizona stopped producing coal in the fall of 2019 when the coal-fired Navajo Generating Station and adjacent Kayenta coal mine that supplied it both closed.
EIA estimates weekly coal production using coal railcar loadings. In 2020, weekly coal railcar loadings have been trending much lower than 2019 levels, and most recent year-to-date coal railcar loadings were down 27% compared with 2019.
Source: U.S. Energy Information Administration, Weekly Coal Production
The decline of U.S. coal production so far in 2020 reflects less demand for coal internationally and less generation from U.S. coal-fired power plants. U.S. coal exports through May 2020 are 29% lower than during the first five months of 2019. U.S. coal-fired generation fell to a 42-year low in 2019, decreasing nearly 16% from the previous year, and has fallen another 34% through May 2020.
Estimated U.S. coal production through mid-July 2020 is 27% lower than the average annual 2019 output, and EIA expects these reductions in production to persist during the remainder of the year. In the latest Short-Term Energy Outlook (STEO), EIA forecasts a 29% decline in U.S. coal production in 2020.
EIA forecasts that U.S. coal production will increase by 7% in 2021, when rising natural gas prices may cause some coal-fired electric power plants to become more economical to dispatch. Much of EIA’s projected recovery in coal production is in the western United States.
Principal contributor: Rosalyn Berry