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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Throughout much of its history, the United States has imported more petroleum (which includes crude oil, refined petroleum products, and other liquids) than it has exported. That status changed in 2020. The U.S. Energy Information Administration’s (EIA) February 2021 Short-Term Energy Outlook (STEO) estimates that 2020 marked the first year that the United States exported more petroleum than it imported on an annual basis. However, largely because of declines in domestic crude oil production and corresponding increases in crude oil imports, EIA expects the United States to return to being a net petroleum importer on an annual basis in both 2021 and 2022.
EIA expects that increasing crude oil imports will drive the growth in net petroleum imports in 2021 and 2022 and more than offset changes in refined product net trade. EIA forecasts that net imports of crude oil will increase from its 2020 average of 2.7 million barrels per day (b/d) to 3.7 million b/d in 2021 and 4.4 million b/d in 2022.
Compared with crude oil trade, net exports of refined petroleum products did not change as much during 2020. On an annual average basis, U.S. net petroleum product exports—distillate fuel oil, hydrocarbon gas liquids, and motor gasoline, among others—averaged 3.2 million b/d in 2019 and 3.4 million b/d in 2020. EIA forecasts that net petroleum product exports will average 3.5 million b/d in 2021 and 3.9 million b/d in 2022 as global demand for petroleum products continues to increase from its recent low point in the first half of 2020.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), February 2021
EIA expects that the United States will import more crude oil to fill the widening gap between refinery inputs of crude oil and domestic crude oil production in 2021 and 2022. U.S. crude oil production declined by an estimated 0.9 million b/d (8%) to 11.3 million b/d in 2020 because of well curtailment and a drop in drilling activity related to low crude oil prices.
EIA expects the rising price of crude oil, which started in the fourth quarter of 2020, will contribute to more U.S. crude oil production later this year. EIA forecasts monthly domestic crude oil production will reach 11.3 million b/d by the end of 2021 and 11.9 million b/d by the end of 2022. These values are increases from the most recent monthly average of 11.1 million b/d in November 2020 (based on data in EIA’s Petroleum Supply Monthly) but still lower than the previous peak of 12.9 million b/d in November 2019.
In the past week, crude oil prices have surged to levels last seen over a year ago. The global Brent benchmark hit US$63/b, while its American counterpart WTI crested over the US$60/b mark. The more optimistic in the market see these gains as a start of a commodity supercycle stemming from market forces pent-up over the long Covid-19 pandemic. The more cynical see it as a short-term spike from a perfect winter storm and constrained supply. So, which is it?
To get to that point, let’s examine how crude oil prices have evolved since the start of the year. On the consumption side, the market is vacillating between hopeful recovery and jittery reactions as Covid-19 outbreaks and vaccinations lent a start-stop rhythm to consumption trends. Yes, vaccination programmes were developed at lightning speed; and even plenty of bureaucratic hiccoughs have not hampered a steady rollout across the globe. In the UK, more than 20% of adults have received at least one dose of the vaccines, with the USA not too far behind. Israel has vaccinated more than 75% of its population, and most countries should be well into their own programmes by the end of March. That acceleration of vaccinations has underpinned expectations of higher oil demand, with hopes that people will begin to drive again, fly again and buy again. But those hopes have been occasionally interrupted by new Covid-19 clusters detected and, more worryingly, new mutations of the virus.
Against this hopeful demand picture, supply has been managed. Squabbling among the OPEC+ club has prevented a more aggressive approach to managing supply than kingpin Saudi Arabia would like, but OPEC+ has still managed to hold itself together to placate the market that crude spigots will remain restrained. And while the UAE has successfully shifted OPEC+ quota plan for 2021 from quarterly adjustments to monthly, Saudi Arabia stepped into the vacuum to stamp its authority with a voluntary 1 million barrels per day cut. The market was impressed.
That combination of events over January was enough to move Brent prices from the low US$50/b level to the upper US$50/b range. However, US$60/b remained seemingly out of reach. It took a heavy dusting of snow across Texas to achieve that.
Winter weather across the northern hemisphere seemed harsher than usual this year. Europe was hit by two large continent-wide storms, while the American Northeast and Pacific Northwest were buffeted with quite a few snowstorms. Temperatures in East Asia were fairly cold too, which led to strong prices for natural gas and LNG to keep the population warm. But it was a major snowstorm that swept through the southern United States – including Texas – that had the largest effect on prices. Some areas of Texas saw temperatures as low as -18 degrees Celsius, while electricity demand surged to the point where grids failed, leaving 4.3 million people without power. A national emergency was declared, with over 150 million Americans under winter storm warning conditions.
For the global oil complex, the effects of the storm were also direct. Some of the largest oil refineries in the world were forced to shut down due to the Arctic conditions, further disrupting power and fuel supplies. All in all, over 3 mmb/d of oil processing capacity had to be idled in the wake of the storm, including Motiva’s Port Arthur, ExxonMobil’s Baytown and Marathon’s Galveston Bay refineries. And even if the sites were still running, they would have to contend to upstream disruptions: estimates suggest that crude oil production in the prolific Permian Basin dropped by over a million barrels per day due to power outages, while several key pipelines connecting Cushing, Oklahoma to the Texas Gulf Coast were also forced to shutter.
That perfect storm was enough to send crude prices above the US$60/b level. But will it last? The damage from the Texan snowstorm has already begun to abate, and even then crude prices did not seem to have the appetite to push higher than US$63/b for Brent and US$60/b for WTI.
Instead, the key development that should determine the future range for crude prices going into the second quarter of 2021 will be in early March, when the OPEC+ club meets once again to decide the level of its supply quotas for April and perhaps beyond. The conundrum facing the various factions within the club is this: at US$60/b, crude oil prices are not low enough to scare all members in voting for unanimous stricter quotas and also not high enough to rescind controlled supply. Instead, prices are at a fragile level where arguments can be made both ways. Russia is already claiming that global oil markets are ‘balanced’, while Saudi Arabia is emphasising the need for caution in public messaging ahead of the meeting. Saudi Arabia’s voluntary supply cut will also expire in March, setting up the stage for yet another fractious meeting. If a snow overrun Texans was a perfect storm to push crude prices to a 13-month high, then the upcoming OPEC+ meeting faces another perfect storm that could negate confidence. Which will it be? The answer lies on the other side of the storm.
Much like the year itself, the final quarter of 2020 proved to be full of shocks and surprises… at least in terms of financial results from oil and gas giants. With crude oil prices recovering on the back of a concerted effort by OPEC+ to keep a lid on supply, even at the detriment of their market share, the fourth quarter of 2020 was supposed to be smooth sailing. The tailwind of stronger crude and commodity prices, alongside gradual demand recovery, was expected to have smoothen out the revenue and profit curves for the supermajors.
That didn’t happen.
Instead, losses were declared where they were not expected. And where profits were to be had, they were meagre in volume. And crucially, a deeper dive into the financial results revealed worrying trends in the cash flow of several supermajors, calling into question the ability of these giants to continue on their capital expenditure and dividend plans, and the risks of resorting to debt financing in order to appease investors and yet also continue expanding.
Let’s start with the least surprising result of all. For months, ExxonMobil had been signalling that it would be taking a massive writedown on its upstream assets in Q4 2020, which could lead to a net loss for the quarter and the year. Unlike its peers, ExxonMobil had resisted making writedowns on the value of its crude-producing assets earlier in 2020. At the time, it stated that it had already built caution in the value assessments of those assets, reflecting ‘fair value’; not so long after that bold statement, ExxonMobil has been forced to backtrack and make a US$20.2 billion downward adjustment. Unusually, that meant that non-cash impairments aside, ExxonMobil actually eked out a tiny profit of US$110 million for the quarter on the strength of margins in the chemicals segment, but a full year loss of US$22.4 billion: the first ever annual loss since Exxon and Mobil merged in 1998. This was better than expected by Wall Street analysts, who would also be cheering the formation of ExxonMobil Low Carbon Solutions, in which the group would pump some US$3 billion through 2025 to reduce its greenhouse gas emissions by 20% from 2016 levels. That acknowledgement of a carbon neutral future is still far less ambitious than its European counterparts, but is a clear sign that ExxonMobil is starting to take the climate change element of its business more seriously.
If ExxonMobil managed to surprise in a good way, then its closest American rival did the opposite. Chevron had been outperforming ExxonMobil in quarterly results for a while now, but in Q4 2020 retreated with a net loss of US$665 million. That was narrower than the US$6.6 billion loss declared in Q4 2019, but still a shock since analysts were expecting a narrow profit. Calling 2020 ‘a year like no other’, the headwinds facing Chevron in Q4 2020 were the same facing all majors and supermajors, despite gains in crude prices, refining margins and fuel sales were still soft. Chevron’s cash flow was also a concern – as was ExxonMobil’s – which prompted chatter that the two direct descendants of JD Rockefeller’s Standard Oil were considering a merger. If so, then there is at least alignment on the climate topic: Chevron is also following the trail blazed by European supermajors in embracing a carbon neutral future, with CEO Michael Wirth conceding that Chevron may ‘not be an oil-first company in 2040’.
On the European side of the pond, that same theme of lowered downstream performance dragging down overall performance continued. But unlike the US supermajors, the likes of Shell, BP and Total were somewhat insulated from the Covid-19 blows at the peak of the pandemic as their opportunistic trading divisions capitalised on the wild swings in crude and fuel prices. That factor is now absent, with crude prices taking on a steady upward curve. That’s good for the rest of their businesses, but bad for trading, which thrives on uncertainty and volatility. And so BP reported a Q4 net profit of US$115 million, Shell followed with a Q4 net profit of US$393 million and Total closed out the earning season with industry-beating Q4 net profit of US$1.3 billion, above market expectations.
The softness of the financials hasn’t stopped dividend payouts, but has also been used by Europe’s Big Oil to set the tone for the next few decades of their existence. Total and BP paid a hefty premium to secure rights to build the next generation of UK wind farms; Total joined the Maersk-McKinney Moller Center for Zero Carbon Shipping to develop carbon neutral shipping solutions and splashed out on acquiring 2.2 GW of solar power projects in Texas; BP signed a strategic collaboration agreement with Russia’s Rosneft to develop new low carbon solutions; and aircraft carrier KLM took off with the first flight powered by synthetic kerosene that was developed by Shell through carbon dioxide, water and renewables. That’s a lot of a groundwork laid for the future where these giants can be carbon neutral by 2050.
The message from Q4 seems clear. Big Oil has barely begun its recovery from the Covid-19 maelstrom, and the road to a new normal remains long and painful. But this is also an opportunity to pivot; to set a new destination that is no longer business-as-usual, but embraces zero carbon ambitions. Even the American supermajors are slowly coming around, while the European continues to lead. Will majors in Asia, Latin America and Africa/Middle East follow? Let’s see what that attitude will bring over this new decade.
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