The oil and gas industry is rarely unremarkable, but over the past two weeks there have been several events of note, including:
Biden renewing Chevron’s special license. The licence exempts the oil giant from the 2019 US imposed sanctions barring imports of Venezuelan oil and US dollar transactions made with PDVSA (Venezuela’s state oil company), essentially extending the time Chevron has to wind down its operations there to 01 December 2021.
ExxonMobil relinquishing its entire 80% stake in its deepwater oil prospect off the coast of Ghana (Deepwater Cape Three Points), leaving the venture’s two other participants (Ghana National Petroleum Corp. and Ghana Oil Co.) to search for a new operator. Meanwhile, on the other side of the planet, ExxonMobil is developing the offshore Bacalhau oilfield in Brazil with Norway’s Equinor acting as operator (each hold a 40% participating interest, with state-owned Petrobas taking the remaining 20%). They’re set to make a US$ 8 billion investment for phase one.
ExxonMobil’s other news, however, made larger headlines when, in a surprising twist, a small group of investors won three seats on its board of twelve directors. What makes this move so unusual is not – as one would expect – the fact that the investors, named Engine No. 1, are an environmental activist hedge fund established less than a year ago, but rather their success in securing these seats when they invested so little (a mere US$ 54 million, which is an absolute miniscule 0.02% stake). But how did this happen? And what exactly does this mean for the oil giant’s future?
As for the how, blame is being placed at CEO Darren Woods’ door: ExxonMobil losing US$ 25 billion last year to covid-19 is a big reason, especially since this was the company’s first loss since 1998. Even though they weren’t the only ones to suffer these kinds of figures, their shareholders were angry, including several large pension funds, advisory services and fund managers who ended up supporting the nominations. Compounding on this is the direction the company has chosen to follow in recent years. Instead of embracing the renewables trend, as its competitors have, its focus has remained staunchly on growing its ‘core competencies’ (i.e. its oil and gas business). While it is true that investment in renewable energies cannot match the current rates of return provided by fossil fuels, in taking this stance ExxonMobil has portrayed itself as stubbornly antiquated, quickly losing value and acting out of step with other global companies. Engine No. 1 took advantage, putting forward four very credible candidates with vast experience in the industry (the three successful ones were an oil refining exec, a biofuels programme exec and an energy dept. official), who offered detailed analysis (80 pages’ worth) blaming the company’s climate approach for their losses. It’s what the shareholders wanted to hear: the nominees were presenting them with a new direction of travel, a call for ExxonMobil to recognise that energy transition is a serious and unavoidable issue which must be addressed and planned for if the company is to survive, let alone thrive.
What does this mean?
As for how this will affect ExxonMobil, stocks have recovered as the world has begun to get back on its feet, but if they want stability over the long run, they’ll need to keep up with the times and diversify their options. The new directors only take up a quarter of the board, so they will be in a minority, and how pivotal a role they’ll play will depend on what committees they’ll infiltrate and what alliances they form among the other directors. As for their overall strategy for ExxonMobil and how environmentally conscious they actually aim to be, we might not have any certainties yet, but it’s worth remembering that Engine No. 1 is a hedge fund, not an environmental charity. Its main aim is to make a profit on its investment and climate change is factored into their planning because they view it as a real and serious business risk.
If nothing else, the very reason for Engine No. 1’s successful nominations and the events which led up to them suggests that the company will take a good look at its current ethos. Already under pressure at home from a number of lawsuits filed in several US states, and by the environmental pledges its competitors were making, last year ExxonMobil had announced prior to the shareholder’s annual meeting that they would be spending US$ 3 billion over the next half decade on a new ‘low carbon business unit’, which aims to cut the intensity of its CO2 emissions from its upstream production by 20% and the intensity of its more devastating methane emissions by 50%.
A smoke and mirror promise? How does it compare to others?
Their promises, however, fall far short of what many of the European major players have committed to: prompted by the Paris Agreement 2016 and the Greenhouse Gas Protocol (GHG Protocol), in early 2020 BP announced its pledge to achieve net-zero GHG emissions by 2050, forcing the metaphorical hands of both Royal Dutch Shell and Total to do the same.
These pledges do have some issues: none of them actually pledge to cut emissions directly – the most effective way of meeting their ‘net zero’ targets. Rather the goal is often to reduce ‘intensity’ and to offset production. And almost none of the companies’ pledges include scope 3 emissions.
Plans for offsetting emissions is dubious in and of itself, in that capture technology is not yet equipped to meet the requirements of the more ambitious pledges and the scale of reforestation is… questionable at best. The other problem, of course, is that offsetting and capturing doesn’t mean that fossil fuel emissions will necessarily be reduced – it is entirely possible for them to increase so long as they outsell them with renewable fuels.
As for scope 3 emissions, these are the most difficult to measure since they originate from assets not owned or controlled by the oil companies but that the organisation indirectly impacts in its value chain (e.g. transportation and distribution). BP did include such emissions in its pledge but deliberately excluded the scope 3 emissions coming from its stake in the Russian Rosneft, which accounts for nearly half of its total oil production. It’s still better than ExxonMobil’s pledge, which doesn’t include scope 3 emissions at all.
Even with their many loopholes, European big oil’s promises are far and above those offered by their American equivalents. Engine No. 1’s directors are in a prime position to move ExxonMobil forward in a way that will help them avoid what’s happened to Shell – more on that on the next blog post – but it’s a difficult path to navigate, involving steep changes and an about turn in direction for the mighty oil giant. One suspects, however, that the reason for the election of the new board members, combined with external pressures (international policy making and increasingly environmentally conscious state governments) and internal demands (shareholders and investors) will provide the company with sufficient motivation to make substantial change.
Anyone watching the news last week will have heard about ‘negative’ oil prices and producers paying people to take their oil off their hands – but what exactly does that mean, and how was it caused?
For starters, it’s a case of applying the basic economic principle of supply and demand. There is currently too much oil and nobody wants it. The reason for the latter is easy enough to identify: Covid-19 and the ensuing global shut down. People aren’t leaving their homes, no one’s flying anywhere, bulk products aren’t being shipped across the globe, factories aren’t running. Demand for oil has dried up. Oil production, however, has not, and aside from the obvious explanation of it being very difficult (sometimes impossible) and very expensive to turn off the tap, there are actually several other, complex reasons for why prices fell so drastically:
BAD TIMING AND GLOBAL POLITICS:
Covid-19 hit while global oil production was already high.
As a result of the development of fracking and shale oil in the USA over half a decade ago, there has been a glut of oil permeating the market. This (amongst other reasons) led to a significant downturn in prices in 2016 and as a result, the Saudi led OPEC – a legal cartel which aims to stabilise global oil prices – cooperated with several non-OPEC states (most notably Russia) to co-ordinate production cuts in order to counter the increase in American oil exports, and thus raise oil prices to a more stable, economic level. This alliance (known as OPEC+) fell apart once Covid-19 hit China. The Chinese shut down caused a major drop in the demand for oil and triggered a summit where OPEC agreed to further cut production, requiring also that OPEC+ members follow suit. Russia, however, refused. The official stance was that they wanted to wait for a better understanding of the pandemic before taking action. They also argued that there was already a shortfall as a result of political issues in Libya, which would help to offset the slump in prices.
Many analysts believe that Russia’s unwillingness to cut production was due in large part to it being disgruntled towards the United States, who have been one of the main beneficiaries of the OPEC+ cuts over the past four years (since they have had no such limitations on their production). Political relations between the two states have also not helped matters, especially with Trump’s general propensity for using oil as a political weapon against states and in particular the US sanctions targeting the building of the Russian Nord Stream 2 pipeline.
In retaliation for their lack of cooperation, Saudi Arabia then initiated an unexpected price war against Russia, turning on their taps and causing another massive drop in prices.
Meanwhile, producers in the United States kept producing in spite of the slump, even reaching record output highs in March 2020 – this seemed clearly counter-intuitive, not least because the US’ development of shale oil moved it from being one of the world’s largest importers to being the world’s biggest exporter (and thus it benefits far more from higher oil prices). The problem was twofold: one, production costs in the US are generally much higher than those found in rival, Middle Eastern states, and two, many American companies had secured billions of dollars’ worth of debt finance over the past few years to fund their increase in production. They simply could not afford to slow down.
The drop in market price quickly hit so low, however, that US ventures became commercially unfeasible and had no alternative but to begin shutting down operations. As a result, in early April the US, Russia and OPEC agreed to a deal to cut production. This agreement, while historic, seems to have done almost nothing to assure the market in the face of a global shut down – with many considering it too little, too late: there is a substantial amount of excess oil already on the market and even when quarantine restrictions are lifted, it will be some time before demand catches up to match/exceed supply.
A LACK OF STORAGE AND THE MAY FUTURES
At this point it is worth briefly explaining the two main oil grades which are used to set the majority of the world’s crude oil prices: Brent Crude and West Texas Intermediate (WTI). The former sets the prices of approximately two thirds of the global market, but WTI is produced in the US and is the US benchmark. It is this latter one which fell into negative prices – and while both Brent and WTI tend to move in lockstep (with Brent also having dropped to its lowest figures in over two decades) there were additional incidents relating to WTI which exacerbated the situation.
The other thing worth explaining quickly is the concept of a futures contract (often simply referred to as ‘futures’). Futures themselves are standardised, regulated, derivative financial contracts that oblige parties to transact a good at a specified price (‘strike price’) on a future date, with their specifications allowing market participants to trade them uniformly: each oil futures covers 1,000 barrels; dates for delivery are available up to nine years later; and title is officially transferred with the physical movement of the oil. They provide certainty for those who wish to sell or purchase crude physically (and who also need time to actually produce the oil/prepare to receive it), since the parties are able to contract with set, pre-determined prices that will not change based on the naturally volatile market price at the date of delivery (contracting for this purpose is known as ‘hedging’).
On the other hand, traders make a profit (and equally risk suffering losses) through market fluctuations. Some might retain the futures contract until it expires, requiring them to take delivery (these are usually traders who buy/sell for industry-related clients, such as producers or refineries), but most traders have no intention of doing so and instead sell the contracts forward to take advantage of the (hopefully) higher contango prices (i.e. when the price of futures is higher than the spot price) on later-dated contracts.
The vast majority of crude oil transactions take place via futures, but that does not mean the spot market (where trading for large, one-off transactions for near-term delivery takes place) should be underestimated, in fact it is vital: reported prices on the spot market are the basis of pricing for other forms of transaction, including futures. Additionally, as the expiration date of a futures contact approaches, it should become more liquid and the price should quickly begin to converge with the spot price.
The May futures for the WTI market were due to expire (and did) on Tuesday 21 April 2020 (the final day of trading for May). When that happened, whoever was still holding a futures contract would obliged to take physical delivery of the goods. Traders who had initially held off selling futures for this month began to panic as they realised their mistake: when futures are so close to expiration the only interested buyers tend to be companies who might otherwise have purchased oil on the spot market, i.e. they want to take possession of the oil and use it relatively quickly (like airlines, refineries etc.) Due to the glut, the earlier drop in prices and, most significantly, the sudden plunge of demand due to Covid-19 (which also severely weakened the spot market), these kinds of buyers for futures had dried up, and any who were willing to purchase the futures realised that they could take advantage of the situation by waiting until prices fell even further. Exacerbating the situation were the bulk exchange-traded fund rollovers (see below) and a lack of storage space (which continues to be a problem) – most notably in the terminals of Cushing, Oklahoma.
Cushing OK would be a tiny, inconsequential city (population: 8,000), were it not for the fact that it is the delivery point for WTI crude (and thus the pricing point for WTI futures). It is also where several main oil pipelines converge, essentially making it a key transhipment location between producers and refineries in the southern Gulf coast and buyers in the north. At full capacity (its current state) it stores up to 76 million barrels, which is over 10% of all US oil storage space.
Unlike Brent, which is a waterborne crude and does not suffer the same storage constraints (ships, after all, can come and go – to an extent), WTI is mostly onshore, with Cushing itself being a landlocked location in the centre of the United States. With the surplus in oil already filling the terminals there, not only were traders afraid of being forced to take delivery once the futures expired, they also realised they would have nowhere to store any of it (analysts have likened the situation in Cushing to a clogged bottle neck or traffic jam).
With the obligation to take delivery looming, those who still had May futures began paying companies to take the oil off their hands. The price they paid was calculated by what the buyers’ projected storage, insurance, transport costs etc. would be to do so. This was ultimately what dropped the WTI benchmark to below zero.
ETFS AND THE UNITED STATES OIL FUND
As the price war between the Saudis and the Russians drove prices low, it was natural to assume that this was an ideal time to invest in oil (based on the premise that crude prices will rise again since economies will, inevitably, have to reopen). This kind of thinking is not necessarily wrong but, as is the case with any financial investment, would-be venture capitalists should always undertake their due diligence before investing their money. Many didn’t and a great number of bullish speculators unfamiliar with the market (colloquially referred to by some as ‘oil tourists’) pumped over one and a half billion dollars into the United States Oil Fund (‘USO’), the largest exchange-traded fund (‘ETF’) in America (typically, ETFs are companies which use pooled investor money – similar in concept to a mutual fund – to invest in stocks, bonds and other assets). The USO ETF is designed specifically to follow price movements of WTI futures and, if futures are within two weeks of expiration, it will roll over the front month contracts to the second front contracts (this means that, when futures approach the expiration date they will be sold and the next month’s contracts purchased, usually simultaneously, thereby avoiding taking delivery). The USO is not a direct bet on oil prices and it incurs costs when it rolls its futures over. Not many of its new investors were aware of any of this.
The massive increase in investment quickly made the USO ETF one of the biggest players in the WTI market: according to a Bloomberg report, over the course of the last few months it held almost 30% of all WTI May and June futures. With such a huge and sudden injection of cash for the May futures (amidst the events which led to a crash in demand for oil) their prices swiftly rose; but then the USO sold all their May futures during their mandated rollover, buying June and July ones instead. When that happened, prices for the May futures dropped and, accordingly, they rose for June and July. Any traders left still holding May contracts suddenly found themselves in a state of trouble (see above) and when the market opened there was a huge differential in spread.
As an interesting side note, one of the companies that suffered unexpectedly from the USO’s actions was the Bank of China, which had pre-set the date to roll over its May WTI futures as the day before expiration (unlike other Chinese banks which had rolled over earlier in April). Specifically it was scheduled for Monday 20 April at 10:00 (ET), which was when the May futures were still trading at US$0, but the lack of demand (and thus liquidity) meant they took losses anyway. It’s unclear how many May futures they had to sell, but they suspended trading the next day and there was a flurry of angry investors on various Chinese social media platforms claiming that as a result of the day’s events they owed the Bank of China money (despite investors being forbidden from borrowing money to buy Bank of China funds). Additionally, Bloomberg reported the Bank’s oil related funds suffered losses of 600 million yuan.
WAS THIS A ONE OFF?
To a certain extent WTI prices dropping to such unprecedented levels was the consequence of a perfect storm of unfortunate events and it is therefore not unreasonable to conclude what happened was a localised, one-off incident. Having said that, until (at the very least) the storage issue is resolved we’re likely to continue seeing massive fluctuations in price. Case in point: S&P Global has instructed its clients to roll over all their WTI June futures into July to avoid What they believe will be a second plunge below zero for this front month. In doing so, June futures have now suffered a drop in prices and at the time of writing, almost 50% of them have been liquidated. July and September prices are more stable, but they will almost certainly fall into the same pattern until the global economy starts moving again, or at least until storage space is opened and the planned international production cuts reduce global supply to meet demand.
One recent idea to help alleviate the US glut – at least from a national perspective – was for the American government to purchase a large amount of the excess oil. It would do so via the Strategic Petroleum Reserve (‘SPR’), which is an inland oil reserve holding the largest supply of petroleum on the planet. The oil is owned and stored by the US government specifically with the aim of reducing disruptions in American supplies (the idea was conceived in the 1970s when the US suffered from an oil embargo resulting from difficulties in US-Arab relations). As and when it is deemed necessary by the President, the stored oil is released at a competitive rate, to avert potential short term crises (petroleum has been released, successfully fulfilling the SPR’s purpose, on a number of occasions in recent history).
The SPR currently has almost 80 million barrels’ worth of spare storage, and considering all oil purchased for the SPR is paid for with taxpayer’s money, it seemed economical to take advantage of the rock bottom prices. The Trump administration instructed the Department of Energy to start purchasing the oil in March 2020, but was made impossible when Congress refused to include funds for them to do so when they passed their most recent stimulus package (with federal funds channelled to areas of higher priority, given the effects of Covid-19 and the resulting shutdown).
Instead the government has decided to lease 23 million barrels’ worth of space to private oil companies. This will certainly help but the other factors remain unresolved, which means this might not be a one-off, but it’s hoped the lesson of what happened with the May futures will at least mitigate some of the volatility.
COULD THIS HAPPEN TO BRENT?
The fact that this happened to the American WTI benchmark, which has arguably less global influence than Brent does, and that the situation was exacerbated by the uniquely acute inland storage issue there, would suggest that this is a concern for the United States only. Brent, however, has already been affected by the fallout from the Covid-19 crisis, but the good news is it’s unlikely its prices will fall to the same extent that they have for WTI.
First, Brent futures are somewhat different in that they’re for cash, not physical, settlement, unlike WTI (physical settlement requires physical delivery of the crude once the futures expires, but with a financial settlement contract, the holder is merely either credited/debited the difference between their entry price and the final settlement). Secondly, Brent is a waterborne crude, with its pricing being based heavily on the Dated Brent index, which in turn bases its prices on crude from terminals at various coasts along the North Sea.
Using the North Sea as the primary location for which to base prices has its advantages: production there has been seeing a slow decline over the past few years (although prior to the pandemic, one of the terminals withdrew its plans to shut down for maintenance, which would actually push the North Sea supply to some of its highest levels in nearly a decade). Additionally, the North Sea terminals, unlike those in landlocked Cushing, have the infrastructure to allow for tankers to take delivery of the crude oil (i.e. they can take it away). As a result, Brent hasn’t suffered from the same storage-induced panic felt by the WTI traders in April – although that doesn’t mean it hasn’t suffered at all, there is still a global glut and therefore a storage issue that isn’t likely to improve until the agreed OPEC+ and US production cuts kick in, and even then the effects won’t be felt immediately. In the meantime, there are global reports that oil is being stored in every conceivable space, from the more conventional salt mines and caverns, to disused railcars.
Storage space if filling up fast, everywhere, the North Sea terminals have nowhere near the capacity that Cushing does and things might also be made worse if there were to be a sudden influx of cheaper, American produced ‘Brent-style’ crude flooding into Europe (indeed, why wouldn’t American companies sell to Europe and alleviate their storage issue? And being cheaper than Brent is currently, why would European companies choose not buy it?)
Of course, tanker owners have benefitted from this: the cost of chartering a VLCC has temporarily skyrocketed, with some shipowners set to experience their best quarters in history (which is welcome relief after the Covid-19 shutdown and the ensuing drop in demand for oil caused a massive slump in freight rates). How have companies been able to pay for this? The contango market has meant that oil prices have fallen faster on the spot market than the futures market (see above), in doing so, traders have been able to finance their storage by buying oil on the cheap in the spot market and then make a profit on it by selling it for higher prices in the futures market (for back month contracts).
Things, however, do seem to be looking up for Brent: in the past week prices have begun to rebound as global lockdowns and travel bans have slowly eased, but the fact still remains that the OPEC+ and US deal came too late. The lowest dip in the world’s demand for oil might be behind us, but the surplus is already out there and until the market can find that balance between supply and demand again, prices aren’t going to get much higher. The only saving grace producers – especially smaller and medium sized companies – will have, is to obtain a solid offtake agreement with a company that has a strong credit rating and a sure way of disposing of the oil… good luck getting one of those in this economy.
The 1971 IOPC Fund ceased to exist on 31 December 2014. The 1992 IOPC Fund, however, is still going strong. This fact was not lost on the Venezuelan fishermen’s union who lodged a claim in Venezuela in respect of damage sustained as a result of an oil spill in May 1997 from the tanker Plate Princess. In 2009 they obtained a judgment against the shipowner and also against ‘The International Fund for Compensation for Oil Pollution Damage’. In March 2015 Master Eastman made a Registration Order in respect of that judgment.
In Sindicato Unico de Pescadores del Municipio Miranda del Estado Zulia v. IOPC  EWHC 2476 (QB);  1 Lloyd’s Rep Plus 2, Picken J has set aside the Registration Order. The 1992 Fund was not involved in an incident which occurred at a time when Venezuela, although a signatory to the 1992 Protocol, had yet to ratify, accept, approve or accede to it. The Venezuelan judgment could not be regarded as applying to the 1971 Fund Convention as amended by the 1992 Protocol. Even if the judgment had been against the 1992 Fund, there was no relevant exception to the 1992 Fund’s immunity under art. 5(1) of the International Oil Pollution Compensation Fund 1992 (Immunities and Privileges) Order 1996. The only possible exception, in art. 5(1)(b) “in respect of actions brought against the 1992 Fund in accordance with the provisions of the  Convention” would not apply.