Changing oil landscape could be a boon for crude carriers and complex refiners

Disclosures and statements: I am long Teekay Tankers, Euronav, DHT, PBF Energy, and a basket of other crude shipping stocks. This article represents my opinions about the market and is not investment advice. If you notice any factual issues, please write me: calvinfroedge@gmail.com or message me on Twitter @calvinfroedge

Perhaps you’ve heard of the new #IMO2020 regulations which went into effect on January 1st. These regulations limit the sulphur content of “bunker fuel,” which is what, until December 31st 2019, most ships on the planet burned for propulsion. Most of this fuel was produced as a byproduct of refiners processing medium and heavy sulphurous crudes. Roughly 6.5m barrels per day of heavy residuals were produced, and the marine market used 3.5–4m barrels of it. The only way that ships can still use the old fuel as of January 1 is to either have a scrubber, a device that removes the sulphur, or to simply not comply. Non compliance will likely only be an issue among smaller ships in “backwater” locations, as the ramifications of a large operator such as Maersk not complying could be very costly. Singapore has stated 2 years of jail time for non compliance, and the US is offering whistle blowers 50% of multimillion dollar fines.

As of now, it is projected that around 12% of global tonnage has installed scrubbers, and by the end of the year, 20% of global tonnage. If we assume a non-compliance rate of 15% and an average scrubber penetration of 15% in 2020, then we can assume that 1–1.2m barrels per day will still be used by the marine industry. This means demand has dropped off the cliff for HSFO.

This presents a big problem for many refiners: A product which could previously be sold at a premium to crude has increasingly negative margins. Meanwhile, residuals produced from sweet crude (crude that has less than 0.5% sulphur content) are pricing near an all time high, at a staggering $35 premium to Brent. To illustrate just how nuts the change in dynamics are, consider that just yesterday a barrel of heavy, sweet Australian crude sold for a staggering $35 premium to Brent.

How is this possible? How could a barrel of crude sell for such a premium over Brent? The answer is no one is buying that crude to make diesel and gasoline. They are buying it to provide compliant marine fuel. Pyrenees just happens to be a crude grade that is safe to run through ship engines with very little processing. Don’t believe me? Offer an alternative explanation. Why else would someone pay just under the Singapore spread of VLSFO to Brent, more than $20 above the value of a barrel of gasoline?

Heavy and medium sweet crudes are not very common. Refineries historically invested in processing medium sour and heavy sour crude grades, which had a high sulphur residual field yield that was then burned as bunker fuel. In a post IMO2020 world, bunker fuel must have a low sulphur level. So, simple refineries want crude that matches their previous feedstock but has a lower sulphur residual yield. For refiners with a high sulphur residual yield, the biggest question is what will be done with it.

This is a continuation of a trend that Argus media discussed back in September:

What will they do with all the HSFO?

For years, complex refiners in places like the United States, Europe and Korea invested in desulphurization technologies to get rid of sulphur, as regulations for diesel standards limited sulphur content. Only the maritime industry worldwide, and diesel engines in developing countries continued to burn higher sulphur fuels. Refiners in places like Russia, Southeast Asia, and Latin America did not. What this means is that the refineries that can deal with high sulphur feedstocks are in different places. As long as HSFO trades at a large discount to Brent, incentives encourage complex refineries like PBF Energy to buy HSFO rather than crude oil, as it improves their margins. This effectively means seaborne heavy sulphur oil gets shipped twice. First, the simple refinery in the developing country would buy raw crude to meet their domestic fuel needs, and then the waste product, which was previously used up by the marine industry, would need to be shipped to someone who wants it. However, there is limited refinery capacity for coking. There are a few million barrels of coking capacity in the US, but much of this is already in use by US refineries to remove sulphur from their existing feedstocks. PBF Energy recently restarted their idled Chalmette coker in order to take advantage of some of this cheap feedstock.

In the meantime, whether cheap HSFO is purchased by traders wanting to arbitrage price differentials, or it is stored by refineries until they find a buyer, HSFO will need to be stored somewhere.

This issue was breached by a well known energy analyst in June 2019:

“It [residual fuel oil] will have to go somewhere and the price is going to provide an incentive for vessel owners and refiners to do something about it…The problem is that they will not do enough about it by January 1, 2020…First it will fill the onshore storage facilities — there are probably enough onshore tanks for the first six months. Then it will have to go into floating storage on tankers,”

Andrew Lipow, Lipow Oil Associates

The incremental demand for floating storage under such a scenario would be astronomical, as even just ~1M barrels of excess HSFO production per day would require ten Aframax tankers (a type of crude tanker which can operate in many environments and waterways) per week to handle.

Many refiners do not currently care about marine fuel demand, and have been more interested in the margin benefits that will come from being able to run HSFO feedstock as well as purchase high sulphur crudes at a discount. However, with such large spreads between LSFO and HSFO, this could well be something refiners respond to, especially if cracks are pinched in other areas of the business.

Some have suggested that excess HSFO will be burned for power or used for asphalt production. A recent Bloomberg piece estimated that at current prices, around 1M additional barrels could be absorbed by the power generation sector. Even if this is true, additional capacity will need to be added to burn this fuel directly, which would take both capex and time.

Energy industry participants I have talked to about this thus far are skeptical. Many developed countries have already severely limited using oil for power generation, and the price of HSFO would need to be competitive with the price of coal to be burned in developing countries with coal capacity.

HSFO can actually be used as a direct coal substitute, but only after it has been further processed by a complex refinery into a coal-like cake, also known as coke. The asphalt industry does use some HSFO, but yields are much higher starting with heavier crudes (such as WCS, a Canadian tar sands grade) than dealing with HSFO, and large players, especially inland players who receive tar sands oil via pipelines, will not want to reconfigure their supply chain to take advantage of what may be a temporary dislocation.

No matter which way you look at it, HSFO will need to be stored and moved, and not simply to a bunker location (the place where ships get fuel) as before, but to a second ship or facility, to either be kept until it has found a use or to be processed by someone who can. This suggests a very bright future for those who carry crude oil, especially those who operate Aframax class tankers (such as Teekay Tankers and Tsakos Energy Navigation). The right way to look at it, in my opinion, is that this incremental increase in HSFO movement is effectively new demand for crude oil tankers.

Back to VLSFO

Now, consider what I said earlier about the Pyrenees barrel selling for just shy of $100. In a well supplied market, this would never happen. The spread between tar sands oil (WTC) and Pyrenees is close to the price of a barrel of Brent. In a post IMO2020 world, crude quality matters more than ever before.

Marine fuel demand will not change significantly. We will still need to supply roughly the same amount of fuel as before to the maritime industry. If the demand is 3.5–4m barrels per day, and roughly 1m barrels of demand can still be satisfied by HSFO, that implies that 2.5–3m barrels per day of VLSFO and MGO (another compliant marine fuel, similar to diesel) will need to be produced in order to keep up with demand.

There are two ways to produce compliant fuel. The first is to start with a heavy sweet crude and produce a residual fuel. In order to be useful as marine fuel, the fuel must fit a specification similar to old bunker fuel standards, but just with less sulphur. This is known as “straight run” fuel.

The second option is to produce a blend or distillate based fuel. A blend is produced by taking the heavy residual fuel and mixing it with distillates in order to reduce the sulphur content. For the blend to perform well in ship engines, it needs to fit a specification that ship owners are comfortable with. Fitting a profile is important as it influences what lubricants are used and how the engine must be maintained. If the fuel is “off spec”, it means that some issue with the fuel, such as containing too much sediment, or being too viscous, or not viscous enough, or not having the correct “flash point”, could mean engine damage or even a disastrous engine halt, which means a ship “stuck” at sea. One US traded ship owner recently commented that they are loading multiple fuels into different tanks because they are worried they won’t make it to the next port, while multiple fuel and shipping agencies have published reports, and even red alerts, warning owners about the risks of running “off spec” fuels.

Straight run fuel is the preferred option for ship owners. However, it requires heavy, sweet crude grades that are similar to the old bunker fuel grades, just with lower sulphur content. The problem is that there is a limited supply of these crudes, and that’s why we’re seeing such massive differentials in the market.

All of this has several possible implications:

  1. Crude flows change to accommodate greater demand for heavy, sweet crudes. These crudes are found in places like South America, Australia, and West Africa. Production of Pyrenees from Australia is a mere 15k barrels per day. Generally, these crudes are much farther from the customers who want them (simple refineries), resulting in additional demand for companies who move crude oil.
  2. Off spec blends need to go to a refinery to get re-refined. This results in additional storage, movement, and re-work, as well as delays. The tankers must do the work to facilitate this, resulting in higher demand for them while the market figures out how to do blending correctly.
  3. Blending requires part high sulphur residual fuel and part distillate fuel. In a 3.5% residual (what most refiners have been producing up till now), the blending ratio would be approximately 1:5. This means to yield six barrels of LSFO you’d need to blend 1 barrel of HSFO and 5 barrels of distillate. More blending could result in a large incremental jump in global gasoline and/or diesel demand, increasing crude as well as refined product movement.

In all of the scenarios above, dirty crude tanker demand increases. The earnings of companies like DHT, International Seaways, Diamond S Shipping, and Euronav increase. In a scenario where more blending occurs, it’s beneficial to companies like Scorpio Tankers and Ardmore Shipping, as they are clean tankers moving distillates.

IMO2020 Switch Complications

So far, we’ve seen issues such as lack of fuel barges (there is more demand for storing fuel and refueling ships with more fuel grades added, but barge fleet has not grown). This has resulted in interesting trades, especially in the flexible Aframax sector, where ships have been used as an alternative to fuel barges.

We have also seen reports of VLSFO blend issues and long fuel lines, fuel discharges, and in some cases, engine issues. We are still in the early days of the IMO2020 switch, and it is speculated by many industry participants that such logistical issues could persist well into the year. For instance, I was sent the following document (authenticity unconfirmed) from an Asian ship broker:

This matches other alerts put out by groups like FOBAS warning of things like dangerous sediment levels and off spec blends.

Increased tanker demand is about more than just sanctions and seasonality

As IMO2020 has played out, we have seen tanker earnings increase dramatically across all vessel classes. VLCC operators have currently averaged ~130k/day in 2020, an astronomical figure representing free cash flow yields in the double or triple digits depending on vessel age.

Source: Poten Partners
Source: Galbraiths

Some Aframax operators are earning as much as 275k per day with their ships for “lightering” jobs, and 140k for longer jobs (such as in the Gulf of Mexico and the Black Sea / Mediterranean). In the case of such companies, their boats are earning more in a day than they earn in a typical month.

Source: Riverlake

These are historic cash flow levels that are now “locked in” for the Q4 and Q1 periods, and will likely stay stronger than normal throughout the year and into the future. Q4 was guided in Q3 reports at levels not seen in many years. Many tanker companies will report their best earnings in Q4 and Q1 in more than a decade.

Forward yields are currently being projected by analysts at rates in excess of 20%, with forward NAVs and FCF valuations at very low levels. Despite a large run up in tanker shares over the past 4 months, I believe we’re just at the beginning, as the first of these firms, Euronav, reports Q4 earnings at the end of this month. Some analysts are expecting FCF in excess of 1 billion dollars for Euronav in 2020, a stock with a market cap of ~2.6B today.

Some market participants have suggested this earnings improvement is a temporary spike due to ships being taken out of the market due to sanctions, as well as tensions in the Middle East. It is true that sanctions and Middle East tensions helped tanker earnings. As many as 70 VLCCs were taken out of the market in 2019 due to sanctions, and remain out of the market. Another 44 VLCCs were used for floating storage of compliant fuel in Singapore alone, and approximately half of those continue to store fuel in the Strait of Malaca. I contend many vessels previously storing VLSFO will in the future store HSFO, especially older ships, which will take older vessels out of the market. Though 73 ships were delivered in 2019, the forward supply picture in tankers is the best in decades, with many older ships facing special surveys and losing their employment prospects. If earnings drop, older ships will be taken out of the trading fleet and either used for storage or scrapped.

Most of the sanctioned ships were due to tensions with Iran, which are not likely to come of soon. In fact, just today, the US put sanctions on practically every part of Iran’s economy, and noted that sanctions are not going away soon.

The market anticipated increased demand due to IMO2020 and this is part of why many ships were delivered in 2019. The market did not anticipate sanctions or war, and it certainly did not anticipate a Brent sized spread between VLSFO and HSFO. The underlying fuel economics are telling us that there is far more HSFO than needed, and not enough VLSFO. The supply picture is telling us no new ships can enter the trading fleet until 2022, as a crude tanker takes around two years to deliver.

I’m very long.

“Frontline’s VLCCs make it a ‘Very Large Cash Company’ ”

— Clarksons Platou

***

“Depending on the strength of the crude tanker market in subsequent quarters, total dividend payments in 2020 should exceed $2 per share”

— Amit Mehrotra at Deutsche Bank, Discussing Euronav

***

“We started the New Year and the new quarter with booking one of our 23 Suezmax tankers for a Time Charter Equivalent (TCE) in excess of $100,000/day. Although this type of rates cannot be expected for all our vessels in all areas, it is another confirmation of the strength of the market. Our operating costs are $8,000/day for each vessel.”

— Herbjorn Hansson, Nordic American Tankers

Software developer, investor, energy markets analyst.

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