The price of Brent crude increased in the first half of January, rising from a low of $51 at the start of the month to reach a high of $56 on 12th January, as supply constraints came into focus. Oil prices then remained rangebound in the second half of the month, with the price of Brent holding at around $55 as the near-term demand outlook came under pressure.

Oil prices rose to an 11-month high in early January, following Saudi Arabia’s announcement of a unilateral cut of 1 million b/d to crude production in February and March, draws to US crude stockpiles and a weaker US dollar. However, gains were capped by concerns over near-term oil demand amid lockdowns and the emergence of virus mutations that could prompt tighter mobility restrictions. Restrictions were expanded or extended in the US and Europe amid rising COVID-19 cases and hospitalizations. Meanwhile, the UK and South Africa imposed strict lockdowns to combat new highly transmissible virus variants. Restrictions were also introduced or extended in Asia, the region which has led the global oil demand recovery. In the second half of the month oil prices found some support from a proposed $1.9 trillion US stimulus package announced before the 20th January inauguration of US President Biden, and as US crude stockpiles plunged 9.9 million bbls in the week to 22nd January to reach their lowest level since March 2020 .

Saudi Arabia commits to extra supply cut

On 5th January, Saudi Arabia unexpectedly committed to a unilateral cut of 1 million b/d to crude production in February and March, helping to offset worries that rising COVID-19 cases globally and new variants would curtail fuel demand. This is in addition to its existing January quota and gives the Kingdom a target crude supply of 8.12 million b/d for February and March. Meanwhile, most other OPEC+ producers agreed to hold production steady over February and March in the face of new coronavirus restrictions, although Russia and Kazakhstan are allowed to raise output by a combined 75,000 b/d in February and a further 75,000 b/d in March. Higher quotas for Russia and Kazakhstan came as cuts to operations of their mature wells and fields would create lasting damage to production capacity. Overall, this means OPEC+ production cuts are set at 8.13 million b/d for February and 8.05 million b/d for March, instead of the January level of 7.2 million b/d. The group will reconvene in early March to discuss April output.

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Last year was tough and the spread of Covid-19 has had a massive impact on all industries, including shipping. As we are seeing the light at the end of the pandemic tunnel with the vaccination programmes being rolled out, the focus is shifting towards what happens next. Clean energy and decarbonisation are again in the headlines with the governments increasing spending, announcing new projects and bringing ambitious environmental targets forward. This poses a number of questions for shipping – what technology to use and what fuel to burn as well as in what shape and form energy will be shipped in what looks like the not so distant future.

Cleaning up shipping

Despite not being the fastest industry to transform and adapt, a major change happened in shipping just over a year ago. The IMO2020 legislation introduced a much lower limit on the amount of sulphur in the bunker fuel that ships can burn. While there are plans to reduce NOx emissions that ships produce, shipping is now facing an ever-increasing pressure to contribute to the global push for decarbonisation.

While the car industry is already embracing the new technology, in the form of electric vehicles powered by batteries and increasingly looking into fuel cells, shipping remains in limbo and has not “decided” on the technology that will take it forward. The main question is what type of technology will be able to fit into the limited space on a ship, provide for a good range and not impair a ship’s carrying capacity. While traditional power plants can be replaced with hectares of solar panels or wind farms to generate the equivalent energy, this cannot be achieved on a vessel. Below is an overview of the potential solutions for shipping and how they may transform bunkering.

Carbon footprint offset / carbon capture and storage

Offsetting emissions or using carbon capture would mean that shipping may continue using the current fuels (with further abatement technology but with the ever growing pressure to change) or transition to the next generation of fuels, which could have lower SOx, NOx, and CO2 emissions. These fuels could be LNG (10-20% less carbon emissions), which is already gradually taking off and methanol. Both have lower energy density than conventional fuels and require certain handling conditions.

Offsetting carbon emissions could potentially be done by either buying carbon credits from other businesses, using alternative “green” investments such as carbon capture or by planting trees although calculations suggest that offsetting a single voyage requires planting and growing hundreds of thousands of trees.

Carbon capture and storage (CCS) is a solution similar to planting trees, although the emitted carbon will not be captured by the trees but rather by the CCS facilities. There are a number of projects being developed whereby salt caverns and decommissioned oil and gas fields will be used to store carbon dioxide.

If this is the preferred way going forward, then bunkering is unlikely to change dramatically. Bunker fuel will still likely be delivered by a tanker barge, truck or pipeline.

Ammonia

Ammonia is a gas that could be a good solution as it doesn’t produce any carbon when burnt. While currently most of ammonia is produced using hydrogen from natural gas, ammonia projects using “green” hydrogen obtained by electrolysis also exist meaning the entire chain could potentially be carbon neutral. Ammonia has lower energy density, so it requires either more frequent refuelling or more storage capacity on board compared to fuel oil. It also needs certain storage conditions and generally is not pleasant to handle due to its pungent smell.

Bunkering ammonia would not look very different from taking on LNG as it is typically carried by LPG/ammonia tankers.

Batteries

This is already a viable option for road vehicles, and we are seeing faster than expected uptake. While batteries may be a viable option for short-haul shipping, including ferries and small craft, this technology is unlikely to be able to produce enough energy to power a seagoing vessel in the near future. There is hope that solid state batteries may change this situation at some point in a more distant future.

A pioneering electric ferry

Should battery technology develop to allow them to be installed on seagoing vessels, bunkering may look very different to what it looks now. Ship’s batteries could be recharged by a floating charging barge or at the jetty or potentially swapped to allow a quicker turnaround.

Fuel Cells

Fuel cells were invented almost 2 centuries ago, although until now their application has been mostly limited to power generation, space and military. However, they are increasingly being used in the automotive industry and several JVs have been concluded to extend its application to marine technology.

Fuel cells can reach 80-90% efficiency, although most currently rely on hydrogen storage and supply. Storing hydrogen can be tricky as it is prone to leakages and is very explosive. Fuel cells can also be developed to use LNG, methanol, ammonia and other fuels as the source of hydrogen. To achieve the maximum reduction in carbon dioxide emissions all these fuels will also have to come from “green” sources.

The diagram of a fuel cell

A ship equipped with fuel cells in the future will likely be supplied by a tanker carrying hydrogen, LNG, ammonia, methanol or other fuels or from the jetty.

Nuclear

Fitting ships with nuclear reactors can, with correct maintenance and servicing, deliver enormous amounts of power and provide an almost limitless range. This technology has primarily been used by the military, although a small number of nuclear-powered merchant vessels have also been built. Concerns about safety and the long-term cost of deactivating and storing spent nuclear fuel have outweighed the benefits.

Russian nuclear ice-breaker

Nuclear powered ships do not need to “bunker” frequently, however they also require the offloading of used nuclear fuel for recycling. Had ships made a switch to nuclear power, the bunkering industry would likely not exist in the current form. It is possible that only a handful of suppliers would be allowed to operate in the market, either run by or under a very tight supervision from the international agencies.

Energy transportation by sea may not be the same

Decarbonisation will not only affect the type of fuel ships use but also how energy is moved around the globe.

As the share of wind and solar energy generation continues to increase, it increases the need for storing excessive energy. Batteries are one way to do it. Another way is to convert the electric energy into fuels, for example by separating hydrogen from water using electrolysis or going even further by reacting hydrogen with nitrogen (from the atmosphere) to produce ammonia. Hydrogen and ammonia can then be loaded and transported by gas carries.

Out of the other two fuels mentioned in the article, LNG will continue to be transported by gas (LNG) carriers, and only methanol is transported in the liquid form and will require tankers. Should batteries dominate, it will likely require specialist carriers or be transported as a container good.

It goes without saying that new technologies and fuels, besides having technical feasibility, also need to make sense economically. There is no doubt that governments will increasingly support the green fuels initiatives, introduce legislation, provide subsidies and the current capital inflows will help make these technologies cheaper and ready for mass implementation.

This is a time of a great change, but also great opportunity. The change in the energy landscape will no doubt transform shipping and bunkering, and we may have no other choice but to embrace this transformation and be part of it.

Anton Shamray Senior Analyst P: +44 207 4675 856
E: Anton.S@navig8group.com

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Brent crude prices rose to their highest level since March in November, hitting a high of $48 on 25th November.

Oil prices trended upwards over the course of the month from a low of $39 at the start of November. The price of Brent crude closed out the month at $47.Oil prices were supported at the start of November by talk of a possible extension of OPEC+ output curbs beyond January 2021 and a steep 8 million bbls w-o-w fall in US crude stockpiles. However, uncertainty surrounding the outcome of the 3rd November US election, surging cases of coronavirus and the re-introduction of lockdown measures in Europe kept prices under pressure. Oil prices then jumped after drugmakers Pfizer and BioNTech initially said an experimental COVID-19 treatment was more than 90% effective, offsetting pressure from increasing Libyan supply. Oil prices continued to rally from mid-November, as Moderna said its experimental mRNA COVID-19 vaccine was 94.5% effective in preventing infection and AstraZeneca later said its vaccine was 62% effective under two full dosing regimens. Oil prices found further support in late November as the market eyed a US presidential transition to Joe Biden and on speculation of a three-month extension to OPEC+ supply cuts, ahead of a scheduled full OPEC+ meeting on 1st December. However, OPEC+ postponed talks until 3rd December as key players still disagreed on output policy for 2021.

On December 3rd, OPEC and non-OPEC allies including Russia agreed to increase collective crude production by 500,000 b/d in January, but failed to come to a compromise on a broader policy for the rest of next year. Subsequent output adjustments will be decided at monthly ministerial meetings, with any further increases in output beyond January capped at 500,000 b/d each month, whilst production cuts are also possible.

Meanwhile, ministers agreed that a compensation mechanism, which requires production beyond quotas to be compensated for by additional cuts, will continue until the end of March 2021, allowing full compensation of overproduction from participating countries. Russia has cumulative overproduction of 530,000 b/d, which needs to be cut for one month to catch up with its targets, whilst Iraq has cumulative overproduction of 610,000 b/d.

Although short of a widely expected extension of existing cuts until at least March 2021, oil prices found support from this compromise to continue some cuts to production. After the OPEC+ decision, Brent crude extended gains to reach $49 during intra-day trading on 4th December.

Data on the efficacy of three COVID-19 vaccines was released in November, with vaccines ready to be submitted for regulatory approval, supporting hopes of a swifter recovery in the global economy and oil demand.

The first announcement by Pfizer and BioNTech on 9th November initially showed a 90% success rate. On 16th November, Moderna said its experimental mRNA vaccine was 94.5% effective and remains stable under standard refrigeration for 30 days. Both vaccines were shown to work equally well across age groups, ethnicities and genders.

On 23rd November, AstraZeneca said its vaccine was 62% effective under two full doses and can be stored under standard refrigeration for at least six months. Concerns were later raised about the robustness of results for a sub-group of trial participants under 55 years old who received a half-dose regimen with 90% efficacy. However, efficacy of 62% for two full doses is well above the 50% efficacy required by US regulators, whilst Europe’s drug regulator has said it will not set a minimum efficacy level for potential vaccines. US healthcare workers recommended that the first COVID-19 inoculations could start within days of regulatory consent in December.

The latest OECD projection sees global GDP returning to pre-pandemic levels by end 2021, aided by vaccine rollouts and accommodative fiscal monetary policies.

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VLSFO prices have risen by $75/ton in just 30 days; the previous talk about a Covid-19 vaccine and a corresponding sharp rise in oil prices has now become a reality. In the past few weeks, we have had the very big news of 3 successful Covid-19 vaccine trials, with the corresponding jump in prices. There has been further price support with positive comments on the OPEC+ group extending their current cutbacks into 2021, and this has now finally been agreed with only a 0.5 million b/d increase in January (the original plan was to raise production quotas by 2 million b/d from January 2021).

The net result is that in past 30 days we have moved from a bearish position, when a second Covid wave was dominating the news, to now, where the ‘imminent’ implementation of vaccine programs is seen as the path to significant gains in oil demand.  This has seen VLSFO prices hit levels not seen since in early March, and in Singapore rise from $305/ton to around $380/ton (up 25%) in this very short period.

At the same time forward curves have jumped higher, although they remain extremely flat through the next 18 months.  The Singapore VLSFO curve at the start of November was a clear reflection of the near-term bearish concerns from the second covid-19 wave, showing a drop in December and only a gradual uplift through the outlook period.  The recent news on vaccines had an immediate bullish impact on prices and now for the earlier part of next year, the VLSFO forward curve in Singapore is almost $60/ton higher than it was four weeks ago.  Even looking as far out as 2022, the curve is still more than $40/ton above what it was showing at the start of November.

Another aspect to the price rise has been a widening in the VLSFO/HSFO spread.  Differentials tend to widen as prices rise (and narrow as prices fall), and this has happened with this latest price increase.  Although the differential between the two bunker grades is still very narrow by historical standards, the VLSFO/HSFO spread in Singapore is now around $70/ton compared with only $53/ton at the start of November.

General developments in the oil markets would indicate a further widening in this spread, based on the relative weakening of HSFO prices and relative strengthening of VLSFO as:

• Demand for fuel oil into the power-generation sector eases; Saudi Arabian demand is down after the summer peak aircon demand and Pakistan has decided not to go ahead with a 500,000 ton HSFO tender for December delivery, although LSFO demand in South Korea is up in December by around 100,000 tons as utilities move to replace coal-fired capacity that has been shut-in because of winter air-pollution issues.
• and at the same time, relative VLSFO prices strengthen with improving margins for gasoil, gasoline and jet fuel margins as product demand in Asia rises (and product supply in Europe is reduced because of cuts in refinery runs).

Any further increases in oil prices are likely to add to these general widening pressures on the VLSFO/HSFO spread, lending further support to scrubber economics.

We have always referred to the underlying movements in bunker prices being led by crude oil, and of course it is the same this time around.  VLSFO has largely tracked changes in the hugely traded Brent and WTI crude futures markets, and will continue to respond to the current big stories of vaccines, the prospects for oil demand and OPEC+ outcomes.

Steve Christy Strategic Communications Director P: +44 207 4675 860
E: SteveChristy@navig8group.com

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This time a year ago the market was talking about the upcoming IMO2020 sulphur regulations change. The operators of the non-scrubber tonnage were in the process of putting together the switch-over plans from HSFO to VLSFO and starting to purchase the compliant fuel, while bunker fuel producers worked tirelessly on the different recipes for the VLSFO blends.

In October 2019, Integr8 Fuels started collecting VLSFO sample test data and one year later managed to accumulate over 75,000 test results. Marking the anniversary, this article looks at the key fuel quality developments comparing VLSFO and HSFO. Despite the drop in the HSFO demand and testing, over 15,000 HSFO test results formed part of this analysis.

The data shows that in the past year the share of HSFO off-specs increased, overtaking VLSFO, which in turn saw a decrease. The severity of VLSFO off-specs also decreased, while increasing for HSFO. Out of the four bunker hubs analysed, currently ARA has the highest probability of VLSFO and HSFO off-specs.

VLSFO: fewer off-specs than HSFO

Prior to the IMO2020 switch, it was widely expected that VLSFO would turn out to be more problematic than HSFO and this was indeed the case early in the transition. Given that VLSFO producers had to hone their blending recipes, the share of VLSFO off-specs stood at 5.1% on average between November 2019 and January 2020, almost double the HSFO share (Figure 1).

As the year went by and producers gained more experience with VLSFO, the reduction in the share of off-specs followed. On the other hand, and quite unexpectedly, the share of HSFO off-specs steadily increased, currently standing higher than VLSFO.

This development shows that while previously HSFO was considered an “easier” fuel to buy compared with VLSFO, this is no longer the case. The bunker buyer is encouraged to exercise the same due diligence when buying HSFO given the increase in the share of off-specs.

Off-spec severity lower in VLSFO, higher in HSFO

Fuel quality data shows that it is not only the share of VLSFO off-specs that decreased but also the severity.

Figure 2 breaks down the off-specs by parameter, which for simplicity have been put into four groups. The ‘Other’ group contains the parameters that cause less severe quality issues if found to be off-spec comprising of ash, water, sodium and others.

In VLSFO there has been a steady reduction in the prevalence of sulphur and TSP (a measure of fuel stability) off-specs, which are critical quality parameters, while the occurrence of off-specs in the ‘Other’ group has increased with sodium in particular causing some issues in a number of ports in Asia.

HSFO shows a very different trend. Both sulphur and TSP off-specs are on the rise, mostly driven by TSP. This may potentially indicate a change in the composition of HSFO, whereby the formulations are becoming more “complex”.

While the above changes are good news for the VLSFO users, HSFO buyers should be aware of the rising TSP off-specs.

Watch out for VLSFO and HSFO quality issues in ARA

Looking at the global quality averages can help understand the general direction, although when it comes to bunkering vessels, individual ports, which collectively make up the global trend, should also be looked into. Figure 3 shows the breakdown of VLSFO and HSFO off-specs in four key global bunkering hubs.

The share of VLSFO off-specs in ARA, despite a drop in August – October, remains much higher than in the other ports and above the global average. The picture is similar for HSFO, with the share of ARA off-specs rising to the highest in August – October, while Panama and Fujairah seem to have dealt with the past quality issues. Singapore on the contrary remains one of the best ports for HSFO quality where less than 1 in 100 HSFO stems are tested off-spec, compared with almost 8 in 100 in ARA.

Looking at the severity of VLSFO off-specs in ARA, it is a mixture of sulphur and TSP issues, despite the reduction of these in the global trend. On the other hand, the HSFO issues here are mostly related to density (also with a sharp increase in St. Petersburg) and viscosity, which are less critical and can often be handled well on board the vessel.

Overall, it has been an interesting year when it comes to bunker fuel quality and despite the initial concerns the IMO2020 transition generally went well. However, monitoring fuel quality data remains important and Integr8 Fuels will continue highlighting any significant fuel quality trends going forward.

Anton Shamray Senior Research Analyst P: +44 207 4675 856
E: Anton.S@integr8fuels.com

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Well it’s that time of the year again, the overcoats are being thrown on in the Northern Hemisphere and the clocks have changed and in the world of Bunkering this means only one thing, it’s time to consider Cold Flow properties again.

Why is this so concerning? Winter comes once a year and Cold Flow is nothing new, but the idiosyncrasies of the Bunker Industry allow fuel blenders to thrive within the ‘grey areas’ with regard quality.

Which other industry allows fuels to be sold on multiple and sometimes obsolete International standards or even local specifications?. Indeed 16 years since the 2005 specification was released we still see this being sold, despite 2010, 2012 and the latest 2017 versions being published.

Worryingly, even the latest 2017 specification does not provide adequate protection for cold flow properties with only the winter specification requiring the seller to report Cloud and Cold Filter Plugging Point rather than specifying a hard limit.

Furthermore it is quite remarkable that even Charter Parties have not been adjusted to the latest specifications and that they don’t mandate the use of winter grade fuels only specifying fit for purpose, a statement no supplier will ever warrant.

So what are the grey areas and how can we prevent these issues impacting the end user?

Issues

In short, not only are things not what they seem, they are not even what they are called!

This statement certainly applies for DMA distillates across a large swathe of North West Europe and the epicenter of ARA ports where blenders have for some years now pushed the envelope using additives to masquerade a summer grade fuel as a winter specification. Indeed whilst there generally are warning signs that we can use to detect such fuels there are exceptions and therefore you cannot assume simply on a pour point result that a fuel is a winter grade which will give you adequate protection.

In understanding the effect of the additives we need first to understand the effects of cooling on a distillate fuel such as DMA.

The Cooling Process

As a distillate cools down the first point of note is what is known as the Cloud Point, this is the temperature under laboratory conditions at which wax crystals in the fuel become visible by way of the first wisps of a cloud.

Beyond the cloud point, the fuel becomes almost jelly like until such a point, again under laboratory conditions that the fuel blocks a 45 Micron filter, its Cold Filter Plugging Point.

Finally the fuel will reach its Pour Point, in other words it will solidify, stop pouring etc.

Under normal circumstances from point to point, i.e. cloud to CFPP, a delta of 2 to 5 degrees Celsius is standard. It is when these ranges vary beyond 5 degrees when it can be assumed that additives are in play.

Additive Use

As mentioned earlier, one weapon in the armoury of a fuel blender is additives in order to improve the performance of a fuel, one type of which is a middle distillate flow improver (MDFI). These MDFI additives work to improve operability at colder temperatures by depressing both the CFPP and the Pour Point. Cloud Point however is unaffected.

Additives can be added proactively or re-actively and have varying effects depending on the fuel and dosing rate and their effects generally lessen with larger quantities of additive.

So armed with the routine behavior of unadditized fuels when cooling it is feasible to identify fuels with far wider temperature variances from Cloud Point to Pour Point.

Current Position

Recent data available to Integr8 fuels suggests that a large proportion in ARA, North West Europe and ports replenished from this area have a Cloud Point above 10 Deg C and a delta from Cloud to Pour Point of 16 Deg C which takes us to the Winter grade Limit for Pour Point (-6 Deg C). See Diagram below.

The DMA fuels that exhibit such properties are usually identifiable by their higher densities (0.87 to 0.89 Kg/Ltr) as can be seen from the data below, whereby the average delta for such fuels from Cloud to Pour Point is 25 Deg C.

Skaw on the other hand worryingly bucks that trend with fuels with similar poor cold flow operability as ARA exhibiting far lower Densities (0.843 Kg/Ltr) and far better combustion characteristics (54 Cetane Index v 42 in ARA). This results in the specter of even the most eagle-eyed technical manager not spotting what lurks behind the mask.

Therefore both examples would in the eyes of ISO 8217: 2005/10/12 meet the winter grade specification but in real terms could create significant operational challenges onboard the vessel.

Control Measures

So proactively what can be done to minimise risk to the vessel and the end user?

Firstly it is essential to understand the vessel, its uses for distillate fuels, its limitations and its upcoming voyage. Some vessels are more sensitive to cold flow properties than others, for example those with cranes such as a Geared Bulk Carrier or Heavy lift vessel given we would be concerned about ambient air temperatures (& wind chill) rather than simply the sea temperatures.

Secondly it is obvious that this is more of a concern if a vessel is headed to colder climes, for example the Baltic in the middle of winter. Planning is therefore essential to consider whether for example a summer grade fuel picked up in Singapore is fit for purpose in the Baltic in January, I very much doubt it would be.

Finally, and most importantly should risks be identified during procurement then a data driven process of risk mitigation should follow.

Buyers must check during enquiry that:

• Their expectations are clearly passed to their counterparty, for example Cloud Point 0 Deg C Maximum.

• Fuel is guaranteed to 2017 Winter Grade wherever possible which mandates the reporting of Cloud Point and CFPP..

• If the fuel is not guaranteed to 2017 then a Certificate of Quality should be obtained for the batch in question with

Cloud Point or CFPP data provided which meets the requirements.

Inevitably such demands may result in a premium being charged by the supplier, however given the circumstances it is a price worth paying to swerve such fuels.

Conclusion

So to conclude until such time that adequate protection is provided within ISO 8217 it is essential that buyers understand the risk of such fuels and put suitable buffers in place to protect them from issues.

Control measures may be able to be utilized post issue such as more additive or a small amount of heating (which may be possible given some vessels have converted old fuel oil tanks into distillate tanks) but it by no means guarantees a resolution.

The best bet is to plan, purchase smartly and if necessary accept a price premium given the challenges these masquerading fuels bring.

Chris Turner Manager – Bunker Quality and Claims P: +65 6622 0042
E: chris.t@integr8fuels.com

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Since our Integr8 notes and podcasts in late August we have taken a far more cautious approach on potential near-term gains in bunker prices.  As we have (too) often outlined, absolute prices in our markets are driven by what is happening in the overall oil market, with some variations as relative crude and product prices shift.

The concern in the markets two months ago about a second Covid wave and a slowing rebound in oil demand have happened.  The net result has been bunkers moving in a very narrow price range, with daily VLSFO prices quotes in Singapore remaining within only a $40/ton range for the past 3 months.

One point worth noting on relative pricing is that over the past month VLSFO has strengthened slightly against crude oil.  Although it is still at very low levels versus crude, VLSFO in Singapore is now at 107% of Brent, up from a low of just 101% in August, but nowhere near the 120-130% just before the pandemic.

This slight upturn has come with some minor relative strengthening in jet and gasoil prices, which does have an underlying impact on the VLSFO ‘blend’ price (in our recent Integr8 webinar we went into detail about the inter-relationships and determining factors for VLSFO pricing).  However, demand and pricing for gasoil and jet (along with gasoline and diesel) will have to rise a lot more to push this relative price of VLSFO significantly higher.

This brings the focus back to the bigger picture in oil markets.  The overall fundamentals are key, and we are going through a period where oil supply has not been an issue, with the OPEC+ group doing a very good job of cutting production.  All the focus is on demand, with the emergence of a second Covid wave leading to more lockdowns and constraints on the rebound in global oil demand.

The graph below illustrates four different analysts’ views on oil demand.  All measurements are against the corresponding quarter in 2019 and there is a fairly consistent view on how demand fell in Q1 and Q2 this year and how the recovery has taken place in Q3.  Looking ahead through to the end of next year, three of the analysts have very similar expectations, looking at further gains in Q4 this year, but then only limited increases through all of next year, such that even by Q4 2021 global oil demand will still be 1-2 million b/d below demand in Q4 2019.  One analyst is even more bearish, seeing the demand rebound falter this quarter and through the first half of next year, but then hitting similar numbers to the other three analysts for the second half of next year.

One analyst has extended their quarterly outlook into 2022 and this shows global oil demand returning to the 2019 level in Q2 2022, another 18 months away.  The general expectations at this stage are that it will take until the very end of next year or the early part of 2022 before total oil demand gets back to 2019 levels.  It is this view that over-arches the very flat price expectations at the moment.

The question is: what can happen to change this?

Although headline analysis is looking at the global position, there are very different developments taking place on a regional basis.  Economies and oil demand have rebounded far quicker in Asia-Pacific than elsewhere.  Activity in China is back close to pre-Covid levels on many levels, even including domestic airline travel.  For the region as a whole, oil demand is expected to return to 2019 levels as early as Q2 next year and continue rising after this, which will support regional refining and oil markets.  Any return in the US is not seen until the start of 2022, either under a Trump or Biden presidency (at the moment any political/energy policy differences between the two are seen as having a longer term impact and not in the near-term global oil markets).

Europe is looking like ‘more of a drag’ on demand than other areas and in the longer term this could have a marked impact on ‘local’ refinery closures and product pricing.

Given these current circumstances, it is difficult to see prices moving significantly higher in the very near term.  The obvious trigger to prices rising steeply is the introduction of a covid-19 vaccine, or even the very strong indication that one is imminent.  The increases in oil demand with the introduction of a vaccine could exceed analysts’ current views.  News of a vaccine will push futures prices much higher, and with the mantra ‘buy on the rumour, sell on the fact’, the initial price hike could be high (before prices settle back down).

The forward curve today does not reflect any step change in demand that a vaccine could offer.  In fact, looking at monthly average prices, the forward curve on VLSFO in Singapore is extremely flat and still within the recent $20/ton band for another 12 months.  Even going into 2022 any increase in the curve is very gradual.

There will always be some price movement, and in the very near term there are also risks to the downside, with any large-scale moves into lockdowns or issues surrounding the OPEC+ agreement and the outcome from their 30^th November/1^st December meetings.  However, if and when there is a successful covid-19 vaccine, this is likely to push oil prices up significantly and well above the current VLSFO forward curve.

Steve Christy Strategic Communications Director, Navig8 P: +0207 4675 860
E: SteveChristy@navig8group.com

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New trends in US crude trade may arise, as oil demand recovers but impacts from the Covid-19 pandemic on US oil supply linger.

US crude exports have expanded sharply in recent years following the lifting of US oil export restrictions in December 2015, driven in large part by rising US tight oil production, which increased by 6.1 million b/d between 2012 and Q1 2020 to reach 8.3 million b/d. Shipments reached a record high of 3.5 million b/d in Q1 2020, supported by expanded pipeline infrastructure that boosted crude flows to export terminals.

On the other hand, US crude imports by sea have declined since 2010, falling 5.0 million b/d between 2010 and Q1 2020 to sit at 2.5 million b/d. Declining seaborne imports came against a backdrop of rising domestic oil supply and higher landborne imports from Canada, which doubled between 2010 and Q1 2020 to reach 4.0 million b/d.

As Q1 2020 drew to a close, fundamentals in the oil market shifted significantly. The Covid-19 pandemic caused unprecedented destruction to global oil demand, as countries imposed ‘lockdown’ restrictions and economic activity declined. Global oil demand collapsed by 15.6 million b/d y-o-y in Q2, whilst global crude throughput fell 11.4 m b/d y-o-y.

Meanwhile in April, a flood of oil entered the market as OPEC+ supply cuts ended, following the collapse of discussions in early March. Amid a massive oversupply, crude oil prices crashed, which resulted in price-sensitive US shale operators shutting-in supply. US production fell sharply, with tight oil supply dropping 2.3 million b/d in two months to 6.0 million b/d in May.

US crude exports dropped back only 0.3 million b/d q-o-q in Q2, supported by lower domestic oil consumption and inventory building in Asia. Shipments have rebounded somewhat in Q3 as global demand continued its recovery and curtailed US supply has been restored quickly.

US seaborne crude imports were initially boosted by the disruption in OPEC+ supply. Discharges of cheap Saudi crude, loaded amid Saudi Arabia’s price war with Russia, increased in May and June. However, higher imports partly offset falling US supply to maintain high crude flows into US storage, with elevated stockpiles subsequently suppressing imports into Q3.

Despite US exports not dropping as much as expected during the initial stages of the pandemic, growth in US crude exports is expected to remain limited and volumes may hold around the 3 million b/d mark into 2021.

Undermining the outlook for US crude export growth is the projection of US crude supply declines beyond September 2020, owing to reduced drilling activity, with US tight oil production declining 0.3 million b/d y-o-y in 2021. Export growth also faces headwinds outside the US from high global oil inventories, whilst persistent ‘first-wave’ and emerging ‘second-waves’ in Covid-19 affected countries could prolong economic contraction into 2021. Supply factors may also play a role, such as tapering OPEC+ cuts supporting higher OPEC+ exports, or potential shifts in Libyan, Venezuelan or Iranian crude flows.

However, there remain positive factors that could support a more optimistic outlook, including from continued gradual improvements in global oil demand. There is inherent upside risk, including from the impact of a Covid-19 vaccine ahead of end-Q1 2021, which could spur the pace of demand recovery. Meanwhile, high oil inventories in the US, likely to suppress domestic US refinery output somewhat, could push more crude to export markets.

Elevated US crude stockpiles are likely to keep US seaborne imports under pressure in the near-term. However, with US crude inventories falling steeply in August to return close to the 5 year range, the outlook for rising seaborne crude shipments to the US is positive, with shipments having the potential to increase by 0.7 million b/d y-o-y in 2021.

Seaborne imports appear well positioned to benefit from a projected rise in the US crude deficit next year, as US oil demand continues to improve and domestic US oil supply eases back. However, landborne shipments are expected to largely recover, although remain limited by pipeline infrastructure and muted growth in Canadian production, whilst further draws on US crude stockpiles may also present a headwind to import growth.

VLCCs are likely to be supported next year by higher US imports of Middle Eastern crude as OPEC+ supply cuts ease, whilst Aframax demand is expected to benefit from higher US crude imports from Latin America. Meanwhile, Suezmaxes are likely to benefit from firmer US imports of both Middle Eastern and Latin American crude.

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In all our previous notes and podcasts we have been relatively bullish on bunker prices rising from their extreme lows at end April, even though at some stages there was a stuttering in the upward trend. 

The sentiment was driven by tightening oil fundamentals; demand began to rebound and OPEC+ made major cuts to oil production.  But these signals have taken a turn.  In our Integr8 podcast 3 weeks ago we did take a more nervous approach to any further short term rises in price, but bunker prices have taken more of a hit and have dropped $40/ton (for VLSFO in Singapore) in the past 14 days.

Looking at oil fundamentals at the moment, there are far fewer concerns about oil supply, with the OPEC+ countries producing at close to the agreed levels; it is much more about demand now.  The reversal in crude prices has come from a far greater concern about the ‘rebound’ in total oil demand, with the emerging threat of a second Covid-19 wave and the associated lockdowns taking place.

Since mid-May VLSFO prices have closely tracked the price movements in Brent futures, with Singapore prices very close to 102% of the Brent price throughout the period (on a weight basis).  So, as the crude price has moved up or down, this has led VLSFO up or down by a similar amount.

Although VLSFO prices have closely tracked movements in the Brent price for the past 4 months, this is not the case for HSFO.   The price of HSFO has strengthened considerably against crude (and so VLSFO), going from 66% of the Brent price in early May to 84% currently.  The drivers here are that demand for HSFO has been relatively flat and one of the least affected products from covid-19, and at the same time refinery runs have fallen and the OPEC+ production cuts have focused on heavier, higher sulphur crude grades; all this has led to a ‘constrained’ supply of high sulphur fuel oil.

Between early May and now the price of HSFO in Singapore has risen by around $100/ton, with $55/ton of this accounted for by the underlying rise in crude prices, but a further $45/ton gain because of the relative strength in HSFO.  It is these dynamics that have squeezed the VLSFO/HSFO differential over the past 3½ months.

The very recent drop in oil prices reflects the changing perspective of how fast oil demand can recover and how long the covid-19 impact could last.  Over the past few months most analysts have downgraded their views on future oil demand, with for instance demand estimates for the third and fourth quarters this year reduced by 1.6-1.8 million b/d since July.  Also, expectations for next year are relatively flat and 1 million b/d below levels projected in July.  The current demand position is ‘the rapid rebound has come to an end and any future increase will be far more muted’.  Hence, the drop in oil prices over the past 2 weeks.

Looking at different oil products, it is clear the demand impact on the bunker market has been far less than for other sectors.  In the graph below the orange line represents the change in total fuel oil demand on a monthly basis vs the corresponding month in 2019.  This shows fuel oil demand running at around 0.5 million b/d below 2019 levels throughout this year and next year.

In contrast jet/kerosene demand collapsed in April and even by the end of next year is still expected to be below 2019 levels (the airline industry is looking at 2024 to stand a chance of getting back to earlier demand).  It is then the road transportation sector where the biggest swings in absolute demand are taking place.  Gasoline, diesel, gasoil has accounted for the biggest part of the demand loss and the biggest rebound since April.  However, only minor gains are forecast between now and the end of 2021.  The possible second Covid-19 wave is hanging heavily over this and economies generally.

Putting all these demand developments together, total oil demand is not expected to get above 2019 levels until the end of next year, or possibly into 2022.  Hence the bearish sentiment in today’s market.

In past notes, we have looked at changes in US oil stocks as an early indicator of how well oil demand is doing.  This will remain an influence, but low refinery margins and higher Covid-19 infection rates and lockdowns have had a bigger (negative) impact.

It could be the case that prices fluctuate around recent levels, but for the next major leap upwards in price there has to be the sign and confidence of a successful Covid-19 vaccine.  Mixed into the recent news was a halt in one of the key, advanced, vaccine trials (which is typical for such trials) and this has been taken as a bearish signal in the oil markets.

So, in addition to all the other oil indicators we have highlighted before, we must add pharmaceutical developments to the list.  There are close to 200 Covid-19 vaccine trials currently underway and 9 of these are in their final phase large-scale trial before possible approval.  Some analysts are suggesting Q1 next year as a potential time-frame for a vaccine to hit the market.  This may be the case, but this is an area where those carrying out the clinical trials and those in a position to approve (or not) a vaccine are far better placed to know than the rest of us.

As before, headline news on US oil stocks, refinery margins and US/China/Russia/Saudi Arabia politics will all steer oil prices, but the current signal for any big hike in bunker prices (and oil prices generally) is likely to be the emergence of a Covid-19 vaccine.

Steve Christy Strategic Communications Director P: +44 207 467 5860
E: SteveChristy@navig8group.com

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In recent times, we have written as to the importance of having an open mind when it comes to claims investigations when assessing the bunker stems against issues experienced onboard but what is equally important, is that we have a solid base for a claim against the fuel in the first place.

Indeed the most basic hurdles to overcome are whether we are basing the claim on a sample representative of the bunker contract and are we confident as the sample’s provenance, in other words, how, where, when it was drawn and is it fully representative of the supply?

At the end of the day, you will not be surprised that as a former laboratory chemist, that for years I have been heard preaching the same mantra in that “any laboratory is only as good as the quality of the sample provided”.

So how do we address one of the biggest variable of them all?

Prior to supply

Proactively buyers should always look to clarify means of delivery and the location of the sampler used to produce the binding contractual samples. Singapore is a notable exception in that SS600 and SS 648 mandate that samples which form the BDN are drawn from the vessels manifold but many areas have no such control with samples being drawn from the barge manifold unless agreed in writing prior to supply.

Truck and ex pipe deliveries require special attention in order to define how and from where samples are drawn which ultimately will be listed on the BDN and are inevitably the binding samples in the case of a dispute.

It is also important to understand access limitations given the continued Covid-19 challenges. Clarification must be sought early as to whether crew members can attend a barge or shore installation to witness samples being drawn and/or can barge crew attend the vessel as given the importance of samples the mobilization of surveyors would always be recommended.

Recently we have identified that some suppliers list these Covid limitations in their calling instructions, so all stakeholders should be sure to read them thoroughly as this document may give you the “heads up” needed to appoint a surveyor in advance to protect your interests.

Time of delivery

At the end of the day, if you don’t raise concerns at the time as to the provenance of samples or any deviation from sampling protocols then you have little recourse in the future.

Indeed it would not be the first time that the representative (and contractually binding sample) does not bear any resemblance to other samples presented which of course could expose you to the full weight of the claim.

Therefore any deviation or issue should be documented in a Statement Of Fact (SOF) or Letter Of Protest (LOP) at the time of supply and should this be refused or not accepted to be signed by the supplier, then urgent communications should be made to the relevant counter-parties in order to document the occurrence.

Common deviations include:

• Lack of continuous drip sampler on board the barge resulting in “SPOT ONE SHOT” samples forming the BDN.

• Continuous drip sampler not started at commencement of delivery.

• Cubitainer seen to be full prior to delivery completion.

Post delivery

Particularly if time is of the essence on completion, it can be a bad habit to ignore the samples and concentrate on the ullaging – which of course would render all previous attention potentially useless. It is essential that the entire sampling process is covered from the moment the cubitainer is connected to the continuous drip sampler until the last sample has been sealed and accurately documented on the BDN and both the BDN and the sample labels have been signed off by all parties.

Conclusion

So to conclude, I would argue that given some of the quality challenges and the issues with barge accessibility for the crew given Covid-19 concerns, it is almost essential to employ a barge based surveyor to protect buyers interests even in a relatively low flat price world as we have at present.

This allows any deviations relating to Quantity and Sampling to be noted, documented and dealt with at the time and gives you peace of mind in the event a claim occurs further down the line.

Remember the adage, the laboratory is only as good as the sample provided – you are wise to always employ a gold standard ISO 17025 accredited laboratory for your testing but if the sample is not representative then it is irrelevant and is a recipe for disaster.


Chris Turner Manager – Bunker Quality & Claims P: +65 662 200 42
E: chris.t@integr8fuels.com

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