In the LOOP: USGC delivered crude cargoes to UK rebound

Imported barrels of crude into the UK from the US Gulf Coast rebounded from a five-week low Friday, with shippers swapping out Suezmaxes for Aframaxes on delivered cargoes.

Delivered crude cargoes from the USGC to the UK for the week ended October 26 increased around 1 million barrels week on week, according to data from S&P Global Platts Analytics. An additional 269,000-barrel cargo was exported from the USGC to the Netherlands for that same time period, representing a week-on-week decline in USGC crude cargoes to Rotterdam of 1.35 million barrels.

Ongoing fall maintenance and soaring freight rates have contributed to lower crude demand in the region.

Cargoes delivered into the UK for the week ended October 26 included two 536,000-barrel cargoes and one 501,000-barrel cargo, all of which arrived in Liverpool. Essar Oil operates the 205,500-b/d Stanlow refinery near Liverpool.

Freight rates for Aframax vessels have been steady to higher since October 5, with the USGC-UK Continent route moving up w130 points or over 144% over those 15 consecutive trading days. On Friday, freight for the USGC-UKC route fell for the first time since October 5 to w205, down w15 points day on day.

Shipping sources have attributed the bullish movement in rates to a combination of factors, including the increase in export activity to Europe. Weather-delayed itineraries, steep bunker prices and limited tonnage availability — dwindling on those increased US crude exports and lightering demand — have also lent bullish support to rates.

So far in October, there have been 22 Aframaxes booked to lift cargoes to Europe from the USGC, up significantly from 15 in September and 12 in August, according to Platts fixture logs.

Despite the uptick in delivered USGC crude cargoes to the UK, overall delivered cargoes into Northwest Europe from the USGC appeared to fall 262,000 barrels week on week to 2.104 million barrels. As overall exports have declined, the assessed differentials for Permian light sweet WTI MEH crude and offshore medium sour Mars crude have weakened.

On Monday morning, WTI MEH was heard talked at WTI cash plus $6.60/b, up 30 cents from its assessed value Friday but down 20 cents week on week.

Mars was heard talked Monday morning at WTI cash plus $5/b, down 30 cents on week.

Both WTI MEH and Mars have been exported to the UK and Rotterdam in increasing quantities in recent months, according to market sources.

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One crude, two prices: Oman puts benchmark DNA in the spotlight

Why is the benchmark value of Oman crude oil sometimes spectacularly different when assessed by S&P Global Platts, compared to the value established for the very same crude oil through trading on the Dubai Mercantile Exchange?

In 2018, it is an important question because the answer shines a bright spotlight on how different the DNA can be for different price benchmarks representing the same market, which ultimately can have huge value implications.

In the last week of September, physical Oman crude for loading in November surged to settle as much as $7.61/b higher on the DME, when compared to the value of physical Oman delivered for the same month, as assessed by Platts. To put it another way, Oman was at times 10% more expensive when valued by the DME reference price than by the Platts Oman benchmark – raising the value of a VLCC loaded with Oman by $15 million. Significant price differences between DME Oman and Platts Oman continue this month.

But why? In itself, the crude is the same, the loading dates are the same, the time of trading is more or less the same, and the market participants active in trading Oman oil are broadly the same. At first glance, arbitrage alone should theoretically prevent Platts Oman and DME Oman from decoupling too much.

Understanding how Platts and DME Oman are different reveals how vital it is to understand the DNA of any benchmark, especially if you plan to use one to better understand the value of a multi-billion dollar oil market.

Oman Blend is a medium sour grade of crude oil that has served the world markets well for many decades. It is openly traded on the spot market without destination restrictions. It is popular with buyers as diverse as China’s ultramodern refineries to the ageing California refinery fleet, burdened as it is by high costs and challenging economics.

With no shortage of buyers, stable production, a diverse trade community and a sterling reputation for quality and reliability, it is easy to see why the value of Oman crude has become a key benchmark and a good reference for understanding global crude prices.

Trading activity alone is just one input into the value of a benchmark. The final benchmark price from any provider is shaped by three core forces: the definition of the benchmark, the way market data is collected, and the analytical approach applied to that data to come up with a single, final value. Taken together, these three forces are what we call methodology, at Platts.

Platts Oman and DME Oman represent the same crude oil, but they differ in each methodological respect. The value of Oman on the DME reflects the value of Oman on its own. The value of Oman as assessed by Platts reflects the value of Oman, but also includes the potential delivery of Murban crude oil from Abu Dhabi, at the seller’s option, if economics support delivering an alternative crude oil.

Platts collects data from across the spot markets using our Market on Close assessment process, which is underpinned by transparent bids, offers and trades with named counterparties.  The DME reflects trade on the exchange with its own, publicly described price settlement process.

The challenge is to understand the differences in methodology, and then to consider which methodology best suits the market’s needs.

Platts introduced Murban as an alternative delivery crude oil for our Oman benchmark in January 2016 along with along with a Quality Premium that reflects Murban’s relatively premium market value.  That followed deep industry consultation through 2015, when many market participants highlighted the value of having a pressure release valve for Oman.

Just a few months ago Total delivered a cargo of Murban to Shell instead of an Oman in the Platts MOC – the very first time this particular alternative delivery was used, demonstrating the importance and value of the idea.

As a general guideline, the more popular a crude oil is among buyers, and the more relevant the price is for the global economy, the more essential new ideas and innovations like alternative delivery are – and they usually need to be introduced long before they are actually needed.

We have pioneered alternative delivery mechanisms for Platts Brent, Platts Dubai, and indeed Platts Oman. In our view, a strong crude benchmark needs at least a million barrels per day of deliverable oil from the spot market to support it, including the core grade and its alternatives.

When you break down the economics of Oman crude – including the fact that 200,000 b/d or more of production is already committed to local refining – the case for alternative delivery is strong indeed, especially when you consider other factors like field maintenance. Logistical headaches like standard field work can be major migraines for benchmarks that aren’t well prepared.

In reality, evidence that Platts Oman and DME Oman are actually very different benchmarks has been in front of all of us for years. Platts Oman and DME Oman have decoupled more than 20 times since we introduced the Murban alternative delivery mechanism in 2016. And over the lifetime of the two benchmarks, Platts Oman and DME Oman have often been very different indeed. At the end of the day, it is up to market participants to decide which benchmark price best meets their needs.


This article first appeared in The National on 28 October 2018.

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IMO meeting eliminates doubts over 2020 delay: Fuel for Thought

If any doubts remained that the International Maritime Organization’s tighter sulfur emission limits for ships in 2020 could be delayed or otherwise watered down, those doubts should have been laid to rest at a key committee meeting of the UN body last week.

The IMO’s global marine fuels sulfur limit is set to drop from 3.5% to 0.5% at the start of 2020, forcing ship operators to use cleaner, more expensive alternatives to heavy fuel oil and bringing wide-ranging other consequences for commodity markets.

S&P Global Platts Analytics forecasts a shift of approximately 3 million b/d of marine demand from high sulfur fuel oil to lower sulfur alternatives, and a significant jump in crude prices as refiners increase runs to maximize middle distillate output to meet the new demand.

The January 1, 2020 implementation date for the new sulfur limit was decided two years ago, but doubts have repeatedly surfaced since then about whether it would be met, or could be postponed or phased in in a more relaxed manner.

Those doubts were given another outing at a meeting of the IMO’s Marine Environment Protection Committee (MEPC) last week.


A Wall Street Journal story on October 19 raised the prospect of the US putting obstacles in the way of the sulfur cap, quoting a White House source as saying the Trump administration would seek to “mitigate the impact of precipitous fuel cost increases on consumers.”

The oil market reacted as if the Trump administration was opposing the lower sulfur cap outright: the 2020 hi-low fuel oil swap narrowed significantly on the morning of October 19, showing reduced expectations of a large-scale shift in marine demand that year.

At the MEPC meeting last week, the US delegation made it clear it was just supporting a proposal for an “experience-building phase” in the initial period after 2020 when concerns over fuel availability and quality may cause problems for shipowners.

The authors of that proposal — first submitted by the Bahamas, the Marshall Islands, Liberia, Panama and various shipping associations — “envisage the experience-building phase as a time to permit all stakeholders (such as ship operators, engine manufacturers, refineries, bunker suppliers, recognized organizations, member states and observer organizations) to provide input on an inclusive IMO process that will enable the current challenging regulatory requirements to be safely addressed without unduly penalizing individual ships,” according to a draft of the document.

The proposal was rejected late last Wednesday. While proponents of this measure defended it as a data-gathering exercise that would assist with robust implementation of the tighter sulfur cap in 2020, some of its detractors saw it as an attempt to water down the regulation.

The IMO has repeatedly stressed there is no opportunity between now and 2020 to delay the implementation.


Last week’s MEPC meeting also adopted another measure designed to help with enforcement of the new sulfur limit – a ban on the carriage of non-compliant fuels, now coming into effect at the start of March 2020.

The IMO has no powers itself to enforce its regulations, and in the high seas it is the responsibility of the flag state where a vessel is registered to check whether it is burning the right type of fuel.

This was previously an area of concern for some forecasting widespread non-compliance in 2020, as not every flag state would be expected to be vigilant in enforcing the sulfur limit.

The carriage ban helps allay this concern by empowering port states to check whether the vessels leaving their waters have sufficient 0.5% sulfur fuel for their entire journey. Port states governing most of the major oil hubs across the world would be likely to have robust enforcement measures in place, making non-compliance a much more difficult prospect for any vessel calling at those hubs.

A proposal to delay the implementation of the carriage ban was discussed at the MEPC meeting and received some support, but was ultimately rejected.

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Near-term seaborne thermal coal market in limbo as China plays its cards

Uncertainty looms in the seaborne thermal coal market as suppliers await for any positive indications from China on loosening its policy on imports during the seasonally strong fourth-quarter.

Thermal coal suppliers are a worried lot, especially as there are no other alternative markets which can potentially absorb the excess tonnages.

Seaborne thermal coal prices have been holding strong since the second-half of 2016 mainly due to policy changes in China. Earlier in 2016, China tried to shore up its own ailing domestic market, but things quickly spiraled out of control when Chinese domestic thermal coal prices more than doubled, and end-users began to bear the brunt of high prices.

China has since introduced fresh policies aiming to cool domestic prices, but looks like that has not met with enough success.

Thermal Coal Platts PCC 1 FOB Qinhuangdao 5500 kcal/kg NAR 7-45 day (VAT) Yuan/mt

The price of Chinese 5,500 kcal/kg NAR, which was at Yuan 365/mt FOB Qinhuangdao in January 2016, was assessed by S&P Global Platts on Monday at Yuan 668/mt, well above the Yuan 500-570/mt range Chinese authorities want to maintain.

And even if Chinese utilities want to tap the seaborne market for cheaper cargoes during the winter restocking period, they are deterred by the so-called import quota system in place.

The price of FOB Kalimantan 4,200 kcal/kg GAR, a grade popular across consumers in Asia, has slumped from a high of $51.50/mt seen in February this year to about $37.90/mt as on Monday, according to Platts data. Compared with October last year, the price has slumped by more than 17%.

Yet by the end of Q3, several Chinese importers had fully used up their import quotas, leaving little room for more seaborne trades to take place in Q4.

In the first nine months of 2018, China imported a total of 228.96 million mt of coal, including thermal, coking coal and anthracite, up 11.8% on the year, Chinese customs data shows.


As we enter into the peak winter-restocking period, Chinese authorities are still unrelenting on the import restrictions.

That might spell bad news for seaborne coal suppliers, but can China make do with what they have in terms of domestic production or will they have to eventually tap the seaborne market?

That’s a big question, especially when China is also fighting its own battle to curb pollution levels and looking to venture into the cleaner energy space. There have been several inefficient coal mines that have been shut during stringent safety checks and that has curtailed production to a certain extent.

“Chinese thermal coal market should remain largely tight in Q4, as environmental crackdowns, safety checks and potential re-imposition of import restrictions should limit supply,” Citi said in its research note.

Last year, China also tried to reduce pollution levels by shifting to cleaner LNG in Q4. LNG imports in the fourth-quarter of last year shot up year on year, but China was still not able to source enough clean fuel to cater to the strong winter demand.

The result: Not only did they have to clamour back to the coal market much sooner than anticipated, but they also had to work through their Lunar New Year holidays to ensure sufficient coal production at their domestic mines.

Will history repeat itself or does China have a better plan this year, learning from their previous decisions?

While most of the Indonesian coal suppliers are confident that China will enter the seaborne market in November, several Chinese buyers are emanating pessimistic views.

Another factor that has helped drive coal prices in the past couple of years has been the supply disruption in Indonesia due to unseasonal rains. Several major producers have said that rains have dented their production in the past few quarters.

The Indonesian government is also taking the coal production numbers quite seriously this year as their currency takes a hit against the strong US dollar and the archipelago looks to boost its export numbers to shore up its revenues.

The government has allowed production of an additional 25 million mt in 2018, taking the actual production target to 507 million mt for the year, but as rainy season usually begins in Q4, will we see another bout of supply disruption?

There are a lot of factors which play a role in dictating the seaborne coal price movements in the near term, but China definitely holds the key.

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Insight Conversation: B. Anand, Nayara Energy

B. Anand is CEO of Nayara Energy, the owner of India’s Vadinar refinery and a top buyer of Iranian oil. In a recent Insight Conversation video, Anand spoke to Sambit Mohanty about the company’s crude purchases and wider strategy.

There are two major themes affecting the market right now: US sanctions on Iran and the US–China trade war. How will those two factors impact the dynamics of crude flows into India?

As you know, India and Iran have been very robust partners as far as crude supplies are concerned. India has been the logical market for much of the Iranian crude to flow and Nayara has been relying a lot on Iranian crude. It’s a logical fit. There is a great relationship that we share, which I am sure other refineries in India also do. So the US sanctions on Iran will definitely have a massive economic impact, as far as India is concerned.

We are keenly watching the developments and how the replacement happens, should there be a complete embargo on Iranian crude. Those are the kind of uncertainties everyone is talking about. As far as we are concerned, fortunately the kind of refinery that we are, it offers us plentiful choices to look at alternate crudes. More importantly, [we are fortunate in] the shareholders that we have, both in terms of Rosneft and Trafigura… Both have substantial footprints, or if you like to use the word, access points. This will help us get crude from all over the world and we will rely a bit on that to combat the situation.

B Anand, Nayara Energy

Would Nayara be open to buying US crudes?

What drives our decision is the economic value of the crude.  We are probably one of the very few refineries that has the ability to process crudes with a range of APIs, from the light to the heavies. Having invested substantially in a coker and other related secondary facilities, it means the lower the API, the more margins you make. US crude is very much on the table for one to evaluate and to look at. I’m sure that, with all the geopolitical gyrations that are happening, we may see some different kind of economics emerge which may not have been there before. So for us the short answer is that we will definitely consider US crudes to the extent that they are viable for us.

Looking from a global supply perspective, do you think the market is ready for the shortfall of up to 2 million b/d that everyone is expecting because of the sanctions on Iran?

The challenge is not just Iranian replacement. There are also issues around declining production in some of the other mature markets – be it in Venezuela or some other parts of Latin America, or the challenges of many of the OPEC countries to step up their production. So we are steering towards a bit of an uncertain environment in terms of how these barrels will get replaced. Everyone is in the wait-and-watch zone.

I’m sure there are a lot of requests made to some of the OPEC producers to step up their production. I’m sure Russia is doing their bit in terms of stepping up production and I am sure there is sufficient crude being produced, even back in the US. So it’s to be seen how the balance gets matched.

B Anand and Sambit Mohanty

India’s retail oil prices have been rising, with prices of gasoline and diesel hitting record highs in the past few months. What are the options for the government? Do you think this might impact demand?

 In countries like India and other emerging markets, high fuel prices have cyclical ramifications in terms of inflation. The ramification straightaway straddles back to your currencies in terms of the depreciation they have to go through. And of course, [there are] associated industry-related ramifications which come alongside it, let alone the emotional ramifications which come from the people.

In India, rising fuel prices is a matter of massive concern for the government. You keep hearing about rising prices in the news and the concerns of the common man. So I generally believe that at some point in time you will start noticing some demand destruction. We haven’t noticed that yet, but there will definitely be a point in time when you will know that this is not going to sustain itself.

Coming back to what are the choices the government has in terms of how it will manage this: clearly, one of the great initiatives the government took a couple of years back was to deregulate prices. On those premises, players like us have made substantial investments in the retail fuel space. There is a strong initiative from the government to get more and more private partners into the supply and distribution side. So we believe and we are hoping that there won’t be any change in the progress of policies the government has undertaken.

The only tool the government has, considering that we rely substantially on imported crude, is to evaluate the tax structure. Tax revenues play an important role in the recovery of the current account and fiscal deficit. But in the past, the government did not necessarily pass on the benefit of low prices to the consumer. I’m assuming the government may look at that and try to give some relief to the Indian consumer if the trend is going to be rising prices.

As the CEO of the company, could you give us a brief overview about your crude and product strategy and your vision for Nayara Energy?

For us, the most important thing is to ensure that we run the refinery at its optimum. The refinery has in the past demonstrated ability and flexibility to digest different crudes and producing products to meet the needs of the market. In this context, the vison is to further diversify that basket. We would like to diversify the entire gamut of what we can use, including condensates that can come into the game along with stable crude. We are looking to develop ourselves to have the flexibility of looking at different energy sources as well, while producing these hydrocarbons.

On the products front, there are two interesting developments. One is the government’s initiative to be more environmentally friendly and move to BS-6 [Bharat Stage 6] fuel norms, which are equivalent to the Euro 6 emission norms. I think we have our investments in place and we hope to play a leadership role in building up that product basket. The second is the huge opportunity coming our way when the IMO 2020 regulations set in. It will become our priority to make sure that we have the right set of crude and products.

As far as the product distribution strategy is concerned, our barrels have traveled to far, far places. So we clearly understand how to make inroads into different markets from where demand can emanate. The strategy also embraces the fact we have built a very robust on-ground fuel retail network. There is a clear ambition to reach 7,500 retail stations in the next two to three years, with a clear focus towards enhancing throughput and embracing India into the energy scene, which you know has challenges of penetration.

So that’s how we will blend it. I think we will eventually have a strategy on products that will leverage our global reach and the reach of our shareholders Rosneft and Trafigura, and our own focus on India from the domestic side.

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China’s steel mills concerned by Beijing’s focus on private sector

When the current Chinese leadership took office in 2013, there was much talk about China’s economy becoming more market-driven, entrepreneurial and less reliant on the state. But the country appears to have been moving in the opposite direction in recent years and now Beijing seems to be trying to exert greater control on the country’s private sector.

Like most of China’s economy, privately-owned steel producers do not enjoy the same benefits as their state-owned rivals. One benefit they do possess, however, is flexibility. Therefore, potentially being subject to greater controls – having their wings clipped to a certain extent – is unsurprisingly receiving mixed reactions.

According to China Chamber of Commerce for Metallurgical Enterprises, private steel mills produced 264 million mt of crude steel in the first half of 2018, accounting for 58.55% of total output. This makes the private sector an extremely important part of the steel landscape in China.

Last month, Qiu Xiaoping, vice minister of the Ministry of Human Resources and Social Security, rattled a few cages by saying in a speech that privately-owned companies must improve their “democratic management” to ensure greater employee participation and wider profit distribution. To achieve this, private enterprises must adhere to the principals of the Communist Party and put employees in senior management positions, Qiu said.

It was the timing and tone of Qiu’s speech that generated market chatter. The private sector has already been squeezed by a slowing economy, supply-side reform and increasingly stringent environmental protection demands. Comments about engaging enterprise management and sharing profits through party branches and labor unions further worried some business owners. It also added to the uncertainty at a time when Chinese businesses are concerned about the long-term impacts of the China-US “trade war.” This uncertainty could undermine appetite to further invest in privately-owned businesses.

China’s National Bureau of Statistics publishes industrial sector performance results every month. Mid- and large-sized companies are defined as those with an annual turnover of at least Yuan 20 million ($2.9 million).

Chinese steel mills: Turnover and profits of SOEs, collective and private companies

In the first eight months of 2018, SOEs, private and collective companies all saw their turnovers and profits rise on a yearly basis. However, when compared with the numbers from January-August 2017, collective and private companies suffered a big downturn.

The private sector’s deteriorating performance is accompanied by rising debt-to-asset ratios. They have been forced to borrow more to survive the slower economy, while banks have withdrawn credit. Higher costs due to upgrading environmental protection facilities, along with more stringent requests to pay employees’ social issuances, have all heaped on the pressure. Amid China’s deleveraging campaign, debt-to-asset ratios have been falling at SOEs, but the ratio for private enterprises has been rising.

Smaller companies have also been hit by fewer tax concessions and a tightening up of shadow bank lending.

Though private companies find it harder to source credit at a time when China is trying to address its soaring debt problems, there has been little impact on bank loans to SOEs. Banks are more willing to lend to SOEs because they are effectively underwritten by local governments that need the revenues and jobs that steel companies generate. Even if an SOE is insolvent, local governments, more often than not, would not allow the company to fail.

In the latest China Credit spotlight report from S&P Global Ratings, it was noted that SOEs had “led improvements in capital discipline, under the close watch of state reformers.” SOEs comprised 63% of the 254 companies in Ratings’ China portfolio, which was down on last year. “The declining trend in SOE composition should reflect the wider participation of private enterprises in the economy and rising services sectors,” S&P Ratings said.

Jiangsu Shagang is the largest private steelmaker in China and is the world’s sixth-largest producer at 38.4 million mt last year. In S&P Ratings’ report, Shagang received a business risk profile score of 4 (fair) and financial risk profile of 2 (strong).

Its major state-owned rival, He Steel Group (formerly Hebei Iron & Steel), China’s second-largest producer after BaoWu, received a business risk profile score of 4 and financial risk profile of 6 (vulnerable). Shagang will likely continue to thrive but smaller privately-owned steelmakers could all be deemed to be “vulnerable,” S&P Global Platts notes.

China’s environmental protection agenda has also hit private companies hard, with some wondering if the tough emissions targets were put in place partly to flush out private mills. To update environmental protection facilities to the requested standards is costly, especially for private mills with less financing support than SOEs.

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In the LOOP: US crude exports to South Korea soar

US Gulf Coast crude exports to South Korea nearly tripled week on week, coinciding with wider Dubai/LOOP Sour and Brent/WTI swap spread and despite persistently high freight rates from the US Gulf Coast to North Asia.

Waterborne crude exports from PADD III to South Korea increased by 2.717 million barrels week on week to 4.225 million barrels for the week ended October 19, according to data from PIRA.

South Korea has emerged as one of the top buyers of US crude in recent month, taking both USGC light sweet grades like WTI MEH as well as medium sour grades Mars, Poseidon and Southern Green Canyon.

The increase in exports to South Korea coincided with a wider Dubai/LOOP Sour swap spread.

Second-month Dubai’s premium over front-month LOOP Sour has increased $4.97/b since the start of October to $4.55/b.

Dubai began the month at a discount to LOOP Sour.

As Dubai’s premium to LOOP Sour increases, USGC domestic medium sour grades become more competitive with comparable Dubai-based Middle Eastern grades in export markets.

At the same time, the Brent/WTI swap spread widened, making domestic light sweet grades more competitive with comparable Brent-based grades in export markets.

Brent’s premium over WTI since the start of the month has increased 55 cents/b to $9.93/b.

The export flows from the USGC to South Korea ramped up despite soaring freight costs in the past few weeks that have limited exports to other areas of the world.

South Korean buyers of US crude, however, receive government freight kickbacks that can lower the total cost to ship from the USGC to Asia.
The kickbacks are meant to incentivize buyers to diversify sources of crude away from more volatile Middle Eastern supply and toward areas of more stable supply, including the US.

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Trump administration may struggle to obstruct IMO 2020

The International Maritime Organization is much like the large commercial ships it regulates in one respect: while slow to get moving in the first place, it can be difficult to stop once its inertia has been overcome.

This is the problem the US delegation at the UN body may face at a key meeting being held October 22-26, if it seeks to put obstacles in the way of tighter marine fuel sulfur emission limits.

The IMO’s global sulfur cap is due to drop from 3.5% to 0.5% at the start of 2020, with wide-ranging consequences for the shipping and oil industries, and late on Thursday the Wall Street Journal quoted a White House source as saying the US would seek to “mitigate the impact of precipitous fuel-cost increases on consumers.”

The tighter sulfur cap is being forecast to add several dollars to the oil price from 2020 as refiners increase crude runs to maximize middle distillate output and meet the new marine demand for cleaner fuels. The US may be baulking at the prospect of that crude increase, particularly as it could come in the middle of its next presidential election campaign.

The oil market appears to be reacting as if the Trump administration were opposing the lower sulfur cap outright: the 2020 hi-low fuel oil swap narrowed significantly on Friday morning, showing reduced expectations of a large-scale shift in marine demand that year. This would seem to be an overreaction, given the reality of the situation at the IMO.

For a start, it’s not clear that the US is putting up that kind of opposition, and the WSJ’s White House source denied it was trying to delay the implementation.

Any such delay would be next to impossible at this late stage. At the meeting of the IMO’s Marine Environment Protection Committee (MEPC) next week – the committee that originally decided on the 2020 implementation date two years ago – the earliest that any proposal under discussion could become effective would be March 2020.

If the US — or any other country — were to seek to overturn the new 0.5% sulfur limit, it would need to find a majority of the signatories to Marpol Annex VI, the IMO’s convention on pollution from ships, who were willing to amend it. None of the European Union’s member states would be likely to support such a move, and a coalition would be difficult to form without them.

In any case, a change of this kind could not be adopted before the January 1, 2020 deadline.

What seems more likely is that the US is set to lend its support to a proposal for a so-called “experience building phase” for the IMO’s ban on the carriage of non-compliant fuels, currently expected to come into force in March 2020. This ban is a supplementary measure designed to help the enforcement of the sulfur cap, and the experience building phase — first proposed by the Bahamas, Liberia, the Marshall Islands, Panama and various shipping associations, and up for discussion at the upcoming MEPC meeting — would allow for more relaxed implementation of that ban for an initial period, although it is unclear exactly how that would work.

Whether a majority can be found for this proposal remains to be seen – while US support would be significant, many delegations are still reluctant to support any measure that could be interpreted as watering down the sulfur cap. The IMO took a long time to start regulating shipping’s emissions, and it would take a great force to stop it now.

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Could LNG shipping spot rates hit $250,000/day?

Spot day charter rates for LNG carriers have hit their highest levels since mid-2012 on the back of low prompt availability of vessels in both the Atlantic and Pacific basins.

This week, S&P Global Platts assessed Pacific and Atlantic day rates for LNG vessels at $140,000/day and $130,000/day, respectively, up 40% since mid-September, and nearly 3.5 times higher than a year ago when rates were still around $40,000/day.

The surge in rates indicates that LNG supply is growing faster than new ships are being delivered. The year 2018 will see the largest number of newbuild LNG carriers added to the global fleet, taking it well past the 500 mark.

Asia Pacific LNG shipping spot rates

Shipping typically accounts for 5%-20% of the delivered LNG price ex-ship, meaning big moves in rates can have a significant effect on the final price of gas, and the ability of traders to arbitrage LNG cargoes between regions.

Day rates first broke the 6-figure level around mid-September. Multiple shipping sources said no ships were available from independent ship-owners across both basins with chartering opportunities focused on relets from portfolio players or traders.

In the Pacific region, a spot charter for mid-November was reportedly north of $160,000/day, and several multi-month charters in the low-$100,000s/day.

“What we are about to witness in LNG shipping has only happened twice since 2008 with great magnitude,” Nicolay Dyvik, shipping research analyst at DNB Markets, said, adding that LNG freight rates could rise as much as $250,000/day if markets get tighter.

High freight rates are a product of tight supply of ships and strong arbitrage fundamentals that allow ship-owners to command higher charter rates. Dyvik said this last happened in 2008 in the dry bulk freight market, when Capesize rates hit $250,000/day, and in 2013-2014 when VLGC rates peaked at $150,000/day.

“Now it could happen in LNG,” he said earlier this week, adding that at last count, only two LNG vessels were available for prompt cargoes in the current market — one in the Middle East and one in the Far East region.

This is a long way from the lows of 2016 and 2017 when spot rates were hovering at $25,000/day, leaving ship owners struggling to breakeven with nearly 50 ships free on the spot market. Many owners had idled their LNG carriers and extended drydocking to avoid operating losses.

The LNG supply side ramp up isn’t’t quite done yet, leaving room for much higher vessel demand and providing the basis argument for even higher freight rates, especially in the Atlantic basin.

The projects ramping up in coming months are Shell’s Prelude Floating LNG, two trains at Inpex-operated Ichthys LNG in Australia, Train 5 of Cheniere’s Sabine Pass, Cheniere’s Corpus Christi and potentially the third train at Novatek’s Yamal LNG in the Russian Arctic.

That’s a whopping 27 million mt of new LNG supply that will need vessels. This will be followed by another 40 million mt/year of new LNG projects in the US by 2020, adding to Atlantic basin shipping demand.

“This trend is important to watch because US liquefaction capacity is currently only about 1/3 of where it will be by the end of 2020. This means that as the US represents a greater and greater percent of global supply, the weighted average shipping distance should also start to trend upwards,” Jeff Moore, Head of Asia LNG Analytics at S&P Global Platts, said in the new report titled “Supercooled: The evolving LNG fleet driving the global gas boom.”

Platts Analytics estimates that the average shipping distance for US LNG has shown the most dramatic increase in the last 5 years, due to shipments to Asia. It also states that the average shipping distance for a US LNG shipment is 9,268 nautical miles, more than double the 3,936 nautical miles for Australian LNG.

“This could have major implications on spot shipping prices as the limited number of LNG vessels could be tied up, as they look to serve longer and longer voyages,” Moore said.

Hence, LNG shipping rates are more likely to head upwards than downwards for now.

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Australia’s bid to be the world’s largest LNG exporter may fizzle out

Australia’s bid to challenge Qatar as the world’s largest LNG exporter has been weakened by several factors including gas shortages, domestic supply commitments, natural declines at its LNG projects and the lack of a cohesive energy policy.

As a result, Australia is unlikely to overtake Qatar’s LNG export volumes for any meaningful duration on a sustainable basis, an analysis of production data showed.

In the most optimistic scenario Australia’s LNG exports may match Qatar’s for a few months in 2019 or 2020 when its production peaks, but the Pacific Rim nation will not be able hold its top position on an annual basis for very long unless circumstances change.

Australia vs Qatar LNG Exports

Qatar’s LNG export capacity is the highest in the world at 77 million mt/year, and the combined nameplate capacity of Australia’s 10 LNG projects put together is 88 million mt/year. The problem is that while Qatar consistently reaches full capacity, and sometime exceeds it, Australia’s projects consistently run up to 15% below capacity.

In fiscal year (June-July) 2017–2018, Australia exported 62 million mt of LNG as the last of its projects were ramping up. The government currently forecasts LNG exports to hit the 77 million mt/year mark in fiscal year 2019–2020, close enough to beat Qatar. But even Australia has its doubts.

“However, given the narrow difference between the projected exports of the two nations, Australia overtaking Qatar is not a certainty,” the Office of the Chief Economist said in its latest Resources and Energy Quarterly report.

Australia’s LNG exports will peak in 2020 at 79.4 million mt, but still remain below Qatar’s production of around 80.7 million mt on an annual basis, according to data from S&P Global Platts Analytics. After that Qatar’s goes into expansion mode to reach its 100 mtpa target by 2020.


Several factors have contributed to Australia’s lesser-than-expected LNG exports.

Much of the shortfall is from Gladstone on the east coast, that’s home to three LNG projects — Origin-ConocoPhillips’ Australia Pacific LNG, Shell’s Queensland Curtis LNG and Santos-led Gladstone LNG.

They exported 20.4 million mt of LNG in 2017 representing capacity utilization of 81%, with APLNG operating at 96% capacity, QCLNG at 78% and GLNG at 67%, according to Adelaide-based consultancy EnergyQuest.

These projects in Queensland state, based on onshore Coal Bed Methane or CBM gas, have been controversial for several reasons.

Conventional LNG projects are sanctioned on Proven or 1P reserves with 90% recoverability, but the Queensland projects were sanctioned on Proved Plus Probable or 2P reserves with 50% recoverability, according to EnergyQuest’s chief executive Graeme Bethune’s paper at the World Gas Conference 2018.

This was one of the first mistakes.

Bethune said two of the projects, QCLNG and APLNG, had sufficient CBM reserves at the 2P level, but GLNG barely had enough 2P reserves for one train in a two-train project.

But since a single train was not commercially viable, the two-train project went ahead with plans to source gas from domestic market conventional gas reserves like the Cooper basin and other CBM projects, including acreage in neighboring New South Wales, he said.

“The LNG industry in Eastern Australia is fundamentally weak because its elements were developed in the wrong order,” according to a 2017 study by the Institute for Energy Economics and Financial Analysis.

It said plants were approved with no consideration of the domestic market, CSG fields failed to produce the gas expected, the projects suffered huge cost overruns and the massive overbuild of LNG capacity resulted in the East Coast domestic markets being undersupplied.

The problems were exacerbated by state restrictions on gas development and the oil price crash that sucked up capex needed for funding upstream work at Australian companies like Santos and Origin Energy.

“Santos in particular cut drilling and prioritized buying gas from the domestic market rather than spending scarce capital on drilling. At the same time the lower oil price meant that any prospect of east coast shale gas development went out the window,” Bethune said in his paper.

Other factors like higher gas demand in the power sector, different states implementing divergent energy policies and the lack of national energy policy meant that gas shortages were imminent, with supplies caught between domestic demand and LNG export commitments on the east coast.

Backed into a corner, the Australian government introduced the Australian Domestic Gas Security Mechanism in 2017 to ensure domestic gas supply even if “LNG projects may be required to limit exports or find new gas sources”.

The political impasse on energy policy remains.

The Australian federal government hasn’t produced any energy projections since 2014, probably for political reasons, Bethune said last month, adding that east coast gas producers should prepare for heavy-handed political intervention over the next year.

This will take its toll on Australia’s LNG export capabilities.

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