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Analysis: Global Natural Gas Crisis Dampens Momentum For ‘Cleaner’ LNG

Europe’s energy crisis has cooled efforts to lower the carbon intensity of liquefied natural gas (LNG) shipments, as buyers worried about a winter supply crunch prioritize securing shipments of any kind over burnishing their green credentials.

Natural gas can be certified as low- or no-carbon if its producers can prove they have reduced greenhouse gas emissions associated with getting it to market, or if they purchase carbon offsets to cut its net climate impact.

But the number of deals to ship carbon neutral LNG around the world has dropped to less than 10 so far this year, from 30 in 2021, according to energy research firm Wood Mackenzie. And demand for the greener fuel has dried up, according to Reuters interviews with nine LNG market analysts, industry officials and traders.

“Lower carbon or carbon neutral LNG cargoes have lost their appeal in the current high price environment,” said Felix Booth, head of LNG at energy analytics firm Vortexa. “Energy security and affordability is front of mind for all buyers.”

The decline in international demand for the so-called “greener” gas is a potential setback in the fight against climate change because it removes a financial incentive for producers to reduce their climate impacts.

The market for such fuels had taken off a few years ago with a flurry of international deals that sparked industry optimism producers would be able to reliably cover their costs for cutting emissions or buying offsets – which can run into millions of dollars per shipload.

A 2021 study by Columbia University’s Center on Global Energy Policy pegged the premium on carbon-neutral LNG that year at about $1.75 million for a full cargo of around 100,000 cubic meters.

Several gas drillers, including in the world’s top gas producer the United States, told Reuters they have invested in finding and plugging greenhouse gas emissions associated with production, transport and processing.

But no LNG exporters in the United States have certified their facilities, according to both the liquefaction plant owners and certification company MiQ, which had hoped to land contracts with them this year.

Undermining the market are sanctions and disruptions stemming from Russia’s war in Ukraine. Since Russia’s Feb. 24 invasion of Ukraine, gas prices have soared about 25% in the United States and 32% in Europe .

While gas produces fewer emissions than coal when burned, it can still contribute significantly to climate change by leaking into the atmosphere from drill pads, pipelines and other equipment. The main component of gas is methane, a greenhouse gas more powerful than carbon dioxide during its first 20 years in the atmosphere.

More than 100 countries have pledged to slash methane emissions by 2030 and are expected to detail their plans at a climate summit in Egypt next month.

SOME DRILLERS FORGE AHEAD

Despite the drop in demand for greener LNG, many drillers are tamping down their methane leaks, under pressure from regulators, investors, and big customers.

About a quarter of gas drilled in the United States is being certified to reflect its improved emissions intensity, by companies like Project Canary and MiQ, according to those firms. About a third of U.S. supply should be certified by the end of the year.

Civitas Resources Inc (CIVI.N), a Colorado driller, for example, said it has continued to measure emissions from its operations and certify its facilities even though it stopped seeking price premiums.

“As this market evolves, we believe there will be long-term demand for certifiably cleaner natural gas products,” Civitas Chief Sustainability Officer Brian Cain said.

Drillers EQT Corp (EQT.N) and Chesapeake Energy Corp (CHK.O) are among the other U.S. gas producers certifying supply.

But exporters of gas appear to be lagging.

To export gas, the fuel must be supercooled into LNG and then shipped across the sea, a process that produces substantial additional greenhouse gas emissions.

MiQ early this year said it expected to be certifying U.S. LNG cargoes within months. To date, however, U.S. LNG companies have yet to certify their facilities.

Cheniere Energy Inc (LNG.A), the top U.S. LNG producer, said it has provided emissions information for all cargoes shipped since June, but has not partnered with third-party certification programs.

It declined to disclose the emissions details of its shipments to Reuters.

Other U.S. LNG suppliers, like Cove Point LNG and Cameron LNG, also told Reuters they are not certifying their cargoes.

Vincent Demoury, secretary general of the International Group of Liquefied Natural Gas Importers (GIIGNL), said LNG exporters may be hesitating because passing on the cost of carbon offsets is difficult in a high-priced environment. But he said he expected the outlook to eventually improve.

Reuters by Nichola Groom, October 21, 2022

ARA Oil Product Stocks Level on the Week (Week 42 – 2022)

Independently-held refined oil product inventories in the Amsterdam-Rotterdam-Antwerp (ARA) area dropped.

The latest data from consultancy Insights Global show the biggest loss was in gasoline. This was probably a response to the series of refinery closures in France caused by strikes, as supplies head to that country in attempt to fill the big supply gap.

Exports to the US increased, where there are concerns of low stock levels for road fuels. Diesel stocks dropped on the week for the same reason.

Naphtha stocks built up again on the week, as demand from the petrochemical sector remains low because running petrochemical facilities is currently very expensive as natural gas prices remain high.

Demand in Asia may have started to increase though, as shipments from the Mediterranean region to ARA have fallen, which suggests some supply is going to Asia.

Fuel oil stocks dropped on the week, with cargoes departing for Italy and west Africa. It was also suggested that there is more demand in Singapore, with arbitrage economics supportive of that route from Europe.

Jet fuel stocks in ARA went up on the week, with cargoes arriving from South Korea and the Mideast Gulf, as demand in Europe begins to fall with the start of the winter months.

Reporter: Bea O’Kelly

Infrastructure Investments for LNG

On April 11, 2022, it was announced that a “heads of agreement” (HOA) was signed by TotalEnergies (Total) with Sempra Infrastucture, Mitsui & Co. ltd and Japan LNG Investment. Sempra Infrastructure owns 50.2% of the project while Total, Mitsui and Japan LNG Investment each own 16.6%

According to TotalEnergies’ Chairman and CEO Patrick Pouyanné: “The expansion of Cameron LNG will contribute to our LNG growth strategy by investing in low-cost, long-term competitive LNG projects with lower GHG emissions.” This statement from the CEO was given to the public as a way to justify expansion of the Cameron LNG project located in Louisiana, USA.

This HOA is significant because the companies agreed to jointly increase production capacity to more than 6.75 mn tonnes per year (tpy). They also agreed to add a fourth train to improve on debottlenecking of the plant. Moreover, the project is seen as a way boost exports of USA LNG in the wake of recent events by Russia to affect Europe’s energy supply.

If Norway’s Equinor took the initiaive to help and solve Europe’s energy crisis, then it seems France’s TotalEnergies is striving to take the lead in promoting Europe’s energy transition. The HOA is an indicator of how seriously the company is taking its ambitions to push Europe forward on the energy transition.

Per OilPrice.com, the French supermajor is the world’s largest exporter of USA LNG and the second-largest LNG trader.

With the final investment decison on the Cameron LNG project to come in 2023, Russia’s invasion of Ukraine has raised concerns of how more exports of USA LNG can be carried out in the present. On March 25, 2022, a deal between the USA and European Union (EU) was initiated for the USA to increase deliveries of LNG to EU markets in the amount of 15 billion cubic meters. This circumstance reveals how critical USA LNG is to the EU’s energy supply mix.

TotalEnergies has been in business with USA LNG since September 2016 when the company acquired 75% of the Barnett Shale assets in North Texas from Oklahoma City-based Chesapeake Energy. Due to declining production, the Barnett shale assets are set to bottom out around 2028. What’s important here is that the production capacity at Total’s Barnett shale fields will allow the company to regasify its natural gas reserves into LNG at Cameron, in order to transport and export the natural gas from USA to Europe, Asia and African markets.

TotalEnergies is also launching North America’s first Cabon Capture & Storage (CCS) project at the Hackberry Carbon Sequestration (HCS) project. According to Thomas Maurisse, senior vice president LNG at TotalEnergies:

We are pleased to join forces with our partners to significantly reduce CO2 emissions at Cameron LNG export terminal, thus enabling us to supply our customers with low-carbon LNG, a key fuel for the energy transition and a valuable asset for diversifying Europe’s energy supply

It’s essential to point out that even when the largest companies are pushing for ways to successfuly carry out Energy Transition around the globe, that committments to natural gas production and exports via LNG will continue to grow over time. TotalEnergies even highlighted in its 2021 Energy Outlook that natural gas and renewable energy sources would play complementary roles to achieving the energy transition toward Net Zero.

One of the concerns is how geopolitics and international events are going to affect the global energy outlook and prospects.

For instance, Algeria and Morocco have both announced plans to source more gas reserves to the benefit of TotalEnergies, Eni and USA exporters. But underlying political and territorial issues between those two countries are inevitably going to be a major problem. Algeria cut off Morocco’s access to its gas pipeline in 2021 after Morocco announced that it would develop LNG terminal capacity.

Upstream has been writing about energy companies that are exploring Africa’s potential for LNG pipeline infrastructure as an alternative to Russia and Persian Gulf producers. For instance, Siva Prasad of Rystad Energy said “Asian and European importers will need to consider African priorities as they develop projects, as many African producers are focusing on supplying energy locally as well as to intra-African markets, along with catering to global markets.” Prime examples include a a proposed natural gas pipeline from Tanzania to Zambia.

This summer is already signaling a competition for LNG tankers among the world’s largest energy companies — TotalEnergies, Shell, China Unipec — to stock up on LNG supplies ahead of the winter season in 2022. Because of this trend the price of LNG carriers is rising to the highest levels in 10 years, at around $120,000 a day, as LNG import demand is expected to grow higher and higher for developed countries.

Here’s another illustration of how more infrastructure investment is needed for FLNG. According to Spanish Energy Minister Teresa Ribera a gas pipeline from Portugal, through Spain, could be built in less than one year for the benefit of France, Spain and other European energy consumers. Calling it a “new interconnection” German Chancellor Olaf Scholz agreed that the pipeline would be beneficial to Europe’s energy supply dilemmas.

This is essentially an issue of increasing liquified natural gas (LNG) imports to Europe. With the capacity of Portugal to receive LNG at its terminals on the coastline, it is a perfect way for France to receive more imports of LNG.

However, this plan has been in the works since 2019 as the Spanish grid operator Enagas called for the pipeline to be abandoned.

By Medium, September 20, 2022

Column: Recession Will Be Necessary to Rebalance the Oil Market

Unused capacity in global oil production has fallen to exceptionally low levels, contributing to the intense upward pressure on prices until very recently.

Restoring spare capacity to more comfortable levels will require a business-cycle downturn, which is why a recession or at least a serious slowdown is inevitable.

In common with inventories of crude and products, and new oilfields with rapid development times, under-utilised oil wells and refineries act as shock absorbers in the global petroleum system.

ut since the middle of 2020, all these sources of flexibility have eroded, leaving the market much vulnerable to shocks arising from unexpectedly strong consumption or any disruption to production.

U.S. petroleum inventories including the strategic petroleum reserve have depleted to the lowest seasonal level since 2008.

U.S. shale producers, who supplied almost all the increase in global crude production between 2010 to 2019, are now opting to limit growth to enjoy higher profits.

As a result, spare global production capacity has shrunk and is equivalent to just 1.5% of global consumption, according to Saudi Aramco (“Remarks by CEO Amin Nasser at Schlumberger Digital Forum”, Sept. 20).

Unless and until some of these shock absorbers are rebuilt to more comfortable levels, oil prices are likely to remain high and on an upward trend.

Based on experience, however, inventories and spare capacity will only rise when the global economy enters a period of sub-trend growth or an outright recession.

RECESSIONS AS RESETS

Profit-maximising enterprises do not intentionally invest in higher oil inventories or spare production capacity.

Instead, oil stocks and spare capacity increase unintentionally when consumption proves lower than anticipated because the business cycle suddenly slows.

Large increases in stocks of crude and fuels occurred as a result of recessions in 2001/02, 2008/09 and 2020, and mid-cycle slowdowns in 1997/98 and 2014/15.

There is no counter-case where inventories have risen significantly while business activity has continued expanding rapidly.

Inventories rise when and only when the business cycle slows unexpectedly, and the same is true about production capacity.

Severe recessions leave permanent impacts on oil production and consumption and temporarily result in spare capacity in their aftermath.

Recessions in 1974, 1980, 2008 and 2020 all left oil production and consumption on a permanently lower trajectory than before.

In the first instance, the recessions induced a larger and faster fall in consumption than production, causing inventories to accumulate and resulting spare capacity.

Over time, however, production responded more aggressively as a result of lower investment, while consumption rebounded as the recessions faded.

As a result, inventories have depleted and spare capacity has been reabsorbed in the years following a recession, until prices started rising to restrain consumption growth and encourage more investment in production.

In each case, inventories continued to deplete and spare capacity continued to fall, resulting in consistent upward pressure on prices, until the next business cycle slowdown occurred.

There is no recorded instance where spare oil production capacity rose when the global economy continued to grow strongly.

There is no evidence producers have ever deliberately invested in spare capacity simply to provide more shock absorption or limit further price increases.

Spare capacity in Saudi Arabia and some other Gulf states in the 1980s, 1990s and again in the 2010s was the legacy of business cycle slowdowns in 1980, 1992, 1998 and 2015.

MONETARY POLICY

The same link between spare capacity and business cycle slowdowns has been present in other capital intensive industries such as mining.

It explains why inflationary pressures are cyclical, subdued in the immediate aftermath of a recession, when spare capacity is plentiful, then building progressively as the expansion matures and spare capacity erodes.

It also explains why it was inevitable the U.S. Federal Reserve and other major central banks would be forced to tighten monetary policy aggressively as the current expansion became more mature.

Inflationary pressure stemming from shortages of spare capacity energy markets and other industries had already been intensifying throughout 2021, well before Russia’s invasion of Ukraine in February 2022.

As many commentators have pointed out, the Federal Reserve and other central banks cannot reduce inflation by producing more barrels of oil, cubic metres of gas, and megawatts of electricity.

But they can slow the economy enough to bring energy demand growth back into line with the trend in available production, rebuild inventories, and increase spare capacity to more comfortable levels.

By Reuters, October 11, 2022

Eesti Gaas CEO: Gas Market Competitiveness Needs Access to LNG Terminal

The CEO of natural gas supplier Eesti Gaas, Margus Kaasik, says that while gas prices have started to fall, it is difficult for suppliers to retain market competitiveness without direct access to a Liquefied Natural Gas (LNG) terminal, such as that recently completed in Paldiski.

Appearing on ERR radio news show “Hommik” Tuesday, Kaasik said that while currently LNG from the US and Norway is reaching Estonia via the long-established floating LNG terminal in Klaipeda, Lithuania: “In October and November, weill bring two large shiploads of LNG; one large ship constitutes 1 TWh, while, to put it into context, Estonia’s current [annual] consumption is 3-4 TWh, or three or four such ships, meaning this way Estonia’s annual supply could be guaranteed.”

According to Kaasik, no decision has been made regarding the location of the floating terminal, a vessel specially fitted-out for the purpose and which could be located on either side of the Gulf of Finland, both because there are now the required facilities in both cases (in Paldiski, and in Inkoo, Finland) and because the Balticconnector pipeline links the two countries in any case, though: “At the moment, the signs are that it will go to Finland. This is my opinion, and there is no decision yet. It could also come here, but it is more likely that it will go to Finland.”

In any case, in the normal run of things, Kaasik said, this is immaterial whether the ship is located in Finland or Estonia, though we are not living in normal times. “We can always bear in mind that if we have a pipeline we have gas, and for the most part we do, but given the world we’re in today, that may not be the case indefinitely,” he said.

The uncertainty of the gas market through the summer led to market participants focusing mainly on selling gas domestically.

Kaasik said: “There were minimal sales in other countries. For Eesti Gaas it is the same. At present we are clearly feeling a greater responsibility for the Estonian consumer than for the customer in Finland, Latvia or Lithuania. We have almost never made supply offers elsewhere. The same is true elsewhere.”

“In other words, when the situation is good, the market works. But if problems arise, the market may not guarantee things, then it no longer matters who owns the gas, and so to speak, neither gas nor money have any ‘nationality’. Well, if trouble is at hand, that’s the case.”

At the Klaipeda terminal, the capacities were mainly taken on by Lithuanian and Polish companies, he said, despite attempts to do so on the part of Estonia.

“We also wanted to obtain long-term capacity from Klaipeda; six vessels were offered for 10 years, or 6TWh for six years. This would have been perfect, and we could also have signed longer-term contracts with suppliers. The option was made in such a way that Lithuanian companies were partly preferred, which is understandable. For the remainder, in terms of this, one parcel was given to [Lithuania’s] older brother, so to speak, the Poles, and the other to their Latvian neighbor, who has gas storage and gas-powered plants and who, unfortunately, was seen as being of a greater value than us,” Kaasik said.

In order to be competitive in an LNG-based gas market, access to an LNG terminal is required, he concluded.

He said: “In England, almost 30 energy companies have gone bankrupt because they simply haven’t been able to cope in today’s very difficult market today.”

“Our wish is that we will still get vessel at the beginning of the year, but the case can also be different. Of course, we still hope that we will get our share of this Finnish-Estonian terminal, but we will probably have to fight hard for it,” he said.

At the same time, the price of gas has started to fall, Kaasik noted. “The price rose steeply until the end of August, after that it actually started to fall. I would like to believe that the Russia’s ‘natural gas war’ will peter out, and the price will move towards normalcy. It is still relatively far from that, but the trend at the moment is quite okay,” he said.

By ERR News, October 11, 2022

New Independent Study Confirms Bio-LNG’s Role in Shipping’s Decarbonisation

A new study commissioned by SEA-LNG has found that liquified bio-methane (bio-LNG) can make a major contribution to maritime decarbonization.

Conducted by the Maritime Energy and Sustainable Development Centre of Excellence (MESD CoE) at Nanyang Technological University, Singapore (NTU Singapore), the study explored questions around fuel availability, cost, lifecycle emissions and logistics, providing an overview of the applicability of bio-LNG as marine fuel.

It also investigated the feasibility of LNG and bio-LNG as a realistic pathway for the shipping industry to achieve greenhouse gas emission reduction targets in a sustainable manner.

Bio-LNG can be blended with fossil LNG in relatively small amounts to reach the 2030 International Maritime Organization targets and the biofuel proportion in the mix can be increased to meet 2050 targets.

The findings suggest that pure bio-LNG could cover up to 3% of the total energy demand for shipping fuels in 2030 and 13% in 2050. If it is considered as a drop-in fuel blended with fossil LNG, bio-LNG could cover up to 16% and 63% of the total energy demand in 2030 and 2050, respectively, assuming a 20% blending ratio.

In the long term, shipowners who have invested in the LNG pathway will need to shift to renewable synthetic LNG (e-LNG).

The report also forecasts that the average cost for delivered bio-LNG will fall by 30% by 2050 compared to today’s values, mainly driven by the reduced cost of producing biomethane in large-scale anaerobic digestion plants.

This makes bio-LNG one of the cheapest sustainable alternative marine fuels, compared to biomethanol and electro-fuels, including e-ammonia and e-methanol.

Furthermore, the report highlights that the uptake of bio-LNG in shipping will be linked to the widespread use of biomethane across other sectors.

This will require national and international standards for biomethane injection into gas grids, plus a commonly accepted certificates of origin scheme to efficiently trade biomethane in its gaseous and liquefied forms and to minimise transportation costs.

Peter Keller, Chairman, SEA-LNG, said: “The decarbonisation of shipping will require the use of multiple low and zero carbon fuels. Every fuel has its own individual, but similar, pathway to net zero. When assessing decarbonisation options for the maritime sector it is essential that each pathway is properly evaluated, not simply the destination.

It is crucial that decision making is guided by accurate information that assesses each alternative fuel pathway on a like-for-like and full life-cycle basis (Well-to-Wake).”

Keller added: “The viability of the LNG pathway depends on the volumes of bio-LNG and e-LNG that become available to the shipping industry, and the cost of these fuels in comparison to other zero or low carbon fuels.

This latest study from the Maritime Energy and Sustainable Development Centre of Excellence at Nanyang Technological University, Singapore, confirms that bio-LNG is a solution for the decarbonisation of the shipping sector thanks to the mature and commercially available technologies for fuel production and use on-board, existing delivery infrastructure plus the competitive cost compared to other sustainable biofuels and electro-fuels.”

Associate Professor Jasmine Lam, Centre Director, MESD CoE, NTU Singapore, said: “Our research concludes that bio-LNG, produced from sustainable biomass resources, has the potential to meet a significant proportion of future shipping energy demand.

The findings show that bio-LNG is among the cheapest sustainable biofuels and can potentially offer significant cost advantage over electrofuels by 2050.”

Bruno Piga, Research Consultant for MESD CoE, NTU Singapore, added: “Bio-LNG can provide up to 80% greenhouse gas emissions reductions compared to marine diesel if methane leakage in the production process and on-board methane slip are minimised. It can be used as a drop-in fuel in existing LNG-fuelled engines and can also be transported, stored and bunkered in ports using the existing LNG infrastructure. This reduces logistics costs considerably compared with other alternative fuels.”

By Hellenic Shipping News Worldwide, October 7, 2022

LNG Markets May Tighten Further In 2023, IEA’s Birol Says

LNG markets in 2023 may be tighter than this year as demand may rise in China, India and other parts of Asia, the head of the International Energy Agency (IEA) said on Thursday.

“We may well see that the LNG markets in 2023 will be rather tight, maybe tighter than this year,” said Fatih Birol in remarks at the LNG Producer-Consumer Conference in Japan.

Global gas prices have surged to record levels this year, as Russia’s gas supply cuts have placed enormous strain on the European and global market.

High wholesale gas prices in Europe has seen the bloc import record amounts of LNG cargoes, drawing in volumes from top importing region Asia.

Birol also added that Europe has received a substantial amount of LNG this year, with imports increasing “by a staggering 60%”.

“One of the reasons why Europe can draw so much LNG is that China … (saw) sluggish economic growth this year,” he said.

“If the Chinese economy recovers … it will be difficult for Europe to attract so much LNG.”

China’s imports of LNG are on track to post their first major decline this year, as high prices and weak manufacturing due to COVID-19 lockdowns crimp demand for the super-chilled fuel.

The country became the world’s top LNG buyer last year but surrendered the top spot back to Japan in the first four months of 2022.

Should Japan restart their nuclear power plants, it would free up about 10 billion cubic metres (bcm) of LNG and “help the global LNG market,” said Birol, without specifying a timeframe.

Birol had made similar remarks on Tuesday, saying that Japan’s restart of more nuclear power plants would help ease Europe’s energy supply fears during the winter as more LNG will become available to the global market.

By Reuters, October 4, 2022

Global LNG Floating Storage Hits Record High On Steep Contango Ahead of Winter

The number of LNG carriers being used as floating storage globally has hit a record high as oil majors, commodity traders and other energy companies hold onto LNG cargoes and vessels ahead of peak winter season, according to shipping data and shipbrokers.

The accumulation of a large number of laden LNG carriers without a fixed destination is underpinned by several market fundamentals – the steep contango between November and January that could yield a profit, regions like Europe and North Asia entering early winter with strong inventories and the possibility of a surge in demand in the event of a spell of cold weather.

The Ukraine crisis has resulted in a tight LNG market, and along with some recent supply disruptions like the one at Freeport LNG in the US, LNG cargoes are likely to be heavily sought after in the coming weeks and months, both for energy security and to boost trading positions.

There were as many as 33 LNG carriers in floating storage in the week of Sept. 19, which eased towards the end of the month but rose again to around 31 LNG carriers at the start of October, according to data from S&P Global Commodity Insights.

This is higher than the last time LNG floating storage hit a record high, at almost 30 vessels in mid-2020, when a steep contango along the forward curve incentivized traders to float their ships and hold onto the cargoes ahead of early winter procurement.

In the winter of 2020-21 there were almost no LNG carriers in floating storage as demand had collapsed due to COVID-19 and maximum floating storage in the winter of 2021-22 was only in the mid-teens, S&P Global data showed.

The current contango, where prompt prices are lower than those further out on the curve prices, is steep.

In the first half of September, when Platts JKM — the northeast Asian LNG benchmark — was being assessed for October delivery, the market structure two months forward was still in a modest contango structure. But after the assessment moved into November delivery, the contango structure strengthened significantly, with the Nov-Jan contango as wide as $7/MMBtu, which strongly supported storage economics.

Vessel shortage

Energy companies and commodity traders have been accumulating LNG carriers for a storage play for several months. As early as mid-2022, market participants were indicating that 6-12 month charters for LNG carriers had become very popular, and by the third quarter spot LNG vessels were already hard to come by.

Strong demand for storage has also created a shortage of LNG vessels and contributed to the current surge in spot LNG freight rates, which have risen to around $300,000/day from under $50,000/day in a span of 45 days.

“Charterers still have a close eye on the contango into December and January, and hence interest on tonnage that can cover winter months remains strong, thereby elevating the forecast rates further,” shipping brokerage Fearnleys said in its latest weekly report.

The brokerage said that in the west shippers are focusing on demand for two-stroke LNG vessels, but that availability is almost non-existent, especially when market players are awaiting further updates on the outage at Freeport LNG and do not wish to reveal their market length.

“It is a very tight market. There are only some steam turbine LNG vessels available but they are not the ideal candidate for floating storage as such ships will have much more boil-off,” an LNG ship broker said. Boil-off refers to the LNG that is lost due to vaporization during storage.

The broker said there are no vessels available with ship owners and charterers have to rely on sublets, if any are available, and the freight rate is really up to the company that is controlling shipping assets.

“In the past seven to 10 days, due to scarcity of two-stroke vessels in the market, even the steam turbine ships have been considered by traders who really want to float the cargo,” another broker said, adding that with the market in contango, traders no longer care about the cost.

By Hellenic Shipping News, October 7, 2022

Commodities Worth $394m Traded at IME in a Week

During the past Iranian calendar week (ended on Friday), 1,961,849 tons of commodities worth $394 million were traded at Iran Mercantile Exchange (IME).

As reported by the IME’s Public Relations and International Affairs Department, the exchange traded on its metals and minerals trading floor 1.627 million tons of commodities valued at almost $223 million.

On this floor the IME sold 924,013 tons of cement, 293,000 tons of iron ore, 256,070 tons of steel, 152,000 tons of sponge iron, 355 tons of zinc, 5,575 tons of aluminum, 1,200 tons of copper, 200 tons of molybdenum concentrate, 7 kg of gold bars and 143 automobiles.

Furthermore, the IME witnessed on both domestic and export rings of its oil and petrochemical trading floor 328,480 tons of commodities worth more than $167 million.

Commodities traded on this floor included 83,893 tons of polymeric products, 103,000 tons of vacuum bottom, 34,000 tons of lube cut, 27,160 tons of chemicals, 36,000 tons of sulfur, 3,135 tons of base oil, 540 tons of insulation and 71,802 tons of bitumen.

The IME also traded within the same week 5,756 tons of commodities on its side market.

As previously reported, 9,857,062 tons of commodities worth more than $2.4 billion were traded at Iran Mercantile Exchange during the past Iranian calendar month (ended on September 22).

As reported, the exchange saw on both domestic and export pits of its oil and petrochemical trading floor, trade of 1.616 million tons of commodities valued at more than $882 million.

The IME’s customers purchased on this floor 428,010 tons of vacuum bottom, 437,720 tons of bitumen, 424,602 tons of polymeric products, 142,900 tons of lube cut, 138,754 tons of chemicals, 25,900 tons of sulfur, 18,692 tons of oil and 1,980 tons of insulation.

Furthermore, the exchange saw trade of more than 8.187 million tons of commodities worth more than $1.5 billion on its metals and minerals trading floor.

Items traded on this floor included 4,362,000 tons of cement, 1,727,000 tons of steel, 1,541,000 tons of iron ore, 458,500 tons of sponge iron, 36,000 tons of aluminum, 74,400 tons of zinc, 24,980 tons of copper, 790 tons of molybdenum concentrate, 200 tons of coke, 72 tons of precious metals concentrate and 92 kg of gold bars.

Last was the IME’s side market on which the exchange traded 52,986 tons commodities.

The value of trades at Iran Mercantile Exchange rose 102 percent, and the volume of trades at the exchange increased 128 percent in the past Iranian calendar year 1400 (ended on March 20), which was the highest level of growth in the history of the exchange since its establishment.

Statistical data show that in the past year, in addition to new records in the volume and value of trades of different products, 10 major records in total value and physical market trades were registered. In a way that besides the total value of trades, the volume and value of physical market trades, the volume, and value of industrial products and petrochemicals trades, the value of oil products trades and the volume and value of side market trades all hit records.

IME is one of the four major stock markets of Iran, the other three markets are Tehran Stock Exchange (TSE), Iran’s over-the-counter (OTC) market known also as Iran Fara Bourse (IFB), and Iran Energy Exchange (IRENEX).

By Tehran Times, October 6, 2022

U.S. Refiners Eye Canadian Oil Once Strategic Reserve Turns Off Taps

U.S. refiners are expected to buy more Canadian oil after the Biden administration ends releases from the Strategic Petroleum Reserve (SPR) this fall, traders said, adding this should boost the price of Canadian barrels at a time of tight global supply.

The coming end of SPR releases could shift market dynamics again in a year of high volatility following Russia’s invasion of Ukraine in February. In March the White House announced it would release 180 million barrels from the U.S. strategic reserve to help quell high prices.

The releases have weighed on the price of Western Canada Select (WCS), the benchmark Canadian heavy grade. That oil, because it has similar qualities to the sour crude that dominates U.S. reserves, has traded at around $20 a barrel below U.S. West Texas Intermediate (WTI) crude for much of the summer. In 2021 the average WCS discount was $12.78 a barrel, according to the Alberta Energy Regulator.

The WCS discount to WTI is expected to narrow as the SPR supply dwindles, market sources said.

“Once that overhang goes through, and it may not be in Q4 or Q1 but in Q2 and beyond, we should see a much stronger differential than where we are right now,” one trader said. He added that he expected WCS traded in Alberta to be around $14 or $15 a barrel under WTI next year, compared with about $21 now.

However, increased medium sour crude production from OPEC countries such as Saudi Arabia, as well as discounted Russian Urals, could keep that differential wider, according to RBN Energy.

Canadian crude exports from the U.S. Gulf have dropped in the last two months, falling to around 130,000 barrels per day (bpd) in July and August, below last year’s pace of 200,000 bpd, said Matt Smith, lead oil analyst for the Americas at Kpler. Foreign buyers have turned to discounted Russian barrels, tempering Canadian crude exports.

“It’s a bit of a game of musical chairs,” Smith said. “When the SPR releases finish, these refiners will look to lean harder again on Canadian barrels or seaborne imports.”

Some market participants worry that limited pipeline capacity from Canada to the United States could cause bottlenecks. This could cause a glut in the Alberta hub, which could in turn drive down prices there.

Canada hit record production of 5.5 million barrels a day of oil in 2021, according to the U.S. Energy Information Administration, and is forecast to reach 5.7 million bpd this year.

Enbridge Inc (ENB.TO) is once again rationing pipeline capacity, in a practice known as apportionment, on its Mainline system as Canadian output has risen. That system ships the bulk of Canadian crude exports to the United States.

Apportionment fell steeply last year when the Line 3 pipeline expansion opened and stopped entirely from March until July, but Enbridge has since started rationing capacity on its Mainline again. Crude deliveries into the Kerrobert, Saskatchewan, hub were apportioned by 2% in August and 6% in September, Enbridge said.

Reuters by Stephanie Kelly, October 7, 2022