Is Europe’s Cross-border Infrastructure Prepared for Handling More Regasified Lng?

A substantial increase in imports to the UK, Spain and France has not only provided more volumes to the three countries’ market areas, but also brought much-needed relief to a stretched regional market.

LNG Importers Have Enough Volumes to Share

For many months now, Europe has remained the most attractive destination for spot LNG marketed by producers and trading companies. And this past month was no exception. In April 2022, the total daily average send-out from three British, six Spanish and four French regas facilities increased by about 30pc as compared to the similar period in 2019-2021.

Higher LNG imports drove wider discounts for the prompt products at NBP, PVB and PEG to the neighbouring markets. For instance, the spread between the German day-ahead contract and its French counterpart averaged €11.5/MWh in April versus just over €3/MWh in March. The corresponding NBP product was assessed approximately €30/MWh below the TTF equivalent last month, while in March the price difference between the hubs did not exceed €4.5/MWh on average.

Naturally, this created more export opportunities for shippers active on the LNG receiving markets, which is particularly evident in the UK. Between 1 and 29 April, net exports via the Interconnector and BBL pipelines averaged 65 mcm/d compared with 20 mcm/d in the period from January to March 2022. Had the unplanned maintenance begun on the Interconnector in late April, last month’s flows from the UK to Belgium and the Netherlands might have been even higher.

The influx of LNG supply to Europe could not have come at a better time, given the traditionally volatile weather conditions during the shoulder period and the necessity to fill the region’s low gas stocks.

Limited Infrastructure

At the same time, strong LNG arrivals have highlighted the importance of having adequate cross-border capacity so that volumes are effectively allocated between market areas. Bacton exit capacity limitations and the inability of the Obergailbach-Medelsheim border point and VIP Pirineos to accommodate large flows are raising questions as to whether Europe is well placed to absorb abundant regasified volumes on a regular basis, especially in case of potential additions to LNG import capacity in France and/or Spain.

As the region becomes more dependent on seaborne cargoes, the role played by the exit points like Bacton or VIP Pirineos within the architecture of European gas market continue to evolve. A few years ago regasified LNG that was transported via many of those cross-border connections just complemented pipeline gas imports. In the new reality, easy and timely access to volumes sent from LNG terminals will increasingly define the sustainability of the whole system.

The opinions expressed in this blog are mine only and do not reflect the views of my employer.

Gas-to-Coal Switching Seems Like Option to Mitigate Energy Crisis in Europe. But Is It?

But despite a rapid growth in value, burning coal for electricity generation remains much more profitable than gas this year and through into 2023. It might seem that switching to coal is a good option for easing the current gas supply tightness within the region, but is it?

Not Much Room for Maneuver

In short, there is not much scope for coal-fired power output to further ramp up across Western Europe in the present market conditions.

The capacity factor for German coal units on average has equaled some 50pc year to date. If Germany’s coal plants started operating at ‘at least’ 70pc of their capacity, this would liberate up to 180 GWh/d of gas within the country. Add to this a rise to the 70pc level in Italy and the Netherlands, and an extra gas-to-coal switch would total 240 GWh/d.

On paper, such a shift may seem easy to implement, but in reality it is not that simple, to say the least. First, there are always technical limitations as well as maintenance works carried out, both planned and unplanned. Second, coal supply has been pretty short across the continent in 2022, with geopolitics only adding to competition among European players. Some of them even had to use coal as a substitute for wood pellets from Russia.

Third, you have interregional competition for coal cargoes available in the market. Amid high LNG prices, Asian companies need to look at alternative energy sources, among them coal. And the unwillingness of power generators in Japan and South Korea to buy Russian coal has left them with fewer supply options, thus intensifying competition with European importers.

Finally, historical data shows that the average daily capacity utilization of coal plants in Western Europe since the start of 2022 has been generally at or above the level of recent years. In the past five years, not including the year of 2020 due to a departure from coal-fired generation amid record low gas prices, German coal units operated on average at 44pc of their capacity. For the first three and a half months of 2022, this figure stood at 50pc. In Italy, this year’s capacity factor for coal plants has increased to 37pc as compared to the five-year average of 35pc, while in the Netherlands it has been 57pc vs. 62pc between 2017 and 2021.


Given the wide gap between the current gas price curve and coal switching range, it seems that most power generators which had the ability to maximize output from their coal units have already done that.

The opinions expressed in this blog are mine only and do not reflect the views of my employer

Gas Winter of 2022 Is Finally Over, but This Summer Also Shaping Up to Be Quite Unusual

European Natural Gas Market Fundamental Analysis

2021/22 gas winter at last came to an end and one would think that the European gas market can heave a big sigh of relief. But with the onset of injection season you can hardly expect Q2 and Q3 to become less busy than the winter months, with the summer 2022 shaping up to be very eventful.

Contrary to the fears of many, this past winter in Europe was warm enough to prevent some worst-case demand/supply scenarios from happening. When entering this summer period, the region’s underground gas storages were more than 25pc full, including strategic stocks. This is broadly in line with recent years, except for where the inventories stood in 2019 and 2020 due to then above-normal winter temperatures. But that is where the similarities end.

Summer 2022 Injection Season

A major difference from prior injection seasons is that this summer shippers should take into account the Commission’s regulation, requiring member states’ storages to be at least 80pc full by 1 November 2022. To reach this level, more than 55 bcm need to be injected into the storages across the continent, which is a feasible task but quite a challenging one. Especially since near-curve contracts are holding a premium to those with delivery in Q3 ’22, as at early April.

The success of meeting the 80pc target will very much depend on whether European buyers are able to maintain strong LNG imports throughout the whole gas summer. The current TTF-JKM spread contributes to spot sellers’ preference for the European market over Northeast Asia. But this may change rapidly once Asian importers get into the game.

Of course, there is nothing unusual about the competition for available seaborne volumes between the basins, whether it be summer or winter months. What is unique about the summer 2022 is that spot (and I stress this word) LNG cargoes have now become the region’s best hope for its successful preparation for the heating season.

The opinions expressed in this blog are mine only and do not reflect the views of my employer.

With Jaw-Dropping Gas Prices, Coal Is King Again in Europe

Natural Gas Prices and Coal Energy Production in Europe

Not long ago, it seemed that Europe on its path towards decarbonization should start departing from coal towards cleaner sources of energy. Personally, I wrote on several occasions that time for coal generation had actually run out across most of Western Europe. But, as often happens, the reality has become quite different.

One could hardly have expected as recently as Q1 2020, when coal-fired plants were in fact put on the sidelines amid record-low gas prices, that in a three-year time coal would recover its positions within the continent’s power generation mix. In Q1 2022, the share of electricity coming from coal in Germany rose to above 30pc as compared to just over 20pc in the period from January to March 2020. And this despite the fact that the country’s installed coal power capacity was reduced by approximately one fifth over the past three years.

With gas prices stuck at sky-high levels since late 2021, other Western European countries that possess any significant amount of coal power plants, namely Italy and the Netherlands, have followed the same trajectory.

And do you remember the last time NWE front-month clean dark spread for a 40pc-efficient unit stood lower than clean spark spread for a medium-efficiency gas plant? This happened most recently in July 2021. Since then the gap between the former and the latter has averaged some €60/MWh.


Record-high gas prices have provided perfect conditions for the renaissance in European coal power generation. Naturally, if there had been more nuclear capacity available in Germany for instance, the rise for coal-fired generation might have been somewhat more modest. However, strange as it may sound, coal has partially mitigated the effect of energy crisis hitting the continent in recent months.

The opinions expressed in this blog are mine only and do not reflect the views of my employer.

All Roads Lead to Europe´s Regasification Facilities

Of all major LNG producers, the US provides the largest number of flexible cargoes to the global market, and Europe made up the highest proportion of its weekly exports for the past four months. For the first time since the period between November 2019 and March 2020, Europe’s share in the US LNG exports exceeded that of Asia for so long.

With gas storage inventories standing at low levels and pipeline supply being tight, European buyers have actually had no choice but to rely on spot LNG. And geopolitics lifted TTF contracts to fresh record highs, thus leaving little chance for other regions to compete successfully for available volumes. Last week, more than 20 US-loaded LNG vessels were signalling arrivals at European regas facilities while only one cargo was sent towards Asia, according to Kpler data.

As there have been a strong demand for additional LNG imports from Europe in recent months, Asian importers remained relatively inactive in seeking spot cargoes. Amid above-average LNG stocks accumulated in Northeast Asia in the run up to this winter season, which has so far been much warmer than expected, average monthly exports of LNG from the US to China, Japan, South Korea and Taiwan combined were about 40pc lower YoY during the period between November 2021 and mid-March 2022.

Risk premium added to the European market has declined noticeably since early March, making spot LNG deliveries to Asia more profitable. The high-price environment may continue to somehow constrain the region’s demand for spot cargoes, especially among buyers in South Asia, but importers in Northeast Asia will find it much harder to stay away as terminal tanks need to be replenished ahead of the summer peak demand. The question is whether Asian buyers’ appetite for spot LNG will be strong enough to draw a significant number of cargoes away from Europe in the shoulder period.

The opinions expressed in this blog are mine only and do not reflect the views of my employer.

European Gas Far Curve Becomes Disengaged From Prompt Prices

If winter-delivery products did fall markedly during the period, the front summer did not lose much of its value over the period and far-curve prices actually rose since the year start.

The way demand/supply situation was evolving on the regional market in the first part of Q1 2022 (unseasonably warm and windy weather + record-high LNG imports to Europe) resulted in about 25pc fall in the TTF prompt contracts between 6 January and 18 February 2022.

As the gas winter nears its end, an injection-related demand issue is gradually coming to the forefront, thus supporting summer 2022 products. Tom Marzec-Manser from ICIS made a very good point the other day when pointing out that the total amount of gas in the EU and UK sites is now back to the five-year range. At the same time market participants’ concerns on low European storage levels will likely remain high throughout 2022, given near-record volumes that would be required for refilling tight inventories across the region.

You can find something more interesting further out on the curve. The TTF calendar 2023 and 2024 increased by 1pc and 18pc respectively from the beginning of January. While the 2023 calendar year is trading at far lower levels than prompt contracts, it rose more than twice YoY.

Far-curve price movements provide an understanding of how players assess the market’s fundamentals of the near future. Unlike the record prompt price spike that can be largely attributed to one-off events creating ‘a perfect storm’ for Europe, higher contracts covering 2023 and beyond show that, in the view of market participants, the high-price environment will pertain for quite a long time. The shift away from the period of global oversupply towards a seller’s market can be clearly seen through the back end of the curve.

The opinions expressed in this blog are mine only and do not reflect the views of my employer

Norway’s Gas Exports Firing on All Cylinders

Recently, many words have already been said on the impact that robust European LNG imports had on the region’s supply/demand balance in early 2022. But amid increased deliveries of seaborne cargoes to Europe another key gas exporter gets undeservedly little attention, even though it also has managed to fully seize the opportunities presented by the high-price environment. I am of course referring to Norway.

As gas hub prices reached record highs in Q4 2021, just as another period of seasonal maintenance on the NCS had been finished, Norway immediately maximized exports from its fields. Not surprising given that around 70pc of Equinor’s gas sales are day-ahead indexed with the remaining 30pc being tied to month-ahead prices, the company said during its quarter earnings conference call on 9 February.

Norwegian gas supplies rose year-on-year by more than 10pc in Q4 2021, while the average quarterly gas flows from the NCS to continental Europe and the UK surpassed 320 mcm/d for the first time since Q1 2019. In early 2022, exports from Norway remained close to the previous quarter’s level and if it had not been for some unplanned issues at Troll in January 2022, last month’s flows might even have exceeded those of December 2021 which amounted to approximately 335 mcm/d.

Among many indicators, there is one that illustrates particularly well to what extent Norwegian export capacity has been recently utilized. You just need to have a look at gas field injections and deliveries to the country’s exit points, which in the context of sky-high prices slowed down on average to below 2 mcm/d in the period from mid-October 2021 to mid-February 2022. To put it into perspective, between early 2019 and mid-October 2021 the amount of gas injected into the structure of fields and delivered to Norway’s exit points averaged almost 11 mcm/d.

Unless there are unscheduled outages on the production fields, Norwegian gas exports should remain elevated up to the end of April when the first batch of 2022 annual maintenance is planned at the country’s assets.

The opinions expressed in this blog are mine only and do not reflect the views of my employer


Warm and Windy Week Makes European Gas Prices Weak

Amid record-low storage levels, many players might have had serious difficulties in case of colder temperatures across the region this winter. But so far those pessimistic expectations have not been met, with the weather not destabilizing the supply/demand situation on the regional market.

Apart from the first few days of January, which in fact formed part of the unusual heatwave hitting Europe in this holiday season, the last two weeks have seen the warmest weather conditions since the start of the year. And in addition to above seasonal temperatures during this period, wind blew at its highest speed in much of Western Europe, within NWE in particular, since early December 2021. In late January 2022, wind speeds in Germany reached 8 m/s, compared to the seasonal norm of around 4 m/s.

The combination of warmer temperatures and stronger winds had an immediate impact on European gas demand, in both absolute and relative terms. Between 27 January to 3 February, the average daily consumption in NWE was approximately 10pc lower than for the period from 15 to 26 January. As the share of wind energy in Germany’s electricity mix jumped to 47pc in week 5, that of gas declined to below 10pc.

The reaction of European gas hub prices was not long in coming, especially given that the geopolitical factor took a back seat in early February while LNG cargoes continued to be delivered to the region in large quantities. On Friday, 4 February, the TTF Day-Ahead contract was assessed at €82/MWh, a 11pc decline from early last week.

Favourable weather conditions across Europe have brought some relief to the regional gas market, which was really on edge in recent months. For how long, that is the question.

The opinions expressed in this blog are mine only and do not reflect the views of my employer


So Far This Winter, Extreme Cold Bypasses Key Gas Markets

Amid multi-year low inventories at the European sites, market participants feared a repeat of extreme cold that had hit Asia, US and Europe one after another in early 2021. But unlike winter 2020/21, all the three regions so far have seen pretty mild temperatures.

For instance, Germany experienced around 820 heating degree days between 1 December 2021 and 23 January 2022, as compared to the 30-year average of approximately 860 HDDs. The weather was particularly warm during the Christmas season, with average temperatures in some European capital cities soaring more than 10°C above normal. In the first three weeks of January 2022, the average daily gas consumption in Germany, France, Netherlands and Belgium combined was down 7pc from that of the period between 2016-2021.

Despite La Niña´s cooling effect, severe cold waves have bypassed Northeast Asia this winter. Demand for additional cargoes remained limited within the region over the past month, thus paving the way for diversions towards Europe. Thanks to higher-than-average LNG inventories accumulated ahead of winter, some Asian importers now even have the opportunity to issue large sales tenders.

Winter 2021/2022 across the US has also been much calmer than a year ago. Since the beginning of 2022, Henry Hub spot price has gained almost 15pc against the background of higher heating-related consumption, but this month´s cold weather pattern is incomparable to what the country went through last year.

Gas market is already more than halfway through winter, with many fears about colder weather having not materialized. At the same time, February and March still lie ahead, leaving players cause for concern.

The opinions expressed in this blog are mine only and do not reflect the views of my employer

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As Gas Prices Fall, European Spark Spreads Get Closer to Darks

This is not surprising, given how much prices at regional gas hubs increased over the second half of 2021. At the beginning of this year, coal is still much more competitive for power generation than gas, but the gap between the two is no longer as remarkable as it used to be in mid-December.

Amid soaring natural gas contracts, coal products also rose significantly last year, but the latter’s gains had been somewhat modest when compared to the meteoric rate of the former’s price growth. While the ICE Endex TTF front-month surged by about 250pc between July and mid-December 2021, the European API2 coal monthly futures traded on the Chicago Mercantile Exchange went up by ‘only’ one-third over the same period.

As a result, the indicative NWE front-month baseload spread for a 40pc coal-fired plant averaged €65/MWh in Q3 and Q4 2021, with that for a 49pc-efficient CCGT being at minus €3.5/MWh. At its peak in mid-December, when gas prices reached a new record high across Europe, the difference between dark and spark spreads exceeded €200/MWh.

Within the past month, the premium of front-month clean dark spreads to clean sparks returned to its early November 2021 levels. This was caused by the drop in gas prices in late December, together with the influx of LNG supply into Europe and well above normal temperatures during the Christmas period, on the one hand, and higher coal prices due to Indonesia’s temporary ban on exports, on the other. In addition to that, EUAs have been trading on average at €81/tCO2 for the past month or so, as compared with €50/tCO2 between July and November 2021.

However, despite the narrowed gap between dark and spark spreads, gas is a long way from pushing out coal from the EU energy mix. With the region´s supply picture remaining tight and gas prices being at multi-year highs, utility companies are in particular need of cheaper alternatives.

The opinions expressed in this blog are mine only and do not reflect the views of my employer


As Europe Competing With Northeast Asia for LNG Cargoes, Other Importers Stand Aside

For much of the season, there are typically many clubs challenging for the EPL, Serie A, Bundesliga, La Liga or Ligue 1 titles, like there were multiple buyers competing for available cargoes up until Q4. But as the final part of competition approaches, a list of title contenders is often narrowed down to just two clubs, which in terms of the LNG market are Northeast Asia and Europe.

As recently as in mid-Q3, large quantities of LNG, including a substantial amount of spot cargoes, were directed outside Europe amid unprecedented demand in other parts of the globe. In August, LNG imports to South Asia, Latin America and the Middle East totaled about 6 million tons, while only 4.7 million tons were delivered to the European terminals during that month, according to Kpler. Seasonally stronger consumption in those regions, paired with restricted power generation from some alternative energy sources, deprived Europe of a significant portion of seaborne volumes.

As Q4 was coming closer, things started to change with once active buyers in the spot market stepping aside one after another and Europe recovering the lost ground in the LNG importers league. Between August and November, cargo deliveries at the regas facilities in South Asia, Latin America and the Middle East fell by approximately 40pc, while a record jump in prices at European gas hubs resulted in a 60pc rise in LNG imports to the NWE and Mediterranean ports over the same period.

Outside of Northeast Asia and Europe, some buyers had to restrict imports in a high-price environment and switched to other fuels, as in the case of Chile that found in gasoil a substitute for LNG. Others, like Middle Eastern players, cut their purchases due to lower demand for air conditioning, after a peak in July and Aug. Even Brazil had to retreat to the sidelines, with the need for LNG decreasing to a four-month low in November against the backdrop of increased hydroelectric power generation.

Intense competition on the global LNG market is now happening between buyers in Northeast Asia and Europe. Although the former were managed to build up above-average inventories at the LNG terminals in the lead-up to the coldest months in the Northern Hemisphere, La Niña threatens to strain supply in Asia-Pacific. As for the latter, stable LNG inflows are of particular importance to Europe, given record low stocks of gas in the underground storages.

By and large, the winner of the competition between the two regions is known well in advance. However, again making a parallel between the LNG market and European football, unexpected events occasionally occur, as happened with Leicester City’s 2015/16 Premier League title or LOSC Lille’s 2020/21 Ligue 1 title win 😉

The opinions expressed in this blog are mine only and do not reflect the views of my employer.


Europe’s LNG Imports on Rise, Flows To Asia Unaffected

After a long break, European terminals started to receive large quantities of vessels only in recent months, which among other things eased the supply/demand situation. But Asia’s imports slowed down just for a while, and with colder weather approaching, the region’s players should hunt for cargoes with renewed vigour.

In October, aggregated LNG imports to Europe amounted to more than 7 million tonnes, increasing by 60pc from this year’s lowest monthly level in July. Deliveries to NWE and Mediterranean are expected to grow further in November, according to Kpler data.

Europe’s energy crisis reached its acute stage in late Q3 and early Q4, resulting in unprecedentedly high gas prices, which in turn helped to significantly improve the economics of delivering LNG to the region as compared to the previous months in summer. For instance, a trader buying a cargo on an FOB basis in the US Gulf in late September for delivery to the Dutch TTF could make five times as much as in early July. It is not surprising, then, that the European regas facilities imported over 2 million tonnes from the US in October, for the first time in five months.

Now what about US cargo shipments to Asian countries, given a significant rise in Europe-bound supplies?

Actually, there was almost no change in Asia’s LNG receipts from the US in the past three months, while September’s and October’s imports were down just 10pc compared with the figure for July, when cooling demand peaked within the region. East Asia remained a priority export destination for US LNG during all that time, supported by consistently high prices, with Europe drawing spot cargoes away from Chile and Argentina. Unable to withstand the rising cost of LNG available in the market, the two countries cut their imports by 65pc in the last two months.

Already this month, US LNG imports to Asia are expected to reach the highest level since July 2021. Having learned from the previous winter, Asian buyers now have much more LNG in the storage tanks than a year ago, but La-Niña will keep players in the region on their toes in the coming months. And European importers can only dream of having a calm life, as the JKM-TTF spread for December-delivered cargoes indicates.

The opinions expressed in this blog are mine only and do not reflect the views of my employer.


Wind Power Generation Improves in Northwest Europe, Making Life Easier for Utilities Amid Expensive Gas

People living in Mallnow on the German-Polish border could hardly have imagined that their village would become the key point on the continent’s energy map for some time. The reality is that the Yamal pipeline flows have recently determined price movements at regional hubs.

Meanwhile, gas market does not live by imports from Russia alone. Apart from multiple factors that caused a certain disquiet among market participants (shipments through Mallnow dropping to zero, net withdrawals from European storages speeding up, La Niña expected to add to Asia’s power demand, etc.), there was at least one encouraging development. After several months of reduced wind power electricity production in NWE, where the largest number of the continent’s wind turbines are located, power generation from that energy source significantly improved in early winter.

In October, wind generation in Germany, France, the Netherlands and Belgium combined averaged above 600 GWh/day, the highest level since February 2021. Last month´s increase in wind-farm output is especially notable when comparing with the figure for the period from June to September 2021, which stood at 300 GWh/day. The share of wind in the electricity mixes of the four countries also doubled in October as compared to the previous month.

With wind plants being actively used, gas demand from NWE utilities generally decreased month on month in October, which could not have been more relevant given the high price environment. In the Netherlands, for instance, gas-fired generation was 60 GWh/day on average last month, compared to 85 GWh/day between June and September 2021. In other weather conditions, the country´s electricity producers would have faced difficulties in turning away from gas.

Even with the rebound in October’s wind power generation, 2021 has been marked so far by low output from wind farms. But in the situation in which European energy market finds itself this winter season, it is much more important for players to have ample winds for power generation in the last part of the year as heating demand rises.

The opinions expressed in this blog are mine only and do not reflect the views of my employer.

Locational Spreads Change Sets the Context for 2021 European Gas Market

Towards the end of the film, Sheriff Ed Tom Bell, portrayed by Tommy Lee Jones, feels distracted by all the violence he has come across and visits another old lawman (Barry Corbin) to ask for advice. Sheriff’s friend finishes their conversation, saying: ‘You can’t stop what’s coming. It ain’t all waiting on you’.

Though seemingly a simple phrase, it perfectly explains that the world tends to change over time, which in turn requires everyone to adjust to the new environment. When it comes to European gas, it is the shift in locational spread patterns that, among other things, have set the context for 2021 market.

This year, it has become common to see TTF traded at a premium to other market areas. Take, for example, the front-month spread between VTP Austria and the Dutch hub, which has stood on average at minus €0.2/MWh between 1 January and 22 October 2021 as compared to last year’s €0.5/MWh. Of course, this is partly the result of special circumstances that has prevailed in the market over the course of 2021.

Among them are unstable LNG supplies to the Gate terminal and slow injections into the Europe’s largest Bergermeer storage facility, while Central Europe has at hand the Ukrainian UGSs filled with large amount of gas by non-resident trading companies during the last winter. However, even after all those factors cease to exist, prices on the Dutch hub should not return to previous levels, with the TTF premium over other hubs being key to drawing volumes away from neighbouring markets as the Groningen field is expected to stop production in mid-2022.

Meanwhile, Italy’s PSV and Hungary’s MGP products have now been assessed much lower than in previous years, when compared to the equivalent contracts in the market areas these two countries were importing large volumes from. Following the start-up of new supply routes, demand for gas flowing from NWE and Austria has significantly decreased among players within the Italian and Hungarian markets respectively.

With the TAP pipeline being put in service early in 2021, this year’s imports to Italy via the Passo Gries entry point were restricted to periods in which additional flows from alternative sources were unavailable or when domestic consumption soared. After the completion of Kireevo/Zaychar and Horgos/Kiskundorozsma 2 interconnection points, Serbia and Hungary one after another joined the TurkStream corridor, making trades on VTPA less appealing for local buyers.

From the above, one may realize that a new landscape of price spreads between European gas hubs is taking shape in 2021. Market has gone through another stage of development right before our eyes.

The opinions expressed in this blog are mine only and do not reflect the views of my employer.

What Gas Hub Turkey Should Pay Special Attention To

As a number of new liquefaction plants came on stream worldwide in the latter half of the 2010s and two FSRUs were put into operation in Aliaga and Dortyol, spot LNG cargoes have become an integral part of the country’s gas imports. And it is the US that now dominates over other suppliers of non-contractual volumes to Turkey.

In recent years, US LNG deliveries at the Turkish regasification facilities were rising at a faster pace than receipts from any other source. As recently as 2019, the share of the US in Turkey’s total LNG imports stood at only 8pc, but already in 2020 transatlantic shipments accounted for more than 50pc, increasing further to almost 30pc in the period from January to mid-October 2021, according to Kpler. This year, all spot cargoes, except for two that arrived at Aliaga and Marmara Ereglisi terminals from Qatar and Egypt respectively, were delivered to Turkey from the US plants.

Understandably, the Turkish terminals received less US LNG in the first nine and a half months of 2021 as compared to the same period last year. But in the medium term, it is the US that would be best positioned to significantly increase exports to Turkey. When Calcasieu Pass LNG and Sabine Pass Train 6 enter commercial service, trading companies, which purchase Henry Hub-indexed LNG on FOB basis, will likely have more to offer Turkish buyers.

In that changing context Turkey understands the need to pay special attention to the major US gas hub, going beyond traditional benchmarks such as Brent crude or TTF and PSV prices. The increased role of US LNG in the Turkish market may be reflected in the inclusion of the Henry Hub into the formula for calculating the reference price while launching gas futures on the Istanbul-based energy exchange EPIAS, ICIS reported in early September.

Turkey’s demand for spot LNG depends heavily on the amount of gas imported under long-term contracts. But with access to non-contractual seaborne cargoes, local buyers can be flexible enough to better adapt their activities to a volatile environment.

The opinions expressed in this blog are mine only and do not reflect the views of my employer.

For a look at all of today’s economic events, check out our economic calendar.


European Gas Fluctuates Strongly Amid Poor Liquidity

This week, in only one day, the TTF front-month contract jumped by 30pc first and then recorded a drop of 35pc. A well-received meme comparing this Wednesday’s price movement with Burj Khalifa, the world’s tallest building, describes so perfectly what happened on October 6.

Prices were fluctuating against the backdrop of poor liquidity across the market areas, an issue that has been seen in recent months and has become particularly pronounced starting from September. Given the incredible rise in gas values in late third quarter, the risks associated with inadequately covered positions multiplied, making a huge number of players curb their trading activities. In September 2021, the average daily OTC volumes of trade on the Day-Ahead and Front-Month products on the TTF hub decreased by around 80pc and 73pc respectively, as compared to the corresponding period in 2020.

At the beginning of October gas price rise speeded up, with market participants borrowing more from banks or going into their own funds to meet large margin calls on their positions. In the current environment, major trading houses were forced to add billions of dollars to their credit lines so that they can manage high volatility. Bloomberg and Reuters have written excellent stories on this particular theme earlier this week. You should read them, if you haven’t yet.

Whether liquidity issue continues to affect the market depends on further price developments, which in turn will be primarily determined by fundamentals. As winter rolls around, not only supply side is a key focus of attention now but also fuel consumption for this heating season. Amid colder temperatures expected across much of Europe next week, gas demand may soon come to the fore.

The opinions expressed in this blog are mine only and do not reflect the views of my employer.

Europe Seeing Renaissance in Coal Power Generation, but There Is Limited Room for Switch From Gas

In August, NWE front-month clean dark spreads for 40pc-efficient units recorded on average a €8/MWh premium over clean spark spreads for 55pc gas plants, while in September the gap between the two indicators surpassed €35/MWh.

Given the acute vulnerabilities in the UK energy system, everyone’s attention has been especially drawn to that country in recent weeks. To avoid shortages in electricity supply, Britain was forced to fire up its remaining coal power plants.

Utilities on the other side of the English Channel did the same thing in late summer. For instance, September’s share of electricity coming from coal in Germany reached its highest level since the end of 2018, while the weight of coal generation in the electricity mixes of Italy, the Netherlands and France combined rose by more than 4 percentage points over the past month. In other market environment, a big portion of the coal-fired units, which are in use now, would obviously not be brought back to life.

As coal power plants are still operating far below capacity in Western Europe, there is potential for intensifying their usage. The question is what effect further fuel switching to coal may have on gas market in today’s conditions?

If capacity factors for coal plants in Germany, Italy, the Netherlands and France reached 100pc, an extra gas-to-coal switch would equal about 800 GWh/d. On paper, looks quite impressive. In reality, however, that sort of development is actually impossible due to technical limitations and restricted coal supply in the regional market.

Amid accelerated decarbonization, European gas consumption has become more inelastic than five or seven years ago, which leaves players less room for manoeuvre in a crisis situation, just like we see now. In pursuing a truly wonderful goal of carbon neutrality, the EU energy transition in some way resembles a sports coach who for the first time puts a young and unpractised, albeit very promising, player in the game.

At this stage, without the support of more experienced teammates the player can hardly prove himself when faced with a really strong opponent.

The opinions expressed in this blog are mine only and do not reflect the views of my employer.

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Leaving Aside East Asia, What Other Regions Draw LNG Away From Europe & How Much

This is not only due to strong demand from China, Japan and South Korea, but also to increased supplies to the regions that are not generally regarded as the main competitors for spot seaborne volumes. However, in 2021, a number of buyers outside the Big Three in East Asia have emerged from the shadows.

Europe’s LNG imports bounced back a bit amid sharp rise in gas prices in the regional market in the latter half of Q3, but September’s imports into 11 countries within NWE and Mediterranean are expected to remain well below 5 million tons for the third month running. Among other things, the growth in deliveries at European terminals has been restrained by the unprecedented demand for cargoes among consumers in Latin America, South Asia and Middle East, which together will receive around 21 million tons this summer, 6.7 million tons more than the average for the period from April to September in the two previous years.

This seemingly small amount of LNG could have partly improved the balance in the European gas market suffering from low storage levels. The increase in LNG imports to the three regions in Q2 and Q3 2021 against the same periods in 2019 and 2020 has exceeded this summer’s aggregated injections into the German underground facilities, and has been two times higher than was injected into the Dutch storages from April to September 2021.

Spot cargoes are responsible for most of the growth in LNG deliveries to Latin America, South Asia and Middle East, with volumes being supplied within the regions where liquefaction plants are located, as in the case of US exports to Brazil and Argentina, as well as being re-exported from Europe. Between July and September 2021, as many as seven cargoes were sent from the European terminals to Pakistan, Bangladesh and Kuwait, while another one was delivered from Spain to Puerto Rico, according to Kpler data.

Later this year and early next year, demand for extremely expensive spot LNG in those regions is likely to depend heavily on the availability of alternative energy sources, such as hydropower in Brazil or HSFO in South Asia. In the meantime, loadings continue to set new records, with buyers ready to pay almost $30/MMBtu for a cargo.

The opinions expressed in this blog are mine only and do not reflect the views of my employer

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As Recently as April, Who Could Have Predicted Such Madness in Gas Market

Even market veterans have probably never observed such a rapid revaluation of the forward curve, which, as recently as early April, did not provide indications that something so weird was about to happen in the second part of the year.

Between January 2020 and late March 2021, the Summer ’21 contract at the TTF hub rose by about €6/MWh, while the Dutch Q4 ’21 product gained only €2/MWh. Now, when prices can easily go up or down by €5/MWh in just one day, the change in price by ‘only’ €2/MWh within a 15 months period seems pretty unusual, to say the least.

When entering the summer 2021, forward price expectations of both market participants and external analysts did not meet the realities of future periods because hardly anyone could then predict how perfect the storm would be in Q2 and Q3. It took a few months to gain an understanding of the seriousness of market conditions, which resulted in the Q4 ’21 contract increasing by 3.5 times from late April to mid-September 2021.

Since April, the fire burning in the gas market has only become stronger. Lower Norwegian exports in May due to heavy maintenance, high fuel consumption to run cooling appliances amid the world’s hottest July in recorded history, ‘Fit for 55’ legislation package release, LNG demand remaining robust from Asian and Latin American importers throughout the whole summer, reduced Yamal flows following the August accident at the Novy Urengoy processing facility − that is far from being a full list of things the last six months were filled with.

Clearly, the market should not find some peace after summer season ends. Quite the contrary, more market volatility expected ahead due to intensification of the Nord Stream 2 saga and uncertainty over LNG distribution between key importing regions, accompanied with winter weather forecasts which will be the focus of everyone’s attention amid limited gas storage levels in Europe. Things are just getting interesting.

The opinions expressed in this blog are mine only and do not reflect the views of my employer.

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Magic Of Round Numbers: European Gas Reaches €20, €30, €40 And Now Hits €50

When a commodity reaches another round price level, the number of news stories on that particular product increases tremendously. Last week, this happened with European carbon allowances and natural gas, which took turns in hitting €60/CO2e and €50/MWh respectively. But while the former were practically standing still between May and August, the latter was developing in the last four months as if it got on a high-speed train.

Amid tight supply of both pipeline flows and LNG, the pace of gas price growth has only accelerated during the summer. It took just 22 trading days for the TTF Front-Month contract to rise from €40/MWh to €50/MWh in late August, in comparison with 27 days when going from €30/MWh to €40/MWh and almost 50 days for covering the distance between €20/MWh and €30/MWh.

All the three round levels have been exceeded over the summer period, which once again demonstrates the special importance of this year’s Q2 and Q3 for shaping pricing environment for many months to come. With the UGSs still lacking volumes, players are increasingly concerned about the market balance they will see shortly. If at the beginning of summer 2021 low storage inventories were partly mitigated by expectations of further increase in supply to Europe, it seems there is not much hope for a happy ending as winter approaches.

September’s gas market promises nothing less than a new wave of challenges, given that Norwegian output is restricted to planned maintenance, LNG prices in Asia continue to rise while the Atlantic hurricane season poses risks for cargo loadings at the US Gulf. Is the sky the only limit for European gas prices in the current situation?

The opinions expressed in this blog are mine only and do not reflect the views of my employer

For a look at all of today’s economic events, check out our economic calendar.