European Ports Jammed With LNG Tankers - Driving Up Soaring LNG Prices

LNG tanker waiting to dock

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As winter rapidly approaches in Europe amid a crippling energy crisis, tankers carrying much-needed liquid natural gas (LNG) are causing chaos in ports. Europe's urgent need for natural gas has caused an increase in deliveries to several European ports, but the facilities don't have enough dock space to handle the influx of ships. It has been reported that more than 30 LNG tankers are idling off the coast of Spain waiting to gain access to one of its regasification terminals. Spain has six such import terminals - the largest amount in Europe.

Not only are tankers unable to offload in ports, but they are also being used as storage facilities for extra LNG. Between the delay in getting tankers offloaded and returned to their home ports for refueling and numerous ships being tied up as floating storage, there is increased concern that there will be a shortage of tankers to transport LNG to Europe or other ports around the globe.

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In addition to struggling to meet the needs of a panicking Europe, the backlog of tankers sitting off the coast of Spain and other ports is also causing freight rates for LNG carriers to soar. According to data from a Wall Street Journal report, LNG tanker rates have increased sixfold since January. As of this week, rates were at $450,000 per day.

To complicate matters, there could be delays in bringing the Freeport LNG facility back online next month after a fire disabled the Texas facility in June. Without LNG in operation, US gas prices could continue to climb which in turn would drive up LNG prices internationally.

Until European ports are able to offload the LNG sitting in tankers off the coast, prices will continue to rise as Europe's demand remains high and freight rates soar. There seems to be no end in sight for the European energy crisis as attempts to resolve it continue to create further challenges and inflation.

US Gas Prices Soar As Europe And Asia Scramble For LNG

Image by Jukka Isokoski

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U.S. gas prices have surged to the highest level in real terms since the financial crisis in 2008 as strong demand for LNG from buyers in Europe and Asia puts pressure on inventories. Front-month futures for gas delivered to Henry Hub in Louisiana are trading at almost $9 per million British thermal units, up from just over $3 at the same point last year and less than $3 in 2019.

Front-month futures have surged into a record backwardation of almost $4 above futures for delivery one-year from now, as traders anticipate inventories will remain under pressure through the rest of the year. 

Working gas stocks in underground storage are 335 billion cubic feet or 18% below the pre-pandemic five-year seasonal average for 2015-2019...

To read more visit Zero Hedge.

China’s Phase 1 Trade Pledge Comes Up Empty

25% Tariff On American LNG Needs To Be Removed
LNG carrier with Logan Airport in background
Image by lightgraphs

Now that the dust has settled over the recent signing of the Phase 1 trade deal between the US and China, its apparent that it has more hype than real teeth.

Per terms of the deal, China pledged to purchase $18 billion in US energy products, including liquified natural gas (LNG). The problem with China’s pledge is that it hasn’t removed a 25% tariff placed last year on US LNG imports – in effect, nullifying, at least in part, Beijing’s intent and sincerity.

Simply put, what Chinese firm would want to buy more US LNG with a whopping 25% tariff attached to it? None, unless cargoes from the US can be purchased through a secondary trader with the elimination of the cost prohibitive tariff.

“The U.S. doesn’t have a margin that would allow any country to charge 25%” above global prices, said Michael Smith, chief executive of Freeport LNG, referring to the tariff. Until that tax is removed, “it’s a non-starter,” he said, according to a Reuters report.

The quandary for the US LNG sector arising from the nearly two-year trade war remains. Many of the LNG project development proposals of the so-called second wave of US LNG infrastructure buildout need to sign long, or at least mid-term, offtake agreements with Chinese firms so they can reach the all important final investment decision (FID) needed to go forward.

Without both offtake agreements as well as possible Chinese financing many of these projects will never be built – jeopardizing US chances of bypassing both Qatar and Australia to become the world’s top LNG producer by the mid part of the decade.

The ball is also in China’s court as far as LNG is concerned since global LNG markets are awash in the super-cooled fuel and will be until the mid-part of the decade or even further, putting prolonged and immense downward pressure on prices in the spot market, which has a knock-on effect of also forcing LNG producers to consider renegotiating existing long term offtake agreements currently linked to a Brent crude oil indexation, especially in the Asia-Pacific region, which accounts for around two-thirds of global demand.

Slowdown in Chinese economic growth, both due to the trade war and now the impact of the coronavirus, will also see global economic growth take a hit, thus less need for LNG imports. In fact, due to warmer temperatures again this year in North Asia, Chinese firms have been also trying offload cargoes on the spot market.

Spot prices for LNG in Asia are already trading near ten year lows, with the possibility that they could dip beneath the psychologically important $3/MMBtu price point – a price that will see many producers scramble to cover costs, while some will simply forgo cargo deliveries entirely to avoid loses.

The way out for LNG markets is hard to discern at this time since even more global liquefaction capacity will come online this year, especially in the US, but the removal of Chinese tariffs on US LNG would be a good place to at least start.

Big Oil Joins Hands With Climate Change Agenda

Big Oil Joins Hands With Climate Change Agenda
Liquefied natural gas exports from selected countries in January 2013-May 2019

Qatar, the leading liquified natural gas (LNG) producer for decades, until being eclipsed this year by Australia, is going solar. The tiny gas rich kingdom, however, won’t stay in second place for long. It has plans to ramp up its current 77 million tons per annum (mtpa) of LNG liquefaction capacity to a record-breaking, market changing 126 mtpa by 2027, leaving Australia in its wake. 

Qatar’s ramp up in production also likely has geopolitical motivations as well as commercial and market considerations. Looking forward, if there is regime change in neighboring Iran, which shares the gas prolific north field in the Persian Gulf with Qatar, Iran could become a major gas competitor in the region and further abroad as it develops its own LNG infrastructure. Qatar’s LNG maximization plan is also likely a pushback against the boycott put in place by Saudi Arabia, the United Arab Emirates, and Bahrain in 2017 over allegations that Qatar funds and aids radical terror networks - a claim that Doha vehemently denies.

Qatar’s energy minister Saad al-Kaabi said on Sunday that the kingdom had signed an agreement with French oil and gas major Total SA and Japan’s Marubeni to build a $467 million solar power project with capacity of about 800 megawatts (MW).

Kaabi said by the first quarter of 2021, half of the plant’s capacity should be up and running, adding that the project will reach full capacity by the first quarter of 2022.

He said that Qatar plans more solar projects as the country aims to reduce carbon emissions and minimize its impact on the environment. Kaabi said late last year that Qatar had commissioned a carbon capture and storage plant and aims to sequester 5 million tons of carbon from its LNG operations by 2025.

Qatar’s decision to build a solar power plant speaks volumes for how the world’s energy patch is changing as governments, pressure from investors, the general populace and now big oil comes to terms with GHG emissions, to tackle climate change. Although, much of the climate change agenda seems based on sketchy science and is unfortunately pegged to a leftist political agenda.

Big Oil and the power sector are also bowing to pressure to modify its ways and reduce its carbon footprint. Some of this so far has included plans to replace dirty burning coal fired power plants to cleaner burning natural gas plants. However, since gas is still a hydrocarbon, the future of this cleaner burning reliable fuel is now in the cross hairs of the climate change agenda. 

These are some of the themes that will be discussed this week at the World Economic Forum in Davos, with a wide range of heads of state attending, including President Trump and German Chancellor Angela Merkel – whose meeting itself will give plenty of opportunity for the leftist media to spin things to their own liking, with Trump likely being presented as the 900-pound gorilla in the room against more dignified and worthy leftist heads of state.

Nonetheless, the Forum’s official theme this year is “Stakeholders for a Cohesive and Sustainable World” and there are more than 30 sessions on the program that grapple with some aspect of climate change, ranging from discussions of youth activism to climate’s impact on public and private health systems, The Wall Street Journal reported yesterday.

Going forward, it would be more productive to divorce climate change concerns from a politically left agenda thus not demonizing those who question the movement’s science but who are still concerned over what’s happening. Yet, if the past is any indication of the future that development will remain a pipe dream.

When Texas Oil Fields Develop Gas Problems

When Texas Oil Fields Develop Gas Problems
United States Shale gas plays, May 2011

In 2018, U.S. natural gas production reached a record high, the U.S. Energy Information Administration (EIA) said on Thursday. Natural gas production in the country grew by 10 billion cubic feet per day (Bcf/d) in 2018, an 11% increase from 2017. The growth was the largest annual increase in production on record, reaching a record high for the second consecutive year.

U.S. natural gas gross withdrawals increased every month during 2018 except in June, ultimately reaching a record monthly high of 107.8 Bcf/d in December 2018, the EIA said. 

So-called marketed natural gas production and dry natural gas production also hit monthly record highs of 95 Bcf/d and 88.6 Bcf/d, respectively, in December 2018. Marketed production reflects gross withdrawals less natural gas used for repressuring wells, quantities vented or flared, and nonhydrocarbon gases removed in treating or processing operations. Dry natural gas is consumer-grade natural gas, or marketed production less extraction losses.

U.S. gas exports, both pipeline gas and seaborne liquified natural gas (LNG), increased in lockstep amid gas production highs. This year, U.S. LNG exports continue to increase as Gulf Coast terminals ramp up production, flooding an already saturated global market with prices for spot trading of the super-cooled fuel reaching multi-year lows amid the supply overhang.

Moreover, in 2018 the U.S. shipped/exported natural gas by pipeline more than it imported by pipeline for the first time in 20 years. The EIA also projects that for 2019 this trend will continue.

The Appalachian region remained the largest natural gas-producing region in the country, according to the EIA. Appalachian natural gas from the Marcellus and Utica/Point Pleasant shales of Ohio, West Virginia, and Pennsylvania continued to grow, with gross withdrawals increasing from 24.2 Bcf/d in 2017 to 28.5 Bcf/d in 2018. Ohio saw the largest percentage increase in gross withdrawals of natural gas, up 34%, in 2018 to 6.5 Bcf/d.

Texas develops a gas problem

Texas, home to the lion’s share of the country’s uptick in shale oil production, also saw the largest total volumetric gain in gross gas withdrawals in 2018, increasing to 24.1 Bcf/d, up from the state’s 2017 production of 21.9 Bcf/d. 

The Lone Star state’s increase in natural gas production is mainly due to Permian Basin and Haynesville Shale formation development. In 2018, production in the Permian increased by 2.7 Bcf/d, or 32%, while production in the Haynesville increased by 2.2 Bcf/d, or 34%.

The Permian basin, a power house of both oil and gas production, is about 250 miles wide and 300 miles long, spanning parts of west Texas and southeastern New Mexico. It includes the highly-prolific Delaware and Midland sub-basins.

By the end of last year, it had produced more than 33 billion barrels of oil, along with 118 trillion cubic feet (tcf) of natural gas. This production accounted for a whopping 20% of all U.S. crude oil production and 7% of U.S. dry natural gas production. 

According to analytics and data provider IHS Markit, the Permian shale play holds an estimated 60-70 billion barrels of recoverable crude oil. To put that in perspective, that’s enough to feed all the U.S. refineries for a decade plus. Rystad Energy estimates for the Permian are even higher, placing them at some 100 billion barrels of recoverable oil resources.

However, there are also systemic problems at the Permian. Since Permian fields are shale plays, the majority of its oil production is derived in the first year, in some cases as much as 60%-70%. As oil fields quickly deplete, energy players encounter more gas, which they either have to flare (burn off) or pay to have hauled away.

In the Midland portion of the Permian, the average well produces about 2,000 cubic feet of gas for each barrel of oil in its first year, according to Tom Loughrey, a former hedge fund manager who started shale data company Friezo Loughrey Oil Well Partners LLC, (FLOW), Blomberg said in a report yesterday.

“Shale wells are notorious for their steep output declines; however, that decline is more severe for oil than for gas and NGLs [natural gas liquids]. Gas and NGL production continues for much longer, increasing the gas-to-oil ratio of most U.S. shale plays,” he said.

Meanwhile, Permian producers are already reportedly flaring gas at record levels. The Texas Railroad Commission granted almost 6,000 permits allowing companies to flare or vent natural gas this year. That’s more than 40 times as many permits granted at the start of the supply boom a decade ago, Bloomberg added.

Compounding the problem, shale developers in the Permian need will have to drill even more wills just to maintain current production levels. IHS Markit said earlier this month that the base decline rate, or the rate at which production will fall through the year, has “increased dramatically” for more than 150,000 producing oil and gas wells in the Permian Basin.

Suffice it to say, more pipeline infrastructure is needed to haul away the gas and thereby reduce excessive flaring - a problem that has plagued the U.S. shale industry since its inception nearly a decade ago. Unfortunately, development is still failing to keep up with production. Until then, more gas will be flared, creating both an environmental quandary as well as tarnishing an otherwise stellar story of U.S. oil and gas production renaissance. 

China’s Well-Thought Out Tariff Scheme

China’s Well-Thought Out Tariff Scheme
LNG Carrier
Image by
Ken Hodge

The recently agreed upon so-called phase one trade deal reached between the U.S. and China, if for nothing else, shows that the two sides can actually forge an agreement amid the 16-month plus heated trade war that has caused a global economic slowdown as well as the worst relations between the two powers since the 1950s. Per the deal, Washington reduced some tariffs and Beijing canceled retaliatory duties that were previously scheduled to take effect on December 15.

Several U.S. sectors will benefit from the agreement, but U.S. oil and gas exports to China will not – oil imports from the U.S. will still face a 5% tariff, while U.S. imports of liquefied natural gas (LNG) will still face a massive 25% tariff.  

China, the world’s largest crude oil importer, lowered U.S. crude shipments from a record high hit last year. Chinese customs data showed imports from the U.S. in the first 10 months in 2019 were halved year-on-year to 146,275 barrels per day (bpd).

LNG imports in the first 10 months of 2019 shrank a whopping 87.2% on the year to 258,955 tons, according to Chinese customs. And, it’s the ongoing tariff on LNG that is the most problematic for the American energy sector. 

Unlike oil, the so-called second wave of U.S. LNG development needs Chinese funds. Numerous new projects and project proposals need to sign long term-offtake (supply) agreements with Chinese firms. China is the world’s second largest LNG importer after Japan and within a few years will become the world’s top LNG importer as the government mandates increased gas usage in the country to offset rampant air pollution levels caused by coal usage. 

Moreover, if several new U.S. proposals can’t ink these agreements needed to reach the all-important final investment decision, many will fall by the way side.

The long-term impact of this is severe. Without many of these projects coming to fruition, the U.S. will cede considerable market share in the LNG sector by the mid part of the next decade to Qatar, who will ramp up its capacity from a current 77 million tons per annum (mtpa) to a record breaking 126 mtpa, as well as Russia, who has made LNG development a national priority, East Africa and others.

The loss of American jobs, capital and revenue will be felt across not only the U.S. energy sector but the totality of the American economy.

This is why China slapped first a 10%, then a 25% tariff on U.S. LNG imports. Beijing knows full well how to hit and hit hard at the soft side of the U.S. energy juggernaut.

Perhaps a phase two deal will include a reduction of LNG tariffs, yet to remove the risk going forward a total elimination of LNG tariffs will be needed – and that may be a very long time in the making.

U.S. Dash To Top Gas Exporter Spot Continues

U.S. Dash To Top Gas Exporter Spot Continues
LNG carrier with Logan Airport in background
Image by

The U.S. is continuing its breakneck dash to the top of the liquefied natural gas (LNG) exporters club, but that momentum is still being threatened by the ongoing trade war between the U.S. and China. 

On Thursday, the Federal Energy Regulatory Commission (FERC) said it had approved the construction of four LNG projects and related facilities to export natural gas from the U.S. 

The FERC approved NextDecade’s 3.6 billion cubic feet/day (bcfd) Rio Grande project, Cheniere Energy’s 1.5-bcfd Corpus Christi Midscale, Exelon Corp.’s 0.8-bcfd Annova LNG Brownsville, and Texas LNG’s 0.3-bcfd Brownsville.  

All four LNG project sponsors have applications pending before the U.S. Department of Energy (DOE) seeking authorization to export gas to non-Free Trade Agreement (FTA) countries.

“The Commission has now completed its work on applications for 11 LNG export projects in the past nine months, helping the U.S. expand the availability of natural gas for our global allies who need access to an efficient, affordable and environmentally friendly fuel for power generation,” FERC Chairman Neil Chatterjee said in a release.

Second Phase Push

The FERC approvals also mark the continued push of the so-called second phase of the U.S. LNG juggernaut that has the potential to rival both Qatar and Australia as the world’s top LNG exporter by the mid part of the next decade. However, that possibility is in jeopardy as the trade war between the U.S. and China nears the 1-½ year mark. 

For the U.S. LNG sector to reach its full potential, it needs a plethora of help from China in both the signing of long-term offtake agreements so several project proposals can reach the all important final investment decision (FID), as well as funding from Chinese financial institutions.

The longer the trade war persists the greater the chance that it will negatively impact the U.S. LNG sector for the long-term, thus causing a loss of potential global LNG market share to not only Qatar, and Australia, including market share in the Asia-Pacific region, which accounts for two-thirds of global LNG demand, with that amount forecast to increase going forward, but also to Russia as it ramps up its LNG export sector as well as a host of other smaller and ambitious LNG exporters.

Notwithstanding, one noteworthy significance from yesterday’s FERC approval is that the Texas LNG project is a so-called mid-size project at 4 million tons per annum (mtpa) of liquefaction capacity. Some in the industry maintain that mid-scale LNG projects range up to 3 mtpa, but the Texas LNG project was intentionally designed with mid-scale in mind, which has advantages over larger scale LNG projects, including quicker speed going to market, LNG offtake flexibility, efficient use of capital, and creative technical solutions. According to Texas LNG, the project will also promote a low-risk tolling model which will optimize gas price arbitrage between Texas and global markets.

As of June, Texas LNG had signed a number of non-binding agreements with Chinese, Southeast Asian and European customers for cumulative total volumes exceeding phase one volumes of 2 mtpa. These customers are a mix of state-owned and private enterprises, the company said. 

Texas LNG is also in discussions with additional potential offtakers, including traders and portfolio players, according to the company. Moreover, marketing for full capacity of 4 mtpa is also is underway with negotiations of binding agreements expected to be completed prior to ground breaking in 2020.

Mega Gas Project Just Got Bigger

Mega Gas Project Just Got Bigger
The Sasol gas pipeline in Temane, Mozambique
Image by

French oil and natural gas major Total SA could expand the Mozambique liquified natural gas (LNG) project by adding two more production trains, head of Total exploration and production for Nigeria Mike Sangster said on Tuesday.

“We’re starting to look at studies for train 3 and train 4, because the resources are clearly there to develop,” he said at an oil conference in Cape Town, South Africa. 

Total finalized its acquisition of Anadarko Petroleum’s 26.5% share in the Mozambique LNG project in September for $3.9 billion as part of its takeover of the company’s assets in Africa, including Algeria, Ghana and South Africa. The project includes the construction of a two train liquefaction plant with a capacity of 12.88 million metric tons/year (mmty). Anadarko sanctioned the project in June. 

Mozambique LNG is one of two so-called mega LNG projects that had been seeking sanction in Mozambique for more than four years. The other is ExxonMobil’s Rovuma LNG development, which was expected to reach a final investment decision this year and would have more than 15 mmty of capacity.

Mozambique LNG has an estimated $20 billion price tag and includes the development of the Golfinho and Atum fields located within Offshore Area 1. Area 1 contains more than 60 trillion cubic feet (TCF) of natural gas resources, of which 18 Tcf will be developed with the first two trains. The project is expected to come into production by 2024, a time that Royal Dutch Shell has predicted as having a possible shortage of the fuel. 

The Mozambique LNG project is considered largely derisked since nearly 90% of the project’s production is already sold through long-term contracts with key LNG buyers in Asia and in Europe.

Wood Mackenzie’s Frank Harris, head of LNG consulting, said in June that flexible commercial arrangements, including an innovative co-purchase agreement with Tokyo Gas (Japan’s largest provider of city gas) and Centrica, had been instrumental in securing the Mozambique project a roster of high-quality customers in a crowded LNG market.

Sangster’s comments come as Total, the second largest private LNG seller after Shell, increases its global LNG footprint. In September, the company took over Toshiba’s U.S. LNG assets for $800 million in cash, adding 2 mmty of LNG to its U.S. business. Total said at the time the takeover of Toshiba’s LNG portfolio was in line with its strategy to become a major LNG portfolio player.

In October, Total bought a 37.4% share in Indian gas distribution company Adani Gas for $866 million, giving the company a role in India’s growing LNG market, which is becoming the second largest driver of the fuel in Asia after China.

Total is on track to have an overall LNG portfolio of around 40 mmty by 2020 and a worldwide market share of 10%, the company said. Through its stakes in liquefaction plants located in Qatar, Nigeria, Russia, Norway, Oman, Egypt, the United Arab Emirates, the United States, Australia, Angola and Yemen, it sells LNG in all global markets.

The Inconvenient Truth Climate Activists Are Ignoring

The Inconvenient Truth Climate Activists Are Ignoring
Northwestern North Dakota is one of the least-densely populated parts of the United States. Cities and people are scarce, but satellite imagery shows the area has been aglow at night in recent years. The reason: the area is home to the Bakken shale formation, a site where oil production is booming

Amid the growing green energy push unfolding among mostly the Democratic side of the isle in Washington, noted oil majors like ExxonMobil, Chevron, Royal Dutch Shell, BP and others are finding themselves at odds with investors and the public in general that want a greener footprint, while many in that camp think the days of oil and natural gas usage can magically disappear.

The problem with this thinking is that it’s unrealistic. Despite the best intentions of those that “want to save the planet” by revamping the energy sector and even the fabric of American business, the stark reality is that the world needs and will need hydrocarbons for decades to come.

However, the Left is now starting to even demonize the US shale gas sector which has seen remarkable growth, propelling the country to the world’s third largest exporter of liquefied natural gas (LNG), recently bypassing Malaysia. The US could by the mid part of the next decade or even earlier also challenge both Qatar and Australia as the world’s top LNG exporter, bringing in billions of dollars as well as the geopolitical clout that comes from such a development.

Until recently the US gas industry mostly touted the fact that natural gas, though still a fossil fuel, was the cleanest of all hydrocarbons, especially when pitted against coal and oil.

The gas sector is now fending off claims that it needs to be phased out, even though it’s still struggling to offset and replace dirtier burning coal and oil in much of the world for power generation, including the Asia Pacific region, home to around two thirds of the world’s population, where new coal-fired power plants are being commissioned on a regular basis.

Shell CEO Ben van Beurden picked up on this theme yesterday in a Reuters interview. A defiant van Beurden rejected a rising chorus from climate activists and parts of the investor community to transform radically the 112-year-old Anglo-Dutch company’s traditional business model, Reuters reported.

“Despite what a lot of activists say, it is entirely legitimate to invest in oil and gas because the world demands it,” van Beurden said. “We have no choice” but to invest in long-life projects, he added.

Shell is also backing up van Beurden’s rhetoric with action. The oil and gas major plans to greenlight more than 35 new oil and gas projects by 2025. Shell supplied about 3% of the world’s energy last year and is also the world’s largest buyer and seller of LNG.

Van Beurden also made a statement that the climate change activists conveniently ignore when he said a lack of investment in oil and gas projects could lead to a supply shortage and result in price spikes.

In essence, without both oil and natural gas and the various products that are produced from these hydrocarbons, the world economic system would crumble. Perhaps in time, renewables, including wind and solar for power production and electric vehicles for transportation as well as others can represent a major part of the world’s energy infrastructure. 

However, that time hasn’t arrived.

The best approach is to use both oil and gas with environmental concerns at the forefront including carbon capture systems, while also allowing the renewables sector the time line it needs to catch up – a point that the political left fails to understand, perhaps best called an “inconvenient truth” that they are ignoring.

“One of the bigger risks is not so much that we will become dinosaurs because we are still investing in oil and gas when there is no need for it anymore. A bigger risk is prematurely turning your back on oil and gas,” van Beurden said.

Approaching Winter Season Provides Little Support For Asian Spot LNG Prices

Approaching Winter Season Provides Little Support For Asian Spot LNG Prices
LNG Carrier Fuji
Image by
Ken Hodge

Prices for spot liquefied natural gas (LNG) in Asia continue to cause problems for major producers of the fuel. Prices this year dropped to three year lows amid a persistent supply overhang coming from more production in Australia, the US, Russia and other countries.

The supply overhang has met tepid demand due to more moderate temperatures in North Asia, home to around two thirds of global LNG demand. Most LNG in Asia is used for power generation and mild temperatures either in the summer or in the winter reduces demand for the fuel and puts downward pressure on prices.

Usually by October, however, major buyers, mostly large utilities ramp up procurement of the fuel in anticipation of colder weather. Yet, this year that dynamic has yet to unfold as anticipated. Major buyers in the world’s top three LNG importing countries, Japan, China and South Korea are still reporting ample stocks going into the winter season.

China, for its part, has improved its gas procurement and storage abilities since two years ago when it was caught flat footed during an unseasonably cold 2017 winter season that saw it run out of gas, forcing energy planners to revert back to partial coal usage for power generation and heating, as well as temporarily shut down key industries in the north for periods of time to divert much needed gas supply to residential end users. 

As a point of reference, prices for spot LNG in Asia maxed out in February 2014 at over $20 per million British thermal units (MMBtu). At the time there was still a somewhat limited supply of the fuel, while Japan, in the aftermath of the Fukushima nuclear disaster that eventually shutdown all of the country’s nuclear reactors needed for power generation, increased LNG procurement at a record level.

Markets began pivoting around 2016 when Australia’s massive LNG projects started coming on line, and now with the US recently bypassing Malaysia to become the world’s third largest LNG producer, markets will likely remain oversupplied until around 2023. Royal Dutch Shell, the world’s largest buyer and seller of LNG, sees things a bit differently, claiming that increased LNG demand globally could end the supply overhang sooner. However, Shell, which last quarter posted dismal profits due to lower LNG prices, usually paints a more optimistic picture of market conditions if for no other reason than to appease investors.

However, prices for November loading have at least increased since this summer when they dipped below the $4/MMBtu price point. The average LNG price for November delivery into northeast Asia was estimated at $5.55/MMBtu down from $5.75/MMBtu last week. One cargo sold to China by trading house Vital reportedly fetched $6.25/MMBtu. 

In Europe, Dutch front-month prices, a European benchmark, traded at around 16 euros per megawatt hour, or $5.15, compared to $3.51 at the end of September, Reuters reported on Friday. That was far below the $9.38 they fetched at the same time a year ago.

European countries such as France, Austria and Poland reported gas storage 100% full with tanks across the continent 97.4% full on average, data from Gas Infrastructure Europe showed on Friday.

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