Qatar Petroleum books up capacity in UK, France, Belgium. Launch of LNG trading arm also sign of spot ambition. Qatari move could deter new LNG liquefaction projects.
Nov 13, 2020
Not only has Qatar Petroleum, or QP, been booking new significant long-term capacity at import terminals in northwest Europe over the past year, but it has now also launched an LNG trading arm that can target shorter-term volume placements globally.
It has been suggested that Qatar was caught slightly on the hop with the rapid growth in LNG liquefaction capacity first in Australia and then in the US, prompting Doha in 2017 to lift the moratorium on the further development of the massive North Field and then to target a significant LNG capacity expansion.
Qatar currently has an LNG production capacity of some 77 million mt/year, but has plans to boost it to 110 million mt/year by 2025 with the addition of four more trains and to 126 million mt/year by 2027 with the addition of two further trains.
Qatari energy minister Saad al-Kaabi also said in May that Qatar could even expand its production capacity further. “There is room to go above 126 [million mt/year]. You might hear us in a few years go higher, we have plenty of gas to do that,” he said during a US-Qatar Business Council webinar.
In the meantime, QP has been active in booking new import capacity in Europe.
Most recently on Oct. 13, a QP affiliate signed a 25-year agreement for up to 7.2 million mt/year of import capacity at the UK’s Isle of Grain terminal starting from mid-2025.
Qatari energy minister and QP CEO Saad al-Kaabi said that the agreement meant Doha was “reaffirming” its commitment to the UK’s gas market.
Qatar already has the capacity at the 15.6 million mt/year South Hook LNG import terminal in Wales, which QP co-owns with US major ExxonMobil and France’s Total.
The new Isle of Grain capacity booking was the third in succession in northwest Europe.
In February this year, a QP affiliate booked some 3 million mt/year of capacity at the Elengy-operated Montoir terminal in northwestern France for a term up to 2035.
“Montoir will thereby become a new LNG import terminal position for QP in Europe, facilitating the supply of Qatari and internationally sourced LNG to French and European customers,” QP said at the time.
Kaabi also hinted at further cooperation with Elengy, saying QP looked forward to further strengthening the relationship in the future.
The Montoir booking followed an agreement in September 2019, when QP subsidiary Qatar Terminal Limited, or QTL, agreed to take the full capacity at Belgium’s Zeebrugge terminal from the expiry of the existing long-term contracts until 2044.
QTL is already a party to an existing agreement under which about 50% of the terminal’s capacity is utilized for delivery of Qatari LNG into Belgium under long-term LNG agreements.
Locking down Northwest European import capacity is clearly an important strategy for Qatar given the region’s liquid trading hubs, ample gas storage capacity, and good interconnectivity.
“European regasification capacity will continue to be core part of QP’s evolving commercial strategy, one that is part and parcel with a push into spot market trade,” Samer Mosis from S&P Global Platts Analytics said.
QP on Nov. 9 launched a new trading arm, QP Trading, which is mandated with building a globally diversified portfolio and managing risk through physical and derivatives trading.
Mosis said it was a “tectonic shift” for Qatar whose exports traditionally either go to long-term customers, mainly in Asia, or get placed into Europe through Qatar’s ever-expanding portfolio of regasification capacity.
“It ushers in a new era for the world’s largest, lowest-cost, producer of LNG and represents a tacit recognition by the champion of oil-indexed, long-term deals that spot trade and commoditization are destined to dominate global LNG trade flows,” he said.
QP Trading’s first deal with Pavilion Energy also was accompanied by a pledge that each cargo delivered would come with a statement quantifying greenhouse gas emissions.
Mosis said that given Qatar’s ultra-low development costs, the launch of QP Trading is particularly bearish for any prospective pre-FID LNG project, especially as it occurred simultaneously with the first instance of QP integrating carbon accounting into an LNG deal.
This, he said, removes two potential points of comparative advantage for any aspiring LNG producer.
“Successful operationalization of QP Trading, equipped with anywhere from 20 to 30 million mt/year of spot-destinated supply, holds the potential to increase Qatari spot market penetration and threatens to put the final nail in greenfield LNG’s coffin this decade,” Mosis said.
And with Qatar set to have more than 50 million mt/year of uncontracted capacity through 2026, it will require all possible outlets to maintain its traditional 100% utilization levels, he said.
Oct 28, 2020
Ira Joseph, head of gas and power for S&P Global Platts Analytics, and Ryan Ouwerkerk, manager of Americas natural gas pricing for S&P Global Platts pivot away from the extended outlook into the winter and dive into more immediate spot market movements and their bullish impact on several global natural gas & LNG pricing points.
BELOW: Market insights on energy transition, tomorrow’s fuels and energy sources, and the implications for commodity markets, from oil to power to metals. Check out the new Platts Future Energy podcast.
Nov 16, 2020
Roughly 17,300 cu m of LNG was supplied to the 23,000 TEU containership, which is currently the world’s largest LNG fueled containership.
The operation was carried out via ship-to-ship transfer while the CMA CGM Jaques Saade carried out simultaneous operations and took roughly 24 hours to complete.
According to Total, the carbon footprint of the volume delivered was reduced with the introduction of biomethane, produced in the Schipol area, which made up roughly 13% of the total quantity delivered via the Guarantee of Origin, or GO, certificates mechanism.
The operation “marks the shipping industry’s first commercial use of biomethane on this scale. Such introduction reflects Total’s ambition to get to Net Zero by 2050 and our commitment to help reduce the carbon intensity of the energy products used by our customers,” said Jérôme Leprince-Ringuet, vice president of marine fuels at Total.
In a statement on Nov. 12, the Port of Rotterdam said a total of nine LNG bunker vessels now operate in the Rotterdam area, of which three are working there on a permanent basis.
The CMA CGM Jaques Saade was delivered in Q3 of this year having been constructed in Shanghai and began its maiden voyage to Europe from Asia in September.
Hugo De Stoop, chief executive of one of the world’s largest crude tanker companies, Euronav, took an hour in September to answer questions from S&P Global Platts on supply and demand, floating storage, strategies to manage the coronavirus pandemic, the post-IMO 2020 landscape and the future of marine fuels. Here
Oct 01, 2020
The company, which operates shipping and storage of crude oil, benefited from soaring demand for oil storage at sea as buyers struggled to find storage space on land for surplus crude during a global economic slump caused by the coronavirus pandemic.
Around 150 vessels out of a fleet of 820 were taken for storage at a time where, indeed, we had less cargo to be transported. We had such a massive potential for storage or other services outside the trading, I would say, that our rates went through the roof, and we have enjoyed a very good first quarter and a spectator second quarter. When you say it’s a year of two halves, I want to be a little bit more uplifting than that. I think it’s a year of three good quarters followed by one probably bad quarter, because the third quarter will also be — it’s not going to be as good as the first or second quarter, but nevertheless, it will benefit from a lot of fixtures that had been done in the second quarter and that are long enough to impact positively the third quarter. Where are we today? And that’s the reason why we believe the fourth quarter will be less interesting. We are at a time where there is still not the same consumption in the world of oil that we have pre-COVID.
We probably still have about 10 million b/d consumption lower than where we were. And at the same time, there is almost the same amount of ships and many of those that have been used for different types of jobs than transporting — namely storage and so on — are starting to come back. So we see an imbalance between the capacity to transport the oil and the number of cargoes we need to transport. We are hitting relatively low levels in freight rates, and we don’t see this situation improving before we get back the consumption that we had pre-COVID.
It seems like a number of people, after making very good profits over the last three or four quarters, are now looking to sell their vessels. They will try to do so as early as possible in the declining part of the value cycle. And we, of course, are going to try to do that as late as possible in the declining part of the value cycle. What we have demonstrated in the past, we are always optimistic in terms of acquisition in the down part of the cycle. It’s also a time where people are a bit more reluctant to have the courage to invest in an asset that will not return immediately in terms of return on investment, but we know we are in cyclical markets, so we know that when we invest in the low part of the cycle, it usually pays off on the high side of the cycle.
There are different ways to grow the company. And one of the ways we could have grown the company over the years is by ordering many ships then growing our fleet by simply ordering new vessels. It is like in the airline industry, with what Ryanair or Easyjet and so on have done. They always order the latest generation of planes and then they grow the fleet and tend to outperform the incumbent because they have sort of old generation planes which would consume more. We always thought that, though running eco-ships has a benefit, it has a disadvantage that every time you add a ship to the market, you are deteriorating your supply at a time with the demand for your services is growing at a good pace, but we’re talking about 1% growth. So we have always favored buying second-hand assets or resale of contracts, other terms. People place an order, they can’t finance it or no longer want to deliver the ships, we buy it from them, usually at a discount. That’s how we have tried to grow the company. We don’t want to change that. We certainly don’t want to place an order at a time where we don’t know whether this existing technology and combustion engine using fuel oil are still going to be there in the next 20 years. And we are waiting for the next technology not only to be available, but to be future-proof that we’re not going to change several times technology before knowing exactly what to do. So we’re going to stick to our guns of buying second-hand vessels. We’re obviously going to try to buy modern vessels.
Every year, you have, roughly speaking, 5% of the ships that are too old so they go to the recycling yard or scrapyard. As long as you don’t renew that, your industry can reduce the size of supply by 5% every year, and we don’t believe that the oil demand will be reduced by 5% every year. We believe that we’re going to reach peak oil relatively soon, certainly in this decade. But from there on, the decline will be very gradual. The world will continue to need oil in order to transition to a world that can be less dependent on it. So our service will be needed for the long-term future. And at the same time, we are an industry that can adapt with decline rather than a growing market.
How has the industry managed the impact from the International Maritime Organization’s new sulfur cap in bunker fuels at 0.5% as of the start of 2020? What challenges have there been in the shift form high sulfur fuel oil to low sulfur marine fuels and has there been a winner?
The shipping industry has been involved with the change from high sulfur fuel oil or HSFO to low sulfur fuel oil or LSFO, and Euronav has said that’s a very good change, and has always supported that change. Having said that, it has led to many technical issues. A lot of people are still suffering from it. We may have suffered a little bit less because we were able to accumulate the product that we tested before putting into our engine. Normally, the way to look at it is that you go to the pump station with your ship and you are provided something that has a certificate of quality, but unfortunately, the certificate of quality does not really match the new fuel. It’s more a match of the old fuel, and then I will give you a percentage of the sulfur content. Today, LSFO is probably a winner in the sense that HSFO is forbidden unless you have a scrubber and the retrofitting of scrubbers is too expensive. People have had the demonstration. The spread between the two fuels [HSFO and LSFO] was expected to be a lot higher. At the end of the day, it seems to remain around $50/b. And if you look at the forward curve for the next three or four years, it’s going to stay there.
I think that the winner is already decided, and that’s going to be hydrogen or ammonia. The only problem that we have is that we don’t know when it’s going to be ready and available. I’m speaking about an engine that is really capable of burning efficiently ammonia in a safe way because ammonia is a very toxic gas. But also the infrastructure. And at the moment, it will produce a certain amount of ammonia. It uses fertilizer, but the way it is produced is brown, meaning that we’re using energy to produce it, which is coming from fossil fuels. So it’s a little bit ridiculous to be proud to burn ammonia or hydrogen on board your vessel if you have produced it that way. There are obviously other ways to do it. If your electricity is green and has been made using renewable energy, then co-sharing. That’s what people will tend to. So I think that for the biggest vessels, ones on long voyages over 70, 80, 90 days — any where from 40 to 100 — it is the solution that we will have in the future. It’s going to take time to put the infrastructure in place, and it’s going to take time to finish the development of the engine, which I understand we are nearly there and we talk about two years’ time. That is the biggest question.
In the meantime, do we try to be even more efficient with the existing technology, and it seems that we have reached a limit, and maybe there’s another 5%, 7%, potentially 10% saving on the consumption and therefore, the emissions on the existing technology, but then we hit a brick wall. LNG is offering a solution for the transition, but the problem with LNG is that it is indeed lower in terms of CO2 emission, but it emits another greenhouse gas, not so much onboard the ships. That is methane, CH4, but very much the supply chain. It was mostly because of leakage. So you can address that, but it doesn’t seem that there is political will to address it at the moment. And so we, as an end-user, need to be honest with ourselves. If we swap from LSFO emitting CO2 to using LNG, but we see that from what they call the well to wake, from the production to the burning on board the vessel, damage to the environment is far greater than using CO2, even though on board the vessel, it’s lower. I think we should ask the right questions and not jump into this technology. The risk, of course, is a little bit like with the scrubber. Everybody jumped on the technology, not really knowing what the regulation would be or the spread between the two fuels. We can find ourselves in exactly the same situation. We all order LNG then, five years later, someone finally admits that it is polluting more because we have not been able to solve the leakage problem, and everybody goes back to square one.
This oil crisis has affected many people in many directions in terms of investment capacity. And so temporary storage and the fact that it can be used as a buffer is extremely interesting. We have seen the traders become a little more active than they were before. So it seems that we are getting further away from traditional oil and production, transporting, delivering to the refinery and then sending it to the consumer market. It seems that there are more trades, more sophisticated movement, more deviation of the ships even on a VLCC from time to time. It was rarely the case in the past, we were on route with the cargo towards the US Gulf and suddenly, we do a U-turn, and we do the delivery in China. I cannot remember seeing that. In the last six months, we’ve seen that on three of our own vessels. So I guess it is happening more and more.
I think that inevitably China will continue to grow its consumption and is one of the most important markets. I think that the US will try to limit its consumption, we will try to increase its production. And shale will probably come back when we are around $50/b or more, and it’s a very, very flexible type of production. Because even when people say, my God, there’s a number of companies going bankrupt because of the crisis, what does it mean? It only means restructuring the balance sheet, the production is not really affected. It stops. And then when it makes economic sense, it restarts because people have bought the rights to produce, they have bought all the assets that were stranded for a short period of time. It’s a very dynamic market, it seems to have many lives over and over again.
One of the biggest challenges for the shipping industry has been what you yourself have called “the scandal at sea” with difficulties operating under COVID-19 given the challenges around staffing vessels in various locations.
I think that we’ve been in a luxury position that went through the lockdown. We all live in our apartments or in our homes close to our families and made the best out of it. If we are thinking about our colleagues at sea then we can call it a humanitarian crisis. Because of travel restrictions, because of the diplomacy side, all the embassies have not been able to work fully staffed or issue visas. We have had a lot of people stranded at sea. They were forbidden to embark, forbidden to arrive. We have tried to do a lot. We’ve tried to use by all the relationships that we have try to move these. It’s working a little bit. It’s an absolute worldwide disaster and we will continue to fight.
Now I have to admit that shipping might be guilty of its own way of doing business. So the fact that we are always trying to be discreet, that we are always trying not to be regulated as an industry is back-firing. When we need the world to co-operate, when we need the world to pay attention to shipping, of course everybody is ignoring us simply because they don’t even know we exist. Despite the fact that we are so important for the world economy, for transporting 80% or 90% of all the goods and all the good things that we know about shipping. When you don’t have people that you vote for who are responsible for the crisis to do something about it, chances now are it’s going to be pretty low on their to-do list. And that is a pity but maybe a lesson to be learned as to what it would take to rebrand shipping as a noble good.
Nov 10, 2020
Chinese buyers hesitant to sign new LNG contracts with Australian producers. Woodside's Scarborough expansion faces lack of interest from Chinese buyers. Qatar expansion allows Chinese buyers to diversify from Australian LNG.
Nov 20, 2020
Several executives from Chinese energy companies, including the three main national oil companies, said they don’t expect ongoing spot trade to be impacted, but new deals with Australian gas producers had become difficult.
Australian gas exporters argue that their projects are not contingent on Chinese buyers in a growing Asian market. They also expect the new trade agreement — the Regional Comprehensive Economic Partnership, or RCEP — which was signed by 15 countries on Nov. 15, including the 10 ASEAN states, China, Australia, Japan, South Korea and New Zealand, to open new channels for LNG trade.
Still, low cost suppliers like Russia and Qatar are actively engaging Chinese buyers, and Beijing may seek long-term diversification that allows it to target Australian LNG without impacting its own gas supply should relations deteriorate.
Chinese gas importers make purchase decisions based on demand and prices, but “will have to obey if the government issues new guidelines on trading,” a source with one of the state-owned oil and gas majors said.
“There could be some impact on China’s investment in new LNG projects in Australia, which would need companies to seek government approval or at least require them to discuss with the government before investing,” the person, who declined to be named, added.
At least five other oil and gas executives based in Beijing and Guangdong agreed new contracts with Australia had become difficult.
“The Chinese were potential purchasers of upstream equity in Scarborough, but unfortunately they’ve come back to us and said they are unable to participate in a sale process at the current time,” Woodside Energy’s CEO Peter Coleman said in an emailed statement Nov. 16.
He was “hopeful that we can get back to the negotiating table at a point in the future,” and said the project was not as reliant on offtake agreements as before.
“[T]he reality is the LNG market has changed very dramatically from the last significant investment that Woodside made in Pluto,” Woodside’s executive vice president for development and marketing Meg O’Neill said Nov. 11 at an investor briefing.
“There are more customers buying LNG today than ever before. We expect over the next years that numbers will increase,” she said.
Woodside has a controlling interest in the Scarborough gas field, around 300 km offshore Western Australia, and plans to use the gas to add a second train to Pluto LNG, which currently has a 4.9 million mt/year capacity. It plans to expand processing capacity for Scarborough from a base case of 6.5 million mt/year to 8 million mt/year.
Woodside’s CFO Sherry Duhe said in a briefing that Scarborough’s viability had been stress-tested in the COVID environment at prices below $50/b and it was still “a very economic, attractive, project.”
Coleman said the conversion of initial agreements to firm contracts had slowed because of the pandemic but the engineering ramp-up for Scarborough was on track for early 2021 and FID for Scarborough and Pluto Train 2 in the second half of 2021.
A Singapore-based LNG trader said the lack of Chinese interest in Scarborough may not be fully linked to geopolitical tensions.
“The project was a tough one to begin with, without a concrete timeline, and it was also costly. It’s a buyer’s market with lots of projects out there. We will focus on what is the most competitive,” the trader said.
“If it’s a good project for the Chinese to invest in, the buyers will try to convince the government for their support,” the trader added.
Woodside has acknowledged that competitors like Qatar had introduced low contract prices but called the rival “one price point” that doesn’t reflect the overall market.
“The benchmarks that people want to get out there, the Qatari volumes — you’ve got to take all of that with a grain of salt,” Coleman said at the briefing. “We know what the second-tier buyers are willing to pay, or need to pay, and we have a strategy around that,” he said.
Qatar’s LNG expansion will make all other pre-FID projects more challenging to proceed but some will still capture the market due to differentiation on supply diversity grounds and equity stakes offered alongside LNG sales contracts, Saul Kavonic, Australia energy analyst for Credit Suisse, said.
He said heightened geopolitical tensions alongside greater scrutiny by Australia’s Foreign Investment Review Board are making asset sales, particularly to Chinese buyers, even more difficult. “Australian producers may need to find avenues to develop their projects without the degree of foreign capital hoped for last year,” he added.
In the first nine months of 2020, Australia was the largest LNG supplier to China, followed by Qatar and Malaysia. For Australia, LNG is its second-largest resource export, and its largest LNG customer is Japan, followed by China.
ash prices rise 70 cents to mid-$2s/MMBtu. Balmo contract averages $2.39/MMBtu. Weak production, rising LNG demand lift prices.
Nov 11, 2020
Over the past several trading days, the cash market at Waha is up about 70 cents/MMBtu.
On Nov. 11, prices at the benchmark West Texas location were up another 3 cents to $2.52/MMBtu, preliminary settlement data from S&P Global Platts showed.
In early October, a combination of short-lived factors pushed the market to a nearly 20-month high at $2.91/MMBtu. That move was followed by a sharp retracement in prices earlier this month.
The current rally, though, could be more sustainable following recent and more enduring changes in regional supply-demand fundamentals. In fact, forwards markets are already betting on it.
In November, the balance-of-month gas contract at Waha has traded at an average $2.39, most recently settling Nov. 10 at $2.47/MMBtu. At expiration in October, the balmo contract end trading at just $1.59/MMBtu – more than $1/MMBtu below the cash market at that time, S&P Global Platts M2MS data shows.
Higher cash prices at Waha have accompanied a recent downturn in gas production that has given producers additional pipeline capacity and improved optionality for reaching end-user markets.
Month to date, Permian output has averaged 10.4 Bcf/d – down about 65 MMcf/d compared to the prior-month average and nearly 300 MMcf/d lower compared to September.
After restoring output at curtailed wells this summer, West Texas gas production briefly climbed to over 12.2 Bcf/d. Since early July, though, Permian supply has been on a steady downward trend as reductions in drilling and completion activity begin taking their toll.
According to S&P Global Platts Analytics, recent rig and capital-expenditure cuts in the Permian will likely keep production below 11 Bcf/d until at least mid-2021.
Record-high LNG export demand has also helped to support the Permian gas market recently.
In November, feedgas demand from US terminals has averaged over 10.2 Bcf/d – its highest monthly average on record, according to Platts Analytics.
Stronger demand, particularly at terminals along the Texas and Louisiana Gulf Coast, has increased the call on Permian supply.
For the week ended Nov. 5, eastbound flows from the Permian climbed to an average 5.3 Bcf/d, up from an estimated 4.8 Bcf/d in the three weeks prior. In November, outflows from Texas to the Southeast are also up sharply, averaging about 4.5 Bcf/d month-to-date, compared with a 2.7 Bcf/d average in October, Platts Analytics data shows.
Demand for gas to feed LNG exports has rebounded. BP working to diversify production mix.
Nov 11, 2020
Demand for gas to be liquefied and exported from the US has recovered beyond pre-pandemic levels to nearly its maximum capacity, Orlando Alvarez, president and CEO of BP Energy, told the LDC Gas Forums 2020 Natural Gas Forum.
Europe, which is leading demand for the fuel, could see its LNG intake drop amid new lockdowns caused by a second wave of the coronavirus, Alvarez said. The pandemic’s impact on fuels demand throughout the world could still have a major effect on gas demand in the coming year.
“We’re not through it yet and how that manifests itself through the year 2021 is important,” Alvarez said Nov. 10. The US gas industry “is more dependent on the global economy than it’s ever been, and that’s exacerbated by the COVID[-19] and everything else that’s going on. If you think about your projection for what you think is going to happen to gas prices … more than ever you need to stay glued to what’s going on in the rest of world because that’s impacting our US prices as much as I’ve ever seen.”
Lower demand for oil-derived products — including gasoline, diesel and jet fuel — is also affecting the US gas market as oil drilling drops in areas that were bustling prior to the pandemic. Drilling activity leads to an increase in production of so-called associated gas that is found along with oil. A slow down in production of associated gas could lead to volatility in prices, Alvarez said.
“We’ve sort of taken associated gas production for granted,” Alvarez said. “Associated gas production growth is no longer a guarantee. It’s something we need to watch. Gas producers, gas consumers, this is something we all need to pay attention to.”
Amid the fluctuating gas market conditions, London-based BP is working to diversify its production mix to remain competitive amid a shift in demand for less-polluting energy sources. While Alvarez expects demand for hydrocarbons will remain in place, electricity will increase its share of the energy market with renewables leading the way in the energy transition, he said.
“The more that we talk to customers, the more the demand is changing,” Alvarez said. “Customers are asking for more than just a commodity. If you’re an industrial customer that we sell gas to today, that industrial customer maybe wants fuel for power; they may want a carbon offset to go with their physical natural gas.”
BP is developing products to meet the changing demand, including carbon-offset gas, Alvarez said. While the energy transition has already arrived, oil and natural gas use is unlikely to disappear in the near term, he said.
“Oil and gas will be challenged, but it will still be part of the energy mix for decades,” he said. “We need to make sure that we are doing our best to make it cleaner.”
Timing of Unit 2 repairs following May fire uncertain. Investigation said to be nearing completion: operator.
Nov 19, 2020
The ongoing outage comes during a particularly bullish period of activity for US LNG exporters, following a cratering of global demand earlier in the year due to the pandemic.
At Elba, the smallest of the six major US liquefaction facilities, a repair plan for Unit 2 will be finalized after the investigation into the fire is complete. That investigation is nearing completion, spokeswoman Katherine Hill said in an email responding to questions Nov. 19.
The operator provided similar statements in July and August, saying at each of those junctures that the investigation would be completed in the near term. A spokesman for Shell, the sole offtaker from the facility, did not immediately respond to a message seeking comment.
The terminal near Savannah — originally built to import LNG and later converted to handle exports after the US shale revolution — utilizes Shell’s Movable Modular Liquefaction System design. With 10 trains operating, it has a capacity of 2.5 million mt/year.
To date, because of the fire and ongoing shutdown of Unit 2, all 10 trains have not yet produced LNG simultaneously. Kinder Morgan placed the last of its 10 production units into service Aug. 27. Elba shipped its first cargo in December 2019. Only five more cargoes have loaded in the 11 months since then, according to cFlow, S&P Global Platts vessel-tracking software.
Normally, it could take as long as 100 days for each of the trains at Elba to fill a standard LNG cargo, Platts Analytics data show. By comparison, a single train at Cheniere Energy’s Sabine Pass in Louisiana could fill a standard LNG cargo in just under six days.
The fire at Elba in mid-May occurred in a mixed refrigerant compressor of Unit 2. Two adjacent units that were shut down as a precaution were later brought back online.
Besides the lengthy shutdown of Unit 2 at Elba, Cheniere continues to deal with the inability to use two of its five storage tanks at Sabine Pass that have been offline for almost three years.
While the company has effectively managed operations at the terminal with its other three storage tanks during the outage, being able to use the additional capacity would give it more flexibility, especially during times when consumption is high or access to feedgas may be limited because of pipeline maintenance.
An inadvertent release of gas January 22, 2018, led to the shutdown of tanks 1 and 2 at Sabine Pass in Cameron Parish. Cheniere said in August 2019 that repairs were complete. It has been awaiting regulatory approval since then to bring the tanks back online. A spokeswoman said Nov. 19 that there were no new updates to provide.
Total feedgas deliveries to major US LNG export facilities remained near a record high above 10.2 Bcf/d on Nov. 19, Platts Analytics data show. While the Platts JKM, the benchmark for spot LNG prices in northeast Asia, was assessed 7.8 cents/MMBtu lower on the day at $6.401/MMBtu on Nov. 19, a colder weather outlook for Japan and South Korea in December could bolster spot LNG price sentiment in the world’s biggest LNG import market going forward.
The spread of coronavirus across the world has generated an unprecedented global health and economic crisis, and presented the LNG industry with a demand shock like no other in its history. The outbreak has hit global LNG demand, incited contract disputes, disrupted trade flows and derailed project investment plans amid uncertainty over the length and […]
Aug 14, 2020
The outbreak has hit global LNG demand, incited contract disputes, disrupted trade flows and derailed project investment plans amid uncertainty over the length and depth of the crisis.
With cargo deferments and cancellations leading to a flurry of spot supply tenders and widespread national lockdowns offering little demand support on the horizon, curtailments at production facilities are seen as the only way to help re-balance demand and supply.
Sempra Energy received export permit Nov. 16. Production expected by 2024.
Nov 17, 2020
Sempra had postponed its FID for Energía Costa Azul, or ECA, at least two times this year as it waited for the export permit, the first ever to be granted by the Mexican government. ECA became the first LNG terminal to reach FID in 2020.
The terminal, which will be operated by its two subsidiaries Sempra LNG and IEnova, will include a single-train liquefaction facility with a nameplate capacity of 3.25 million mt/year of LNG, according to a Sempra statement. The first LNG production from the first phase is anticipated in late 2024.
The Pacific Coast project is designed to link natural gas supplies from Texas and the Western US to markets in Mexico and countries across the Pacific Basin, Sempra said.
Capital expenditures for the first phase are estimated at about $2 billion. Sempra plans to fund the project through a combination of equity distributions and debt.
ECA LNG has already signed 20-year sale and purchase agreements with Mitsui and a Total SE affiliate for 2.5 million mt/y of LNG and in February executed a lump-sum, turnkey engineering, procurement and construction contract with a TechnipFMC affiliate for the first phase. ECA LNG is also working to obtain a potential equity investment in the project from Total.
Sempra said it is developing additional LNG export facilities on the Gulf Coast and Pacific coasts including a potential second phase of the ECA LNG export project.