Navigating turbulence in Asia’s LNG market

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French utility Engie has agreed to a 15-year deal to buy 1.75 million mt/year of supply on a free-on-board basis from NextDecade’s proposed Rio Grande LNG export facility in Texas, while Swiss commodity trader Gunvor has agreed to a 20-year FOB deal to buy 2 million mt/year of supply from Energy Transfer's proposed Lake Charles LNG export facility in Louisiana. The two separate agreements were announced May 2, reflecting renewed interest in relatively cheap US LNG supplies amid a surge in spot end-user prices since 2021. There has been a flurry of commercial activity in 2021 and during the first several months of 2022 tied to current and proposed US LNG export terminals, which offer fixed fees and destination flexibility. More than half of the supply from Rio Grande LNG’s first phase is now covered under long-term agreements that are either firm or preliminary. An offtake deal between Engie and NextDecade fell through in November 2020 amid Engie’s environmental concerns about expanding its commitment to US shale gas. The turnabout in the market shifted the dynamics, as has Europe’s efforts to wean itself off Russian pipeline gas in the wake of the war in Ukraine. In a statement announcing its deal with Engie, NextDecade said it aims to reduce CO2 emissions from its facility in Brownsville by more than 90%. NextDecade has proposed a carbon capture and storage project that it would launch after making a final investment decision on the liquefaction terminal. Its current FID target on a minimum of two trains is the second half of 2022, with commercial operations expected to start as early as 2026. With the Engie sale and purchase agreement, under which LNG would be lifted from Rio Grande LNG’s first two trains, NextDecade has now secured long-term agreements covering 6.75 million mt/year of supply that would be produced by the terminal. The project's first phase is expected to account for around 11 million mt/year of capacity. Ultimately, NextDecade has proposed building five trains with total capacity of 27 million mt/year. NextDecade’s other customers are European energy major Shell and China’s Guangdong Energy and ENN. Energy Transfer's deal calls for the LNG it will supply to Gunvor to be indexed to the US Henry Hub benchmark plus a fixed liquefaction charge. First deliveries are expected as early as 2026. The deal will become fully effective upon the satisfaction of certain conditions, including Energy Transfer taking final investment decision on the Lake Charles project, the companies said in a joint statement. In March, ENN and affiliates agreed to 20-year FOB deals to buy 2.7 million mt/year of supply from Lake Charles LNG. Those were the first firm offtake deals announced for the US facility. The purchase price of those deals also will be indexed to the US Henry Hub, plus a fixed liquefaction charge. Energy Transfer, which lost Shell as a joint venture partner in 2020, has proceeded with the development of Lake Charles LNG. Energy Transfer may reduce the size of the project to two trains with 11 million mt/year of LNG capacity, from three trains with 16.45 million mt/year of capacity, the company said in a US regulatory filing in February. Engie said in November 2020 it halted talks over a potential long-term supply agreement with NextDecade amid pressure that European utilities faced from environmental interests to refrain from signing new long-term deals for importing US shale gas. Platts DES Northwest Europe for June was assessed at $22.464/MMBtu April 29. NWE is the delivered price of LNG into Northwest Europe. Platts JKM, the spot-delivered price of LNG into Northeast Asia, was assessed at $21.900/MMBtu. The Platts Gulf Coast Marker for US FOB cargoes loading 30-60 days forward was assessed at $21/MMBtu. The LNG markets were closed May 2. Engie agreed in June 2021 to an 11-year deal with Cheniere Energy tied to the US LNG exporter’s Corpus Christi Liquefaction terminal in Texas. Under the original agreement, a range of about 400,000 to 1.2 million mt/year of LNG was to be delivered to Engie free on board from the Cheniere terminal. The Engie-Cheniere deal was amended in March, with the term extended to around 20 years and the volume adjusted to include a higher average of about 900,000 mt/year over the life of the deal.

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China, the world's largest LNG importer, has become a seller of LNG export cargoes as domestic demand wanes amid pandemic movement curbs in Shanghai and fears of similar restrictions being imposed elsewhere in the country as authorities move decisively to stem the spread of COVID-19. "Except for the big three national oil companies – PetroChina, Sinopec and CNOOC-- which have an obligation to ensure natural gas supply, others LNG importers were heard to have resold many of their LNG imports recently," a trade source with an LNG terminal in south China told S&P Global Commodity Insights. LNG terminals were still profiting from selling long-term LNG cargoes in the domestic market, but reselling LNG cargoes in the international market was proving more profitable, the source said. A trade source with one of the top three state-owned oil majors said it was considering diverting some summer LNG supplies to other places where prices were higher. "China's demand for natural gas, especially for LNG, is expected to slow down this year," he said. This comes as an COVID-19 outbreak in Beijing has sparked fears of a Shanghai-style lockdown there. Mass testing for COVID-19 has also been ordered in several other major cities such as Hangzhou and Guangzhou, adding to concerns of further restrictions. "Not only spot LNG cargoes, but also those term contract volumes with destination flexibility are expected to be resold to other places where prices are higher this year," a third trade source said. Dongguan Jovo, a privately-owned LNG terminal in southern Guangdong province, sold an LNG cargo to Italy on an FOB basis in the first quarter, the Shanghai Petroleum and Natural Gas Exchange reported April 16, citing a response from the Shanghai-listed company on an investors' communication platform as part of its report. The Singapore trading arm of CNOOC also closed a sell tender on April 27 for a cargo loading over July 10-12 from Australia's Northwest Shelf. Award details could not be fully verified at the time of reporting. LNG imports at many terminals have also been reduced, with some terminals in northern China receiving only one LNG cargo in two weeks, another source in Beijing said. Dwindling LNG imports China's LNG imports fell 18% year on year and were down 4.8% month on month at 4.63 million mt in March, the lowest since April 2020, latest customs data showed April 20. Daily trucked LNG loadings scheduled at China's 21 LNG terminals totaled 826 trucks on April 15, down 26.9% from 1,130 trucks on April 1 and down more than half or 51.6% from 1,708 trucks on March 1, data from domestic energy information provider JLC showed. China's trucked LNG prices for coastal terminals and inland plants have dropped to below Yuan 8,000/mt ($1213.90/mt) since April 13, data from the Shanghai Petroleum and Natural Gas Exchange showed, which equates to $22/MMBtu and is close to the spot LNG price assessed in the North Asian market by S&P Global's Platts JKM on April 26. Less expensive domestically-produced natural gas and imported pipeline gas were expected to further squeeze the market share of imported LNG, sources said. PetroChina's Natural Gas Sales Western Branch offered 20 million cubic meters of pipeline gas for delivery over April 21-30 on the Chongqing Petroleum and Gas Exchange for auction last week. The transaction was settled at Yuan 4.4-4.42/cu m on April 19, which is equivalent to around Yuan 6,960-6,989/mt, or around $20/MMBtu, domestic energy information provider JLC said. LNG plants that bought pipeline gas for processing into LNG in the country's northwest sold at around Yuan 7,100-7,250/mt this week, much lower than the Yuan 7,600-8,600/mt offered by LNG terminals, according to market sources. This comes as China continues to increase domestic production of natural gas, with output rising 6.6% year on year to 56.9 Bcm in Q1, National Bureau of Statistics data showed. While China has said it has stopped releasing pipeline gas import data from 2022, its pipeline gas imports were estimated at around 10.54 million mt in Q1, up 7.1% on the year, according to S&P Global calculations based on the country's total natural gas imports of 27.82 million mt and the LNG imports of 17.28 million mt seen in the quarter. "Pipeline gas supply is ample recently," another source in Guangdong province said, adding that this was also weighing on LNG imports.

With 2022's volatile gas prices causing uncertainty across the energy markets, the case for LNG as a marine fuel has been shaken. LNG has previously been called the frontrunner in the race for alternative marine fuels – is that still the case? Editors Sam Eckett and Piers de Wilde are joined by analyst Anastasia Zania to look at the current state of the market, and the future outlook for LNG bunkers. Tell us more about your podcast preferences so we can keep improving our shows. Take our two-minute survey here: https://bit.ly/plattspod22 More listening options: No content (including ratings, credit-related analyses and data, valuations, model, software or other application or output therefrom) or any part thereof (Content) may be modified, reverse engineered, reproduced or distributed in any form by any means, or stored in a database or retrieval system, without the prior written permission of Standard & Poor's Financial Services LLC or its affiliates (collectively, S&P).

South Korea's state-run Korea Gas Corp. will import 1.58 million mt/year of LNG from BP for up to 18 years from 2025 under a new long-term deal as its existing purchase contracts are set to expire, the company said April 22. The sales and purchase agreement with BP Singapore Limited follows a heads of agreement between the two sides that was concluded in September 2019. The latest deal is the first long-term supply contract between the two companies, providing Kogas assured deliveries and an opportunity to stabilize the country's high gas prices. Under the deal, BP will provide 1.58 million mt/year of LNG produced in BP-led projects in the US, such as Freeport LNG in Texas, Kogas said in a statement, adding that the SPA would also "serve as a catalyst to strengthen cooperation between the two companies." The company did not disclose financial details of the agreement, but said the 18-year deal linked to the Henry Hub is "considered very competitive given current LNG prices and crude oil prices." "The supply deal based on LNG produced in the US including Freeport LNG would help Kogas reduce its reliance on the Middle East and diversify supply sources," the statement said. "The deal also allows Kogas to reduce import volumes and change unloading ports, which will help the state utility cope with possible changes in demand and supply," it said. A timely outcome The 18-year deal with BP comes at a time when many of Kogas's existing long-term supply agreements have been expiring since 2019. This includes four contracts totaling 5.78 million mt/year -- 2 million mt/year from Malaysia's MLNG II project, 2 million mt/year from Yemen's YLNG, 1 million mt/year from Brunei's BLNG, and 0.7 million mt/year from Indonesia -- which expired in 2019 alone. Kogas will lose 7.02 million mt/year of Qatari LNG by 2026. The 20-year deal for 2 million mt/year of Rasgas LNG will also expire in 2032. Several more long-term deals Kogas has with other providers, such as 4 million mt/year from Oman's OLNG, are scheduled to expire before 2030. The most-recently signed long-term supply deal was a 20-year agreement signed in 2012, under which Kogas has been importing 2.8 million mt/year from Cheniere's Sabine Pass terminal in Louisiana since June 2017. Kogas said it has been tapping the market for new term contracts amid expirations of previous ones, adding that it will seek to diversify LNG supply sources beyond the Middle East and Southeast Asia to include Russia and the US. In July 2021, Kogas signed an agreement with Qatar Petroleum under which the state utility will import 2 million mt/year of LNG from Qatar for 20 years from 2025. The new supply deals come as Kogas increased LNG imports to meet growing demand for the fuel amid South Korea's push to reduce its reliance on coal and nuclear in power generation. In 2021, Kogas, one of the world's biggest LNG buyers, imported 38.17 million mt, up 19.6% from 2020. Kogas imports in 2021 accounted for 83.1% of the country's total LNG imports of 45.93 million mt. Some 70%-80% of Kogas LNG purchases are based on term contracts and the rest are spot purchases, according to Kogas officials. Kogas currently has nine long-term contracts -- 9.02 million mt/ year in three contracts from Qatar, 4 million mt/year from Oman, 3.5 million mt/year from Australia, 2 million mt/year from Malaysia, 0.7 million mt/year from Indonesia, 1.5 million mt/year from Russia's Sakhalin, and 2.8 million mt/year from the US Sabin Pass. LNG sales by Kogas, which has a monopoly in domestic natural gas sales, rose 4.4% year on year to 12.66 million in the first quarter this year, according to Kogas data compiled by S&P Global Commodity Insights.

The discount of Northwest Europe delivered LNG to the Europe's Dutch TTF natural gas hub grew to its widest level in six weeks April 21. Traders cited weak demand and limited slot availability at regasification facilities. Volatility was expected to continue amid the uncertain supply picture that has been exacerbated by Russia's invasion of Ukraine. "Demand destruction everywhere at the current prices and mild weather," one Atlantic Basin trader said. A second trader said neither the Atlantic Basin nor Asia had much of a buying appetite at the moment. "So, for this reason the high discounts and the problem with the slots," the second trader said. "In the Atlantic, there is a huge discount in PEG or PVB versus TTF, so in order to sell there you need a huge discount." PEG is a French gas hub, while PVB is a Spanish gas hub. S&P Global Commodity Insights' Platts DES Northwest Europe for June was assessed at $26.879/MMBtu April 21, while the June TTF contract was assessed at $32.067/MMBtu. Northwest Europe's $5.188/MMBtu discount to TTF was the widest reported since March 10. The delivered price of LNG into the Mediterranean was assessed at a 30 cent/MMBtu discount to NWE April 21 based on market information. Despite having fallen from record highs in early March, delivered LNG prices to Europe remain sharply higher than a year ago. Market participants have worried about the impact persistently high prices would have on end-user demand for LNG. Meanwhile, for several months, market participants have reported limited regasification slots available in Europe for prompt delivery. That issue was heightened by the significant LNG volumes that headed toward Europe after the war in Ukraine started Feb. 24 amid fears of pipeline gas disruptions. Across the Atlantic, the Platts Gulf Coast Marker for US FOB cargoes loading 30 to 60 days forward was assessed at $25.630/MMBtu April 21, up $1.48 on the day.

Pakistan LNG Ltd has asked interested suppliers to submit bids by April 21 to supply LNG cargoes to meet demand for the summer season as the country grapples with frequent power outages, a government document said April 17. The bids will be opened on the same day and the first cargo has been sought for the window of May 12-13, the second for May 17-18, a third one for May 27-28, a fourth for June 1-2, a fifth in June 2022 and a sixth cargo for June 16-17, the document said. The demand for electricity rises significantly during Pakistan's summer that runs from May to July and consumers usually see load-shedding for eight to 12 hours per day during this period. Power generation rose 11.1% to 8,088 GWh in February to cater to rising demand, compared to 7,281 GWh (10,835 MW) in the same month last year. The rise in generation was due to higher generation from fuel oil, wind, coal and nuclear plants as the government tapped alternative sources to meet surging demand, data from the National Electric Power Regulatory Authority showed. Coal accounted for 32%, hydel around 18%, RLNG for 15%, nuclear around 13%, gas 11% and fuel oil for 7% of the total power generation in February, according to the data. RLNG prices lowered Pakistan's Oil and Gas Regulatory Authority, or OGRA, announced a lower RLNG price for April for Sui Northern Gas Pipelines, with the price pegged at $15.62/mmbtu, down $0.19/mmbu month on month. The RLNG price for Sui Southern Gas Company was $16.91/mmbtu in April, down $0.20/mmbtu month on month, the Authority said. Prices of RLNG have been cut to boost LNG demand and reduce circular debt levels, which are not usually passed down the supply chain when changes in fuel import prices occur. RLNG prices have also dropped because Qatar is supplying LNG to Pakistan on a Government-to-Government contract basis. Pakistan has two agreements with Qatar for 15 years and 10 years basis at 13.37% and 10.2%, respectively, of Brent.

China signed a record high 22.7 million mt of LNG term contracts in 2021, up 516% year on year, with some contracts starting delivery in 2022, which will boost LNG imports in coming years, state-owned oil and gas company CNPC's Economics & Technology Research Institute, or ETRI, said in its latest report published in the week starting April 10. ETRI said China's natural gas imports in 2022 are forecast to reach a total of 185 Bcm, up 10.1% year on year, supported by incremental volumes through the Russia-China natural gas pipeline's eastern route and the commissioning of new LNG terminals such as Zhangzhou and Binhai LNG terminals. China has increased its pipeline gas imports from Russia to 43 million cu m/day or around 15 Bcm/year since December 2021, and the volume is expected to further increase with more pipeline facilities completing constructions, ETRI said, noting that the total length of China's long-distance natural gas pipeline has reached nearly 84,000 km as of 2021. China overtook Japan to become the world's biggest LNG importer in 2021, and its total LNG receiving capacity has reached 91.3 million mt/year by the end of the year, according to ETRI. China's natural gas production is expected to reach 221.6 Bcm in 2022, up 6.2% on the year, slightly higher than the target of 214 Bcm for 2022 set by the National Energy Administration in its work guidelines released on March 29. China's natural gas production was 208.6 Bcm in 2021, including 23 Bcm of shale gas, 10.5 Bcm of coal-bed methane and 4.6 Bcm of coal gas, up 16 Bcm or 8.3% year on year, according to ETRI. Domestically produced natural gas is expected to account for 55% of the country's total natural gas supply, while imported LNG and pipeline gas are estimated to account for 30% and 15% of the total supply in 2022, respectively, ETRI data showed. China's natural gas demand is also expected to grow by 8.2% in 2022, slowing from 12% in 2021, with the largest growth coming from the power generation and industrial sectors, as the country adds around 10 GW of new installed gas power generation capacity this year, ETRI said. "There's still room for peak shaving demand for natural gas power in the east and south China where environmental protection policies are relatively stricter," an analyst with ETRI said. "Overall city gas demand will remain stable this year, with main growth coming from urban residents and heating demand, but there are some uncertainties in the demand increase from coal-to-gas switching in rural areas and commercial and service sectors," the analyst said. China has relaxed the coal-to-gas switching policy in rural areas, while natural gas demand growth is expected to be dampened by tighter COVID-19 restrictions this year, the analyst said.

After settling at its highest price in over a decade on April 7, the NYMEX Henry Hub prompt-month contract largely kept its gains in April 8 trading, as a widening storage deficit and the strength of natural gas exports raised supply concerns. NYMEX Henry Hub May settled at $6.278/MMBtu April 8, just 8.1 cents lower than its prior-day settlement of $6.359/MMBtu on April 7, preliminary settlement data from CME Group shows. The April 7 daily settlement was the highest the prompt-month contract has reached since Dec. 2, 2008, according to data from S&P Global Commodity Insights. Even with the April 8 dip, the May contract has gained more than 70 cents since becoming the front month contract. Late spring price rallies are not uncommon for natural gas futures, though few are as extreme as the recent price run-up, experts said. Traders are looking ahead to the summer months at this time of year, since "all the risk to your outlook is on the front end, where you don't know how warm it will be," Daniel Myers, senior market analyst at Gelber & Associates, said in a telephone interview. Stephen Schork, principal at The Schork Report, had a similar view, saying that "natural gas is a very counterintuitive market, [futures prices] tend to run up before the summer or the winter during the shoulder season months." Supply concerns are likely heating up the typical shoulder season price rally, with US gas stocks lagging the five-year average at a time when European energy security concerns have put additional pressure on US exports. This concern is reflected further along the NYMEX Henry Hub forward curve, with every contract until March 2023 settling above $6/MMBtu in April 8 trading. Just one week earlier in April 1 trading, only two contracts – December 2022 and January 2023 – settled above $6/MMBtu. The 2022-2023 winter strip (November – March) has soared, settling at an average of $6.47/MMBtu on April 8. This is up nearly 60 cents from settling at $5.90/MMBtu on April 1. Supply concerns One source of supply concern heading into the summer and winter demand seasons is the state of US storage, which has recently widened the deficit to its five-year average. In its most recent weekly gas storage report, the US Energy Information Administration observed a 33 Bcf net withdrawal from Lower 48 storage, bringing total levels to 1.382 Tcf. Storage currently sits 22.4% lower than the same week a year ago and 17.1% lower than the five-year average. "We're short on supply in the near term and there is no response really from the supply or demand side to deal with the acute supply crunch," Myers said. "Drilling has picked up, and production is on the way, but it is not evident to the market in the immediate future." US gas production has averaged 93.5 Bcf/d so far in April, down around 300 MMcf/d from March levels, data from S&P Global showed. Volumes have continued to lag the near record-highs seen in December, when US gas production averaged 95.7 Bcf/d. On the demand side, limited fuel switching options and record-high gas exports have also increased the pressure on supply. "A typical response in the market in years past [to high gas prices] would be that power generators are incentivized to burn more coal than gas," Myers said. "It is the case now that the response simply isn't there, both because a lot of coal capacity has been retired over the past several years and because coal prices themselves are under pressure and rising." US LNG exports are on track to see a record-high year, averaging 12.55 Bcf/d year to date, up from 10.33 Bcf/d for the same time a year ago. Global demand for US LNG cargoes is strong, as European countries seek to source alternatives to Russian gas in response to Russia's ongoing invasion of Ukraine. Outlook From a technical perspective, the near-term market reaction will be indicative of where prices might go from here, David Thompson, executive vice president at brokerage Powerhouse, said in an interview. "It will be interesting to see if we can power through this," Thompson said. Remaining near the top of the market highs "would open new technical fresh ground to run in, but we also have the technical conditions for a big sell-off." The $6.10-$6.30 range has historically been an impassable resistance point for other gas futures rallies over the last decade, with a late October 2021 push peaking at $6.202/MMBtu and a February 2014 run-up fizzling out at $6.149/MMBtu. Even the January price spike observed earlier this year, which market watchers characterized as a "classic short squeeze", settled at $6.265/MMBtu. "We are technically overbought on momentum indicators by a significant degree – this doesn't necessarily signal a big collapse in price though. We were also overbought in October, and we chopped sideways before finally selling off going into December," Thompson said. Myers echoed a similar sentiment saying, "I think things will settle down when true summer demand appears."

Soaring feedstock gas and power prices following Russia's invasion of Ukraine on Feb. 24 have sent hydrogen price assessments sharply higher in Europe, underlining the region's potential for imports of the renewable energy carrier. The UK remained the highest priced region globally for low-carbon hydrogen production, with the Netherlands close behind, the S&P Global Commodity Insights Hydrogen Price Wall showed. UK electrolysis production prices averaged around $20/kg in March, more than six times the cheapest locations in Western Australia and the US Gulf Coast. UK prices were also more than 40% higher than in Japan, another potential importer. "As well as regional comparisons, understanding the different options across different production pathways is vital when considering the most appropriate option in each region," S&P Global Commodity Insights Head of Energy Transition Pricing Alan Hayes said. The US is emerging as a low-cost steam methane reforming hydrogen production center, with that production pathway shown as the cheapest globally. The Hydrogen Price Wall shows the lowest cost region for hydrogen production (via conventional steam methane reforming without carbon capture and storage, or CCS) was the US midcontinent at just $1.21/kg. Prices in the midcontinent slipped below other US regions, with power and gas input prices falling steeply on mild weather and reduced demand. The price wall also shows, however, that in locations where power feedstock is cheap, electrolysis production is already under $3/kg. Electrolysis production costs in Australia and the Middle East were lower than fossil-based production with CCS in the same locations. While hydrogen price increases were acutely felt in Europe, prices also rose sharply in Japan, with knock-on effects from global surging LNG prices following the Russian invasion and an earthquake that hit northern Japan on March 16, temporarily shutting down several thermal power plants in the region.

Heading into spring, PJM Interconnection wholesale power prices declined slightly on month in March but remain much higher than a year ago, while the power generation fuel mix shifted away from coal and toward natural gas during the month. "Temperatures across the PJM footprint were 3 degrees Fahrenheit above normal in March, a deviation similar to March 2021, and this kept overall PJM power demand flat year on year," S&P Global Commodity Insights said in a recent research note. The average March high temperature across the PJM footprint was 54.8 degrees F compared with an average February high of 43.8 degrees F, according to CustomWeather data. The average low temperature in March was 37 degrees F, compared with an average low of 26.9 degrees F in February. As a result of the warmer temperatures, average heating degree days declined from 29.1 in February to 18.7 in March. PJM peak load averaged 94,633 MW in March, an 11% decline from February's average peak load of 105,945 MW. In March 2021 peak load averaged 91,609 MW, according to ISO data. PJM East Hub power prices recorded the largest decline on month and the lowest year-over-year change of the major pricing hubs. East Hub day-ahead, on-peak power prices averaged $43.34/MWh in March, a roughly 19% decline on month and about 20% higher than year-ago levels. PJM West Hub on-peak day-ahead power prices averaged $48.29/MWh in March, which was about 8% lower on month and 85% higher than the March 2021 average of $26.09/MWh. Day-ahead on-peak power prices at the AEP-Dayton Hub averaged $46.98/MWh in March, which was down 2.27% on month and about 83% higher on year. Real-time on-peak power prices at the hub increased by just under 2% on month and were 72% higher on year to average $45.90/MWh in March. Northern Illinois Hub day-ahead on-peak power prices averaged $40.69/MWh in March, a 2.39% decline on month and about 77% higher on year. Spot natural gas price movement was mixed in March, with Platts Texas Eastern prices averaging $4.46/MMBtu, a 22% decline from February and about 102% higher than the March 2021 average. Chicago city-gates prices increased by 2.61% on month in March to average $4.60/MMBtu, which was about 86% higher than a year ago. Power generation fuel mix "Steady gas dispatch month on month in March, just above 35 aGW, came with a large decline in coal-fired generation, which was down to less than 16 aGW following the significant impact of the surge in Illinois Basin and Appalachian coal prices," the S&P Global power market analysts said. Coal-fired power accounted for 18.4% of the PJM fuel mix in March, down from 23.8% in February, according to ISO data. "We anticipate coal generation to continue dropping between April and May as coal prices are lifted by a very tight seaborne market, while the present conditions for LNG exports, already close to being maximized, offer a cap on gas prices," S&P Global said. Gas-fired power accounted for 38.3% of the generation mix in March compared with 35.1% in February, while nuclear power supplied 33.6% of PJM's generation mix in March, up from 32.1% in February. Hydropower, wind power and non-wind renewables all accounted for greater shares of the fuel mix in March, averaging 2.5%, 5.2% and 1.5% respectively. Forward power, gas prices PJM West Hub forward power prices for April averaged $56.56/MWh in March trading, 5.8% higher on month and about 100% higher on year. The May contract average $59.72/MWh, which was 11% higher on month and 105% higher on year, while the June contract averaged $60.74/MWh, a 12% monthly increase and 107% higher on year, according to Platts M2MS data. AEP-Dayton Hub forward power prices for April averaged $55.64/MWh in March trading, about 6% higher on month and 94% higher on year. The May contract averaged $59.00/MWh, 11% higher on month and 100% higher on year. The June contract averaged $60.22/MWh, 12% higher on month and 100.2% higher on year. Forward Platts Transco Zone 6 Non-New York gas prices also strengthened heading into summer during March trading. The April contract averaged $4.12/MMBtu, an 8% monthly increase and 88% higher on year. Forward gas prices for May averaged $4.14/MMBtu, about 14% higher on month and 92% higher on year, while the June contract averaged $4.26/MMBtu, which was 13% higher on month and 92% higher on year. "With nuclear refueling largely limited to April and again to the fall shoulder months, our power price outlook for the remainder of the year finds support around $40/MWh, while moving above $50/MWh in the summer," S&P Global said.

Belgian gas infrastructure operator Fluxys is to continue offering LNG transshipments services at its Zeebrugge terminal for cargoes from the Novatek-operated Yamal LNG facility in northern Russia, a Fluxys spokesperson said April 7. Fluxys in 2015 signed a 20-year deal with Yamal Trade -- a subsidiary of Yamal LNG -- for the transshipment of up to 8 million mt/year of Yamal LNG and carried out the first loading under the contract in late 2019. The arrangement allows for Russia's specialized ice-breaker LNG carriers to transfer Yamal LNG volumes at Zeebrugge onto conventional LNG vessels to allow regular onward shipments to Asia-Pacific and Middle Eastern markets. "While currently no European sanctions have been imposed on the receipt of Russian gas, Fluxys -- as a facilitator of an essential service -- is obliged to respect contractual agreements with all customers, including Russian customers," the Fluxys spokesperson told S&P Global Commodity Insights. "It goes without saying that as soon as sanctions are implemented regarding the LNG from Russian LNG carriers, Fluxys would comply and cooperate with the governments concerned," the spokesperson said. "The decision to close our grid to Russian ships is indeed up to the government authorities. This is a major decision, which may have an impact on Europe's supply, as the European market has no immediate alternatives to significantly reduce its dependence on Russian gas." A total of 181 LNG vessels from all sources called at Zeebrugge in 2021, the highest ever number, Fluxys said at the end of March. According to analysts at S&P Global Commodity Insights, around 5.3 Bcm of LNG supply from Yamal LNG was transshipped or reloaded to non-European markets from European terminals in 2021. Of that, an estimated 4.8 Bcm of that was transshipped or reloaded at Zeebrugge. Gas sanctions There are growing calls for the EU to consider sanctions against Russian gas imports, including LNG, in response to Russia's invasion of Ukraine on Feb. 24. European Council President Charles Michel said April 6 that the EU would need to take action on Russian gas imports "sooner or later" to maintain pressure on the Kremlin. While the European Commission has signaled its intent for a sharp reduction in EU demand for Russian gas -- by as much as two-thirds by the end of the year -- contracted European buyers, mostly privately owned companies, have pledged to continue buying. The EC proposed on April 5 a ban on Russian shipping from EU ports, but said certain exemptions covering essentials such as food, humanitarian aid and energy would apply. With European gas prices still at sustained highs, Russian gas suppliers such as state-controlled Gazprom and Novatek are bringing in significant amounts of money. The TTF front-month contract reached a record high of Eur212.15/MWh on March 8, according to Platts price assessments by S&P Global. The contract averaged Eur129/MWh in March, an increase of 640% over the average in March 2021 of just Eur17.50/MWh. The EU's foreign affairs chief Josep Borrell said April 6 that since the start of the war, the EU had paid Eur35 billion to Russia for energy supplies.

Europe can deploy new LNG import infrastructure far more quickly than in the past when there is the "political will" to do so, a senior official from industry group Gas Infrastructure Europe said April 6. GIE deputy secretary general Roxana Caliminte, speaking during a Eurogas-organized webinar, also said it would be important for Europe to lock in long-term LNG supply agreements to guarantee imports. "We are working in very fast-paced times. We've got to be careful to do things right," Caliminte said. Countries across Europe are currently rushing to secure new LNG import infrastructure as they look to cut Russian pipeline imports, with plans being made to realize numerous projects -- both old and new -- in record time. Most of the plans are for floating LNG import facilities -- known as FSRUs (floating storage and regasification units) -- which can be installed more quickly than onshore, permanent import terminals. "Germany, Italy, France, Poland, Greece, the Netherlands -- they are betting their best cards on this infrastructure," Caliminte said. She said that it usually takes three-to-five years to build an onshore LNG terminal. But, she said, when there is the "political will" this time frame can be reduced. In the case of FSRUs, the time frames are shorter, and can be shortened still, she said. "FSRUs are a very flexible and quick option to bring more LNG to Europe. It can take as little as 18-24 months. But today we are seeing an accelerated process -- it would take up to half of the initial timing at 12-18 months," Caliminte said. "Where there is a will, there is a way." Germany is planning to deploy three FSRUs in the near future, while Italy has plans to install two new FSRUs this year. The Netherlands has signed a deal to deploy an FSRU at Eemshaven this year, while France, Estonia and Latvia also hope to realize new FSRU projects. "We need to ensure a fast-track approval process for LNG import terminal projects," Caliminte said. "Member states have to act very quickly and be willing to go beyond business as usual." Spanish case Caliminte also called for improved interconnection between EU countries to help bring regasified LNG to more member states. "In order to get maximum imports through LNG terminals, it is important that gas can be efficiently distributed throughout the entire EU, to the main consumption areas or places with storage," she said. "We may want to look into the Spanish case. Because they have a lot of regasification capacity, but they need to make sure this is sent out throughout Europe in a proper way," she said. Spain has has six operational LNG import terminals with an import capacity of 44.1 million mt/year (61 Bcm/year). That is more than enough to meet the country's annual gas demand, which totaled 36 Bcm in 2021, according to official data. However, the Iberian Peninsula is poorly interconnected with the rest of Europe, with just limited interconnection with France. There are growing calls for Spain and France to revive the stalled Midcat pipeline project to allow more regasified Spanish LNG to be sent out to the rest of Europe. The pipeline project was effectively shelved in 2019 after regulators concluded the 120-km link across the Pyrenees was too costly and ineffective. Long-term contracts Caliminte said Europe also faced the challenge of securing LNG volumes. "As we speak, the challenge is to find the LNG," she said. "The EU wants to substitute 150 Bcm of Russian gas -- this means taking out one third of the global LNG trade," she said. "That is not going to happen because the largest part of global LNG trade is bound in long-term and destination-specific contracts," she said. Caliminte pointed to Qatar as an example, where the majority of its LNG is sold to Asia under long-term contracts. "So it is important to have an open-minded [European] Commission and allow member states to [use] such mechanisms too. There is no way around it," she said. Caliminte also said to secure more US LNG, there was a need for more US LNG liquefaction projects. "US LNG liquefaction capacity is maxed out. To get more US LNG, they need to liquefy more," she said, adding that new projects needed to be bankable. "And in order to be bankable, they need to secure long-term contracts," she said.