2022 Global Power Markets

December 14, 2021 8:30 am - 3:30 pm CST Online Pricing: Complimentary Where energy connects The South American Virtual Forum offers attendees an in-depth look at the South American commodities markets, with a particular emphasis on Argentina and Colombia. We’ll examine oil and gas, LNG, biofuels, petrochemicals , and the impact of the energy transition on these industries. Join us from the comfort of your desk, to explore the issues impacting the markets today, and projections for the future, in topical sessions featuring Platts’ methodology, assessments, and pricing. What's included You can expect live presentations, real-time interaction, and the opportunity to engage in questions and answers with the speakers throughout, right from your desk. Key topics we'll cover -Latin American economic overview-South American upstream-Refined products markets-Shipping and freight markets-Petrochemicals demand and outlook-Biofuels and biodiesel in regional markets-Natural gas and LNG outlook-South American metals outlook  REGISTER NOW MORE INFO

May 10-11, 2022 | Hilton Houston Post Oak, Houston, TX Transforming the future of LNG together The S&P Global Platts LNG Conference welcomes back industry leaders, decision-makers, and market-movers to Houston, TX, for an in-depth look at global LNG markets and networking opportunities. We'll bring together industry experts to discuss Carbon Neutral LNG, pricing, market outlooks, financing large-scale projects, and more. Topics of discussion will include: — Project Expansion: Increasing Export Capacity — Carbon Neutral Fireside Chat — LNG Bunkering: Building Capacity — 2021 Pricing Retrospective — 2022 Market Outlook — Financing Large Scale LNG Projects — Market Dynamics: The Changing Pricing Formula and its Impact on Industry REGISTER NOW MORE INFO

The current European energy crisis is a "stark reminder" of the vital role of LNG in ensuring energy security and economic stability, Jean Abiteboul, the president of industry group GIIGNL, said May 5. In the latest GIIGNL annual report, Abiteboul said the group would monitor the "paradigm shift" in the sector over the coming year as governments and public institutions become increasingly involved in the LNG business. Europe in particular is looking to LNG to replace Russian gas imports and is rushing to install new LNG import infrastructure. Abiteboul said that additional investments "in all stages of the gas and LNG supply chains" would need to be made to meet expected demand growth According to the report from GIIGNL -- which represents the world's LNG importers and import infrastructure operators -- global LNG imports in 2021 rose 4.5% year on year to 372.3 million mt. Growth was driven by economic recovery in China, rising gas demand for power generation in South Korea, lower-than-expected pipeline supplies to Europe and reduced availability of hydropower in Brazil. The increase in global LNG demand came despite spot LNG prices moving higher throughout 2021. The benchmark Platts JKM spot Asian LNG front-month price averaged $18.60/MMBtu last year, compared with an average of just $4.39/MMBtu in 2020. Spot LNG prices have remained at sustained highs in 2022, with the JKM last assessed May 5 at $23.70/MMBtu. Of the total imports last year, 136.3 million mt -- or 37% of the total -- was imported on a spot or short-term basis, short-term meaning under a contract of four years or less. "True" spot volumes -- those delivered within three months of the transaction date -- accounted for 31% of total imports last year, or 116 million mt, GIIGNL said. Re-exports of LNG increased to 3.5 million mt, compared with 2.6 million mt in 2020. GIIGNL said that LNG demand would remain buoyant in the future due to the "much-needed" substitution of coal and polluting liquid fuels as well as the geographical mismatch between gas production and consumption regions. New importing markets Asia, GIIGNL said, remained the main demand center for LNG, growing by 7.1% to 272.5 million mt in 2021, with China overtaking Japan as the world's top LNG importing country. Chinese imports rose by 15% to 79.3 million mt last year. India, however, experienced the greatest decline in LNG imports, falling 9.8% due to the high spot LNG prices and the increase in domestic gas production. Global regasification capacity rose by 46 million mt/year last year, reaching 993 million mt/year, GIIGNL said. Four new large-scale terminals were brought into operation in Brazil, Croatia, Indonesia and Kuwait, while five expansion programs were completed -- four in China and one in Japan. Croatia last year became the 44th LNG importing market, while at least six new markets could start importing in 2022 -- El Salvador, Ghana, Hong Kong, the Philippines, Senegal and Vietnam, the industry group said. While demand growth remained strong, GIIGNL said LNG production had been struggling to keep pace, which contributed to the spot LNG price strength. Some 7.4 million mt/year of new capacity came onstream, of which 5 million mt/year in the US. "Global LNG exports were affected by unscheduled maintenance and shortfalls in feedgas," it said. Increased output from the US, Egypt, Malaysia and Russia was partly offset by lower exports from Angola, Indonesia, Nigeria, Norway, Peru and Trinidad. Only two final investment decisions on new liquefaction capacity were taken in 2021 -- the North Field expansion project in Qatar and Pluto LNG Train 2 in Australia. By 2025, more than 120 million mt/year of new liquefaction capacity is planned to progressively come online, "which should partly relieve tensions in the LNG market," GIIGNL said. Long-term contracts The LNG market has also been marked by a revival in long-term contracts given the ongoing supply uncertainties, mostly around risk to Russian pipeline deliveries. "In an environment marked by geopolitical tensions, risks of energy shortages and price volatility, last year saw a strong return of long-term contracts," GIIGNL said. "Asian buyers, notably Chinese NOCs and independent importers, played a leading role in securing new term purchases from the US, Qatar and Russia," it said. GIIGNL also said 68 new LNG vessels were delivered during the year, with the LNG shipping fleet reaching 700 vessels, including 48 FSRUs and 31 LNG bunkering vessels, representing a 9% increase in cargo capacity. Freight rates remained strong throughout the year and the orderbook at year-end was "remarkably high", with 196 units to be delivered by 2025, it said.

The current European energy crisis is a "stark reminder" of the vital role of LNG in ensuring energy security and economic stability, Jean Abiteboul, the president of industry group GIIGNL, said May 5. In the latest GIIGNL annual report, Abiteboul said the group would monitor the "paradigm shift" in the sector over the coming year as governments and public institutions become increasingly involved in the LNG business. Europe in particular is looking to LNG to replace Russian gas imports and is rushing to install new LNG import infrastructure. Abiteboul said that additional investments "in all stages of the gas and LNG supply chains" would need to be made to meet expected demand growth According to the report from GIIGNL -- which represents the world's LNG importers and import infrastructure operators -- global LNG imports in 2021 rose 4.5% year on year to 372.3 million mt. Growth was driven by economic recovery in China, rising gas demand for power generation in South Korea, lower-than-expected pipeline supplies to Europe and reduced availability of hydropower in Brazil. The increase in global LNG demand came despite spot LNG prices moving higher throughout 2021. The benchmark Platts JKM spot Asian LNG front-month price averaged $18.60/MMBtu last year, compared with an average of just $4.39/MMBtu in 2020. Spot LNG prices have remained at sustained highs in 2022, with the JKM last assessed May 5 at $23.70/MMBtu. Of the total imports last year, 136.3 million mt -- or 37% of the total -- was imported on a spot or short-term basis, short-term meaning under a contract of four years or less. "True" spot volumes -- those delivered within three months of the transaction date -- accounted for 31% of total imports last year, or 116 million mt, GIIGNL said. Re-exports of LNG increased to 3.5 million mt, compared with 2.6 million mt in 2020. GIIGNL said that LNG demand would remain buoyant in the future due to the "much-needed" substitution of coal and polluting liquid fuels as well as the geographical mismatch between gas production and consumption regions. New importing markets Asia, GIIGNL said, remained the main demand center for LNG, growing by 7.1% to 272.5 million mt in 2021, with China overtaking Japan as the world's top LNG importing country. Chinese imports rose by 15% to 79.3 million mt last year. India, however, experienced the greatest decline in LNG imports, falling 9.8% due to the high spot LNG prices and the increase in domestic gas production. Global regasification capacity rose by 46 million mt/year last year, reaching 993 million mt/year, GIIGNL said. Four new large-scale terminals were brought into operation in Brazil, Croatia, Indonesia and Kuwait, while five expansion programs were completed -- four in China and one in Japan. Croatia last year became the 44th LNG importing market, while at least six new markets could start importing in 2022 -- El Salvador, Ghana, Hong Kong, the Philippines, Senegal and Vietnam, the industry group said. While demand growth remained strong, GIIGNL said LNG production had been struggling to keep pace, which contributed to the spot LNG price strength. Some 7.4 million mt/year of new capacity came onstream, of which 5 million mt/year in the US. "Global LNG exports were affected by unscheduled maintenance and shortfalls in feedgas," it said. Increased output from the US, Egypt, Malaysia and Russia was partly offset by lower exports from Angola, Indonesia, Nigeria, Norway, Peru and Trinidad. Only two final investment decisions on new liquefaction capacity were taken in 2021 -- the North Field expansion project in Qatar and Pluto LNG Train 2 in Australia. By 2025, more than 120 million mt/year of new liquefaction capacity is planned to progressively come online, "which should partly relieve tensions in the LNG market," GIIGNL said. Long-term contracts The LNG market has also been marked by a revival in long-term contracts given the ongoing supply uncertainties, mostly around risk to Russian pipeline deliveries. "In an environment marked by geopolitical tensions, risks of energy shortages and price volatility, last year saw a strong return of long-term contracts," GIIGNL said. "Asian buyers, notably Chinese NOCs and independent importers, played a leading role in securing new term purchases from the US, Qatar and Russia," it said. GIIGNL also said 68 new LNG vessels were delivered during the year, with the LNG shipping fleet reaching 700 vessels, including 48 FSRUs and 31 LNG bunkering vessels, representing a 9% increase in cargo capacity. Freight rates remained strong throughout the year and the orderbook at year-end was "remarkably high", with 196 units to be delivered by 2025, it said.

China’s LNG and natural gas markets are unique. Unlike in other North Asian countries, only one-fifth of China’s natural gas consumption is for power generation. Its collective industrial consumption (including fertilizers) accounts for 50% of total gas consumption * . China's natural gas demand by sector Sector 2022* (Bcm) 2021 (Bcm) % Growth Power generation 73.3 66 11.1% Industrial sector 159.9 145.2 10.1% City gas 124.4 116.4 6.9% Fertilizer and chemicals 37.9 37.9 0.0% Total 395.4 365.4 8.2% Note: * Calculation volume based on the growth rates provided by CNPC ETRI Source: CNPC Economics & Technology Research Institute China’s trucked LNG is a much-followed part of this unique market. There are a few reasons for this: LNG that leaves import terminals by truck – totalling around 22 million mt in 2021 – accounts for around 30% of China’s LNG import volume, which was the largest in the world in 2021. It is also a very prompt market and not price-regulated. Therefore, it can give an indication of the immediate prevailing fundamentals in the region of China the trade takes place. In this sense, China’s trucked LNG market is similar to the port stocks trade that takes place for other major bulk commodities, such as iron ore or coal. Like these commodities, the trade takes place off the back of imported cargoes, and it happens in many locations around China – each with different local market dynamics – making it hard to have a unifying “trucked LNG price”. For instance, in south China, there’s less connectivity to pipeline gas from than the north and east China, so it is relatively more reliant on LNG and therefore the demand for trucked LNG comes from power generation, industrial and city gas. In northern China, trucked LNG demand comes mainly from the industrial sector. The regional imbalances can be so big that they can attract, occasionally, trucked LNG from one part of the country to another, as what happened in April 2022, when there were sales of trucked LNG from north to south China. Cargo benchmarks solve this issue by reflecting a whole seaboard or multiple locations, meaning that the fundamentals of the whole are reflected, rather than the minutiae of the local. Unlike these other commodities, in some ways trucked LNG trade is taking place due to a lack of infrastructure: pipelines. Nearly always it would be more cost-effective in the long run to regasify and transport the gas by pipeline to demand sources, rather than ship in individual trucks. Indeed, market participants noted that trucked LNG trade has declined in the last couple of years, especially in areas where alternative infrastructure has been installed. As a difficult-to-store fuel, LNG – unlike many other commodities – is also rarely stockpiled in the expectation (or hope) of upward market movements. Chinese importers slow spot LNG procurement activity in winter Trucked LNG prices have recently diverged from LNG import prices, causing difficulties for importing companies, which are faced with a higher LNG spot import price than their sales price in trucks. This situation is historically unusual: in 16 of the last 24 months, LNG spot prices (represented by the JKM) were below trucked LNG prices, allowing for profitable import and on-selling. There are several reasons for the decoupling that took place in winter 2021. Industrial users of gas in China started to consume less because of high prices caused by fierce competition for the marginal spot LNG cargo between the Pacific and Atlantic basins. This reduction in demand caused an imbalance at terminals in China because cargo imports are agreed several months before trucked LNG sales take place, due to the mismatch in lead times. It therefore took some time for LNG import volumes to react to the sudden sharp reduction in demand from more elastic end-users, leaving an ongoing imbalance in fundamentals. Moreover, China’s LNG importers pulled back from spot purchases as these were more expensive than long-term contract formulas linked to Brent crude oil. This temporarily weakened the pricing link between spot LNG prices and China trucked LNG. Given spot purchases typically accounted for 30%-40% of the country’s LNG imports in the past few years, this also meant that China’s overall LNG imports started to significantly drop year-on-year in Q1, falling over 15% to around 16.5 million mt. Indeed, such was the lack of demand that importers began to sell cargoes in the spot market from both long-term supply and strip tenders. Unipec, CNOOC, ENN and Guanghui all sold cargoes during the winter period. China’s LNG importers were the biggest participants in signing long-term contracts in 2021, in light of the higher spot prices at the time, but only around 6 million-7 million mt of the 35+ million mt of term contracts signed are commencing in 2022. Chinese firms rush to sign new long-term LNG contracts Buyer Seller Volume (mil mt/year) Start date Duration (years) Guangdong Energy Qatar 1.0 2024 10 Suntien Energy Qatar 1.0 end-2022 15 Zhejiang Hangjiaxin Pavilion Energy 0.5 2023 5-7 ENN Novatek 0.6 - 11 Beijing Gas Shell 1.5 2023 10 Henan Investment Group Novatek - 2025 - Guangdong Energy NextDecade 1.5 2026 20 ENN Energy Transfer 2.7 2026 20 ENN NextDecade 1.5 2026 20 Sinopec Venture Global 4.0 2026 20 Unipec Venture Global 2.5 2023 1 Unipec Venture Global 1.2 2022 3 Sinochem Cheniere 0.9-1.8 July 2022 17.5 Foran Energy Cheniere 0.3 2023 20 China Gas Vitol 0.8-5.0 2023 5 ENN Cheniere 0.9 July 2022 13 Guangzhou Development Sinochem 0.4 2023 10 Foran Energy Sinochem 0.2 2023 17 CNOOC Venture Global 3.5 2023-2026 20 CNOOC Qatar Petroleum 3.5 2022 15 CNOOC Petronas 2.2 mid-2020s 20 Guangzhou Development BP 0.7 2022 15 Shenergy Total 1.4 - 20 Shenergy Novatek 3.0 - 15 Guangzhou Development Mexico Pacific 2.0 2026 20 Source: S&P Global Commodity Insights If China’s importers maintain the current strategy, at least one of the following will likely happen: LNG imports will be curbed in 2022 – because term demand only covers circa 15 million mt less than the total import demand from 2021, LNG spot prices will come down and allow for elastic Chinese industrial demand to return, or local prices will rise to meet the international market. Judging from the recent price progression, it looks like south China trucked LNG prices are coming up to meet (and exceed) LNG import prices. This could lead to the situation seen in previous years where spot LNG prices allowed for profitable trucked LNG sales. In fact, the average ex-terminal trucked LNG price in south China has risen to $25/MMBtu, according to domestic market participants. However, the price and timing risks are still there for importers, who are generally buying on an index-linked basis for the future delivery of cargoes and selling in the trucked LNG market on a fixed price basis for very short-term delivery. Chinese spot LNG importers enjoyed an average positive margin of Yuan 1,500-2,000/mt over 2020 from ex-terminal trucked LNG sales, as the JKM fell to a record low of $2/MMBtu in the year as gas demand dwindled significantly due to lockdowns across major cities in North Asia. However, fast forward to winter 2021, and China’s importers faced an almost continuously negative margin for on-selling spot-procured LNG, and hence pulled back from the market. How can importers manage this time and price risk? Greater linkage between upstream and downstream markets required They could be resolved by linking downstream markets like trucked LNG to the international spot cargo price, the main feed-in cost, and the market price China contends with to import LNG. Even though a lot of LNG is invoiced to other benchmarks, LNG spot prices remain the opportunity cost for China’s importers, and are being used in downstream price negotiations or contracts in countries as diverse as Brazil and Japan. In fact, the model of using international LNG prices in Chinese gas contracts already exists. China’s Sinopec introduced spot LNG pricing in its downstream trucked LNG sales by referencing the JKM in its ex-terminal trucked LNG offers from April to October 2021, after procuring spot LNG cargoes through a strip tender on a JKM-linked basis earlier in 2021. BP China signed multiple regasified LNG supply contracts with buyers like ENN for pipeline gas from the Guangdong Dapeng terminal linked to the JKM. This pricing model allows sellers like BP China to import LNG at international spot prices and on-sell gas to the downstream markets via a back-to-back method, ensuring that a positive margin is locked in. Furthermore, state-owned PetroChina also announced its plans to pass through its cost of spot LNG to downstream buyers of its spot natural gas volumes. China’s Shandong province had also allowed city gas distributors to sell their spot LNG cargoes at market prices to non-residential users in October 2021. Because LNG is the glue that links together regional gas markets, LNG price benchmarks are also being used in contracts between upstream suppliers and LNG liquefiers. Multiple 15-year term US feedgas agreements have been signed by Cheniere with American gas producers Tourmaline, EOG and Apache, all referencing the JKM. As China’s gas consumption is forecast to reach 430 Bcm-450 Bcm by 2025 from 395 Bcm in 2022, spot LNG imports will continue to play an important role in the country’s efforts to decarbonize and transition to cleaner fuels. The ability to pass down import costs to downstream markets like trucked LNG would hold the key to ensure sufficient, stable gas supplies to non-residential users at times of peak residential demand, as LNG importers in China would be incentivized to make additional spot LNG cargo purchases, hence reducing margin pressure for them. This would also allow China’s power sector to move toward more market-oriented balancing mechanisms. *According to CNPC’s Economics and Technology Research Institute

US gas futures prices edged back toward the mid-$7/MMBtu range in May 2 trading as domestic supply remains constrained by sluggish production and an enduring inventory deficit. As US upstream activity continues to build, though, the now aging rally faces increasing downside risk later this summer. In early trading, the June contract briefly edged up to $7.55/MMBtu while balance-of-summer futures traded into the mid-$7.60s/MMBtu. The market remained mostly in contango through next winter with January 2023 briefly pricing at nearly $7.90/MMBtu, data from CME Group showed. At a time of year when US gas prices typically trough, the NYMEX bulls are steering the market, apparently spurred persisting supply concerns this spring. In April, spring pipeline maintenances helped to keep US gas production sputtering around 93.2 Bcf/d. Following a steep New Year production decline in January, domestic output remains about 2 Bcf/d, or roughly 2%, below late-December levels, S&P Global Commodity Insights data shows. Low storage levels have added to the market's concern. As of the week ended April 22, US inventories are estimated at 1.49 Tcf. In it's latest storage report, data from the US Energy Information Administration showed the inventory deficit at 305 Bcf – its widest yet this year. An updated forecast published by S&P Global shows cooler weather and elevated heating demand helping to widen the deficit over 330 Bcf by the first week of May. Weather After unseasonably cool weather last month, US temperatures are expected to trend closer to normal through mid-May, according to recent forecasts from the National Weather Service and S&P Global. Heating demand should average about 18 Bcf/d over the next week, undershooting the prior five-year average by about 250 MMcf/d. Gas demand from generators, meanwhile, is expected to average about 26.4 Bcf/d, setting a record high for the seven-day period thanks partly to the continued retirement of coal-fired generating capacity and the recent coal-to-gas fuel switching in the power markets. Based on the Weather Service's seasonal forecast for June, July and August, the outlook for gas-fired electric this summer looks more bullish. Nearly the entire Lower 48 states face an elevated probability for hotter-than-normal temperatures more concentrated risks across the Rocky Mountain and desert West and along the Northeastern Atlantic seaboard. Upstream outlook While the NYMEX gas futures market has good cause for bullishness this spring, steadily brewing upstream activity over the past several months could put a damper on the rally. In the week ended April 27, the US drilling rig count edged up to 799, reaching its highest since March 2020, data published by Enverus shows. Other indicators of upstream activity are also looking increasingly bullish. According to the EIA's April Drilling Productivity Report, drilling and well completions are edging back toward, or already above, pre-pandemic levels in Appalachia, the Haynesville, the Bakken, the Eagle Ford and the Permian. Based on recent activity, S&P Global has forecast US production to rebound this summer, potentially surpassing 96 Bcf/d by late August to early September.

Wholesale on-peak power indexes jumped sharply on the month and year in the US Southeast in April, driven primarily by stronger natural gas prices, and June on-peak power forwards followed a similar pattern, as the Russia-Ukraine conflict's repercussions continue to reverberate through the energy complex. Platts' day-ahead on-peak bilateral assessments, as reported by S&P Global Commodity Insights, averaged in the high $70s/MWh across four geographically dispersed pricing points in the Southeast, and averaged more than $80/MWh in the transmission constrained Florida power market. These latest indexes were up from the high $40s/MWh in March and indexes ranging from $28.50/MWh to $30.78/MWh in April 2021. Spot gas averaged $6.434/MMBtu in April at the Transco Zone 4 pipeline, S&P Global data shows, up from March's $4.812/MMBtu and April 2021's $2.56/MMBtu. At the Florida Gas Zone 3 price point, spot gas averaged $6.465/MMBtu in April, up from March's $4.861/MMBtu and April 2021's $2.601/MMBtu. Power demand likely had little effect on prices in April, according to data collected by S&P Global from the US Energy Information Administration. For example, in the North American Electric Reliability Corporation's SERC region, formerly known as the Southeast Electric Reliability Council, loads averaged 66.8 GW in April, down from March's 69.3 GW but up from April 2021's 65.8 GW. In NERC's Florida Reliability Coordinating Council region, loads averaged 26.8 GW, up from March's 25.7 GW and April 2021's 24.9 GW. The weather's power demand tendencies were mixed, with population-weighted average daily temperatures generally more moderate in April than they were in March or in April 2021, according to CustomWeather data. For example, temperatures averaged 62.7 degrees Fahrenheit in Georgia in April, up from March's 57.6 degrees and April 2021's 62.3 degrees. Combined heating- and cooling-degree days in Georgia in April were down almost 38% from March and down more than 14.2% from April 2021. In contrast, Florida's population-weighted average combined HDDs and CDDs were in April were up 18.9% from March and up 9.2% from April 2021. Temperatures averaged 73.9 degrees F in April, up from March's 70.7 degrees F and April 2021's 72.2 degrees F. Forward markets Looking forward, the National Weather Service's April 21 forecast for May, June and July indicates probabilities for above-normal temperatures ranging from 33% to 50% for the Southeast. Such a forecast may provide a reinforcing boost for June forwards, which were up strongly on the month and year, likely related to the continuing conflict between Russia and Ukraine, consequently tight gas supply conditions in Europe and heavy demand for feed-gas from coastal LNG liquefaction facilities. Into Southern June on-peak forwards averaged almost $78.40/MWh in April, up 42.3% from $55.05/MWh in March and up almost 156% from the $30.64/MWh that June 2021 forwards averaged in April 2021, S&P Global pricing data shows. Florida June on-peak forwards averaged more than $75.20/MWh in April, up 32.5% from March's $56.75/MWh and up 130.6% from the $32.60/MWh that June 2021 forwards averaged in April 2021. Transco Zone 4 June gas averaged $6.759/MMBtu in April, up 34.4% from March's $5.028/MMBtu and up 150.3% from the $2.70/MMBtu that June 2021 gas averaged in April 2021. Florida Gas Zone 3 June forwards averaged $6.85/MMBtu in April, up 32.9% from March's $5.155/MMBtu and up almost 143.7% from the $2.811/MMBtu that June 2021 gas averaged in April 2021. Generation mix April's high gas prices and relatively weak demand likely contributed to nuclear and coal-fired generation regaining some market share, according to EIA data collected by S&P Global. In fact, nuclear power regained the lead share from gas-fired generation in NERC's SERC region. Nuclear power's share was 33.5% in April, up from March's $31.4% but down from April 2021's 34.5%. The SERC coal fleet's share rose to 22% in April from March's 21.4% and April 2021's 21.3%. In contrast, the SERC gas fleet's share fell to 32.8% in April from March's 33.3% and April 2021's 33.5%. Gas-fired generation, which normally dominates NERC's FRCC region, also lost some share, falling to less than 69% in April from March's 73.4% and April 2021's 6.8%. FRCC's nuclear fleet had a 12.3% share in April, down from March's 12.8% but up from April 2021's 11.6%. The FRCC coal fleet supplied 10.2% of the region's power in April, flat with April 2021 but up from 6.6% this March. Solar power's share in the Sunshine State also grew in April, up to 6.2% in April from March's 5.3% and April 2021's 5.2%.

Permian gas benchmark Waha Hub saw its basis spread to cash Henry Hub widen in May 2 trading to its largest discount since October 2020, ahead of a planned maintenance on Kinder Morgan's Permian Highway Pipeline that will substantially limit eastbound takeaway capacity May 3-13. The 2.1 Bcf/d Permian Highway pipeline brings gas from the Waha area of the Permian Basin east to the Katy area near Houston, supplying Gulf Coast demand markets. Waha Hub spot gas dropped 66.50 cents to $5.485/MMBtu in May 2 trading for next-day flows, according to preliminary settlement data from S&P Global Commodity Insights, doubling its basis spread to cash Henry Hub to a $1.815 discount. El Paso, West Texas spot gas saw an even steeper drop in May 2 trading, falling 76.50 cents to $5.38/MMBtu, widening its discount to cash Henry Hub to nearly $2. With less gas able to make its way toward the Gulf Coast from West Texas, East Texas spot gas prices soared in May 2 trading. Katy Hub gained 68.50 cents to trade at $7.205/MMBtu, while further south Agua Dulce gained 73 cents to trade at $7.17/MMBtu, preliminary settlement data shows. With East Texas playing an increasingly important role in supplying the Southeast and its surging LNG feedgas demand so far this year, the anticipated drop in East Texas supply has likely reverberated in Southeast spot gas prices as well, which rose substantially in May 2 trading. Preliminary settlement data shows that Henry Hub rose 46.50 cents to $7.30/MMBtu, with similar gains of 40-70 cents observed across the region. PHP maintenance Permian Highway Pipeline will start scheduled maintenance work on its five compressor stations May 3, with capacity set to decrease 1 Bcf/d-1.1 Bcf/d for May 3-6, then increase to 1.8 Bcf/d for May 7-9, and fall to 1.65 Bcf/d until the planned conclusion of the maintenance May 13. Cash Waha's discounts will likely be widest during the initial May 3-6 stage of the maintenance work, with the spread set to narrow in May 6 trading for May 7-9 flows, in tandem with the 700 MMcf/d increase in capacity available for those flow days. Permian takeaway capacity Waha Hub's spread to cash Henry Hub has largely been insulated from similar blow-outs since Permian Highway Pipeline came online in January 2021, adding around 2 Bcf/d of additional takeaway capacity. July 2021 in-service of the 2 Bcf/d Whistler Pipeline provided even more relief to the Waha basis. Since then, Waha's discount has largely remained below $1/MMBtu, except in sporadic cases of pipeline maintenance or repair work. Most recently, Waha Hub's discount widened beyond $1 in the last week of March, ahead of a four-day planned maintenance project on Gulf Coast Express. With Permian gas production projected to rise over the next several years, a race will emerge between a slew of proposed pipeline expansion projects and rising production volumes, with Waha Hub's spread serving as a barometer for how that balance evens out. Kinder Morgan proposed adding up to 1.2 Bcf/d of capacity on its Permian Highway Pipeline and Gulf Coast Express pipeline April 20, although no investment decision had been taken as of May 2. Whistler Pipeline took a final investment decision May 2 to expand capacity by 500 MMcf/d, with a targeted in-service of September 2023.

The number of LNG ships arriving into Europe rose more than 20% in April compared with the previous month, as continued uncertainty about Russian pipeline gas supplies amid the war in Ukraine lured cargoes to the region. There were 114 LNG ships that arrived in Europe in April, versus 94 in the previous month, vessel-tracking data from S&P Global's cFlow trade-flow analytics software showed. The Mediterranean saw the biggest increase, a rise of 24.4%, while Northwest Europe saw a month-on-month growth of 18.4%. In April, Spain imported the largest number of LNG ships in the Mediterranean. It imported 35 ships, an increase of 25% from 25 ships in March. Italy also increased the number of LNG ships imported by 25%; its imports grew to 15 in April, from 12 in the previous month. In Northwest Europe, France imported the largest number of LNG ships, 26 in April compared with 24 in March, an increase of 8.3%. The UK experienced the highest growth over the same period, where the number of ships increased to 19 from 13, a rise of 46.2%. Following the invasion of Ukraine by Russia on Feb. 24, European LNG outright prices increased significantly in March. They reached their highest level on March 8 at $60.925/MMBtu for DES NWE and have been on a downward trend since then, but are still up sharply from the same time a year ago. Higher prices in Europe attracted an increased flow of LNG cargoes resulting in limited slot availability across the continent. For example, Fos Cavou and Fos Tonkin showed zero receiving capacity until the end of 2022 in reports by Fosmax LNG, the company that manages the two French regasification. Recently, some slots in NWE were heard to be opening up, according to market participants. Lower LNG prices in April followed a higher number of LNG ship arrivals. According to data from S&P Global Commodity Insights, the monthly average for April DES NWE was $31.24/MMBtu, down from $37.33/MMBtu in March. The increase in LNG prices for DES NWE is even more significant year on year as the monthly average for LNG prices was $6.229/MMBtu in April 2021. The higher inflow of LNG into Europe also contributed to the upward trend in European gas inventories which were at 34.6% in the latest reading of Gas Infrastructure Europe, up from 26.3% at the end of March.

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).

Algeria, which is embroiled in a political dispute with Spain over the Western Sahara, is committed to supplying gas to the European country that is seeking to become a natural gas hub for the continent. "Algeria won't abandon its commitment to supply Spain with gas under any circumstances," Abdelmadjid Tebboune told national media, state-run Algeria Press Service reported April 24. Tensions have flared between Algeria and Spain after Madrid in March altered its position regarding the autonomy of the disputed Western Sahara region in Northern Africa. Western Sahara is subject of a dispute between Algeria and Morocco. Algeria's state-owned Sonatrach has not ruled out a "recalculation" of the price paid for its gas by Spain's Naturgy, CEO Toufik Hakkar said April 1. Sonatrach and Naturgy are long-standing partners in the gas sector, but the political row is stoking fears of a disruption of supply at a time of high European gas prices. Sonatrach had opted to maintain its pricing under long-term contracts with buyers despite the rise in prices due to the Ukraine crisis, Hakkar said at the time. However, he singled out Spain for a potential change in pricing terms. The two companies co-own the Medgaz gas pipeline carrying Algerian gas to Spain, and their commercial relationship dates back to the 1970s. 10-year high In October 2020, after gas prices fell to historic lows in Europe, the two parties agreed to revise pricing terms for Algerian gas deliveries. Spanish PVB front month was assessed on April 22 at a Eur9.25/MWh loss on the day, with the contract priced at Eur80.25/MWh, according to S&P Global Commodity Insights data. Spain has seen more LNG delivery as recent gas demand has increased on colder than average weather, which is expected to continue until May 1. Spain is seeking to become a a major gas hub in the 27-member European Union, where consumption reached a 10-year high in 2021, with demand rising by 4% to 412 Bcm due largely to a longer-than-usual winter. Russian pipeline gas was the biggest source of EU imports at 41% in 2021, according to European Commission data, followed by pipeline gas from Norway (23.5%), LNG (20.5%), Algerian pipeline gas (10.5%) and pipeline gas via TAP (2%) and from Libya (1%). Against the background of higher demand and lower domestic production, EU imports rose by 3% to 337.5 Bcm in 2021. Germany imported 83 Bcm of gas, followed by Italy (71 Bcm), France (40 Bcm), Spain (34 Bcm), and Poland and Belgium (both 18 Bcm). US LNG Algeria has already diverted pipeline volume from Spain, which in turn has turned to US LNG to replace the reduced Algerian volume, taking advantage of Henry Hub-indexed long term contracts that Spanish importers have with Gulf of Mexico suppliers. US LNG shipments to Spain hit a monthly record high of 16.3 TWh in March, equivalent to 43% of the country's natural gas intake in the month, establishing the US as the country's principal gas supplier ahead of Algeria, according to data published April 8 by gas grid operator Enagas. US supplies have largely displaced those from Algeria after one of the two pipelines that connect the countries, the 11 Bcm/year Magreb pipeline that transits Morocco, closed in November 2021. Algerian flows to Spain fell 33% year on year in Q1 to 28.1 TWh, also down 29% on the Q1 average over the last five years. Meanwhile, Italy's Eni and Sonatrach have agreed to a new gas supply deal that will rise to 9 Bcm/year by 2023-24, Eni said April 11.The deal was part of a wider Italian mission to Algeria which resulted in the signing of a letter of intent to increase cooperation in the energy field. From a European perspective, the deal should help Italy reduce its dependence on Russian gas. The volume could lift imports through the Transmed pipeline from Algeria to Italy to near its full 30 Bcm/year capacity.

Peak-summer basis prices at Appalachia's benchmark hub Eastern Gas South have fallen to an eight-week low in recent trading as gas production across the region shows signs of upward momentum. Calendar-month prices for June, July and August 2022 are now trading at roughly $1/MMBtu discount to the Henry Hub, making for the widest spread since late February when a series of production freeze-offs fueled a steep rise in benchmark US gas prices, S&P Global Commodity Insights data shows. After rallying alongside Henry Hub earlier this spring, prices at Eastern Gas South appeared to dislocate from the US benchmark recently as Henry Hub summer prices tested historic highs at over $8/MMBtu. Since mid-April, the Eastern Gas South peak-summer strip has widened its discount to Henry Hub by roughly 25 cents, or about 30%, as traders began to doubt the sustainability of $6-$7/MMBtu gas prices in Appalachia this summer. The widening forward price spread from Eastern Gas to Henry Hub also comes as Appalachian Basin gas production shows modest but steady signs of growth. In April, production across the Marcellus and Utica shales has edged up to an average 33.2 Bcf/d, or its highest since January, S&P Global data shows. Based on recent upstream activity, production could be expected to continue growing this summer. Drilling, completions In March, operators across the Appalachian Basin drilled an estimated 89 new wells, hitting a pandemic-era high not seen since April 2020, data from the US Energy Information Administration shows. While well completions in March were unchanged at 95, the monthly numbers appear to have plateaued recently at close to prepandemic levels, the Drilling Productivity Report data shows. In the week ended April 20, the drilling rig count across the Marcellus and Utica shales edged up to 53 and is now just two rigs shy of a 30-month high recorded in March, data published by Enverus shows. Recent upstream investments could be a bullish indicator for Appalachian gas production this summer – a topic that is likely to be addressed by the region's producers on upcoming first-quarter earnings calls. According to an updated forecast published by S&P Global, combined output from the Marcellus and Utica could top 34 Bcf/d by later this summer and potentially reach 34.5 Bcf/d by late 2022.