2022 Global Power Markets

Electric vehicle sales in Europe's largest passenger car markets increased to record highs in 2022, boosted by government incentives, although a number of countries will likely see subsidies for EVs being reduced or eliminated in 2023, which could have some downside risk. The reduction in subsidies comes at a time when battery metal prices are strong, with lithium prices ending 2022 more than double where they were at the start of the year, boosted in part by the increased global EV demand. Click here to see the full-size infographic Learn more: Latest Insight Blog entry: EV sales momentum to face challenges in 2023, but long-term expectations unaffected . And in the latest Platts Future Energy podcast , we uncovered the potential roadblocks facing the EV market in 2023. From lithium prices to government subsidies, learn how these factors may impact EV sales and the battery metals market:

LNG is seeing a competitive boost as a US bunker fuel, as FOB prices have dropped sharply from record highs and spot marine fuel has trended higher. Shipowners are increasingly evaluating shifting economics and environmental considerations. Some market participants see the ability to offer a Henry Hub-linked price as a unique advantage for LNG producers in the US, whether for small-scale or large-scale exports or for use as a bunker fuel. LNG bunker prices in Europe also are seeing additional attention. In recent months, an Italian strategy group was heard to have met with market participants trying to get intelligence about LNG bunkering opportunities in the Mediterranean; they were said to be scouting locations around Poland and Turkey. "The world has been shifting to alternative fuels," said an Atlantic-based LNG trader. "We may see a switch to gas if it keeps coming down." US SE Coast LNG bunkers were assessed at $15.174/MMBtu Jan. 18, or 115% Henry Hub plus $11.25/MMBtu for volumes of 3,000-5,000 cu m. That was slightly cheaper than the latest bulk 0.5%S marine fuel barge value at 1630 London time, which was $15.249/MMBtu, or $589.25/mt. On an equivalent basis, at the same time, USGC HSFO, with the highest sulfur content of the three fuels, was the least expensive, at $9.616/MMBtu. The Platts Gulf Coast Marker for US FOB cargoes loading 30-60 days forward was assessed at $15.35/MMBtu Jan. 18, down nearly 80% from the record-high $73.35/MMBtu Aug. 26, 2022. LNG supplies have flooded the Atlantic in recent months, amid Europe's efforts to build gas inventories while at the same time reducing its reliance on Russian supplies. Europe entered the winter with gas storage more than 90% full. Relatively mild weather since then has kept gas stocks high. Meanwhile, spot marine fuel bunkers pricing has generally trended higher for US Gulf Coast ports in 2023, with assessments tracking recent rebounds for crude futures. Additionally, markets are seeing tight supply and logistical challenges related to fog, further propping up values in recent days. Bulk 0.5%S marine fuel barge value has risen from a Dec. 30 assessment of $567.25/mt, with some sentiment pointing to strong demand from the retail bunkers segment in the US Gulf Coast. On that front, Houston spot 0.5%S bunkers pricing has risen from $580/mt ex-wharf Dec. 30 to its most recent assessment of $618/mt ex-wharf Jan. 17. The New Orleans market, which competes with Houston for retail bunker stems, has seen retail 0.5%S bunkers value jump from $570/mt to end 2022 to its most recent close at $690/mt ex-wharf—a three-month high. "No barrels, resupply uncertain," a source said recently of New Orleans' rising prices. "Suppliers are struggling to find resupply barrels." The situation has seen each of the key USGC ports prop up the other at times on retail values, as ships will generally consider both for refueling operations despite Houston typically carrying a discount to New Orleans. "There are no avails, or won't be soon," a second source said of Houston. "Product is tight, and resupply has gone up in price considerably." That retail spread has been inverted at times in January, but more recently tight supply had led to New Orleans seeing its premium widen over Houston.

In this week's Market Movers Europe with Charlie Wright: Global recovery hopes, Europe still subdued High storage relief for European gas market EC’s market design proposals imminent View Full Transcript Video Transcript The

Platts, part of S&P Global Commodity Insights, is now publishing daily LNG-based natural gas assessments reflecting the value of natural gas delivered inland to end-users in the northeast and southeast of Brazil, effective Jan. 9. This follows market feedback on a need for additional transparency around Brazil delivered natural gas prices as the market continues to liberalize, especially considering new infrastructure that is being built in Brazil and to service gas shipments to the country. Platts first proposed these new assessments in a subscriber note published Sept. 20: https://www.spglobal.com/commodityinsights/en/our-methodology/subscriber-notes/092022-platts-proposes-to-launch-lng-based-brazil-inland-natural-gas-assessments-jan-9-2023. Platts has launched three assessments: one for gas delivered to end-users in the northeast, one in the southeast and one that is the average of both regions. For the northeast netforward assessment, Platts is using the daily Platts DES Brazil LNG assessment (LEBMH01) as the basis for LNG delivered to Salvador, Bahia. For the southeast netforward assessment, Platts is using the daily Platts DES Brazil LNG assessment, but accounting for the additional shipping days needed for arrival to Rio de Janeiro from common LNG supply ports. Inputs once onshore include regasification, port fees, storage, pipeline transportation and average estimated distribution costs based on market intelligence. Inland shipping-related costs are included, while non-shipping related taxes are excluded. The assessments are being published on a fixed price basis in $/MMBtu and reflect market value at 4:30 pm London time. Platts is also publishing these assessments as a differential to Platts JKM. These assessments follow the UK publishing schedule. The calculations will be reviewed periodically to ensure the inputs reflect prevailing market dynamics. The calculations will be reviewed at least once annually, and more frequently based on market intelligence. The assessments will appear in Platts LNG Alert page 1100, Platts Natural Gas Alert page 1100, and Platts LNG Daily under the following price database codes: Assessment Codes Brazil Inland Gas Derived from LNG Cost Northeast $/MMBtu ABINA00 Brazil Inland Gas Derived from LNG Cost Southeast $/MMBtu ABINB00 Brazil Inland Gas Derived from LNG Cost Average $/MMBtu ABINC00 Brazil Inland Gas Derived from LNG Cost Northeast vs JKM $/MMBtu ABIND00 Brazil Inland Gas Derived from LNG Cost Southeast vs JKM $/MMBtu ABINE00 Brazil Inland Gas Derived from LNG Cost Average vs JKM $/MMBtu ABINF00 Please send all feedback, comments and questions to lngeditorialteam@spglobal.com and pricegroup@spglobal.com. For written comments, please provide a clear indication if comments are not intended for publication by Platts for public viewing. Platts will consider all comments received and will make comments not marked as confidential available upon request.

In this week's Market Movers Europe with Nikolaos Aidinis – Antonopoulos: Demand worries dominate in oil Germany begins commissioning tests at LNG terminals Mild, windy weather subdues energy prices Carbon auctions set to resume

Battery storage players in Europe are experiencing both the best of times and the worst of times. The ongoing volatility in the European power market makes the case for grid-scale batteries like never before, but persistent supply constraints and the sky-high cost of key materials — including lithium — continue to paint a challenging picture for project development. Batteries have become "incredibly profitable" in the volatile power price environment, according to Sam Wilkinson, director of clean technology and renewables at S&P Global Commodity Insights. In particular, operators involved in wholesale arbitrage, charging up when prices are low and dispatching when prices are high, have likely enjoyed a bumper year as market prices soared to record highs. These catalysts for batteries look set to continue thanks to long-term policy signals such as the European Union's REPowerEU strategy, which plans to end Russian gas imports and accelerate the bloc's energy transition. The strategy sets higher capacity ambitions for wind and solar projects of 510 GW and 600 GW, respectively. "The levels of renewables they're talking about requires an amount of storage way beyond what we've currently got," Wilkinson said in an interview. Commodity Insights' latest forecast for 2030 energy storage installations in Europe, encompassing both EU nations and non-EU members, stands at 44.6 GW, nearly double its previous estimate of 23.7 GW that it made in February. While this cannot be directly attributed to REPowerEU, it is still the largest single forecast increase the group has ever made. "Really we see exponential growth over the next 10 to 15 years in energy storage," said Peter Kavanagh, CEO of UK-based Harmony Energy Ltd, which brought online Europe's largest battery storage project in November – the 98 MW/196 MWh Pillswood project near Hull, Yorkshire. "The more onshore wind, offshore wind and solar you have on the system, the more intermittency," Kavanagh said in an interview, adding that batteries are needed to "really make the network efficient." Competing with EVs Yet while the battery storage opportunity in Europe might be greater than ever, there has arguably also never been a more challenging environment for developers. Heightened need for lithium-ion batteries by electric vehicle manufacturers is causing supply shortages in the storage market, which compared with EVs accounts for only a fraction of the overall demand for batteries. The project pipelines of the 10 largest energy storage providers equate in total to about 10% of automaker Volkswagen AG's battery procurement plans in the next three years, according to Wilkinson. "Their purchasing power is almost zero in comparison with the automotive companies," Wilkinson said. "It makes it very difficult for them to procure batteries." These supply constraints, combined with the rising cost of raw materials such as lithium, are putting huge pressure on the price of batteries. Platts assessed the price of lithium carbonate (CIF North Asia) at $75,000/mt Dec. 30, up 122% year on year, S&P Global data showed. "The big challenge is . . . the car industry doesn't really care too much about being exposed to lithium prices," Wilkinson said. Consumers buy cars at a given point in time, whereas energy storage projects have longer development time frames, which mean dramatic changes in cost can be a "huge problem" in raising financing. UK growing fast Commodity Insights' latest forecast puts the UK as Europe's largest market for grid-scale energy storage by 2030, with 12.5 GW of capacity, followed by Germany with 8.1 GW and Spain with 5.1 GW. The group's February outlook for the UK was 6.5 GW. Part of the UK's leadership on battery storage is down to it being an early mover. In 2016, National Grid PLC provided four-year, enhanced frequency response contracts to eight projects totaling 201 MW — more than double what was installed in the whole of Europe at that point. "The market's evolved quite a lot since then," Kavanagh said. In particular, the narrative that batteries need long-term contracted revenues has almost entirely disappeared. Harmony Energy's battery portfolio provides eight different services to the system, from arbitrage to frequency response and ancillary services. More fundamentally, operators also see an opportunity for batteries to complement the UK's push for offshore wind, which is targeted to grow to 50 GW by 2030. Batteries are "like an insurance policy or a shock absorber," according to James Basden, founder director of developer Zenobe Energy Ltd. When there's a sudden surge of offshore wind, instead of grid companies having to pay to curtail wind farms, excess electricity is stored by batteries then discharged when demand picks up. "That has a big benefit in terms of savings to the consumer," Basden said in an interview. Zenobe recently began the construction of three batteries in Scotland, totaling 1 GW/2 GWh, which the company said will lower consumer bills by more than £1 billion over 15 years by reducing the curtailment of wind farms. Meanwhile proponents say batteries should also come into their own on cold days when the wind does not blow and could get compensated handsomely. On Dec. 12, as temperatures in the UK plummeted, two coal-fired power plants nearly returned to operation while a gas plant briefly earned a record GBP6,000/MWh in the balancing mechanism, the market used by National Grid Electricity System Operator Ltd. to balance supply and demand in Britain. "It really is a super challenging time for [battery storage]," Wilkinson said, "but the overall opportunity is as big as it has ever been."

Germany is poised to begin commissioning work at its first floating LNG import terminal in a matter of days, enabling the EU powerhouse to receive direct LNG imports for the first time. Germany has long held the ambition to install LNG terminals on its northern coast, but Russia's invasion of Ukraine and subsequent cuts in pipeline deliveries lent new momentum to German efforts to diversify supply through LNG. In all, six import projects are under development -- five backed by the German state and one privately-funded terminal. The first to start up will be Uniper's state-backed FSRU at Wilhelmshaven -- the Hoegh Esperanza -- which arrived in port on Dec. 15. "The first gas will flow on Dec. 22," a Uniper spokesperson told S&P Global Commodity Insights. During the commissioning phase, gas send-outs of between 15 GWh/d and 155 GWh/d into the Open Grid Europe network are expected. "Commercial operation of the FSRU is currently planned to commence mid-January with an expected maximum capacity of roughly 155 GWh/d," Uniper said in a market transparency note. That is the equivalent of some 15 million cu m/d of gas flow, which on an annualized basis would mean total supply of some 5.5 Bcm/year. That is a far cry from the 158 million cu m/d regularly supplied to Germany from Russia via the now damaged and idled Nord Stream pipeline system before June this year. The loss of Russian gas has hit Germany hard, with record high prices putting significant pressure on German buyers of Russian gas forced to procure substitute gas on the open market. Platts, part of S&P Global Commodity Insights, assessed the benchmark Dutch TTF month-ahead price at an all-time high of Eur319.98/MWh on Aug. 26. Prices have weakened since on the back of healthy storage and demand curtailments, though prices remain historically high with Platts assessing the TTF month-ahead price Dec. 16 at Eur118.23/MWh. Nonetheless, managing the deployment of an FSRU within such a short period of time is impressive, with construction work at Wilhelmshaven only having started in May after the project was revived in February. The Hoegh Esperanza could also have an expanded capacity in the future, with Uniper having flagged a potential send-out capacity of 7.5 Bcm/year. Other startups As well as the FSRU at Wilhelmshaven, two other projects are due to begin operations shortly. Private developer Deutsche ReGas is hoping to commission the Neptune FSRU at the port of Lubmin before the end of December. The FSRU arrived into the port on Dec. 16. "Our goal is to be able to start supplying gas as soon as possible," Deutsche ReGas chairman Stephan Knabe said Dec. 16. "But the commissioning can only take place when all the necessary permits have been obtained. We continue to assume December," he said. Deutsche ReGas had said previously the terminal would be technically ready by Dec. 1, but a number of permits remain outstanding, while work on the FSRU at the nearby port of Mukran was also dependent on weather conditions. RWE, meanwhile, plans to deploy a state-backed FSRU at Brunsbuttel in January, later than originally hoped. "According to current planning, it is expected that the construction work for the operation of the FSRU in the port will be completed in January," an RWE spokesperson said Dec. 15. The FSRU will then be able to dock and be connected to the newly constructed technical infrastructure, the spokesperson said. The FSRU reported to be in line to serve Brunsbuttel is the Hoegh Gannet, which is currently in Brest, France, according to Platts cFlow ship and commodity tracking software from S&P Global Commodity Insights. Earlier this year RWE had flagged that the first cargo to arrive at the port would be LNG it had contracted to buy from the UAE, which was originally intended to be delivered in December. Both the FSRUs at Wilhelmshaven and Brunsbuttel are to be supplied with LNG by Uniper, RWE and EnBW unit VNG under a memorandum of understanding signed with the German economy ministry to guarantee their full use until March 2024. Capacity bookings Three other state-supported FSRUs are under development and are due online by the end of 2023 at: Stade (Hanseatic Energy Hub - HEH); Lubmin (RWE/Stena-Power); and Wilhelmshaven (TES/E.ON/Engie). The German economy ministry said in September that the FSRUs at Brunsbuttel and Stade would be operated only until permanent onshore terminals go into operation in 2026. Both permanent terminals have been buoyed in recent weeks by binding capacity bookings and related supply deals. German utility EnBW said this month it had booked 3 Bcm/year of capacity at HEH's planned 13.3 Bcm/year capacity onshore terminal at Stade from the start of commissioning, expected in 2026. As well as booking LNG import capacity at Stade, EnBW will also have the option to move to ammonia as a hydrogen-based energy source at a later date. "This possibility is open to all Hanseatic Energy Hub customers with a long-term contract of more than 10 years," it said. For the permanent 8 Bcm/year site at Brunsbuttel, the US' ConocoPhillips, chemicals giant Ineos and RWE have all booked long-term capacity. ConocoPhillips said in late November it had agreed two long-term agreements with QatarEnergy for the supply of up to 2 million mt/year of LNG into Brunsbuttel for a period of at least 15 years. The LNG will be supplied on a DES basis from Qatar's major North Field East and North Field South expansion projects, in which ConocoPhillips is a partner. Ineos, meanwhile, said Dec. 1 it had signed a long-term agreement with Sempra Energy's infrastructure unit for the supply of LNG from the proposed Port Arthur export terminal in the US. First deliveries from Port Arthur are expected in 2027. The agreement includes a 20-year commitment for 1.4 million mt/year from the first phase of the project, while the two companies also signed a non-binding deal for an additional 0.2 million mt/year from the project's second phase. The permanent Brunsbuttel terminal is expected to begin operations in 2026, although efforts are underway to accelerate the startup, and its capacity could be expanded to at least 10 Bcm/year.

China's natural gas demand in 2023 is expected to rebound from 2022 levels on the back of a gradual opening up of the economy, but high global energy prices and macroeconomic concerns will continue to pressure gas consumption levels. "We expect Chinese gas demand in 2023 to rebound from the low base in 2022, surpassing the 2021 levels, but it will not be a 'V-shaped' rebound," Jenny Yang, senior director, gas, power and climate solutions, S&P Global Commodity Insights, said. "On one hand, a key assumption is that while China has started to relax COVID-related measures, a full exit from COVID controls will still take time and won't likely happen until the second quarter of 2023," she said. "On the other hand, the economy will still be under the pressure of the real estate market downturn and weak exports." Yang said while China's real GDP growth is forecast to improve from 3% in 2022 to 4.4% in 2023, renewable power generation will continue to surge, and policies to rely on domestic coal production will remain in place, which will impact gas demand growth. As a consequence, China's natural gas demand is expected to reach around 364 Bcm in 2022 and grow by around 6% year on year to around 386 Bcm in 2023, according to S&P Global Commodity Insights data. The 2022 gas demand number is nearly 1.4% lower than the National Energy Administration's 369 Bcm demand figure for 2021, making 2022's gas demand the first year-on-year decline in history. "Chinese natural gas demand is still expected to grow but at a much slower rate than historic levels [in 2023], up by around 6% year on year, in part due to new contracts that are expected to support LNG import growth," Szehwei Yeo, LNG analyst at S&P Global Commodity Insights, said. Roman Kramarchuk, Head of Energy Scenarios, Policy & Technology Analytics at S&P Global Commodity Insights, said that for commodities demand in 2023, the most important fundamental factor will be China's COVID policy, as demand softness in 2022 due to lockdowns was a key safety valve for oil, gas and coal markets, while Europe scrambled to replace Russian energy. LNG imports China has been expanding natural gas import capacity and the new LNG import contracts linked to new terminals will help support imports in 2023. China's LNG receiving capacity is estimated to increase to 130 million mt/year by 2023 and nearly 200 million mt/year by 2025, compared with current capacity of 101 million mt/year, the Shanghai International Energy Exchange said June 15. Around nine new LNG term contracts are scheduled to start deliveries in 2023, more than offsetting the two short-term contracts expiring at the end of 2022, according to market sources. "Spot LNG prices will likely remain high in 2023 as Europe refills storage. China will divert cargoes like it did this year (2022) under the combined impact of weak gas demand growth and high spot prices. A price-sensitive market, China will limit spot purchases until prices fall into the $15-$20/MMBtu range or lower," Yang said. "At the same time, Power of Siberia pipeline imports will continue to ramp up, now that the Kovykta gas field has started production. As a result, China's LNG imports will rise from 2022 lows but only marginally, by about 3 million mt year on year, supported by new term contracts," Yang said. S&P Global Commodity Insights expects China's LNG imports to rise to around 65 million mt (89.8 Bcm) in 2023. In November, state television CCTV reported that annual gas supply from the Russia-China natural gas pipeline's eastern route is expected to rise to 22 Bcm in 2023, 30 Bcm in 2024, and 38 Bcm in 2025, based on the current schedule, up from around 15 Bcm in 2022. Yang also said China will continue to look for term supply to support long-term demand growth while limiting exposure to spot market price volatility. China signed 34 LNG contracts, including short-term, medium-term and long-term contracts, between 2021 and 2022 year-to-date, with a total contract volume of 45.91 million mt, starting delivery from 2022 to 2027, calculations showed. Out of the 34 contracts, 15 were between China and the US with a volume of about 21 million mt/year, accounting for nearly half of the total, and five contracts totaling 11.5 million mt were with Qatar, coming a close second. This included the longest contract between Sinopec and Qatar Energy for 4 million mt/year of LNG for 27 years. Given that China aims to hit nearly 200 million mt/year of LNG imports by 2025, it remains under-contracted, and sources have said several long-term contracts are being negotiated and could be finalized when markets stabilize in 2023. Uncertainties Yang said other factors driving gas demand include weather conditions, particularly this coming 2022/23 winter -- which will determine how much gas from storage needs to be replenished globally -- and unplanned outages at liquefaction projects. Other developments expected to influence gas markets in 2023 are the "14th Five-Year Plan on Natural Gas," a key document guiding China's natural gas market development that is yet to be published, and gas price reforms in the midst of volatile import costs. "The key company-level strategies to watch out for include passing through costs to the downstream market in the current high-cost environment, procuring new supply to avoid exposure in the spot market, developing new LNG receiving infrastructure amid the overall low utilization of existing projects and new capacity already under construction, and proposed, new interprovincial transmission pipeline development for new supply to reach markets," she said. However, China is unlikely to make any major change in its approach to the role of natural gas/LNG in the energy mix in 2023. "Using natural gas to displace oil and coal is consistent with the two long-term carbon goals of peaking carbon emissions by 2030 and carbon neutrality by 2060," Yang said.

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The demand for seaborne thermal coal will likely rise 3%-4% globally in 2023, but production may not match up to that scale as current unwillingness of banks to fund coal projects, coupled with the after-effects of the pandemic and the Russia-Ukraine war are still seen as major impediments, Indonesia's Bumi Resources said Dec. 14. "The climate hysteria is increasingly restricting institutional funds and banks from investing in the coal sector, leading to a situation where coal demand would rise but supply would be limited, hence prices could remain elevated at close to 2022 levels," Dileep Srivastava, independent director and corporate secretary at Bumi Resources, told S&P Global Commodity Insights in an interview. The supply-side concerns come after 2022 saw unfavorable weather in countries like Indonesia and Australia hurting output, while the change in traditional trade flows post the war stays on -- all of which took global thermal coal prices to record levels this year. Meanwhile, additional demand from Europe, which sanctioned Russian coal, could eat up supply in Asia as well, particularly for high-CV coal. While global thermal coal prices have eased to some extent in the last couple of months as supply-side concerns waned, they remain at levels higher than the average of last two years. The FOB Kalimantan 4,200 kcal/kg GAR rose to its highest levels for this year on March 10 to $136/mt, while CIF ARA 6,000 kcal/kg NAR physical coal reached an all-time high of $432.50/mt on June 23. Even though the prices have eased since then, the average of 2022 so far is still at $86.55/mt and $298.20/mt, respectively, for the grades. The price of Indonesian 5,900 kcal/kg GAR coal, meanwhile, averaged $181.20/mt FOB between Jan. 1 and Nov. 30, up 61.20% on the year, S&P Global data showed. Renewables versus Coal Stating that coal is the fallback feedstock till a cost-effective and an equally reliable replacement for it is found, Srivastava said that renewables are currently unreliable due to intermittency and storage concerns. To fulfill its Paris Agreement commitment of reducing its national emission by 29% within 2030, Jakarta is expected to use 23% of its requirements from renewable energy sources by 2025 from the current level of around 12%. "Going nuclear is not a universal option, gas prices are increasingly becoming unaffordable, geo-thermal is geographically restricted, hydro is not truly a bulk all weather solution and other feedstocks suffer from size," he said, adding that "Essentially, coal demand is expected to keep rising as far as can be seen, definitely till the end of this decade but supply would increasingly be far shorter leading to elevated prices, which is unfortunate." Indonesia's output risks Indonesian miners are not insulated from the vagaries of nature, Srivastava said, adding that it continues to face shortage of heavy mining equipment as machine manufacturers are wary of beefing up their inventory levels in the face of an anticipated recession. Moreover, higher anticipated domestic demand on the back of revival in industrial activity, coupled with the government's additional coal requirement to protect itself from global supply volatility, could also be a challenge for supply fundamentals. S&P Global reported earlier that Indonesia has requested thermal coal miners to supply 161.15 million mt to the country's power producers in 2023, a stark jump from the 127.1 million mt projected for 2022. Indonesia's domestic coal requirements are seen rising to 209.9 million mt in 2024 before dropping to 197.9 million mt in 2025, according to an official statement Aug. 11. "The La Nina phenomenon of continuous rain since December 2021 led to a contraction in output volumes of 5%-10%, particularly of high-grade coals... The export ban imposed in January 2022 also affected exports. If rains subside in 2023, output can be far higher than 2022," Srivastava said. "High-CV coal price is likely to remain elevated in 2023 as it is in high demand, but its supply ex-Indonesia could remain quite restricted as it produces significantly far more of the lower ranked coals." Bumi in its annual investor presentation Nov. 29 lowered 2022 production outlook to 70 million-76 million mt, from the 78 million-83 million mt range estimated earlier. The company's coal output in January-September was down 9% on the year to 53.7 million mt, mostly impacted by heavy rainfall. Indonesia, the world's largest coal supplier, produced 614 million mt coal in 2021, of which 435 million mt was exported.

China's natural gas demand in 2023 is expected to rebound from 2022 levels on the back of a gradual opening up of the economy, but high global energy prices and macroeconomic concerns will continue to pressure gas consumption levels. "We expect Chinese gas demand in 2023 to rebound from the low base in 2022, surpassing the 2021 levels, but it will not be a 'V-shaped' rebound," Jenny Yang, senior director, gas, power and climate solutions, S&P Global Commodity Insights, said. "On one hand, a key assumption is that while China has started to relax COVID-related measures, a full exit from COVID controls will still take time and won't likely happen until the second quarter of 2023," she said. "On the other hand, the economy will still be under the pressure of the real estate market downturn and weak exports." Yang said while China's real GDP growth is forecast to improve from 3% in 2022 to 4.4% in 2023, renewable power generation will continue to surge, and policies to rely on domestic coal production will remain in place, which will impact gas demand growth. As a consequence, China's natural gas demand is expected to reach around 364 Bcm in 2022 and grow by around 6% year on year to around 386 Bcm in 2023, according to S&P Global Commodity Insights data. The 2022 gas demand number is nearly 1.4% lower than the National Energy Administration's 369 Bcm demand figure for 2021, making 2022's gas demand the first year-on-year decline in history. "Chinese natural gas demand is still expected to grow but at a much slower rate than historic levels [in 2023], up by around 6% year on year, in part due to new contracts that are expected to support LNG import growth," Szehwei Yeo, LNG analyst at S&P Global Commodity Insights, said. Roman Kramarchuk, Head of Energy Scenarios, Policy & Technology Analytics at S&P Global Commodity Insights, said that for commodities demand in 2023, the most important fundamental factor will be China's COVID policy, as demand softness in 2022 due to lockdowns was a key safety valve for oil, gas and coal markets, while Europe scrambled to replace Russian energy. LNG imports China has been expanding natural gas import capacity and the new LNG import contracts linked to new terminals will help support imports in 2023. China's LNG receiving capacity is estimated to increase to 130 million mt/year by 2023 and nearly 200 million mt/year by 2025, compared with current capacity of 101 million mt/year, the Shanghai International Energy Exchange said June 15. Around nine new LNG term contracts are scheduled to start deliveries in 2023, more than offsetting the two short-term contracts expiring at the end of 2022, according to market sources. "Spot LNG prices will likely remain high in 2023 as Europe refills storage. China will divert cargoes like it did this year (2022) under the combined impact of weak gas demand growth and high spot prices. A price-sensitive market, China will limit spot purchases until prices fall into the $15-$20/MMBtu range or lower," Yang said. "At the same time, Power of Siberia pipeline imports will continue to ramp up, now that the Kovykta gas field has started production. As a result, China's LNG imports will rise from 2022 lows but only marginally, by about 3 million mt year on year, supported by new term contracts," Yang said. S&P Global Commodity Insights expects China's LNG imports to rise to around 65 million mt (89.8 Bcm) in 2023. In November, state television CCTV reported that annual gas supply from the Russia-China natural gas pipeline's eastern route is expected to rise to 22 Bcm in 2023, 30 Bcm in 2024, and 38 Bcm in 2025, based on the current schedule, up from around 15 Bcm in 2022. Yang also said China will continue to look for term supply to support long-term demand growth while limiting exposure to spot market price volatility. China signed 34 LNG contracts, including short-term, medium-term and long-term contracts, between 2021 and 2022 year-to-date, with a total contract volume of 45.91 million mt, starting delivery from 2022 to 2027, calculations showed. Out of the 34 contracts, 15 were between China and the US with a volume of about 21 million mt/year, accounting for nearly half of the total, and five contracts totaling 11.5 million mt were with Qatar, coming a close second. This included the longest contract between Sinopec and Qatar Energy for 4 million mt/year of LNG for 27 years. Given that China aims to hit nearly 200 million mt/year of LNG imports by 2025, it remains under-contracted, and sources have said several long-term contracts are being negotiated and could be finalized when markets stabilize in 2023. Uncertainties Yang said other factors driving gas demand include weather conditions, particularly this coming 2022/23 winter -- which will determine how much gas from storage needs to be replenished globally -- and unplanned outages at liquefaction projects. Other developments expected to influence gas markets in 2023 are the "14th Five-Year Plan on Natural Gas," a key document guiding China's natural gas market development that is yet to be published, and gas price reforms in the midst of volatile import costs. "The key company-level strategies to watch out for include passing through costs to the downstream market in the current high-cost environment, procuring new supply to avoid exposure in the spot market, developing new LNG receiving infrastructure amid the overall low utilization of existing projects and new capacity already under construction, and proposed, new interprovincial transmission pipeline development for new supply to reach markets," she said. However, China is unlikely to make any major change in its approach to the role of natural gas/LNG in the energy mix in 2023. "Using natural gas to displace oil and coal is consistent with the two long-term carbon goals of peaking carbon emissions by 2030 and carbon neutrality by 2060," Yang said.

The European Commission is set to publish much-anticipated draft rules on green hydrogen Dec. 15, with a leaked draft drawing criticism from industry and environmental groups alike, as project developers await the policy clarity needed to finalize investment decisions. Industry body Hydrogen Europe has criticized the leaked draft for not going substantially beyond a position set out in a consultation in May. "The new proposal by the European Commission has not substantially changed since it was consulted in May," Hydrogen Europe Chief Policy Officer Daniel Fraile told S&P Global Commodity Insights in an email Dec. 8, noting "numerous calls" by industry and the European Parliament to ease rules. The latest leaked draft "Delegated Act" from the EC include a condition that renewable electricity from the grid used to power electrolyzers for hydrogen production must be produced in the same calendar quarter as the hydrogen production until March 2028. From April 2028, the renewable power must be produced in the same hour as the hydrogen production. After 2027, the renewable power must also come from new production assets, coming online no more than three years before the electrolyzer. Additionality debate MEP Markus Pieper, European Parliament Rapporteur on the Renewable Energy Directive and member of the center-right European People's Party Group said the EC had moved on the principle of additionality. The new proposal allows subsidized wind or solar plants to produce hydrogen for a certain period, Pieper said in a statement Dec. 6. "However, we are still critical that the Commission insists on additionality from 2027 onwards." Other industry members have welcomed the additionality clause, saying it was the only way to guarantee truly green hydrogen. And some have pointed to the cheapest clean electricity supply coming from new renewables regardless. Under the EC proposal, power taken from directly-connected renewables or from a grid that is over 90% renewable is also considered as renewable for hydrogen production, if the production does not exceed a maximum number of hours set in relation to the proportion of renewables in the bidding zone. "If electrolyzers powered the grid without renewable power purchase agreements in places like Poland, the carbon intensity of hydrogen production would be around 40 kgCO2/kg H2, far higher than the 8-9 kg CO2/kg H2 for conventional gray production, whereas for places like Norway it would be round 1 kgCO2/kg H2 due to the level of renewables on the grid," S&P Global hydrogen analyst Matthew Hodgkinson said. Hydrogen Europe said the absence of exemption from the rules after April 2028 for renewable hydrogen production facilities coming online before that date made it difficult for project developers to meet the criteria, as the quarterly correlation would underpin PPAs and investment decisions over the long term. Switching to hourly accounting after that date would be difficult for project developers, the group said. Fraile said with hourly temporal correlation from 2028, producers would not be able to supply green-hydrogen hungry consumers such as steel and ammonia producers, which need a large, constant hydrogen supply at high utilization rates. "It is not simply a question of the hydrogen final price; it is a question of the project's viability," he said. The EU is targeting 10 million mt/year of renewable hydrogen production and another 10 million mt/year of imports by 2030. Platts assessed the cost of producing renewable hydrogen via alkaline electrolysis in Europe at Eur22.96/kg ($24.21/kg) Dec. 8 (the Netherlands, including capex), based on month-ahead power prices, S&P Global data showed. By contrast, costs in potential exporting regions such as the Middle East were assessed much lower at $3.55/kg (Oman, including capex). The industry had already called for monthly correlation between renewables generation and hydrogen production, which Hydrogen Europe said was "already challenging and a significant change to today's market design. No other sector is exposed to such requirements." The EC declined to comment on the leaked proposals. Investment delays Wrangling over the rules set to define green hydrogen has extended for much of 2022. The EC's proposal and consultation on the Delegated Act in May was met with widespread industry criticism, warning that the strict additionality and temporal correlation rules would deter investment. The European Parliament in September passed an amendment to the proposed Renewable Energy Directive, effectively overruling the Delegating Act and scrapping the additionality criteria. The move was initially welcomed by industry bodies, but project developers soon paused investment decisions as the decision led to uncertainty over the rules and the timeline of their implementation. Total announced clean hydrogen capacity in Europe is 29.7 million mt, according to the S&P Global Hydrogen Production Asset Database. But just 0.3% of this is operational, permitted or under construction. Hydrogen Europe warned that a failure of the Parliament and the Commission to reach agreement over the Delegated Act could leave rules within the RED legislation, leading to the possibility of further delays and a fragmented market as EU member states transpose the rules into national legislation. Cautious welcome The industry group did, however, welcome changes to geographical correlation in the EC's new proposal, which require the renewable power facility to be in the same bidding zone as the electrolyzer or an interconnected bidding zone. The EPP Group welcomed the EC's new proposal, but also demanded further changes. EU member states have been discussing the new draft in the week to Dec. 9. "It makes green hydrogen too expensive and threatens to make hydrogen a luxury," Pieper said. An extension to the exemption from additionality requirements was critical to ensuring sufficient supply from local production and imports, he said. "The Commission proposal creates an artificial bureaucratic shortage which would make green hydrogen extremely expensive," he added. But, Hydrogen Europe's Fraile said, without a longer transitional period to 2030, Europe would "remain slave to a fossil fuel economy and will surely not see new technologies such as DRI steel and renewable e-fuels emerge in its territory." Environmental NGO Transport & Environment, which published the leaked draft, also criticized the EC proposal. It said the rules around additionality were too lax, allowing for electrolytic hydrogen to be produced from a grid running on fossil fuel-powered generation. "While hydrogen is badly needed to decarbonize shipping and aviation, without additional renewables tied to hydrogen targets, the Commission's plan may well end up doing more harm than good," T&E Electricity and Energy Manager Geert Decock said Dec. 1.

Extreme volatility in the global LNG market in 2023 will continue to encourage US LNG export terminals to run at high levels, but US Henry Hub prices stand to fall as liquefaction capacity additions flatline, according to S&P Global Commodity Insights' latest 2023 energy outlook. A lack of new liquefaction facilities coming online globally stands to constrain natural gas supply growth despite persistently high prices, according to the outlook. The result will be global gas markets forced to balance on demand destruction and existing stocks instead of LNG supply growth, a dynamic that will be particularly apparent in Europe, where gas and power markets may be even tighter in 2023 as the region faces its first year without significant volumes of Russian pipeline gas. "There is no slack in the system," Michael Stoppard, global gas strategy lead and special adviser at S&P Global, said during a Dec. 8 briefing with reporters. "So we can expect a continuation and a reinvigoration of extreme market volatility that we have seen in both gas and power prices. "Disruptions on the supply side and any clear deterioration of economic output will be met by markets with a volatile price response." Europeans have scrambled to build LNG import infrastructure in an effort to find alternatives to pipeline deliveries from Russia following its invasion of Ukraine in late February. Constraints at existing European regasification terminals in 2022 have led to a dislocation between the northwestern European delivered LNG price and the continental TTF price, with the Platts DES Northwest Europe reaching a record discount of more than $29/MMBtu to TTF in early October before tracing back to around $10/MMBtu currently. S&P Global expects a large increase in European import infrastructure over the next year that could ease the bottlenecks, with some 10 new LNG import terminals proposed or constructed that could be online by the end of 2023. Loosened regasification constraints are expected to tighten the spread between delivered LNG at European terminals and continental gas prices, said Ross Wyeno, lead analyst for LNG Americas at S&P Global. "Our belief is that the net impact of that will be to draw global LNG prices upwards this winter so that Asian buyers are forced to directly compete with the gas buyers within Europe," Wyeno said. "Then potentially we could see prices trailing off a bit more next summer." Across energy markets, China's coronavirus policy is the most important fundamental factor for global energy demand in 2023, said Dan Klein, head of Energy Pathways at S&P Global. Lockdowns softened China's energy demand in 2022, providing relief for gas, oil, and coal markets as Europe scrambled to replace energy supplies from Russia following its invasion of Ukraine in late February. But the S&P Global outlook presumes China's total energy demand will increase by 3.3 million barrels of oil equivalent per day in 2023 from virtually no growth in 2022, representing 47% of the global energy demand growth next year. US LNG export additions flatline in 2023 Persistently high prices have kept existing US LNG terminals running at or near close to full capacity in 2022. US feedgas demand was about 11.5 Bcf/d Dec. 8, after hitting nearly 13 Bcf/d Dec. 1, according to S&P Global data. The Dec. 1 flows marked the highest level of US LNG feedgas deliveries since before an early June explosion and fire at the Freeport LNG plant in Texas pushed some 2 Bcf/d of gas back into the domestic market due to loss of feedgas demand. Freeport LNG is working to resume production by the end of the year. Apart from the Freeport return, S&P Global described a "distinct lack of growth" in North American LNG capacity until late 2024, which is when the developer of the 18.1 million mt/year Golden Pass facility under construction in Texas expects to start production. The lack of new US LNG export capacity and domestic production that is expected to rise by nearly 3 Bcf/d are factors contributing to softer Henry Hub prices in 2023. S&P Global forecasts prices at Henry Hub will average $5.47/MMBtu across 2023, peaking near $7/MMBtu across the first quarter before dipping below $5/MMBtu across the second and third quarters of the year amid tight gas balances and economic headwinds in the US and abroad. Companies close to the heart of the US gas value chain concur that 2023 is likely to offer more gas price volatility, with Freeport LNG's restart one of several factors promising to stir markets in the year ahead. "I think there will certainly be volatility," Kinder Morgan CEO Steve Kean told analysts at the Wells Fargo Midstream and Utilities Symposium on Dec. 8. "And as we get LNG back in ....those are big moves, big chunks of demand coming on."

BP has signed a memorandum of understanding with the Egyptian government with the aim of establishing a large-scale renewable hydrogen production facility in the North African country, it said in a statement Dec. 8. BP is to evaluate the technical and commercial feasibility of developing an export hub in Egypt, exploring high-potential locations across the country for renewables. "Egypt has world-class renewable energy resources, and we look forward to working with the government to explore how we can support its ambitious low-carbon strategy," BP executive vice president of gas and low carbon energy Anja-Isabel Dotzenrath said in the statement. The MOU was signed by BP, Egypt's New and Renewable Energy Authority, the Egyptian Electricity Transmission Company, the General Authority for Suez Canal Economic Zone and the Sovereign Fund of Egypt for Investment and Development (TSFE). TSFE CEO Ayman Soliman said the MOU builds on the fund's green hydrogen portfolio and its "mandate to transform Egypt into a regional hub for green energy." Hydrogen was a prominent theme at the UN Climate Change Conference hosted by Egypt in Sharm el-Sheikh in November, with several deals and projects launched on the sidelines. BP CEO Bernard Looney attended COP27 as a delegate of Mauritania, with which the company signed a separate MOU on green hydrogen production at the conference. The EU signed strategic hydrogen partnerships with Kazakhstan, Namibia and Egypt, seeking a diverse range of suppliers to meet its planned 10 million mt/year of imports by 2030. And Fertiglobe led a consortium commissioning a first phase of the 100-MW Egypt Green hydrogen plant for ammonia production, also supported by Egypt's Sovereign Fund. BP is developing a portfolio of renewable and low-carbon hydrogen projects globally, including in the UK , Netherlands , Germany, Spain, the Middle East, the US and Australia , it said. Europe and Asia-Pacific are seen as becoming major importers of hydrogen and its derivatives, drawing supplies from potential producing regions such as the Middle East, Australia and Latin America. Platts, part of S&P Global Commodity Insights, assessed the cost of producing renewable hydrogen via alkaline electrolysis in Europe at Eur23.70/kg ($24.93/kg) Dec. 7 (Netherlands, including capex), based on month-ahead power prices. Production costs in the Middle East, by contrast, were assessed at $3.55/kg (Oman). In Asia-Pacific, costs were assessed at $3.39/kg in Western Australia, well below the $9.41/kg cost in demand center Japan.

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