2022 Global Power Markets

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The UAE's Abu Dhabi National Oil Co. will supply German companies with LNG and diesel cargoes in 2022 and 2023 as Europe's biggest oil consumer seeks to diversify energy sources amid reduced supply of Russian gas and upcoming European Union sanctions on crude and oil product imports from Moscow. As part of a new Energy Security and Industry Accelerator agreement signed between the UAE and Germany, ADNOC will supply RWE with an LNG cargo in late 2022 to be used in the country's floating LNG import terminal in Brunsbuttel, state-run WAM news agency reported Sept. 25. ADNOC has also earmarked several other LNG cargoes for German customers for delivery in 2023, the agency said, without disclosing further details. The agreements were signed during a state visit by German Chancellor Olaf Scholz to the UAE, the second stop on a three-country trip that started in Saudi Arabia and will take him next to Qatar, where other energy deals are expected to be signed. ADNOC, which completed its first ever direct diesel delivery to Germany in September, has agreed to the terms with Wilhelm Hoyer GmbH & Co. on the supply of up to 250,000 mt of diesel per month in 2023, WAM said. German LNG demand As Russian gas deliveries dwindle from Nord stream, German utilities are working to diversify gas import portfolios and build up the limited import capacity for LNG. Uniper, RWE and EnBW on Aug. 16 signed a memorandum of understanding for gas supplies into the Wilhelmshaven and Brunsbuttel floating storage and regasification units, which are set to start operations this winter with a capacity of 12.5 Bcm/year. Germany is developing a total of five state-backed FSRU projects, but the focus is initially on supplying LNG into the Wilhelmshaven and Brunsbuttel sites. The FSRUs in Brunsbuttel and Wilhelmshaven are to be operated by RWE and Uniper. The reduction in Russian flows to Germany via Nord Stream since mid-June and then the complete halt in deliveries at the end of August have helped keep European gas prices at sustained highs. Platts, part of S&P Global Commodity Insights, assessed the Dutch TTF month-ahead price at an all-time high of Eur319.98/MWh on Aug. 26. It was last assessed on Sept. 23 Eur179.20/MWh, almost three times higher than at the end of 2021. Oil products supply Before Russia's invasion of Ukraine in February, Germany was the world's second-biggest buyer of Russian crude after China, importing 687,000 b/d of crude and 149,000 b/d of oil products from Russia in November 2021, according to the International Energy Agency. Most of the crude was delivered via the northern branch of the Druzhba pipeline system from Russia, with smaller amounts arriving via tanker to Rotterdam and its North Sea ports of Wilhelmshaven and Brunsbuttel. Germany had already seen most of its refiners and oil importers switch away from Russian supplies since March. By mid-April, the government said the country had slashed its dependence on Russian crude to 12% of its imports from 35% before the invasion of Ukraine. The UAE energy producer has also signed agreements with German customers, including power plant operator Steag and copper producer Aurubis for the supply of low-carbon ammonia. The first cargo of low-carbon ammonia from ADNOC arrived in Germany Sept. 15 on its way to Aurubis, which will use the low-carbon ammonia as a feedstock in its wire rod plant. The demonstration cargo, produced by Fertiglobe, an ADNOC unit that produces fertilizers, is the first of several test cargoes to be sent from the UAE to Germany as the UAE energy producer expands its strategic energy partnership. Low-carbon ammonia delivery ADNOC plans to work with several German companies on hydrogen projects and signed deals with companies including Uniper, Aurubis and RWE as it looks to expand into Europe after having establishing export markets in Asia. ADNOC signed an agreement with German companies Hydrogenious and Uniper on March 21 on imports to Wilhelmshaven, covering 7,000-10,000 mt/year of green hydrogen shipments from 2025, as part of a demonstration project. ADNOC aims to supply up to 25% of Germany's imported clean hydrogen and derivatives such as ammonia. The UAE is also targeting a 25% share of the global green and blue hydrogen market by 2030. As part of agreements signed on Sept. 25, UAE's renewable energy firm Masdar will also explore opportunities to develop as much as 10 GW in offshore wind in the North Sea and Baltic Sea in Germany by 2030, WAM said.

For access to all regions in the US Power Tracker series, join Platts Dimensions Pro . Western power forwards are trending higher down the curve following higher gas forwards with forecasts of above-normal temperatures, as spot prices climbed in August on summer heat. Across the Western power markets, several October and November power packages averaged about 60% above their 2021 counterparts, according to S&P Global Commodity Insights data. Power forwards down the curve climbed higher at the end of August. Forwards curve Mid-C on-peak September rolled off the curve at $149.90/MWh, 128% above the 2021 package a year ago, after averaging 31% higher throughout August, according to S&P Global data. On-peak October averaged 64% above its 2021 counterpart in August and reached as high as 96% higher by the end of the month, while on-peak November averaged 59% higher in August and climbed to 82% higher on the last day of the month. Likewise, COB on-peak October averaged 60% above its 2021 counterpart a year ago for August and ended the month 89% higher, while Palo Verde on-peak November averaged 60% above its 2021 counterpart last year at the same time for August and reached as high as 71% above by the end of the month, according to S&P Global data. The three-month outlook indicates a greater probability for above-normal temperatures across most of the western US, with equal chances for above- or below-normal temperatures in the Northwest, according to the US National Weather Service. In gas forwards, SoCal city-gate September rolled off the curve 99% higher than its 2021 counterpart did, as the October package is currently 42% higher and November is 24% higher, according to S&P Global data. Spot market In the spot market, Western wholesale power prices averaged 64.5% higher year on year for August. Palo Verde on-peak day-ahead averaged $121.59/MWh in August, 81% higher year on year, according to S&P Global pricing data. Prices reached as high as $225/MWh Aug. 31, an 11-month high. SP15 on-peak day-ahead locational marginal prices averaged $110.86/MWh in August, 76% higher year on year, according to California Independent System Operator data. Prices climbed as high as $181.51/MWh Aug. 31, an 11-month high. In spot gas prices, PG&E city-gate averaged $9.767/MMBtu in August, 83% higher year on year, as prices reached as high as $10.735/MMBtu Aug. 24, a 42-month high, according to S&P Global pricing data. Sumas averaged $8.105/MMBtu, 118.5% higher than a year ago, and reached as high as $8.860/MMBtu Aug. 24 an eight-month high. Power prices climbed at the end of the month in anticipation of a Labor Day week heat wave that caused CAISO to issue multiple calls for conservation, as well as restricted maintenance operations, energy emergency alert watch, EEA 1, EEA 2, transmission emergency and led to a new peakload record. CAISO set an all-time peak demand record of 52.061 GW Sept. 6, surpassing a 16-year record by 3.6%. Weather impacts While to-date September population-weighted average temperatures across CAISO's footprint have averaged 10% higher than normal, August averaged temperatures were about 1.8% higher than normal and 2.8% higher than a year ago, according to CustomWeather data. The higher temperatures caused population-weighted cooling degree days to average 24% higher than normal and 39% above year-ago levels. Peakload was up 7% year on year to an average of 40.05 GW in August, according to CAISO data. Thermal remained the lead fuel source, averaging 42.3% of the total fuel mix in August, up 3.2 percentage points year on year, while important slipped 4 points to average 16.8%, according to CAISO data. Hydro generation increased 1.5 points to make up 6.5% of the mix, while solar fell 2.4 points and wind shed 2.7 points to average 15.9% and 7% in August, respectively. Farther north, peakload averaged 7.654 GW in August, 8% higher year on year, according to Bonneville Power Administration data. BPA population-weighted temperatures averaged 5.6% higher than normal, leading cooling degree days to average 118% higher, according to CustomWeather data. Hydro was the lead fuel source at 74.3% of the total fuel mix, up 6.2 points from a year ago, followed by thermal at 9.5% of the mix, down nearly 2 points, and wind at 6.5% of the mix, down nearly 3 points, according to BPA data.

2022 has seen the specter of government interventions envelop gas markets: whether it’s price caps, encouraging benchmark diversification, pooling procurement in a centralized platform or using state-owned banks to directly buy LNG cargoes, all ideas appeared to be on the table. While pipeline gas and LNG share several fundamental attributes, they are also different in many aspects. In this flurry of policy proposals and announcements, there are significant changes taking place in the LNG industry itself. These changes relate to price indexation, market participation and trade flows. This piece, as part of a series of articles on LNG industrychanges, will tackle the first point: price indexation. LNG price markers are being used in the spot market, while long-term contracts are still prone to utilizing substitute oil or pipeline gas prices. As substitute prices diverge significantly from the LNG market, a hybrid solution in long-term contracts, combining both mechanisms, is seeing some adoption. Price indexation Price benchmarks used in LNG trade have been in great flux over the last 12 months, triggering large changes in relative values between them. While LNG has always been a difficult market to analyze from a pricing perspective, 2022 has seen this complexity deepen. Here are some broad points to start with, based on data collected by market reporting teams at Platts, part of S&P Global Commodity Insights, and the IHS Connect contract database from January to August: 1. Fixed price trade has globally been in retreat for some time, but North Asia’s usage of fixed prices significantly slumped in 2022; 2. As LNG cargo prices have converged and gas hub prices have diverged an increasing amount of trade referenced LNG-based benchmarks; and 3. Contracts signed for long-term volumes are on course to surpass 2021’s total with ease while crude oil-linked contracts have dropped significantly as a proportion of total trade. Fixed price trade has dropped to around 43% of total spot and short-term trades, or cargoes for delivery within the next two years or so, in 2022 versus 65% of trade in 2021. Digging deeper, fixed price trade in North Asia has fallen from 52% in 2021 to under 20% so far in 2022. Fixed prices now largely appear in tenders issued by state-owned companies in South Asia, Thailand, and Argentina. These locations account for 75% of fixed price trades in 2022. The significant drop in fixed price trades is due to increased market volatility and more developed futures markets. It has been well documented that LNG prices ( JKM , Platts West India Marker , Platts Northwest Europe , Platts Gulf Coast Marker ) have been moving in a tight band while gas hub prices on either side of the Atlantic (represented by Henry Hub and the Dutch Title Transfer Facility, or TTF) have been at record differentials. Added to this, LNG prices have been trading at large discounts to TTF in 2022. Platts Northwest Europe LNG benchmark reached a record discount of $24.475/MMBtu against Dutch TTF on Aug. 26. It is in this context that the amount of JKM-indexed trade in the spot and short-term market globally increased to some 33% in 2022, more than double the 2021 figure. Also apparent from this data is that within Europe itself there is greater variety of indexation being used for LNG cargoes. For example, a recent tender issued requested pricing against the French PEG gas hub for 12 cargoes delivered between 2023 and 2025. Activity reported in the Atlantic LNG Market on Close assessment process of S&P Global indicates this, with almost 40% being reported against the UK’s NBP in 2022. There was no NBP-indexed activity reported in the process in 2021. A peculiarity specific to LNG is the appearance of substitute prices in the long-term contract space. It is also surprising that these substitute prices very rarely appear in the short-term contract space. Henry Hub and Brent, widely used in long-term contracts ex-US and within Asia respectively, are each used less than 5% in near-term trade. While Henry Hub has appeared considerably more in long-term Sales and Purchase Agreements (SPAs) in 2022 – largely due to most of the projects seeking a final investment decision being based in North America – Brent-linked long-term contracts have foundered. According to IHS Connect’s LNG contract database just 0.675 million mt of purely Brent-linked SPAs have been signed so far this year, compared to nearly 18 million mt of such SPAs in 2021. Companies involved in negotiations for contracts that may conclude on a Brent-linked basis have complained that the relationship between LNG prices and Brent slope levels used in historical contracts has become a moving target. Because LNG prices are elevated relative to historical Brent slopes, buyers see a risk in agreeing to contracts now that would leave them at historically high slope levels with a risk of downwards LNG price movement. Sellers also do not want to leave value on the table given the potential to sell LNG in the next few years at considerably higher prices – based on current forward curve values – than historical Brent slope levels would imply. After having a reasonably steady relationship for many years the LNG price-Brent term slope relationship started to crack from 2019 onwards. However, the differences between the two have been greatest since 2021. The few purely Brent-linked term contracts signed this year were agreed in January. Platts has heard of several companies having protracted negotiations for term contracts with a proposed Brent pricing basis, but there is little breakthrough yet on these. For the few short-term tenders concluded on Brent-linked pricing, from winter season strips of cargoes to agreements for deliveries up to two years ahead, the slopes have reportedly been between 20%-35%. This reflects the difficulty of using substitute price benchmarks, as they do not share the same market fundamentals as the LNG market. The current impasse is probably unhelpful for the industry given that consumers are keen to tie down volumes for the next few years when the market is expected to be tight, and producers are also trying to secure regular offtake for production planning purposes and financing collateral. Hybrid contracts, where either Brent makes up a proportion of the deal formula, or a Brent slope is agreed that is subject to an LNG price cap and/or collar, could be one way to resolve the standstill. With both contract structures seen adopted recently, a compromise could be emerging for midterm contracts.

Further expanding energy cooperation is set to be high up the agenda when Russian President Vladimir Putin and his Chinese counterpart Xi Jinping meet in Uzbekistan Sept. 15-16, given Russia's urgent need to find new destinations for its oil and gas exports as Western sanctions close off its previous markets. This year has already seen Russia-China energy cooperation increase significantly. Oil and gas deliveries to China have risen since Russia's invasion began in February, and new supply and infrastructure deals were signed a few weeks before Russia's invasion was launched. S&P Global Commodity Insights estimates that China's crude imports from Russia averaged 1.82 million b/d in January-July, 6.4% higher than in the same period of 2021. China has been happy to take advantage of the sizeable discounts on Russian oil that have opened up following Europe's move to phase out Russian imports. Platts assessed Russia's key crude grade Urals at $69.32/b on Sept. 13, according to S&P Global data, a sizeable discount to benchmark Dated Brent at $91.45/b. Prior to the invasion of Ukraine Urals was trading at a discount of around $10/b to Dated Brent. Export limitations However, Russia's ability to redirect exports East is threatened by strong market competition, China's interest in supply diversity, concerns over the coronavirus pandemic's impact on Chinese demand, as well as Russia's limited export capacity in that direction. S&P Global forecasts China's oil demand will average 15.1 million b/d in 2022, a year on year contraction of 305,000 b/d, before recovering 485,000 b/d in 2023. China will continue to buy Russian crude and perhaps some products, director of the gas research and China energy programs at the Oxford Institute for Energy Studies, Michal Meidan said. "It will certainly buy crude to the extent that it is discounted, but may be reluctant to displace large volumes of oil from other suppliers and massively increase its dependence on Russia," she said. The origin of Chinese imports saw some changes in August, reflecting competition for market share and China's interest in supply diversity. Crude imports from the former Soviet Union declined 13% on month to 1.8 million b/d, while crude purchases from the Middle East, Africa and Malaysia grew. Malaysia exports Malaysian Blend -- re-blended Iranian and Venezuelan grades. "This means that China has been consistently increasing appetite of crudes from those two countries indirectly, as expected since they have been putting down crude prices to compete against the Russian offerings," S&P Global Commodity Insights said. In addition, export capacity constraints mean that Russia is not able to redirect all oil volumes that traditionally went to European markets to Asia. S&P Global estimates that 3.5 million b/d of previous Russian oil exports to Europe will need to be rerouted by Feb. 5, 2023, of which two-thirds will be able to find new buyers. There are also limits to Russia's ability to export oil products to China. "It will be difficult for Russia to fully reroute product exports, leading to expectations for Russian refinery runs to fall further in 2023," S&P Global oil market analyst Rebeka Foley said. Meidan said that China's large refining system and desire to be self-sufficient in oil products will limit demand for rerouted Russian volumes. Russia's main crude export route to Asia is the East Siberia-Pacific Ocean oil pipeline. ESPO has a spur into China and runs to the Far Eastern port of Kozmino. Pipeline operator Transneft said that ESPO worked at its full 80 million mt/year, or around 1.6 million b/d, capacity in the first seven months of 2022. Russia also plans to increase oil export capacity at Kozmino by over 7 million mt/year by October. This would be an increase of about 20% on Kozmino's current capacity of 36 million mt/year. Russia can increase export capacity at the port by returning to deliveries via rail from Skorovodino. Russia also ships around a quarter of its deliveries to China under long-term contracts via Kazakhstan. In the longer term, Russia is developing new oil and gas export infrastructure at ports along the Northern Sea Route. The route runs through Russian territorial waters in the Arctic and has shorter delivery times and lower costs, as well as less geopolitical risk than traditional routes. Supply deals In early February state-run oil giant Rosneft signed a 10-year supply deal with China's CNPC for supply of 100 million mt, or around 200,000 b/d, of crude. The deliveries will be shipped via Kazakhstan for refining at plants in northwest China. At the same time Gazprom signed a 10 Bcm/year gas supply deal with CNPC. This adds to a 30-year supply contract for 38 Bcm/year between Gazprom and CNPC signed in 2014. Shipments are carried out via the Power of Siberia pipeline, which was launched in December 2019. Gazprom said Aug. 31 that supplies via the route were up 60% year on year in the first eight months of 2022. Gazprom's 2021 exports were an estimated 10.5Bcm, so if the 60% growth is maintained through 2022, the total number for this year will be around 17 Bcm. Chinese companies are also seen as potential buyers for stakes in projects that Western companies are exiting due to sanctions. They have increased their investments in Russian projects since 2014, when Russian companies' access to Western financing was restricted due to sanctions. Chinese companies already hold stakes in Russian projects including Novatek's Yamal LNG and Arctic LNG 2.

Before skyrocketing gas prices encouraged Norwegian supply and LNG imports, Russia had been the largest single source of gas supply for Europe. However, it was Russia's invasion of Ukraine —followed by Gazprom reducing and then halting deliveries to Germany via Nord Stream— that signaled a tipping point in Europe's gas supply. The following interactive chart illustrates the fast-changing paradigm of European gas imports.

Platts, part of S&P Global Commodity Insights, will launch daily spot cash differential assessments for JKM LNG physical cargoes Oct. 17, 2022. This follows industry feedback and data observed for an expanding proportion of floating price transactions taking place in the Asia-Pacific LNG spot market. Cash differentials, also known as premiums or discounts, represent the prices counterparties trade against benchmark values published. Platts will publish spot cash differentials for the daily JKM assessment (AAOVQ00), which will reflect the spread between the JKM assessment against three derivative assessments as below: LNG Japan/Korea Spot Crg DES (AAOVQ00) vs LNG Japan/Korea derivatives Balance-Month Next-Day (LJKMB00) LNG Japan/Korea Spot Crg DES (AAOVQ00) vs LNG Japan/Korea derivatives Pricing Month (LJKMO00) LNG Japan/Korea Spot Crg DES (AAOVQ00) vs LNG Japan/Korea derivatives Mo01 (LJKMO01) These cash differential assessments will reflect values at the close of the Asia LNG Market on Close assessment process at 4:30 pm (0830 GMT) in Singapore and will follow the Singapore publishing schedule. Please send all feedback, comments, or 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 to the public upon request.

More evidence of demand destruction in advanced economies emerged Aug. 5 when a closely watched survey of consumer habits by the Office of National Statistics showed that 42% of adults in the UK had cut back on non-essential travel in vehicles in response to higher costs. The survey showed that 51% were now using less gas and electricity in response to the rising costs of living and commodities. The UK is the world's sixth largest economy and under normal conditions consumes about 280 million barrels of oil annually in the form of transport fuels to power its fleet of almost 40 million vehicles, according to official government figures. Crude oil prices have fallen in recent weeks amid growing signs that surging global inflation and slowing economies will hit demand growth. The front-month contracts for both ICE Brent and NYMEX crude have shed around $10/b in the week alone. Signs of possibly weakening UK demand come as the Bank of England warned inflation in the UK could close the year above 13% and enter a deep economic recession. Although a small participant in terms of global oil consumption, the stresses impacting the domestic transport fuels market are indicative of wider global concerns about demand now outweighing worries over spare capacity and drained stocks. OPEC agreed Aug. 3 to a modest supply increase of 100,000 b/d to its allotted output despite lobbying by the US and the majority of the alliance's producers pumping close to full capacity. Across Western Europe, gasoline and middle distillate demand has only just recovered to prepandemic levels of 1.8 million b/d and 5.6 million b/d, respectively, Platts Analytics estimates. However, regional demand for the fuels -- which peaked in 1992 and 2006, respectively -- is seen falling to 1.35 million b/d and 4.7 million b/d by 2030 under a reference case scenario.

India is to update its Nationally Determined Contribution (NDC) under the United Nations' Framework Convention on Climate Change to include a 50% target for renewables in the power mix by 2030, the Environment Ministry said Aug. 3. The update confirms some, but not all, of Indian Prime Minister Narendra Modi's COP26 pledges made in November last year. Then Modi pledged to reach net-zero emissions by 2070 and have 500 GW of renewables by 2030. India would strive to get 50% of its energy from renewable sources by 2030, reducing total projected carbon emissions by one billion tonnes, he said. "India now stands committed to reduce emissions intensity of its GDP by 45% by 2030, from 2005 level and achieve about 50% cumulative electric power installed capacity from non-fossil fuel-based energy resources by 2030," the Ministry said. There was no reference to the 500 GW renewables capacity or one billion tonne CO2 reduction goals, although the updated NDC is yet to be officially published. India's renewables installed capacity now stands at 168 GW, which is 42% of the total power capacity of 404 GW, Power Ministry data showed. The NDC would be implemented via government programs with support from states and union territories, the Ministry said without giving details. The government had launched several programs to scale up India's adaptation and mitigation efforts, the Ministry said. For instance, Indian Railways' net-zero emissions by 2030 alone would abate 60 million mt CO2 annually, it said. In its previous NDC India had committed to reduce emissions intensity by 33%-35% from 2005 levels, with non-fossil fuel sources accounting for 40% of the generation mix by 2030. Under Platts Analytics' Reference Case, India's power generation emissions are seen increasing from 1.28 billion mt in 2022 to 1.61 billion mt in 2050. Under a scenario putting India on course to meet Paris Agreement goals, the country's CO2 emissions from power generation would need to peak at 1.4 billion mt in 2023 before falling to 1.18 billion mt in 2030 and 997.46 million mt by 2050. Financial support The Environment Ministry called for funding assistance to deliver on the updated plans. "Providing new and additional financial resources as well as transfer of technology to address the global climate change challenge are among the commitments and responsibilities of the developed countries under UNFCCC and the Paris Agreement," it said. India needed its "due share" of international finance and technological support, it said. In the run up to COP26 the UK presidency admitted wealthy nations had failed to honor a pledge to provide $100 billion a year of climate support for less wealthy nations by 2020. The earliest the target cold be achieved was 2023, according to analysis by the Organization for Economic Cooperation and Development. June generation up Data from India's Central Electricity Authority, meanwhile, showed India's fossil-based thermal generation up 24% year on year in June to some 106 TWh. Renewable generation in May, the latest data available, was at 21 TWh, up 44% YoY, accounting for around 14% of the generation mix. INDIA: GENERATION MIX IN MAY (TWh) May-22 May-21 Thermal 108.38 87.51 Nuclear 3.47 4.00 Hydro 12.83 11.75 Import 0.35 0.57 Wind 10.17 7.10 Solar 8.83 6.00 Biomass 0.31 0.30 Bagasse 0.72 0.40 Small hydro 0.64 0.55 Others 0.21 0.18 Total 145.91 118.36 Source: Central Electricity Authority

In Europe, with a hot summer ongoing and a cold winter expected, re-establishing secure sources of energy in light of Russia’s war in Ukraine is a top priority. S&P Global Commodity Insights reporters Shivani Pandya and Sasha Foss speak with crude oil director Joel Hanley about plans to address the crunch in European natural gas supply, and how a return to oil-fired power generation is not as simple as some might suggest. Subscribe to Platts Dimensions Pro for access to assessments and premium content covering the front-month TTF natural gas benchmark ( GTFTM01 ), European fuel oil ( AAYWT00 ), and much more. This podcast episode was produced by Jennifer Pedrick from Houston. 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).

The next few months will be "critical" for Europe to build up sufficient gas stocks to make it through the upcoming winter given uncertainty over Russian gas supplies, the head of the International Energy Agency said July 18. In a new commentary, IEA executive director Fatih Birol said an additional 12 Bcm of gas needed to be saved in the next three months that could then be stored across the EU to bolster stocks. EU gas storage sites are currently 64% full, but Birol warned that the EU would need to reach a level of more than 90% should Russia cut supplies to Europe from the start of the heating season in October. "And even then, it could still face supply disruptions in the latter part of the heating season," Birol said. "Achieving that 90% storage level is still possible, but Europe needs to act now and make every remaining day count," he said. Under new EU storage rules, member states must ensure their gas storage sites are filled to an average 80% of capacity by Nov. 1, 2022, and to 90% by Nov. 1 in subsequent years. However, the EC has said in a draft winter preparedness communication that without demand reduction measures, EU stocks could be filled to just 65%-71% of capacity in the event of a full Russian supply halt. Birol warned that if Russia decided to completely cut off gas supplies before Europe can get its storage levels up to 90%, the situation would be "even more grave and challenging." 'Big ask' Birol said the first immediate step toward filling European gas storage to adequate levels before winter was to reduce Europe's current gas consumption and to put the saved gas into storage. "Some of this is happening already because of sky-high gas prices, but more is required," Birol said. Concerns over storage have seen European gas prices remain at sustained highs through 2022. The Dutch TTF month-ahead price hit a record Eur212.15/MWh on March 8, according to Platts price assessments by S&P Global Commodity Insights, and was last assessed at Eur159.50/MWh on July 15, up by 86% since the start of 2022. Birol said significant additional demand reductions were needed to prepare Europe for a "tough" winter ahead. He said 12 Bcm of additional gas savings represented some 130 LNG tankers. "This is a big ask, but it does not exaggerate the scale of what is needed," he said. Birol said it was "categorically not enough" to rely on gas from non-Russian sources. "These supplies are simply not available in the volumes required to substitute for missing deliveries from Russia," he said. Birol said that would be the case even if gas supplies from Norway and Azerbaijan flowed at maximum capacity, if deliveries from North Africa stayed high, if domestic output followed recent trends, and if inflows of LNG increased at a similar rate as the first half of 2022. "That is already a lot of 'ifs'," Birol said. Five--point plan To encourage gas saving, Birol unveiled a five-point plan that the EU could follow. First, he said the EU should introduce auction platforms to incentivize EU industrial gas users to reduce demand. "Industrial gas consumers can offer part of their contracted gas supply as demand reduction products for compensation, which can lead to efficiency gains and a competitive bidding process," he said. Such a process has also already been outlined in the draft EC communication that is due to be officially proposed on July 20. The second point is to minimize gas use in the power sector, which could be done by temporarily increasing coal- and oil-fired generation while accelerating deployment of low-carbon sources, including nuclear, Birol said. The third point in the plan is to enhance coordination among gas and electricity operators across Europe, including on peak-shaving mechanisms, to help reduce the impact of lower gas use on power systems. Fourth, Birol said, would be to bring down household electricity demand by setting cooling standards and controls, and finally the EU should harmonize emergency planning across the EU at the national and European level. "If these types of measures are not implemented now, Europe will be in an extremely vulnerable position and could well face much more drastic cuts and curtailments later on," he said.

Canada is to allow gas turbines used to flow gas through the Nord Stream pipeline from Russia to Germany that are repaired on Canadian territory to be returned to Germany under a sanctions waiver, a senior Canadian government official said July 9. In a statement, Canada's natural resources minister Jonathan Wilkinson said Germany's economy would suffer "significant" hardship in the event of a shortage of gas. Russia's Gazprom on June 16 cut gas supplies via the Nord Stream pipeline to Germany to just 40% of capacity, citing maintenance issues with gas turbines at the key Portovaya compressor station. One turbine that had been sent by Germany's Siemens to a factory in Montreal, Canada, for maintenance had been stuck in the country after Ottawa imposed sanctions against Moscow that meant the turbine could not be returned. Another turbine was shut down after Gazprom said its window for undergoing required maintenance work had passed. "Canada will grant a time-limited and revocable permit for Siemens Canada to allow the return of repaired Nord Stream turbines to Germany," Wilkinson said in the statement posted to his Twitter account. This, he said, would support Europe's ability to access "reliable and affordable energy" as it continues to transition away from Russian oil and gas. "Absent a necessary supply of gas, the German economy will suffer very significant hardship," he said. High prices European gas prices remain at sustained highs following the Nord Stream cuts and further uncertainty over future Russian gas flows. The benchmark Dutch TTF month-ahead price is now back close to the all-time high of Eur212.15/MWh reached in early March, according to Platts price assessments from S&P Global Commodity Insights. The TTF month-ahead price was last assessed at Eur168.98/MWh on July 8, up 105% since the start of June and 420% higher year on year. The market remains concerned about the fate of Nord Stream flows. Its annual maintenance shutdown began July 11 and is scheduled to last until July 21, and there are fears over whether the pipeline will restart at all following the work. With Nord Stream flows cut to zero, Russian pipeline gas is currently only reaching Europe via Sudhza in Ukraine and via the TurkStream pipeline to Southeast Europe and Turkey. Flows at the Sudzha point -- the only route for Russian gas deliveries via Ukraine at present -- were nominated at at 41 million cu m/d for July 11, according to data from Ukrainian grid operator GTSOU, in line with recent daily flows via Sudzha. The head of Germany's Uniper on July 8 said he hoped it was not too late for Gazprom to remedy the situation regarding Nord Stream flows. "I hope Nord Stream will come back at full capacity and that the technical problems can be solved," Uniper CEO Klaus-Dieter Maubach said at a press conference. "I haven't given up hope yet that things will go back to normal," he said, adding that the level of Nord Stream flow post-maintenance would be "decisive" for Uniper for the coming months.

The UAE Port of Fujairah's growing profile as an energy hub is set for another boost, with Abu Dhabi National Oil Co.'s plans to build a 9.6 million mt/year LNG plant in the eastern emirate. The project, currently in the design phase, is expected to be complete between 2026 and 2028, sources told S&P Global Commodity Insights – not in time to ease the current gas crunch, as the world scours for new supplies to replace Russian volumes. But analysts say it could be well-poised to capture growing demand for the fuel, if high prices do not set long-term consumption back and environmental regulations in Europe do not close off that market. Fujairah, which is already the world's third largest oil bunkering hub, is hoping to benefit from the project, with new stakeholders expected to be attracted. The facility, which will include two 4.8 million mt/year trains, will raise ADNOC's LNG production capacity to 15.6 million mt/year, giving neighboring Qatar – currently the world's largest LNG exporter – a formidable regional rival. ADNOC, which declined to comment on the project, owns a 70% stake in the ADNOC LNG joint venture, which has a current capacity to produce 6 million mt/year at Das Island in the Persian Gulf. Other shareholders in ADNOC LNG are Mitsui & Co. with a 15% stake, BP with 10% and Total with 5% ADNOC is in talks with those partners to take part in the Fujairah facility, sources said, and Japan's INPEX intends to consider participating, its CEO told S&P Global. ADNOC's new project comes at a time when the world's demand for LNG is high as Russia restricts piped gas supplies to Europe and countries around the globe seek gas as a transition fuel to replace dirtier crude. Gas prices in Europe and Asia have soared to record highs in 2022 as Europe wrestles with Asia over LNG cargoes in a tight market. The JKM spot LNG price for delivery into northeast Asia hit a record $84.76/MMBtu in March and was last assessed at $41.65/MMBtu July 4, according to Platts assessments from S&P Global. Asia destinations ADNOC has traditionally sent its LNG to Asia and up until 2018 supplied around 90% of its volumes to Japan under long-term agreements but has sought since to diversify its customer base by signing multi-year contracts. Adding Europe as a potential new destination for ADNOC's LNG will depend on several factors, including the ability to lock in long-term contracts. The destination for LNG "will depend on which parties want to sign contracts for the LNG (most likely Asia), the state of the global LNG market and prices when the plant comes on stream," said Jonathan Stern, a research fellow at the Oxford Institute for Energy Studies. However, he added, "it will be difficult for European companies to make long-term commitments because of their emission targets." Since 2019, India has been the UAE's top LNG customer, based on Kpler shipping data. Platts Analytics, in a June 13 report, noted that none of ADNOC LNG's term customers sent any cargoes to Europe, despite lucrative LNG spot prices. The last time ADNOC LNG sent any volumes to Europe was in June 2009, it said. However, as demand destruction from high LNG prices seeps into Asia, Europe may become a more attractive destination. "Europe's need to replace 160+ Bcm of Russian gas will create huge need for additional LNG in the medium term," said Robin Mills, CEO of Qamar Energy. "Sellers can name their terms at the moment and buyers are realizing the danger of exposure to volatile and potentially very high spot prices. The question is what 'long term' means for European buyers given their decarbonization targets, 10 years or longer?" Platts Analytics has revised its Indian LNG demand forecast down an average of nearly 10 billion cu m/d from 2022 through 2025 on the back of higher prices expected during this period. "South Asia, once thought to be one of the key drivers of global demand in the medium term, could disappoint to the downside amid lingering elevated spot prices and limited cover by long-term contracts," Platts Analytics said in an April 29 report. New gas The expansion of ADNOC's LNG capacity comes as new gas developments are set to increase alongside its expansion of oil production capacity to 5 million b/d by 2030 from about 4 million b/d currently, which will yield higher associated gas. ADNOC had announced in December a rise in national gas reserves of 16 Tcf, bringing the UAE's gas reserves base to 289 Tcf. The location of Fujairah for the new LNG production will also be of added value to ADNOC, given the aging facilities at Das Island, located far offshore. The fact that Fujairah lies outside the problematic Strait of Hormuz in the Persian Gulf reduces its geopolitical risk profile. "For the UAE this [project] is very important and may replace the Das Island plant in future, as that plant is now very old dating from the late 1970s," said Stern. Fujairah will also gain from the growing number of LNG tankers that will call on the port, which is considering adding LNG bunkering services, its managing director, Captain Mousa Murad, said. "Fujairah can also benefit that available gas will attract industrial companies that will use gas instead of, for example, diesel to set up projects," said Murad.

Japan's Ministry of Economy, Trade and Industry expects no immediate disruption to imports from Russia’s strategically important Sakhalin 2 LNG project following a decree transferring ownership of the operator -- hitherto led by Shell and Gazprom -- to a new entity, METI minister Koichi Hagiuda said July 1, adding that contingency planning was underway. Russian President Vladimir Putin issued a decree June 30 transferring all rights and obligations held by Sakhalin Energy, the operator of the Sakhalin 2 project, to a new Russian company citing unspecified “actions by the US and linked foreign countries and organizations that are unfriendly and incompatible with international law.” It comes after Shell, Gazprom’s main partner in the project with a stake of 27.5% minus one share, announced its withdrawal from Russia on March 8 in light of the invasion of Ukraine. "We are currently in the midst of scrutinizing the impact on Japanese companies' stake holdings in the Sakhalin 2 project as well as on Japanese companies' LNG imports from the project based on this presidential decree," Hagiuda told reporters. "We believe we are not in a situation where Sakhalin 2 LNG cannot be imported immediately," Hagiuda said. "To be prepared for various contingency situations, we will need to take carefully thought-out measures.” Japan had already warned in June of a rising risk of disruption to Russian LNG supplies, vital for power generation in the country, amid rising tension and global competition for LNG as Europe tries to reduce its dependence on Russia. The two-train Sakhalin 2 LNG facility -- which was launched in 2009 -- produced and shipped a record volume of LNG in 2020, reaching 11.6 million mt. It had an original design capacity of 9.6 million mt/year, but upgrades have seen output consistently exceed capacity. The operator also produced over 100,000 b/d of Sakhalin Blend crude in 2020. Shell has had a rocky history at Sakhalin, where it was originally the majority stakeholder before being obliged to surrender part of its stake in 2006. Analyst George Voloshin of Paris-based Aperio Intelligence said the decree came after inconclusive efforts by Shell to sell its stake, reportedly involving Chinese counterparties. Operational 'paralysis' Voloshin described the decree as a “clear and unambiguous expropriation,” but went on to say it was also intended to “normalize the production situation” amid a state of “paralysis” following Shell’s decision to exit. The decree stipulates existing stakeholders, also including Japan’s Mitsui and Mitsubishi, with 12.5% and 10% stakes respectively, have a month to submit their approval for the transfer of stakes to the newly created company, after which the government will rule on the admissibility of the submissions. It was unclear on what grounds the government would or would not allow the existing shareholders to hold proportional stakes in the new company. In the event of refusal or the deadline being missed, the corresponding stakes are to be sold, with the proceeds transferred on behalf of the shareholders to government-designated Russian bank accounts, from which any expenses incurred to date can be deducted. A Shell spokesperson said: “As a shareholder, Shell has always acted in the best interests of Sakhalin 2 and in accordance with all applicable legal requirements. We are aware of the decree and are assessing its implications.” However, Voloshin questioned the likelihood of the foreign stakeholders assenting to the transfer on the terms set out and suggested the eventual buyers would most likely be from China or India, potentially at steeply discounted prices and leading to an “inevitable” switch of LNG exports away from Japan. “Shell's plans to withdraw from Sakhalin 2 have resulted in a paralysis at the operating company. Its inability/unwillingness to sell its stake quickly enough [reflecting] the geopolitical and economic context… and the prospect of steep losses suggests the paralysis will last for as long as Shell is a shareholder,” Voloshin said, adding Shell had been the “driving force” behind operations. Japan’s Hagiuda, however, was more moderate. "We recognize that this presidential decree is not about a seizure. It is questioning existing stakeholders’ consent to move to a new entity after having transferred all of the rights and obligations from Sakhalin Energy to the newly establishing entity," Hagiuda said. "Either way we will give rigorous consideration from a standpoint of ensuring stable supply for Japan's power and gas," he said, adding the country currently has two to three weeks’ worth of LNG inventory held by power and gas companies. Japan exposure Russia accounted for 9% of Japan's total LNG imports of 74.32 million mt in 2021, its fifth-largest supplier, according to data from Japan's Ministry of Finance. Almost all of Japan’s Russian LNG imports come from Sakhalin 2. Officials from Mitsui and Mitsubishi said they would consider their response following discussions with other stakeholders and Japan’s government. A Mitsubishi spokesperson added that Sakhalin 2 was producing as normal. Tokyo Gas does not currently see any impact on its Sakhalin 2 LNG procurement, a company spokesperson said.

The US Supreme Court's June 30 ruling restricting the US Environmental Protection Agency's authority to regulate climate pollution from existing power plants will likely hamper the Biden administration's ability to issue future climate and energy rules that have a major economic impact, according to legal experts. In a 6-3 decision, the conservative justices on the high court, for the first time, invoked a legal line of reasoning known as the "major questions" doctrine in finding that the Obama-era Clean Power Plan exceeded the EPA's authority. The major questions doctrine, according to the majority, holds that courts should not defer to agencies on matters of "vast economic or political significance" unless the Congress has explicitly given them the authority to act in those situations. In repealing and replacing the Clean Power Plan, the Trump administration found that doing so would have no practical effect on the US power sector, in part because the industry had already met the program's emissions reduction goals before its 2022 start date. But the Supreme Court, siding with a coalition of red states and coal producers that challenged the Obama-era rule, found that its approach to generation shifting went too far. The court's decision also focused on the possible inclusion of similar systemwide measures in a future EPA regulation. The June 30 ruling in West Virginia v. EPA (No. 20-1530) was largely based on the idea that the EPA "must point to clear congressional authorization" in issuing regulations under Section 111(d) of the Clean Air Act, although experts predicted it will also curtail other agencies' rule-writing abilities. "Capping carbon dioxide emissions at a level that will force a nationwide transition away from the use of coal to generate electricity may be a sensible solution to the crisis of the day," Chief Justice John Roberts wrote for the majority. "But it is not plausible that Congress gave EPA the authority to adopt on its own such a regulatory scheme in Section 111(d)." Court expected to scrutinize 'major' rules Supporters of the Clean Power Plan's "beyond the fence line" approach were quick to note that the US electric utility industry has long relied on generation shifting and emissions trading schemes as cost-effective ways to comply with Clean Air Act rules. The Clean Air Act's landmark Acid Rain Program, for example, allowed older, dirtier coal-fired power plants to pay cleaner coal-fired units for emissions allowances that reduced overall compliance costs for the industry. EPA rules addressing interstate smog pollution have also adopted a similar approach. "This notion that rules can't be controversial, that they can't be creative or expansive, is troubling," Jack Lienke, regulatory policy director of the Institute for Policy Integrity at New York University School of Law, said in an interview. "The traditional approach is when statutes are written in broad terms and are susceptible to multiple reasonable interpretations, courts defer to agency readings of that text so long as they're reasonable." Jay Duffy, an attorney with the Clean Air Task Force, said he did not interpret the court's ruling as prohibiting generation shifting entirely. Indeed, the court's majority said it has "no occasion" to decide whether Section 111(d)'s statutory phrase "best system of emission reduction" refers "exclusively to measures that improve the pollution performance of individual sources." "I think you could have inside the fence approaches paired with market mechanisms, and I don't think that is eliminated by this decision," Duffy, who briefed the Supreme Court case for public health organizations, said in an interview. Nevertheless, legal experts on both sides of the debate agreed that future EPA efforts to tackle climate pollution under the Clean Air Act will be subject to far more scrutiny by the high court. "The majority had no trouble finding that the question of how the US electricity sector should be structured (and how much electricity should come from coal as opposed to other sources) was a major question," Jeff Holmstead, a former EPA air office chief in the George W. Bush administration, said in an emailed statement. "Because it is a major question, EPA can make such determinations only if there's a clear statement that this is what Congress intended." Nathan Richardson, an attorney and assistant professor at the University of South Carolina School of Law, said the court's focus on the Clean Power Plan's "novel approach" could also spell trouble for other climate- and energy-related administrative rulemakings. The EPA is in the process of finalizing rules to control methane emissions from existing oil and gas facilities. And in March the US Securities and Exchange Commission proposed requiring publicly traded companies to reveal climate risks and carbon emissions data in financial filings. That proposal has already sparked a fierce debate. "Every time an agency tries to do something, it's subject to this kind of inquiry: is it like what you did before?" Richardson said in an interview. "Any time an agency does something that is new and different and major, with major being totally up to the whims of the judges, then there's the potential for it to get thrown out, or more precisely, thrown back to Congress." US Rep. Frank Pallone, D-N.J., who chairs the House Committee on Energy and Commerce, said in a June 30 statement that the decision "does not derail our commitment or ability to achieve our climate goals." "EPA continues to have many powerful tools at its disposal and there is more both Congress and [US President Joe Biden] can do to meet the climate crisis head-on," Pallone said. "I am determined to get the job done."