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<channel><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/agriculture/052026-strait-of-hormuz-closure-may-trigger-severe-food-price-crisis-fao</link><description>The Strait of Hormuz closure could trigger a &amp;quot;severe&amp;quot; global food price crisis in the next six to 12 months, the UN Food and Agriculture Organization said in a statement May 20. The Strait of Hormuz, a critical artery for global energy and fertilizer trade, handles about 30% of global urea exports and significant volumes of ammonia and phosphates, making it a key chokepoint for agricultural</description><title>Strait of Hormuz closure may trigger &amp;apos;severe&amp;apos; food price crisis: FAO</title><pubDate>20 May 2026 13:51:00 GMT</pubDate><author><name>Sampad Nandy</name><name>Samyak Pandey</name></author><content><![CDATA[ Fertilizers, Chemicals, Energy Transition, Renewables May 20, 2026 Strait of Hormuz closure may trigger âsevereâ food price crisis: FAO By Sampad Nandy and Samyak Pandey Editor: Manish Parashar Getting your Trinity Audio player ready... HIGHLIGHTS FAO Food Price Index up 1.6% MOM in April Avoid export restrictions on energy, fertilizers: FAO Onset of El NiÃ±o may further worsen the crisis: FAO The Strait of Hormuz closure could trigger a "severe" global food price crisis in the next six to 12 months, the UN Food and Agriculture Organization said in a statement May 20. The Strait of Hormuz, a critical artery for global energy and fertilizer trade, handles about 30% of global urea exports and significant volumes of ammonia and phosphates, making it a key chokepoint for agricultural inputs, according to the FAO. Decisions taken now by farmers and governments on fertilizer use, imports, financing and crop choices will determine food prices over the next six to 12 months, the FAO said. The FAO suggested policies to tackle the potential food price crisis. It recommended to look for alternative corridors to bypass the strait and urged countries to avoid imposing export limits on energy, fertilizers and inputs as near-term measures. It also suggested limiting biofuel consumption to ensure stable food supply in the medium term and building stable regional reserves to absorb food supply shortages in the long term, the FAO said in its statement. "Start seriously thinking about how to increase the absorption capacity of countries, how to increase their resilience to this choke, so that we start to minimize the potential impacts," FAO Chief Economist Maximo Torero said May 20. The latest FAO Food Price Index rose for the third consecutive month in April, averaging 130.7 points, up 1.6% from its revised level in March and 2% higher year over year. The food supply situation could worsen with the onset of El NiÃ±o, which is expected to bring droughts and disrupt rainfall and temperature patterns across several regions, the FAO said. FAO projections show that global fertilizer prices could rise 15%-20% in the first half of 2026 if the crisis persists. S&amp;P Global Energy CERA forecasts that the Middle East will export 10 million mt of nitrogen in 2026, accounting for 23.4% of global outflows. CERA projects that the Middle East will export 23 million mt of urea this year, accounting for 38.5% of global outflows. US-Israeli Conflict with Iran Essential Energy Intelligence for today's uncertainty. See What Matters > ]]></content></item><item><link>https://www.spglobal.com/market-intelligence/en/news-insights/research/2026/03/us-israel-iran-war-provokes-shipping-lane-shifts</link><description>Global supply networks may feel the impact through a mixture of energy market disruptions, airfreight challenges and container freight shipping network interruptions.</description><title>US-Israel Iran war provokes shipping lane shifts</title><pubDate>03 March 2026 17:10:00 GMT</pubDate><author><name>Ines Nastali</name><name>Chris Rogers</name><name>Vania Alvarez Murakami</name><name>Eric Oak</name></author><content><![CDATA[ Research â Mar 03, 2026 US-Israel Iran war provokes shipping lane shifts By Ines Nastali, Chris Rogers, Vania Alvarez Murakami, and Eric Oak The US and Israel on Feb. 28 launched a large-scale, coordinated air campaign against Iran, striking a broad range of leadership, military, security and nuclear targets. A forced government change is now a key objective according to S&amp;P Global Market Intelligence country risk analysts. Global supply networks may feel the impact through a mixture of energy market disruptions, airfreight challenges and container freight shipping network interruptions. In the case of energy, shipping via the Strait of Hormuz needs to continue; flows of LNG may be disrupted as well as crude oil. Energy supply chain disruption Absent an extended closure of the Strait, or the destruction of liquefaction assets, the impact is unlikely to be long term in nature. The Islamic Revolution Guard Corps (IRGC) is likely to expand targeting of critical Gulf energy infrastructure if US and Israeli strikes target Iranian critical national infrastructure and major crude export terminals. Air freight disruption Global air freight networks face challenges from the halt to flights through many of the regional ports, including the hubs of Doha and Dubai. These hubs handle around 2.6 million metric tons and 2.2 million metric tons of airfreight respectively, or around 4.0% of the total global airfreight volumes. The ability of air freight networks to adapt is partly limited by aircraft flight ranges, though networks can rapidly adapt as was shown during the pandemic. Container shipping disruption Continued discussions on these events are taking place at TPM 26 this week. join the conversation. Container shipping faces challenges to both local actions in the Strait of Hormuz and the wider region through shipping via the Red Sea. Local actions in the Strait of Hormuz impact key shipping hubs for container freight, including Jebel Ali in Dubai, as we previously identified at the time of June 2025 conflict. Container lines are also redirecting shipping away from the Red Sea once more. CMA CGM SA has ordered all vessels in the Gulf to proceed to shelter and AP Moeller Maersk A/S has rerouted vessels bound for the Red Sea around the Cape. Want to understand the broader story? Connect with us to learn more Learn More ]]></content></item><item><link>https://www.spglobal.com/market-intelligence/en/news-insights/research/2026/04/hormuz-closure-project-logistics-supply-chain</link><description>The near-total closure of the Strait of Hormuz amid the war in the Middle East will haunt global breakbulk and project markets, experts say.</description><title>Hormuz closure triggers â&amp;#x80;&amp;#x98;havocâ&amp;#x80;&amp;#x99; for project logistics supply chain</title><pubDate>24 April 2026 12:00:00 GMT</pubDate><author><name>Carly Fields</name></author><content><![CDATA[ BLOG â Apr 24, 2026 Hormuz closure triggers âhavocâ for project logistics supply chain By Carly Fields The near-total closure of the Strait of Hormuz amid the war in the Middle East will haunt global breakbulk and project markets long after the final missiles are fired, sector specialists say. Speaking during a March 26 Journal of Commerce webcast, JosÃ© Enrique Sevilla-Macip, senior research analyst for Latin America Country Risk at S&amp;P Global Market Intelligence, said there had been a 97% decrease in transits across the Strait of Hormuz over the past 25 days, noting that on March 25, for the first time since the conflict began, not a single vessel crossed the waterway. The paralysis is triggering a shift from initial price shocks to actual physical shortages of fuel and goods. On the ground, the logistics of moving breakbulk and project cargo goods has become a balancing act of cancellations and rerouting. Marc Cowie, CEO for North America at project cargo forwarder Trans Global Projects (TGP), said that many carriers are refusing to even quote for cargo entering the war region due to skyrocketing insurance premiums. The disruption is also creating a âlag impactâ that will persist for months. âThere will undoubtedly be ships out of position, cargo out of position, and thereâs going to be a knock-on effect,â Cowie said on the webcast. âItâs going to take some time to get back to normality.â For panelist Christian Ohlrich, global director for logistics at energy storage products manufacturer Fluence Energy, the crisis is manifesting most acutely in the energy sector. He described the âfuel shockâ as a primary concern, with bunker supplies depleting rapidly, particularly in Asia. This has led to a chaotic environment for manufacturing and project execution. âItâs creating quite some havoc,â Ohlrich said. âItâs crunching schedules. Itâs increasing costs.â He noted that while larger projects can still attract the necessary multipurpose vessels, smaller, less âenticingâ shipments are being delayed by weeks. That is not, however, stopping Fluenceâs project operations. âWe have plenty of buffers,â Ohlrich said. âIâm still making all my commitments. Itâs just changing the flow of project execution.â This includes changing internal team arrangements to meet the sequence of a project. âItâs an inconvenience rather than a hindrance,â he said. Oil prices expected to remain elevated The bunker fuel shortage is unlikely to ease in the short term. Sevilla-Macip expects oil prices to remain above $100 per barrel for at least the next month, although he holds out hope they could return to $60 by year-end if hostilities cease soon. However, the path to peace is cluttered with âsignpostsâ of further escalation, he said. These include potential Iranian attacks on US aircraft, the involvement of Tehran-backed Houthi militants in the Bab-el-Mandeb Strait, or the targeting of critical civilian infrastructure such as desalination plants. In the face of this volatility, the advice from project shippers and forwarders is a mix of tactical flexibility and rigorous planning. TGPâs Cowie urged shippers to work in close partnership with forwarders to find alternative routes or modes, such as trucking cargo across the Arabian Peninsula to safer ports. âWe have to remain flexible, remain calm,â Cowie said. âLogistics is about challenges. It is about overcoming those challenges.â Ohlrich echoed that, stressing the need for better foresight. âTighten up your planning and forecasting as much as possible,â he advised the webcast. âThe better you can plan ahead, especially in situations where you see these kinds of disruptions, the better.â This article was originally published in the Journal of Commerce on March 30, 2026. Subscribe to JOC.com Learn more about our data and insights Click Here ]]></content></item><item><link>https://www.spglobal.com/market-intelligence/en/news-insights/research/2026/02/red-sea-shipping-reopens</link><description>Red Sea shipping resumes amid reduced Houthi attacks, but renewed threats create uncertainty for shippers. Capacity increases may impact freight rates.</description><title>Red Sea shipping reopens, but renewed Houthi threats keep route uncertainty high</title><pubDate>20 February 2026 14:10:00 GMT</pubDate><author><name>Ines Nastali</name></author><content><![CDATA[ Research â Feb 20, 2026 Red Sea shipping reopens, but renewed Houthi threats keep route uncertainty high By Ines Nastali Container carriers are now restarting services via the Red Sea amid a continued reduction in Houthi attacks on maritime shipping, according to reports. One of the routes connects India via the Middle East with the US operated by AP Moeller Maersk, confirming earlier reports that Indian shippers will benefit from a service for reefer products. To benefit from increased traffic, Red Sea Container Terminals opened Egyptâs first semiautomated facility at Sokhna Port near the southern entrance to the Suez Canal in mid-January 2026, the Journal of Commerce reports. Sending more vessels through the Suez Canal might present a downward pressure point on freight rates as capacity is freed from the longer Cape of Good Hope diversion. While these developments might mean more capacity going through the Suez Canal in the coming months, the situation could easily change if the Houthis resume their attacks. An indicator of the volatility of the situation is CMA CGM SAâs announcement that some of its Asia-Europe services (FAL1, FAL3 and MEX) that went through the Suez Canal in 2025 will go back to transiting via the Cape of Good Hope, as a result of a âcomplex and uncertain international context,â adding to the uncertainty that shippers are facing when planning journey times and amid renewed threats of attacks by the Houthis in January 2026. The share of east-to-west shipments via the canal remains at 18.7%, close to its two-year average and well below the pre-disruption level of about 80%. According to Market Intelligence analysis, there remains a severe risk of attacks on vessels in transit in the one-year outlook if, as is likely, the ceasefire between Hamas and Israel breaks down permanently. If those attacks resume, the risk for vessels is likely to remain highest closest to, and inside, Yemeni territorial waters in areas controlled by the Houthi, particularly around Hodeidah where the Houthi likely maintains a significant arsenal of anti-ship cruise missiles, uncrewed surface vessels (USV) and uncrewed underwater vehicles (UUV). All Houthi attack incidents using USVs have been conducted within a 70-nm radius of Hodeidah. The Houthis have been using the period since the announcement of a ceasefire to rearm and increase weapons shipments via Iran and the Horn of Africa and rebuild port infrastructure and facilities around Ras Isa and Hodeidah, including new jetties and artificial island facilities to support tanker and cargo ships. Those were damaged in Israeli and US airstrikes. This aligns with a similar tactical pause in attack activity that the group adopted during the previous ceasefire in Gaza from Jan. 19âMarch 16, 2025. Egypt opens new semiautomated Red Sea terminal as Suez traffic grows Learn More ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/podcasts/energy-evolution/051926-how-the-war-in-iran-is-accelerating-asias-energy-transformation</link><description>In this episode, host Eklavya Gupte explores how the war in the Middle East has exposed Asia&amp;apos;s deep reliance on fossil fuels while also accelerating the region&amp;apos;s energy transition. Ruchira Singh, energy transition editor at Platts, part of S&amp;amp;P Global Energy, speaks with Nobuo Tanaka, chair of the steering committee at the Innovation for Cool Earth Forum and former executive director of the</description><title>How the war in Iran is accelerating Asia&amp;apos;s energy transformation</title><pubDate>19 May 2026 16:36:12 GMT</pubDate><author><name>Eklavya Gupte</name><name>Ruchira Singh</name></author><content><![CDATA[ Crude Oil, Natural Gas, LNG, Energy Transition, Renewables, Hydrogen May 19, 2026 How the war in Iran is accelerating Asia's energy transformation Featuring Eklavya Gupte and Ruchira Singh HIGHLIGHTS War exposes Asia's fossil fuel reliance Crisis accelerates region's energy shift EV and hydrogen adoption set to rise In this episode, host Eklavya Gupte explores how the war in the Middle East has exposed Asia's deep reliance on fossil fuels while also accelerating the region's energy transition. Ruchira Singh, energy transition editor at Platts, part of S&amp;P Global Energy, speaks with Nobuo Tanaka, chair of the steering committee at the Innovation for Cool Earth Forum and former executive director of the International Energy Agency, about the emerging dynamics between petrostates and electrostates, and where Asia stands on the threshold of its energy future. Echoing the 1970s oil shocks that gave rise to the LNG market, Tanaka believes this crisis will spark another tectonic shift, elevating renewables to the mainstream and fast-track Asia's electrification. From faster electric vehicle adoption to expanding low-carbon hydrogen trade and strengthened regional collaboration, Asia is poised to respond with a decisive shift toward cleaner, more resilient energy systems, he says. US-Israeli Conflict with Iran Essential Energy Intelligence for today's uncertainty. See What Matters > ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/metals/051526-world-steel-review-cbams-article-6-embrace-comes-with-strings-and-forms-attached</link><description>The European Commission&amp;apos;s draft rules on recognizing third-country carbon pricing under the bloc&amp;apos;s Carbon Border Adjustment Mechanism represent a pragmatic but tightly controlled opening that could accelerate investment in Article 6 of the Paris Agreement while creating new compliance challenges. The widely anticipated implementing regulation, published May 13 and open for consultation until June</description><title>CBAM&amp;apos;s Article 6 embrace comes with strings and forms attached</title><pubDate>15 May 2026 17:34:38 GMT</pubDate><author><name>Staff </name></author><content><![CDATA[ Energy Transition, Emissions, Carbon May 15, 2026 CBAM's Article 6 embrace comes with strings and forms attached By Staff Editor: Richard Rubin Getting your Trinity Audio player ready... HIGHLIGHTS Draft rules could spark investment in Article 6 trade Importers face mounting paperwork to claim carbon price cuts Article 6 credits capped at 10% of emissions The European Commission's draft rules on recognizing third-country carbon pricing under the bloc's Carbon Border Adjustment Mechanism represent a pragmatic but tightly controlled opening that could accelerate investment in Article 6 of the Paris Agreement while creating new compliance challenges. The widely anticipated implementing regulation, published May 13 and open for consultation until June 10, lays out detailed methodologies for how carbon prices paid abroad translate into reductions in CBAM certificate obligations. "It creates a real financial incentive to put a credible domestic carbon price in place," Adam Hearne, CEO at CarbonChain, told Platts, part of S&amp;P Global Energy. "Companies that already pay a carbon price, or buy qualifying credits, can lower their effective CBAM cost, making their goods more competitive in the EU market. This tilts the playing field towards countries that are building or linking carbon markets." Under the world's first carbon border tax mechanism, importers of carbon-intensive goods into the EU from six covered sectors -- aluminum, cement, electricity, fertilizers, iron and steel, and hydrogen -- are now liable for their emissions. Demand signals The draft's design is deliberately restrictive on international credits. Only carbon credits authorized under Articles 6.2 or 6.4 of the Paris Agreement would qualify for CBAM liability reductions, and their use would be capped at 10% of emissions covered under qualifying third-country carbon pricing mechanisms. This structure amounts to a "compliance-adjacent demand signal for authorization and tracking-ready units, potentially supporting investment in Article 6 market infrastructure," said Eszter Bencsik, voluntary carbon markets analyst at S&amp;P Global Energy Horizons. The EU's CBAM started its definitive phase on Jan. 1, 2026, but importers will only be able to purchase CBAM certificates starting in February 2027 to cover the emissions embedded in their imports for 2026, giving businesses more time to adapt to this carbon pricing mechanism. Dan Maleski, a senior environmental markets adviser and CBAM lead at Redshaw Advisors, believes the likelihood of international Article 6 credits being used under CBAM is likely to remain relatively limited. "The implementing act is very clear that any recognized carbon cost must be mandated and legally required, rather than the result of a voluntary purchase," Maleski told Platts. "In principle, this significantly limits the scope for international credits, as host countries would effectively need to forgo domestic revenue streams. Out of the 30-plus active emissions trading systems globally, only South Korea currently permits the use of international credits within its ETS, and even then under very strict limitations and conditions, Maleski added. The EU's CBAM works alongside the EU Emissions Trading System to prevent carbon leakage by imposing carbon pricing on imports as Brussels phases out free allowances for domestic producers. Carbon permits in Europe are currently almost eight times more expensive than compliance prices in China, the world's industrial powerhouse. Platts assessed EU Allowances for December 2026 at Eur75.04/mtCO2e ($87.39/mtCO2e) on May 14. This compares with China's compliance emission allowance, which was valued at Yuan 80.06/mtCO2e ($11.76/mtCO2e) on May 8, according to the Shanghai Environment and Energy Exchange. Compliance burden These rules, however, add a significant administrative burden for operators seeking to claim carbon price reductions, market participants cautioned. Operators will need to submit additional reports on carbon price reductions, on top of monitoring and verification plans and carbon accounting rules they already face, according to Pauline Miquel, policy and research lead at CBAM consultancy CBAMBOO. "This is a lot more work to be able to let an importer forecast their cost because all of this is the basis for the importer's cost modeling," Miquel said. "And without this, it's almost impossible for an EU importer to understand how much they're going to pay in CBAM liability." They will also need to calculate how the price paid translates into embedded emissions at the product level, she added. The lack of accredited verifiers presents a further hurdle. If operators choose to use verified emissions rather than default values, "it's going to make it very difficult to have all of this ready for 2027," Miquel said. But many believe the explicit recognition of Article 6 credits, even in limited form, demonstrates the EU wants to support the Paris Agreement's international carbon market mechanisms, with the 10% cap designed to prevent over-reliance on offsets and to push real domestic decarbonization. This could drive increased investment in third-country carbon pricing infrastructure, Article 6 credit supply, and verifier and accreditation services over the next 12-24 months, Hearne said. A US-based carbon market analyst said the proposal reflects a broader positive trend of the EU being more flexible and open to carbon credits and recognizing the positive effects of carbon projects, pointing to similar developments in the Corporate Sustainability Reporting Directive. Domestic vs international credits The proposal could also reinforce a price premium for credits that can be evidenced through UN-grade accounting, she added, while laying foundations for greater integration of Article 6-aligned credits into other carbon pricing frameworks. "International credits face the highest integrity gateway -- Article 6 authorization plus a quantitative cap -- while domestically issued credits, including those linked to mitigation abroad, could be recognized without an EU-level integrity screen or usage limit," Bencsik said. This bifurcation risks an uneven playing field, she noted. Exporters under regimes with permissive domestic crediting rules may be able to evidence a higher carbon price effectively paid, and therefore secure larger CBAM reductions, than peers reliant on internationally transferred units constrained by Article 6 rules. The proposal's practical impact will depend heavily on implementation details, especially administrative burden, certification and verification robustness, and interaction with rebates or other forms of compensation. A further dynamic to watch is pricing behavior in domestic credit markets. "Because domestic credits reduce CBAM obligations only insofar as they contribute to an evidenced carbon price effectively paid, some jurisdictions could face incentives to support higher domestic credit prices or tighter supply to retain compliance value domestically rather than see larger net financial outflows via CBAM certificate surrender," Bencsik added. US-Israeli Conflict with Iran Essential Energy Intelligence for today's uncertainty. See What Matters > ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/blog/energy-transition/052026-et-highlights-hormuz-electrification-article-six-cmab-singapore-carbon</link><description>Energy transition highlights: Our editors and analysts bring you the biggest stories from the industry this week, from renewables to storage to carbon prices.</description><title>ET Highlights: Hormuz crisis pushes electrification, Brussels eyes Article 6 under CBAM, Singapore carries forward unused carbon offset</title><pubDate>19 May 2026 20:05:00 GMT</pubDate><author><name>Staff </name></author><content><![CDATA[ Energy Transition, Renewables, Emissions, Carbon May 20, 2026 ET Highlights: Hormuz crisis pushes electrification, Brussels eyes Article 6 under CBAM, Singapore carries forward unused carbon offset Energy Transition Highlights: Our editors and analysts bring together the biggest stories in the industry this week, from renewables to storage to carbon prices. Top story Hormuz crisis exposes structural energy flaw, pushes electrification case: ETC The closure of the Strait of Hormuz triggered a historic disruption to fossil fuel supplies and should accelerate clean energy deployment, with governments and markets responding to disrupted oil and liquefied natural gas flows by fast-tracking renewable electricity, electric vehicles and heat pumps rather than locking in new fossil fuel infrastructure, according to the Energy Transitions Commission. The crisis has disrupted around 18 million b/d of oil supply and 20% of global LNG trade, or more than 110 Bcm/year, with 75% of the world's population living in fossil fuel-importing countries, the report said. If sustained, elevated prices could add $1 trillion-$2 trillion in annual energy costs globally, it said. "This is a reminder to governments -- both in Asia and in Europe -- that as long as we have fossil fuel-based economies, we are vulnerable to another political event," ETC co-chair Adair Turner told Platts, part of S&amp;P Global Energy, in an interview. "Four years ago, it was Russia-Ukraine. Now it's the Gulf. Who knows what the next one is." The ETC, a global coalition of leaders from across the energy landscape committed to achieving net-zero emissions by mid-century, said fossil fuel systems were "structurally vulnerable" because of their dependency on continuous extraction, trade and transport. Benchmark of the Week Eur75.04/mt ($87.23/mt) Platts-assessed, nearest December EU ETS carbon allowances May 14. Explore Platts Energy Transition Price Assessments Editor's Picks: Free and premium content SPGlobal.com Brussels opens door to limited use of Article 6 credits under CBAM Companies importing carbon-intensive goods into the EU could use international carbon credits to lower their Carbon Border Adjustment Mechanism costs under draft rules published by the European Commission, provided the credits meet Paris Agreement standards and represent no more than 10% of the emissions from facilities where the goods were produced. The Commission published the draft implementing regulation on third-country carbon price recognition under CBAM, with the guidance now open for public consultation until June 10. Australia shortlists renewable hydrogen projects for funding amid budget cuts The Australian Renewable Energy Agency has shortlisted seven renewable hydrogen projects for the second round of the Hydrogen Headstart program, according to a government announcement, a day after spending cuts to the flagship initiative were announced. ARENA has invited the projects to submit full applications for funding from the program, which received a revised allocation of A$1 billion ($660 million) in the 2026-27 (July-June) federal budget announced on May 12, ARENA said. Renewable hydrogen is complex, capital-intensive industry and takes time, but it is a critical enabler of industrial decarbonization, particularly for hard-to-abate sectors, ARENA said. Canadian Solar managing 'solar downturn' that has lasted 'longer than expected' Canadian Solar is focused on key strategic markets as solar energy production continues to experience challenges, though its battery storage business is attracting greater interest. The solar downturn has lasted longer than expected, according to Shawn Qu, Canadian Solar's executive chairman and chief technology officer. During the company's first-quarter earnings call, Qu said the company has refocused on strategic markets, noting the creation of CS PowerTech in December 2025, which is helping it reshore US manufacturing. Canadian Solar shipped 2.5 gigawatts of solar modules and 2.1 gigawatt-hours of storage capacity in the first quarter, above guidance. S&amp;P Global Energy Core Singapore allows carbon tax companies to roll over 2025 offset quota Singapore will allow companies liable for the carbon tax to carry forward their unused International Carbon Credit offset quota from emissions years 2025 to 2026, the National Environment Agency and Ministry of Sustainability and the Environment said. The one-year rollover is intended as a "transitional measure" to give international carbon markets under Article 6 of the Paris Agreement more time to mature and for more ICCs to become available, according to the statement. The move is largely anticipated by the market, though many sources expect the official announcement to be made in June, as in the previous year. Major UK construction project replaces diesel with hydrogen at no additional cost The Lower Thames Crossing infrastructure project in the UK is on target to slash CO2 emissions during the construction phase by replacing diesel with battery-electric and hydrogen fuel-cell equipment, at no additional overall cost. The company will replace a total of 63 million liters of diesel via direct electrification, hydrogen fuel cell vehicles on the construction site and biofuels, the groupâs Supply Chain and Sustainability Director Katharina Ferguson said at a recent event at the Port of Tilbury, close to the construction site. The project has a contract to purchase 2,500 metric tons of renewable hydrogen from producer GeoPura over five years, displacing over 12 million liters of diesel per year. Solar generation likely to top coal output in ERCOT for first time in 2026: EIA Annual power generation from utility-scale solar resources will surpass coal-fired generation in the Electric Reliability Council of Texas market for the first time in 2026, the US Energy Information Administration forecasts, though an analysis of ERCOT data indicates that this occurred already the year before. The EIA, in its May Short-Term Energy Outlook, forecast that solar generation in ERCOT would reach roughly 78 billion kilowatt-hours this year, compared to about 60 billion kWh for coal-fired output. By comparison, ERCOTâs solar generation in 2025 was around 57.1 billion kWh while coal produced nearly 60 billion kWh, according to EIAâs report. ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/energy-transition/051826-ecosperity-week-iea-urges-balanced-transition-credits-for-early-southeast-asia-coal-exits</link><description>Transition credits must strike a balance between power system reliability and carbon credit integrity to enable early coal plant retirements in Southeast Asia, where relatively young coal fleets are crucial for energy security, the International Energy Agency said in a report released May 15 at GenZero&amp;apos;s Ecosperity Week 2026 event in Singapore. The report, &amp;quot;Financing the Modernization of Power</description><title>ECOSPERITY WEEK: IEA urges balanced transition credits for early Southeast Asia coal exits</title><pubDate>18 May 2026 14:57:54 GMT</pubDate><author><name>Himanshu Chauhan</name></author><content><![CDATA[ Energy Transition, Carbon, Renewables May 18, 2026 ECOSPERITY WEEK: IEA urges balanced transition credits for early Southeast Asia coal exits By Himanshu Chauhan Editor: Aastha Agnihotri Getting your Trinity Audio player ready... HIGHLIGHTS Demand limited; compliance markets seen as strongest anchor Philippines projects priced at $35-$50/mtCO2e, aligning with Singapore ICCs Policy reversal risk cited as key concern for buyers Transition credits must strike a balance between power system reliability and carbon credit integrity to enable early coal plant retirements in Southeast Asia, where relatively young coal fleets are crucial for energy security, the International Energy Agency said in a report released May 15 at GenZero's Ecosperity Week 2026 event in Singapore. The report, "Financing the Modernization of Power Systems Beyond Coal: The role of transition credits in Southeast Asia," emphasizes that transition credits should only be issued where carbon revenues demonstrably bring forward retirement or emissions reductions that would not otherwise have occurred on the same timeline. The report noted that it's a critical consideration in Southeast Asia, where phasedown commitments are emerging, but early retirement is not mandated. "Transition credits may support modernizing power systems and accelerating coal transitions, but only under the right policy, planning and market conditions," Sue-Ern Tan, Head of the International Energy Agency Regional Co-operation Centre. Transition credits are a type of carbon credit issued from verified emissions reductions achieved by accelerating the early retirement of coal-fired power plants and replacing their generation with cleaner energy sources. Singapore allows entities covered by its carbon tax to offset up to 5% of their emissions using eligible international carbon credits, creating compliance demand for high-integrity credits, including those generated under Article 6.2 bilateral agreements. Platts, part of S&amp;P Global Energy, assessed Singapore's eligible ICCs at S$31/mtCO2e on May 14. Platts reported that Singapore and the Philippines signed their Article 6 implementation agreement on April 30, establishing a framework for generating and transferring carbon credits from mitigation projects. Among published methodologies, Verra's VM0052 is being piloted at the South Luzon Thermal Energy Corporation plant in the Philippines, the IEA report noted. The methodology includes requirements for just transition plans, grid stability assessments, and system operator involvement to ensure energy security is maintained during the transition. "When we look at VM0052 in particular, all the stuff around integrity is part and parcel of the methodology. But very much in particular when it comes to coal shutdown, there are huge questions around what happens to the community," Mandy Rambharos, Chief Strategy Officer at Verra, said. Philippines projects priced around Singapore ICCs The Philippines transition credit pilot project is currently priced at indicative levels of Singapore-eligible International Carbon Credits, aligning with Singapore's carbon tax range, the panel said. The Transition Credits are priced there, not only because current demand is limited to Singapore, but the price per credit turned out to be around $35-$50/mtCO2e, Eric Francia, President and CEO of ACEN, told Platts. So it suits the range of Singapore ICCs, he added. During the panel discussion, he noted that while variables such as coal prices, interest rates, foreign exchange rates, and solar and battery prices continue to fluctuate, current modeling suggests that transition credits remain within the range of Singapore's carbon tax trajectory. Demand remains limited; offtakers critical Transition credit demand remains modest, with compliance carbon markets offering the strongest potential anchor for future demand, the IEA report noted. "Weak demand signals today mean there may not be sufficient clear price signals for commitments to early retirement investments in the near term," the report said. Francia emphasized that offtakers are essential to make transition credit projects financially viable, noting that ACEN is looking to Singapore and Japan for support, with hopes that Europe might offer opportunities when it allows limited use of international credits starting in 2036. At the same time, Frederick Teo, CEO of GenZero, cautioned against over-reliance on Singapore's carbon tax as a demand anchor, noting that if the tax rises to S$100/mtCO2e, buyers will seek to average down their effective price rather than pay the maximum rate. Nat Keohane, President at the Center for Climate and Energy Solutions, noted that the Philippines transaction presents an opportunity to demonstrate how disparate demand sources, including voluntary corporate commitments, Singapore's carbon tax compliance, and Article 6 sovereign demand, can be combined for a single project. Transition credits may also help address supply-demand gaps in the Carbon Offsetting and Reduction Scheme for International Aviation (CORSIA), where airlines can use eligible credits to offset compliance obligations, the panel suggested. However, the report noted that the risk of policy reversal remains a key concern, as changes in domestic priorities could weaken integrity requirements and reduce buyer confidence. US-Israeli Conflict with Iran Essential Energy Intelligence for today's uncertainty. See What Matters > ]]></content></item><item><link>https://www.spglobal.com/market-intelligence/en/news-insights/research/2026/05/the-most-wanted-exposure-lp-allocation-intent-and-unicorn-ai-deal-concentration-in-private-markets</link><description>Capital continues to flow decisively toward artificial intelligence (AI), with limited partners (LPs) signaling stronger allocation intent to the AI theme than to any other across private markets. </description><title>The Most Wanted Exposure: LP Allocation Intent and Unicorn AI Deal Concentration in Private Markets</title><pubDate>05 May 2026 04:00:00 GMT</pubDate><author><name>Ilja Hauerhof</name><name>Daniel J. Sandberg</name></author><content><![CDATA[ RESEARCH â MAY 2026 The Most Wanted Exposure LP Allocation Intent and Unicorn AI Deal Concentration in Private Markets By Ilja Hauerhof and Daniel J. Sandberg Capital is flooding into AI, with no end in sight. More than 75% of limited partners (LPs) say they plan to deploy capital into AI over the next 12 months, a stark contrast to blockchain at 18%. LP demand for AI exposure is broad-based: endowments, wealth managers and family offices are all leaning in. But scalable exposure is narrowing. Global AI investment jumped 115% year over year in 2025 to $235 billion from $109 billion, with 82% of the incremental dollars coming from rounds of at least $1 billion. AI is the most-wanted exposure in private markets. Itâs also becoming the hardest to access without paying up. Read The Full Research View This Paperâs Source Code Key findings: LPs continue to prioritize AI as a core private markets allocation, with intent holding firm across investor types despite constrained liquidity, indicatingâ¯a structural preference and long-term conviction in AIâs role in value creation.â¯ AI VC fundâ¯performanceâ¯reinforces LP preferences, but both capital inflows and returns are increasingly concentrated, withâ¯mostâ¯incremental capital absorbed by $1B+â¯transactions.â¯ Geographic imbalances are widening, with US markets capturing the bulk of AI deal activity while European and UK investors increasingly export capital cross border. One case-studyâ¯highlightsâ¯howâ¯dataâdrivenâ¯screeningâ¯enables opportunity discovery across geographies and beneath the unicorn deal tier.â¯ Explore the data used to conduct this research: Headcount Analytics The Headcount Analytics dataset provides an view of a company's workforce composition, trends, and metrics. Combine Headcount Analytics with S&amp;P Capital IQ Financials, Transactions data, Key Developments, and other sources for comprehensive analysis. Monthly updates since 2010 cover more than 5 million entities worldwide. Rounds of Funding The MI Transactions Rounds of Funding offering includes private placement data for public and private companies. This data set provides detailed information for each funding stage. The details provided on the structure of each funding round help users understand growth stages more clearly. Company Intelligence The Company Intelligence dataset contains a robust offering of qualitative data, including Topic Tags. Topic Tags are niche industry classifications with nuanced insights into a companyâs operations. Currently 300+ Topic Tags are available relating to 2 million+ private and public companies relevant to the surface. With Intelligence (part of S&amp;P Global) The With Intelligence platform is a comprehensive data and analytics solution designed to support professionals across the investment management and financial services sectors. It provides users with access to a wide range of tools and resources that facilitate informed decision-making and enhance operational efficiencies. Want to replicate this research? View Our Source Code WATCH WEBINAR REPLAY Track AI and Thematic Funding Flows in Private Markets Watch Now ]]></content></item><item><link>https://www.spglobal.com/ratings/en/regulatory/article/double-whammy-hits-global-auto-volumes-s101685388</link><description>This report does not constitute a rating action. Chart 1 Tough market conditions in China and U.S. tariffs have left a mark on the global auto industry. Both weigh on an already subdued outlook for 2026. As a result of the Middle East war, we have revised our volume forecasts (see table 1). While our ratings are unaffected for now, the auto industry remains on edge, as competitive pressures and high supply chain costs coincide with mounting inflation-driven demand risk. Trade tariffs and intensi</description><title>Double Whammy Hits Global Auto Volumes</title><pubDate>19 May 2026 14:08:51 GMT</pubDate></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/energy-transition/051826-xpansiv-ramps-up-hourly-energy-matching-as-tech-giants-demand-stricter-rules</link><description>Renewable marketplace and infrastructure provider Xpansiv is ramping up solutions for hourly matching in energy certifications, as it sees growing demand for stricter rules of origin from tech companies and other end users. &amp;quot;Some companies are seriously thinking about hourly matching of energy consumption and certificates, and generators want to be able to serve these customers,&amp;quot; senior vice</description><title>Xpansiv ramps up hourly energy matching as tech giants demand stricter rules</title><pubDate>18 May 2026 18:23:11 GMT</pubDate><author><name>Felipe Peroni</name><name>Sidney Dumars</name></author><content><![CDATA[ Energy Transition, Renewables, Carbon May 18, 2026 Xpansiv ramps up hourly energy matching as tech giants demand stricter rules By Felipe Peroni and Sidney Dumars Editor: Benjamin Morse Getting your Trinity Audio player ready... HIGHLIGHTS Xpansiv ramps up hourly matching solutions Tech firms drive demand for stricter rules Data barriers challenge smaller market players Renewable marketplace and infrastructure provider Xpansiv is ramping up solutions for hourly matching in energy certifications, as it sees growing demand for stricter rules of origin from tech companies and other end users. "Some companies are seriously thinking about hourly matching of energy consumption and certificates, and generators want to be able to serve these customers," senior vice president Russell Karas told Platts. The company, which runs a spot exchange and several other services for environmental commodities, including carbon credits and renewable energy certificates, has partnered with Granular Energy, a digital platform for managing energy portfolios, focused on building infrastructure for hourly matching of energy certificates. The first goal of the partnership, inked in late April, is to enable energy suppliers and buyers to time-stamp energy data with registry-issued energy attribute certificates (EAC) through a single platform. Demand for hourly matching is driven by tech companies and data centers and is also boosted by regulatory frameworks such as the EU's Carbon Border Adjustment Mechanism (CBAM) and voluntary protocols such as the Greenhouse Gas Protocol. "Generators are serving data centers and hyperscalers, who want optionality and flexibility for certifying energy," said Russell Karas, Senior Vice President at Xpansiv. "We need to be able to cater to these large tech companies, or you would be at a competitive disadvantage," he added. GHG Protocol changes The GHG Protocol board held a public consultation about a change to the scope 2 guidelines, from October 2025 to Jan. 31, 2026. One of the key proposals is that a company now certifying energy consumed in an entire year would be required to match all certificates on an hourly basis for its energy use to be considered renewable. The revision was considered necessary because the current scope 2 guidance was released in 2015. At that time, renewable energy claims were made in annual or, at best, monthly increments, with companies buying certificates that match their energy consumption for the period. The GHG Protocol board is expected to hold a second public consultation in 2026, according to sources, when more opinions will be heard. Meanwhile, the EU's CBAM entered its definitive phase on Jan. 1, 2026, and under its rules, companies can reduce their carbon liability through hourly matching claims. Bottlenecks While some consider hourly matching the next frontier for clean energy, others believe this requirement is excessively tight and might drive consumers away from decarbonization initiatives. "The shift toward hourly temporal matching, updates to the GHG Protocol, and navigation of US tax credits have created massive data management barriers, particularly for smaller players," a US renewable energy consultant said. At the same time, increased energy requirements from data centers are expected to drive REC prices up over the next few months. "Data centers are aggressively procuring renewable energy, taking whatever they can get," a consultant said. "At the same time, existing renewable assets are aging and retiring with fewer new builds in voluntary markets, creating supply constraints," he added. Platts' weekly assessment of New Jersey REC Class 1 contracts increased on May 14, with the 2025 vintage increasing 60 cents to $26.05/MWh and the 2027 vintage 45 cents to $25.75/MWh. The weekly assessment of Pennsylvania Tier 1 REC 2026 vintage rose 45 cents on the same day, to $24.25/MWh, while the 2027 vintage moved to $25.75/MWh, up by 85 cents. Handling the generated energy and certificates on an hourly basis requires significant data processing capacity, which small companies don't have. Other bottlenecks include fragmented workflows for issuing, trading and redeeming certificates, manual reconciliation in some cases and difficulties in exchanging data across different platforms. One common problem mentioned by market participants is the need to navigate multiple platforms, each requiring different logins to issue, transfer and redeem certificates. With increased requirements for granularity in energy certifications, the manpower needed to complete these tasks grows exponentially. Registries have also been adapting to hourly matching, but many expect the transition to be gradual due to its complexity. "The problem we are asked to tackle is how to take lots of data and distill it, to take all the rows and be able to condense it," Karas said. "Whenever you have new rules, there is always going to be a learning curve, but the idea of these rules is to drive investment where more renewables are needed." US-Israeli Conflict with Iran Essential Energy Intelligence for today's uncertainty. See What Matters > ]]></content></item><item><link>https://www.spglobal.com/market-intelligence/en/news-insights/research/2026/04/oil-price-shocks-are-testing-resilience-across-methodologies-among-sp-smallcap-600-indices</link><description>The war in the Middle East and the subsequent surge in oil prices have been key drivers of volatility across U.S equity segments as inflation expectations risk de-anchoring. </description><title>Oil Price Shocks Are Testing Resilience Across Methodologies Among S&amp;amp;P SmallCap 600 Indices </title><pubDate>09 April 2026 06:30:00 GMT</pubDate><author><name>Patricia Medina</name></author><content><![CDATA[ Research â 9 April, 2026 Oil Price Shocks Are Testing Resilience Across Methodologies Among S&amp;P SmallCap 600 Indices By Patricia Medina Executive Summary The war and the subsequent surge in crude oil prices have amplified volatility in U.S. equity markets, including the S&amp;P SmallCap 600 Index. Analysis of small cap equities reveals varying degrees of resilience to recent market fluctuations. The AI-driven tools in S&amp;P Global Market Intelligenceâs Capital IQ Pro platform, along with Xpressfeed, Portfolio Analytics, and data from S&amp;P Dow Jones Indices, help clients uncover insights into equity volatility. This article examines the extent to which elevated oil prices influence the distribution and density of the S&amp;P SmallCap 600 index and a sample of small cap indices with diverse construction methodologies, using 10-year historical daily data. Also, it explores the sector-level dispersion of risk-adjusted returns between cyclical and defensive sectors within small caps as a potential consequence of these dynamics. The war in the Middle East and the subsequent surge in oil prices have been key drivers of volatility across U.S equity segments as inflation expectations risk de-anchoring. The chart below illustrates the density and distribution of four S&amp;P SmallCap 600 stock indices compared to oil price fluctuations since 2016. The oil price range exhibits more outliers on both ends compared to indices. On Friday, February 27 (black dot), the day before the first U.S-Israel strikes on Iran, the four S&amp;P SmallCap 600 equity indices traded at decade highs, while West Texas Intermediate (WTI) oil price stood at $67.06ânear recent lows. Then, the war began, pushing oil price higher settling at $99.56, in contrast to declining levels across the S&amp;P SmallCap 600 indices two weeks into the conflict by Friday, March 13 (red dot). During this period, the average decline across the analyzed group was about 85 points, with variations observed on each index's specific profile. Historical data is available via Xpressfeed and other delivery mechanisms that investors can leverage to populate algorithms and models. S&amp;P SmallCap 600 Index &amp; S&amp;P SmallCap 600 Equal Weighted Index Both indices experienced declines as the war continued, with the Equal Weighted version declining more than the group average and outpacing the market-cap weighted counterpart. Despite the pullback, both indices remain near long-term highs, even as oil tested $100 by March 13. Historically, the S&amp;P SmallCap 600 Index has shown retests around the 1,300 and 950 levels over the past decade. The Equal Weighted version, which has yet to break above 2,000, displays moderate density near 1,600 and 1,000 since 2016. S&amp;P SmallCap 600 Value Index &amp; S&amp;P SmallCap 600 Growth Index As oil price trended higher on the chart above, the Value and Growth categories demonstrated greater resilience to the downside during the initial 10 trading days of the war, remaining near their decade highs. The Value Index showed the highest resilience. The Growth Index's decline was also less than the group average, approaching 1,150. Both indices are characterized by limited historical stock dispersion in the last decade. As noted below, small cap equities tend to be sensitive to spikes in oil prices as they increase input and logistics costs. The climbing oil price is also impacting dispersion across the 11 sectors in the S&amp;P SmallCap 600 index. In addition to S&amp;P Dow Jones Indices performance monitoring, the chart below plots YTD figures, accessible via Capital IQ Proâs Portfolio Analytics offered by S&amp;P Global Market Intelligence. These tools can be combined with user-defined custom functions to allow for ad-hoc or scheduled batch reporting. By mid-March, Energy sector equities posted higher risk-adjusted returns while defensive sectors Utilities and Health Care hovered toward the lower end of the spectrum. Learn more about Portfolio Analytics on Capital IQ Pro Click Here Learn more about Xpressfeed Click Here ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/051326-1250-mw-chpe-transmission-line-into-nyc-reaches-commercial-operation-early</link><description>The 1,250-megawatt Champlain Hudson Power Express transmission line reached its commercial operational date on May 13, making it officially available for scheduling transactions. The line can supply roughly 20% of New York City&amp;apos;s power demand at full capacity. &amp;quot;The good news is that because we finished testing early, we are able to participate in the May energy market, which is great for New York</description><title>1,250-MW CHPE transmission line into NYC reaches commercial operation early</title><pubDate>13 May 2026 18:52:04 GMT</pubDate><author><name>Jared Anderson</name></author><content><![CDATA[ Electric Power, Energy Transition, Renewables May 13, 2026 1,250-MW CHPE transmission line into NYC reaches commercial operation early By Jared Anderson Editor: Giselle Rodriguez Getting your Trinity Audio player ready... HIGHLIGHTS Can supply 20% of NYC power demand Will participate in July capacity market The 1,250-megawatt Champlain Hudson Power Express transmission line reached its commercial operational date on May 13, making it officially available for scheduling transactions. The line can supply roughly 20% of New York City's power demand at full capacity. "The good news is that because we finished testing early, we are able to participate in the May energy market, which is great for New York City because if there is a heat wave, CHPE can help meet demand," Peter Rose, senior director of stakeholder relations for Hydro Quebec said in a phone call. The project developers and owners had initially expected the high-voltage direct-current transmission line to become operational in early June, but testing was completed early, and the line entered commercial operational status shortly after midnight on May 13. Transmission Developers, backed by private equity firm Blackstone, is developing CHPE. The project began construction in November 2022 and will be supplied with hydropower from provincially owned Hydro-Quebec's reservoir system. "CHPE is currently available for energy market operations," a CHPE spokesperson said in an email. Deadlines, economics The owners have a contract with the New York Energy Research and Development Authority that starts June 1, which is the first day of the month after the project has reached commercial operations. That means between May 13, and June 1, Hydro Quebec will schedule transactions on the line when energy market prices are high enough to support the economics, Rose said. Third parties can also schedule transactions when economic, as the transmission line is governed by an open-access tariff. The contract with NYSERDA has a strike price of $97.50/MWh in the first year, and it escalates from there. Required testing to participate in the New York Independent System Operator's July capacity market was completed by the NYISO deadline, so the line will also start participating in that market. "We thought we were only going to be available in August, but can start a month early," Rose said. "The New York Independent System Operator confirms that the CHPE transmission facility has satisfied applicable tariff requirements necessary to participate in NYISO's wholesale electricity markets," Kevin Lanahan, NYISO's senior vice president of external affairs and corporate communications, said in an email. "Following the completion of required testing and submission of a valid notice of intent, CHPE is now eligible to commence participation in the capacity market starting with the July auction and is eligible to participate in NYISO's energy market systems consistent with existing market rules," he said. Spot market transactions will depend on whether power prices support them. With higher temperatures forecast over the coming days in the New York City area, electric cooling demand could increase power prices. The high temperature in New York City on May 17 is forecast to reach 87 degrees Fahrenheit, according to the National Weather Service. A 2025 heat wave pushed NYISO Zone J spot power prices to a daily average of $181.83/MWh June 24. Zone J on-peak day-ahead power prices have averaged $43.14/MWh thus far in May. US-Israeli Conflict with Iran Essential Energy Intelligence for today's uncertainty. See What Matters > ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/energy-transition/051426-interview-hydrogen-push-should-not-lose-momentum-once-energy-crisis-cools---hydrogen-association-of-india</link><description>Geopolitical tensions in the Middle East and the resulting volatility in energy markets have given renewed urgency to global conversations around energy security and alternative fuels. While fluctuations in crude oil prices may temporarily influence investment priorities, experts at Hydrogen Association of India believe the global hydrogen transition is being driven by much deeper structural</description><title>INTERVIEW: Hydrogen push should not lose momentum once energy crisis cools - Hydrogen Association of India</title><pubDate>14 May 2026 12:55:21 GMT</pubDate><author><name>Donavan Lim</name></author><content><![CDATA[ Energy Transition, Hydrogen May 14, 2026 INTERVIEW: Hydrogen push should not lose momentum once energy crisis cools - Hydrogen Association of India By Donavan Lim Editor: Alisdair Bowles Getting your Trinity Audio player ready... HIGHLIGHTS Hydrogen transition driven by structural forces Green hydrogen costs expected to drop to $2/kg India targets domestic hydrogen ecosystem by 2030 Geopolitical tensions in the Middle East and the resulting volatility in energy markets have given renewed urgency to global conversations around energy security and alternative fuels. While fluctuations in crude oil prices may temporarily influence investment priorities, experts at Hydrogen Association of India believe the global hydrogen transition is being driven by much deeper structural forces that extend beyond short-term market cycles. Platts recently spoke to Sachin Chugh, vice president of the Hydrogen Association of India, who said that hydrogen should not be viewed merely as a reaction to oil price volatility, but as a strategic pillar of future industrial and energy systems. "Historically, periods of high crude prices have accelerated interest in alternative fuels. However, the long-term case for hydrogen today is far stronger than in previous energy transitions because it gets linked directly to the energy security and simultaneously complements industrial decarbonization, manufacturing competitiveness, and national sustainability goals," he said. While conventional fossil fuels are expected to remain extremely important in the global energy mix for the foreseeable future, hydrogen is steadily emerging as a complementary energy vector, particularly for sectors that are difficult to electrify directly. Experts at HAI acknowledge that green hydrogen currently faces economic and infrastructure-related challenges. Production costs remain higher than fossil-derived alternatives, and significant investments are required in storage, transportation, and distribution networks. However, similar challenges were also witnessed during the early phases of solar and wind deployment, where costs declined sharply with scale, policy support, and technological innovation. "It is important to understand that energy transitions are evolutionary, not instantaneous. Hydrogen will scale progressively as infrastructure develops, demand aggregates, and technology matures," Chugh said. The HAI expects the price of green hydrogen in India to drop to around $2/kg by 2030, Chugh said. Platts, part of S&amp;P Global Energy, assessed India Renewable Hydrogen Term Contract at $3.227/kg or $28.3969/MMBtu on May 7. Beyond climate commitments For India, the hydrogen opportunity extends beyond climate commitments. With nearly 88% dependence on imported crude oil, diversification of the energy basket is increasingly being viewed as a strategic necessity for long-term economic resilience and energy independence. The association believes India's immediate focus should be on developing a domestic hydrogen ecosystem through phased and practical adoption pathways. One such approach could involve the production of hydrogen-derived e-fuels and their gradual blending with conventional fuels like gasoline or diesel, similar to the country's successful ethanol blending program. In its direct form, early applications could include blending hydrogen into gas distribution networks, deployment of hydrogen-enriched compressed natural gas (HCNG) based power generation and mobility solutions, and gradual expansion of its applications in domestic cooking systems. "Blending in any form provides an effective transition mechanism. Even small percentages can help create demand visibility, enable infrastructure development, improve operational familiarity, and stimulate investments across the value chain," Chugh said. Another critical area requiring attention is the development of globally harmonized hydrogen standards, including certification frameworks, carbon intensity definitions, and transportation protocols. Harmonization can play a vital role in enabling international trade, investor confidence, and scalability of projects. Despite current cost barriers, there is growing optimism that green hydrogen economics will improve significantly over the coming decade due to declining renewable energy prices, electrolyzer manufacturing scale-up, localization, and supportive policy mechanisms. India's green hydrogen production costs are expected to move steadily closer to global competitiveness by 2030, potentially positioning the country as both a major consumer and exporter of green molecules and derivatives such as green ammonia. "The discussion should not be whether hydrogen replaces fossil fuels overnight. The real opportunity lies in building a balanced, resilient, and diversified energy ecosystem where hydrogen becomes an important contributor to industrial growth, clean mobility, and energy security," Chugh added. As governments and industries navigate an increasingly uncertain geopolitical and climate landscape, hydrogen's role is expected to strengthen steadily, not merely because of temporary oil price fluctuations, but because of its long-term strategic relevance to the future global economy. US-Israeli Conflict with Iran Essential Energy Intelligence for today's uncertainty. See What Matters > ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/crude-oil/051826-india-eu-eye-collaboration-to-build-energy-supply-chains-port-infrastructure-modi</link><description>India is accelerating efforts to build resilient energy supply chains by collaborating with global partners to soften the blow from geopolitical conflicts and the energy crisis that are threatening economies across the globe, Indian Prime Minister Narendra Modi said May 16. &amp;quot;First came COVID-19, and then came wars, and now an energy crisis. This is turning out to be a decade of disasters. If</description><title>India, EU eye collaboration to build energy supply chains, port infrastructure: Modi</title><pubDate>18 May 2026 01:55:35 GMT</pubDate><author><name>Sambit Mohanty</name></author><content><![CDATA[ Refined Products, Crude Oil, Energy Transition, Gasoline, Renewables, Hydrogen May 18, 2026 India, EU eye collaboration to build energy supply chains, port infrastructure: Modi By Sambit Mohanty Editor: Aastha Agnihotri Getting your Trinity Audio player ready... HIGHLIGHTS Renews call for quick end to military conflicts Energy shortages threatening world economies India is accelerating efforts to build resilient energy supply chains by collaborating with global partners to soften the blow from geopolitical conflicts and the energy crisis that are threatening economies across the globe, Indian Prime Minister Narendra Modi said May 16. "First came COVID-19, and then came wars, and now an energy crisis. This is turning out to be a decade of disasters. If things don't normalize soon, a lot of efforts and successes that we achieved over many decades will go waste and hit the world economy," Modi told a gathering in the Netherlands during his visit to Europe, which also includes visits to Norway, Sweden, and Italy. India is witnessing a rise in calls for austerity to curb energy use, alongside flight cancellations and a reduction in imports, as supply chain disruptions stemming from the West Asia conflict have increased freight and insurance rates, while rupee depreciation is making imported inputs more expensive. With India importing more than 85% of its crude oil needs, elevated global energy prices are threatening to sharply inflate the country's oil import bill and further weaken the domestic currency, which has lost more than 5% since the start of the Middle East conflict, analysts and industry experts told Platts, part of S&amp;P Global Energy, last week. On May 10, Modi told a gathering in India that the country should reduce gasoline and diesel consumption through measures such as remote work and virtual meetings, as rising oil prices were placing significant pressure on foreign exchange outflows. "The growing strategic convergence between India and Europe and underscored the importance of trusted partnerships in an increasingly complex and uncertain global environment. India and Europe must work together to build resilient and diversified supply chains," Modi said while addressing a European Round Table for Industry (ERT) in Gothenburg on May 17. "India-EU Free Trade Agreement would further unlock new opportunities for both sides," he added. Modi highlighted India's ambitious infrastructure and energy transformation, including large-scale investments in transport, logistics, renewable energy, green hydrogen, and nuclear power. He invited European industry leaders to partner with India in areas such as telecoms and digital infrastructure; AI, semiconductors, electronics, and deep tech manufacturing; green transition and clean energy; infrastructure, mobility, and urban transformation; and healthcare and life sciences, an Indian government statement said May 17. Strategic partnerships India and the Netherlands are also actively cooperating to counter these disruptions by building trusted, transparent, and future-ready supply chains, with a specific focus on clean and renewable energy, Modi said. Modi and Prime Minister of the Netherlands Rob Jetten agreed to elevate the India-Netherlands bilateral relationship to a strategic partnership by following focused, time-bound initiatives and a joint plan of action. To this end, India and the Netherlands adopted the Roadmap of India-Netherlands Strategic Partnership for the next 5 years (2026-2030), the Indian government statement said. "With a view to further strengthening the partnership between India and the Netherlands in the field of renewable energy, the two leaders welcomed the establishment of a Joint Working Group under the Memorandum of Understanding on Renewable Energy which provides ample scope for a diversified agenda for cooperation in renewable energy, including innovative solar energy, green hydrogen, storage and investments in the renewable energy sector to facilitate energy transition," it added. In Gothenburg, Modi met with Robert Maersk Uggla, the chairman of Maersk. "We discussed the great opportunities in India and increased investment, especially in sectors such as port infrastructure, logistics, and more," Modi said on social media platform X. According to S&amp;P Global Energy CERA, India's shipbuilding industry accounts for less than 1% of the global shipping market. This contrasts sharply with China, which holds a 61% share of the order book in major commercial shipping segments. South Korea and Japan also have significant global influence, with advanced technological capabilities and strong export pipelines. India's commercial fleet is much smaller than China's large merchant marine, underscoring the country's growth potential in shipyards. India has pledged to secure 1,000 commercial ships over the next decade as part of a national push to expand its shipbuilding industry and maritime sector, according to Rahul Kapoor, head of shipping and metal analytics at CERA. New Delhi is also promoting the development of integrated shipbuilding clusters -- industrial parks with state-of-the-art facilities and skill-development centers designed to stimulate innovation and productivity. India plans to create eight maritime clusters, comprising five new facilities and three expanded ones. Backed by state governments and with pre-secured land, these clusters will host activities ranging from manufacturing and equipment production to insurance and leasing services, Kapoor said. US-Israeli Conflict with Iran Essential Energy Intelligence for today's uncertainty. See What Matters > ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/crude-oil/051526-singapore-airlines-warns-full-impact-of-middle-east-fuel-shock-still-to-come</link><description>Singapore Airlines Group has warned that the full impact of the Middle East fuel shock will weigh on its earnings in the next financial year, as elevated jet fuel prices are billed on a delayed basis and broader macroeconomic conditions could affect demand amid a prolonged crisis. The remarks come even as SIA posted strong FY2025/26 results for the year ended March 31, when its fuel hedging</description><title>Singapore Airlines warns full impact of Middle East fuel shock still to come</title><pubDate>15 May 2026 09:46:46 GMT</pubDate><author><name>Mia Pei</name><name>Shu ling Lee</name></author><content><![CDATA[ Refined Products, Agriculture, Energy Transition, Jet Fuel, Biofuels, Renewables May 15, 2026 Singapore Airlines warns full impact of Middle East fuel shock still to come By Mia Pei and Shu ling Lee Editor: Alisdair Bowles Getting your Trinity Audio player ready... HIGHLIGHTS Jet fuel prices more than doubled in March Fare hikes not enough to offset rising fuel costs Group reiterates aim for 5% SAF adoption by 2030 Singapore Airlines Group has warned that the full impact of the Middle East fuel shock will weigh on its earnings in the next financial year, as elevated jet fuel prices are billed on a delayed basis and broader macroeconomic conditions could affect demand amid a prolonged crisis. The remarks come even as SIA posted strong FY2025/26 results for the year ended March 31, when its fuel hedging resulted in a S$218 million (US$170 million) gain in the second half of the year, compared with a S$13 million loss in the same period the year prior, according to exchange filings on May 14. Fuel costs stood at S$5.03 billion for the financial year, accounting for 27.7% of total annual expenditure. Jet fuel prices "have more than doubled since the conflict began," SIA said, noting that the impact was only partially reflected in March because of lagged fuel pricing mechanisms. "The full impact is expected to feed through in FY2026/27," it said. While the national air carrier of Singapore and its low-cost subsidiary, Scoot, have raised air fares across their network, the adjustments do not fully offset the rise in jet fuel prices, which is the group's single-largest expenditure item. "Depending on the duration and how the situation in the Middle East develops, there could be broader implications for supply chains and macroeconomic conditions affecting demand patterns," the group said. Platts, part of S&amp;P Global Energy, assessed the FOB Singapore jet fuel/kerosene cargo outright price at $151.92/barrel on May 14, down $7.88/b on the day, with healthier regional supply pressuring spot premiums lower. The benchmark averaged $200.42/b in April and $195.40/b in March, more than double pre-crisis levels of $89.03/b in February. SIA's comments echo analysts' warnings that fuel costs will materially compress margins next year, despite higher fares and resilient premium demand. Jason Sun, analyst at DBS group research, said in a note May 15 that despite Singapore jet fuel prices having stabilized at around $150-$160/b over the past few days, materially below the peak disruption levels where prices surged more than 100%, it still represents a 70% increase from pre-conflict levels. Sun noted that "price-sensitive regional markets" are likely to face margin pressure ahead, as yield resilience is tested amid the full impact of the fuel shock. "Air India also remains a significant drag, as its recovery continues to be constrained by higher exposure to the Middle East and weaker pricing power, amid ongoing operational and FX challenges," Sun said. SIA holds a 25.1% stake in Air India after the Indian national carrier merged with SIA's co-owned Vistara in 2024. Tata Group owns the remaining 74.9% of Air India. SIA noted in its filing that Air India faces headwinds, including industry-wide supply chain constraints, airspace restrictions, and operational constraints to its key Middle East markets, on top of high fuel costs. "Nonetheless, it continues to make progress in its fleet renewal... and improve its operational performance." SAF commitment In the results briefing, SIA reiterated its commitment to decarbonizing group operations, with sustainable aviation fuel "a key lever in the journey towards achieving net zero carbon emissions by 2050." It underscored the importance of diversifying SAF sources, as well as scaling global production and adoption. Both SIA and Scoot aim to source 5% of total fuel requirements from SAF by 2030. "Since 2024, we have purchased 2,000 tons of neat SAF from Neste and around 2,500 tons of CORSIA-eligible SAF (emissions reductions) from World Energy and SkyNRG," it said in a May 15 results briefing. "In February, SIA and Scoot -- together with CAAS, the Singapore Sustainable Aviation Fuel Company (SAFCo), and seven other companies -- signed an MOU to trial SAF purchases in Singapore," it noted. The trial SAF purchases have continued as planned despite the delay in Singapore's SAF levy. Platts-assessed SAF (HEFA-SPK) FOB Straits averaged $281.65/b in April, down from $289.06/b in March but up from $245.56/b in February. Capturing sustainable demand SIA also highlighted its ongoing moves to capture growth opportunities for the long term despite a challenging operating environment, including prompt adjustments to frequencies and capacity. A SIA official told Platts last month that the group has been increasing services even as some global airlines have been cutting capacity or trimming outlooks, including ad hoc supplementary services to London Heathrow and Frankfurt in Germany, and an additional three-times-weekly service to London Gatwick. The group is also capturing "more high-value, time-sensitive cargo" across key sectors such as healthcare and perishables, with tonnage up 26% in March 2026. In the last quarter of FY2025/26, cargo operations strengthened, with the load factor rising to 55.9% from 51.2% over the year. US-Israeli Conflict with Iran Essential Energy Intelligence for today's uncertainty. See What Matters > ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/energy-transition/051526-cbams-article-6-embrace-comes-with-strings-and-forms-attached</link><description>The European Commission&amp;apos;s draft rules on recognizing third-country carbon pricing under the bloc&amp;apos;s Carbon Border Adjustment Mechanism represent a pragmatic but tightly controlled opening that could accelerate investment in Article 6 of the Paris Agreement while creating new compliance challenges. The widely anticipated implementing regulation, published May 13 and open for consultation until June</description><title>CBAM&amp;apos;s Article 6 embrace comes with strings and forms attached</title><pubDate>15 May 2026 12:00:34 GMT</pubDate><author><name>Eklavya Gupte</name><name>Irina Breilean</name><name>Ben Carding</name></author><content><![CDATA[ Energy Transition, Carbon May 15, 2026 CBAM's Article 6 embrace comes with strings and forms attached By Eklavya Gupte, Irina Breilean, and Ben Carding Editor: Adithya Ram Getting your Trinity Audio player ready... HIGHLIGHTS Draft rules could spark investment in Article 6 trade Importers face mounting paperwork to claim carbon price cuts Article 6 credits capped at 10% of emissions The European Commission's draft rules on recognizing third-country carbon pricing under the bloc's Carbon Border Adjustment Mechanism represent a pragmatic but tightly controlled opening that could accelerate investment in Article 6 of the Paris Agreement while creating new compliance challenges. The widely anticipated implementing regulation, published May 13 and open for consultation until June 10, lays out detailed methodologies for how carbon prices paid abroad translate into reductions in CBAM certificate obligations. "It creates a real financial incentive to put a credible domestic carbon price in place," Adam Hearne, CEO at CarbonChain, told Platts, part of S&amp;P Global Energy. "Companies that already pay a carbon price, or buy qualifying credits, can lower their effective CBAM cost, making their goods more competitive in the EU market. This tilts the playing field towards countries that are building or linking carbon markets." Under the world's first carbon border tax mechanism, importers of carbon-intensive goods into the EU from six covered sectors -- aluminum, cement, electricity, fertilizers, iron and steel, and hydrogen -- are now liable for their emissions. Demand signals The draft's design is deliberately restrictive on international credits. Only carbon credits authorized under Articles 6.2 or 6.4 of the Paris Agreement would qualify for CBAM liability reductions, and their use would be capped at 10% of emissions covered under qualifying third-country carbon pricing mechanisms. This structure amounts to a "compliance-adjacent demand signal for authorization and tracking-ready units, potentially supporting investment in Article 6 market infrastructure," said Eszter Bencsik, voluntary carbon markets analyst at S&amp;P Global Energy Horizons. The EU's CBAM started its definitive phase on Jan. 1, 2026, but importers will only be able to purchase CBAM certificates starting in February 2027 to cover the emissions embedded in their imports for 2026, giving businesses more time to adapt to this carbon pricing mechanism. Dan Maleski, a senior environmental markets adviser and CBAM lead at Redshaw Advisors, believes the likelihood of international Article 6 credits being used under CBAM is likely to remain relatively limited. "The implementing act is very clear that any recognized carbon cost must be mandated and legally required, rather than the result of a voluntary purchase," Maleski told Platts. "In principle, this significantly limits the scope for international credits, as host countries would effectively need to forgo domestic revenue streams. Out of the 30-plus active emissions trading systems globally, only South Korea currently permits the use of international credits within its ETS, and even then under very strict limitations and conditions, Maleski added. The EU's CBAM works alongside the EU Emissions Trading System to prevent carbon leakage by imposing carbon pricing on imports as Brussels phases out free allowances for domestic producers. Carbon permits in Europe are currently almost eight times more expensive than compliance prices in China, the world's industrial powerhouse. Platts assessed EU Allowances for December 2026 at Eur75.04/mtCO2e ($87.39/mtCO2e) on May 14. This compares with China's compliance emission allowance, which was valued at Yuan 80.06/mtCO2e ($11.76/mtCO2e) on May 8, according to the Shanghai Environment and Energy Exchange. Compliance burden These rules, however, add a significant administrative burden for operators seeking to claim carbon price reductions, market participants cautioned. Operators will need to submit additional reports on carbon price reductions, on top of monitoring and verification plans and carbon accounting rules they already face, according to Pauline Miquel, policy and research lead at CBAM consultancy CBAMBOO. "This is a lot more work to be able to let an importer forecast their cost because all of this is the basis for the importer's cost modeling," Miquel said. "And without this, it's almost impossible for an EU importer to understand how much they're going to pay in CBAM liability." They will also need to calculate how the price paid translates into embedded emissions at the product level, she added. The lack of accredited verifiers presents a further hurdle. If operators choose to use verified emissions rather than default values, "it's going to make it very difficult to have all of this ready for 2027," Miquel said. But many believe the explicit recognition of Article 6 credits, even in limited form, demonstrates the EU wants to support the Paris Agreement's international carbon market mechanisms, with the 10% cap designed to prevent over-reliance on offsets and to push real domestic decarbonization. This could drive increased investment in third-country carbon pricing infrastructure, Article 6 credit supply, and verifier and accreditation services over the next 12-24 months, Hearne said. A US-based carbon market analyst said the proposal reflects a broader positive trend of the EU being more flexible and open to carbon credits and recognizing the positive effects of carbon projects, pointing to similar developments in the Corporate Sustainability Reporting Directive. Domestic vs international credits The proposal could also reinforce a price premium for credits that can be evidenced through UN-grade accounting, she added, while laying foundations for greater integration of Article 6-aligned credits into other carbon pricing frameworks. "International credits face the highest integrity gateway -- Article 6 authorization plus a quantitative cap -- while domestically issued credits, including those linked to mitigation abroad, could be recognized without an EU-level integrity screen or usage limit," Bencsik said. This bifurcation risks an uneven playing field, she noted. Exporters under regimes with permissive domestic crediting rules may be able to evidence a higher carbon price effectively paid, and therefore secure larger CBAM reductions, than peers reliant on internationally transferred units constrained by Article 6 rules. The proposal's practical impact will depend heavily on implementation details, especially administrative burden, certification and verification robustness, and interaction with rebates or other forms of compensation. A further dynamic to watch is pricing behavior in domestic credit markets. "Because domestic credits reduce CBAM obligations only insofar as they contribute to an evidenced carbon price effectively paid, some jurisdictions could face incentives to support higher domestic credit prices or tighter supply to retain compliance value domestically rather than see larger net financial outflows via CBAM certificate surrender," Bencsik added. US-Israeli Conflict with Iran Essential Energy Intelligence for today's uncertainty. See What Matters > ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/energy-transition/051526-japans-idemitsu-invests-in-us-carbon-removal-firm-crew</link><description>Japan&amp;apos;s Idemitsu Kosan has invested in US-based CREW Carbon through its corporate venture capital arm, the Japanese refiner said May 15, as the companies explore deploying carbon dioxide removal technology at wastewater treatment facilities globally. The collaboration will investigate using CREW&amp;apos;s Wastewater Alkalinity Enhancement technology at facilities in Japan and other Joint Crediting</description><title>Japan&amp;apos;s Idemitsu invests in US carbon removal firm CREW</title><pubDate>15 May 2026 05:14:47 GMT</pubDate><author><name>Ruchira Singh</name></author><content><![CDATA[ Energy Transition, Carbon, Emissions May 15, 2026 Japan's Idemitsu invests in US carbon removal firm CREW By Ruchira Singh Editor: Aastha Agnihotri Getting your Trinity Audio player ready... HIGHLIGHTS Wastewater Alkalinity Enhancement tech in plan CREW's wastewater tech creates carbon credits Japan's limestone aids CO2 sequestration plan Japan's Idemitsu Kosan has invested in US-based CREW Carbon through its corporate venture capital arm, the Japanese refiner said May 15, as the companies explore deploying carbon dioxide removal technology at wastewater treatment facilities globally. The collaboration will investigate using CREW's Wastewater Alkalinity Enhancement technology at facilities in Japan and other Joint Crediting Mechanism countries, Idemitsu said in a statement. "This investment allows Idemitsu to deepen their technical CDR expertise and commercial understanding of the carbon removal market," Idemitsu said. The WAE process prevents CO2 from entering the atmosphere, ensuring it remains in wastewater discharged from sewage plants, Idemitsu said. Additionally, CREW has a proprietary measuring, reporting and verification (MRV) system that calculates the net CO2 removed, enabling certified carbon credits that can be sold, it added. "Sequestering the CO2 in the wastewater removes the need for investment in carbon capture units, avoiding a large installation footprint," the company said. Net-zero at 2050 Idemitsu is evaluating business models that promote negative emissions and developing technologies that support achieving carbon neutrality in society by 2050, it said. To enable these targets, Idemitsu is making strategic investments in startups with advanced expertise and a track record in CDR and MRV, the company added. Achieving carbon neutrality targets will require a general reduction in CO2 emissions, but also reliable, transparent processes that remove CO2 from the atmosphere, it said. Japan is one of the world's leading producers of limestone used in the CREW process and provides an environment in which calcium carbonate required for CO2 sequestration in CREW's CDR solution can be economically sourced, it said. Platts, a part of S&amp;P Global Energy, assessed Pre-CEC Current Year carbon credits at $10/mtCO2e May 14, down 21.26% from a month ago. US-Israeli Conflict with Iran Essential Energy Intelligence for today's uncertainty. See What Matters > ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/energy-transition/051426-hormuz-crisis-exposes-structural-energy-flaw-pushes-electrification-case-etc</link><description>The closure of the Strait of Hormuz triggered a historic disruption to fossil fuel supplies, and should accelerate clean energy deployment, with governments and markets responding to disrupted oil and liquefied natural gas flows by fast-tracking renewable electricity, electric vehicles and heat pumps rather than locking in new fossil fuel infrastructure, the Energy Transitions Commission said in a</description><title>Hormuz crisis exposes structural energy flaw, pushes electrification case: ETC</title><pubDate>14 May 2026 23:10:12 GMT</pubDate><author><name>James Burgess</name></author><content><![CDATA[ Natural Gas, LNG, Crude Oil, Energy Transition, Renewables May 14, 2026 Hormuz crisis exposes structural energy flaw, pushes electrification case: ETC By James Burgess Editor: Giselle Rodriguez Getting your Trinity Audio player ready... HIGHLIGHTS ETC urges renewables over fossil lock-in Hormuz closure disrupts 18 million b/d oil flows 'Readily deployable' alternatives are key difference The closure of the Strait of Hormuz triggered a historic disruption to fossil fuel supplies, and should accelerate clean energy deployment, with governments and markets responding to disrupted oil and liquefied natural gas flows by fast-tracking renewable electricity, electric vehicles and heat pumps rather than locking in new fossil fuel infrastructure, the Energy Transitions Commission said in a report published May 15. The crisis has disrupted around 18 million b/d of oil supply and 20% of global LNG trade, or more than 110 Bcm/year, with 75% of the world's population living in fossil fuel-importing countries, the report said. If sustained, elevated prices could add $1 trillion-$2 trillion in annual energy costs globally, it said. "This is a reminder to governments -- both in Asia and in Europe -- that as long as we have fossil fuel-based economies, we are vulnerable to another political event," ETC co-chair Adair Turner told Platts, part of S&amp;P Global Energy, in an interview on May 15. "Four years ago, it was Russia-Ukraine. Now it's the Gulf. Who knows what the next one is." The ETC, a global coalition of leaders from across the energy landscape committed to achieving net-zero emissions by mid-century, said fossil fuel systems were "structurally vulnerable" because of their dependency on continuous extraction, trade and transport. "Supply is geographically concentrated and relies on a small number of critical transit routes, meaning that relatively localized disruptions can rapidly propagate into global economic shocks," it said. Renewable energy is inherently more secure, Turner said. "Clean energy systems are more distributed, more efficient and less exposed to the price shocks created by continuous dependence on traded fuels," he said. The ETS said stocks provided only a temporary buffer, were unevenly distributed and did not remove exposure to higher prices. As a result, governments should focus their efforts on boosting renewable deployment. "Accelerating the deployment of these technologies can reduce global oil demand by 20% and gas demand by more than 30% by 2035, insulating economies from the next shock," the report said. "Clean energy systems are more resilient because they change the physical and economic structure of energy supply," the report said, adding that decentralized energy supply alternatives were already available. "The key difference between this crisis and previous crises is the availability of readily deployable alternatives," the ETC said, contrasting the current price shock with the oil crisis of the 1970s. Chinese solar photovoltaic exports doubled in March 2026 compared with February, while 50 countries recorded all-time high solar import records, the report said. Electric vehicle registrations in the EU rose nearly 50% year over year in March, while EV searches in Australia surged 75%-80% in a single week and heat pump sales hit records in the UK, the ETC said. Around 70%-90% of clean energy costs are upfront capital, rather than fuel costs, it said. As such, while geopolitical disruptions can temporarily affect new projects, but not current energy consumption, it noted. "Faced with the latest fossil fuel supply crisis, governments, policymakers and businesses should accelerate the shift towards the more resilient and secure energy systems that clean technologies can deliver, while managing short-term distributional impacts and supply risks," it said. "The market is already signaling the answer," the ETC said. "Policy must not contradict it." Policy priorities Policy priorities should include accelerating renewable power deployment, electrifying road transport, heating and cooking, developing green fuels and fertilizers and improving energy efficiency across all sectors, it said. The group said oil and gas fields typically take 5-10 years to reach production. By contrast, rooftop solar and heat pumps can scale within months, while electric vehicles were already structurally reducing oil demand, it said. Alongside these measures, the ETC recommended the careful management of targeted fossil fuel subsidies, acknowledging that there could be a short-term increase in fuels such as coal to bridge the supply crunch, particularly in Asia. Such use should be time-limited and not come from new capacity, it said. New LNG commitments should be made only with robust methane standards and short-term contracts. In the EU, it said the Emissions Trading System structure should be reformed but not weakened, to preserve carbon pricing credibility. Platts, part of S&amp;P Global Energy, assessed nearest December EU ETS carbon allowances at Eur75.04/mt ($87.23/mt) on May 14. Meanwhile, the ETC warned against blanket fossil fuel subsidies, large-scale new upstream oil and gas or the weakening of 2030 and 2050 climate targets. "New fossil infrastructure now would lock in the next shock," the ETC said in a statement accompanying the report. Previous crises offered a stark warning that short-term fossil fuel subsidies were a "sticking plaster" rather than a long-term solution. "The 2026 Iran crisis is not an isolated event, but a clear manifestation of a structural vulnerability in the global energy system," it said. US-Israeli Conflict with Iran Essential Energy Intelligence for today's uncertainty. See What Matters > ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/energy-transition/051126-kawasaki-mb-energy-daimler-truck-sign-up-for-liquid-hydrogen-supply-chain-in-europe</link><description>Kawasaki Heavy Industries, MB Energy and Daimler Truck have signed a joint development agreement to establish a liquid hydrogen supply chain to Europe via the Port of Hamburg, targeting commercial operation by the early 2030s, the companies said May 11. The agreement, which expands upon an existing memorandum of understanding for a Japan-Germany hydrogen supply chain, will leverage the companies&amp;apos;</description><title>Kawasaki, MB Energy, Daimler Truck sign up for liquid hydrogen supply chain in Europe</title><pubDate>11 May 2026 11:52:44 GMT</pubDate><author><name>Ruchira Singh</name></author><content><![CDATA[ Energy Transition, Hydrogen May 11, 2026 Kawasaki, MB Energy, Daimler Truck sign up for liquid hydrogen supply chain in Europe By Ruchira Singh Editor: Ankit Ajmera Getting your Trinity Audio player ready... HIGHLIGHTS Hamburg to serve as Europe's gateway 100 fuel cell trucks to operate by 2026 Kawasaki building liquid hydrogen carriers Kawasaki Heavy Industries, MB Energy and Daimler Truck have signed a joint development agreement to establish a liquid hydrogen supply chain to Europe via the Port of Hamburg, targeting commercial operation by the early 2030s, the companies said May 11. The agreement, which expands upon an existing memorandum of understanding for a Japan-Germany hydrogen supply chain, will leverage the companies' expertise to assess the economic viability of a liquid hydrogen supply chain, according to the statement. "By bringing our liquefied hydrogen technologies to Europe, we aim to support industrial and heavy-duty vehicle demand and help establish a scalable international hydrogen corridor," said Kei Nomura, executive officer and general manager, hydrogen strategy division at Kawasaki. Kawasaki specializes in the design and manufacture of essential infrastructure, including hydrogen liquefiers, liquid hydrogen storage tanks and liquid hydrogen carrier ships, which it will utilize for this initiative, according to the statement. The collaboration aims to establish transportation routes from potential hydrogen-producing countries to Germany and, in doing so, promote the use of hydrogen across European industries, beginning with Daimler Truck's zero-emission vehicles. Daimler Truck plans to introduce 100 liquid hydrogen-powered fuel cell trucks into customer operations by the end of 2026, with series production slated for the early 2030s, according to the statement. Volker Ebeling, senior vice president, new energy, storage and infrastructure at MB Energy, said Hamburg is ideally positioned to become Germany's main gateway. "We are combining MB Energy's infrastructure, our service station network and our trading expertise with Daimler Truck's next-generation hydrogen truck developments and Kawasaki's pioneering hydrogen storage and shipping technologies," Ebeling said. In January, Kawasaki and Japan Suiso Energy signed a contract to build a 40,000-cubic-meter liquid hydrogen carrier, marking a move toward establishing a commercial-scale hydrogen supply chain. Platts, part of S&amp;P Global Energy, assessed the India renewable hydrogen term contract at $3.23/kg on May 7, up 0.6% month over month. US-Israeli Conflict with Iran Essential Energy Intelligence for today's uncertainty. See What Matters > ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/energy-transition/051326-australia-shortlists-renewable-hydrogen-projects-for-funding-amid-budget-cuts</link><description>The Australian Renewable Energy Agency has shortlisted seven renewable hydrogen projects for the second round of the Hydrogen Headstart program, according to a May 13 announcement, a day after spending cuts to the flagship initiative. ARENA has invited the projects to submit full applications for funding from the program, which received a revised allocation of A$1 billion ($660 million) in the</description><title>Australia shortlists renewable hydrogen projects for funding amid budget cuts</title><pubDate>13 May 2026 06:44:53 GMT</pubDate><author><name>Ruchira Singh</name></author><content><![CDATA[ Fertilizers, Chemicals, Energy Transition, Renewables, Hydrogen May 13, 2026 Australia shortlists renewable hydrogen projects for funding amid budget cuts By Ruchira Singh Editor: Surbhi Prasad Getting your Trinity Audio player ready... HIGHLIGHTS Australia shortlists seven hydrogen projects Projects span 120-750 MW electrolysis capacity Program allocates A$1B in production credits The Australian Renewable Energy Agency has shortlisted seven renewable hydrogen projects for the second round of the Hydrogen Headstart program, according to a May 13 announcement, a day after spending cuts to the flagship initiative. ARENA has invited the projects to submit full applications for funding from the program, which received a revised allocation of A$1 billion ($660 million) in the 2026-27 (July-June) federal budget announced on May 12, ARENA said. "Renewable hydrogen is a complex, capital-intensive industry and progress takes time, but it is a critical enabler of industrial decarbonisation, particularly for hard-to-abate sectors," ARENA CEO Darren Miller said. "What we're seeing are expressions of interest that are considered and well aligned to future market demand." The shortlisted projects include Bell Bay Powerfuels, a 300 MW project in Tasmania; South East Queensland Power-to-X Project, a 150 MW project in Queensland; and Portland Renewable Fuels Project, a 220 MW project in Victoria, according to the announcement. The renewable hydrogen end-use for the projects are methanol, sustainable aviation fuel, ammonia, urea and alumina, according to the government agency. Australia reprioritized funding support for clean energy in the budget May 12, halving spending for Hydrogen Headstart, in a year wracked by energy shocks and cost-of-living increases. Builds on existing support Announced in the 2023-24 budget, Hydrogen Headstart aims to catalyze Australia's hydrogen industry to become a global leader in the emerging global trade for clean fuels, according to ARENA. "Renewable hydrogen presents Australia with a significant economic and decarbonization opportunity," Miller said. "Its potential to develop low-emission fuels for aviation and shipping, as well as key inputs for fertiliser could also help improve the nation's energy resilience in the longer term." Round 2 of Hydrogen Headstart builds on ARENA's support for renewable hydrogen, with the Agency having already committed over A$1.2 billion to two projects in Round 1 and over A$396 million to 68 renewable hydrogen projects since 2017 through other funding programs. Hydrogen Headstart's first round concluded last year, awarding A$1.2 billion to Orica's 50 MW Hunter Valley Hydrogen Hub and to Copenhagen Infrastructure Partners' 1,500 MW Murchison Green Hydrogen Project. Under Hydrogen Headstart, projects seeking to produce renewable hydrogen or its derivatives can apply for a production credit delivered over 10 years to bridge the commercial gap between the cost of producing renewable hydrogen and market prices, it said. Shortlisted applicants now have until early September to submit their full applications, it said. Following the assessment phase, a recommendation will be made to Chris Bowen, Minister for Climate Change and Energy, for approval of which projects will receive support. Platts, a part of S&amp;P Global Energy, assessed Australia renewable-derived ammonia delivered into Far East Asia, with high-capacity factors at $760.77/mt May 11, up 0.76% from a month ago. ARENA's shortlisted projects for A$1 billion Hydrogen Headstart program: Applicant Project title Electrolysis facility size (MW) State Hydrogen end use Bell BayPowerfuelsPty Ltd Bell BayPowerfuels 300 Tasmania Methanol EuropeanEnergyAustralia Pty Ltd South East Queensland Power-to-X Project 150 Queensland Methanol HAMR Energy Pty Ltd Portland Renewable Fuels Project 220 Victoria Methanoland SAF HIF Asia Pacific Pty Ltd HIF Tasmania e-Fuel Facility 140 Tasmania Methanol Murchison Hydrogen Renewables Pty Ltd Murchison Green Hydrogen Project Stage 1B 500 Western Australia Ammonia PerdamanCommercial Developments Pty Ltd Perdaman Helios (Karratha): Decarbonising Fertilisers 750 Western Australia Urea Summit Hydro Pty Ltd Gladstone Green Hydrogen Project 120 Queensland Alumina Source: ARENA US-Israeli Conflict with Iran Essential Energy Intelligence for today's uncertainty. See What Matters > ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/crude-oil/060324-interactive-platts-global-bunker-fuel-cost-calculator</link><description>The Platts global bunker fuel cost calculator shows how Platts price assessments for methanol, ammonia, LNG, bioblends and conventional oil-based fuels can be used to calculate the cost of marine fuels around the world, taking into account the EU Emissions Trading System and adjusted for energy density to put them on an equal footing.</description><title>Interactive: Platts global bunker fuel cost calculator</title><pubDate>14 May 2026 13:30:00 GMT</pubDate><author><name>Max Lin</name><name>Rowan Staden-Coats</name><name>Abhishek Anupam</name><name>Sophie Byron</name><name>Esther Ng</name><name>Megan Gildea</name><name>Santiago Canel Soria</name></author><content><![CDATA[ May 14, 2026 INTERACTIVE: Platts global bunker fuel cost calculator By Max Lin, Rowan Staden-Coats, Abhishek Anupam, Sophie Byron, Esther Ng, Megan Gildea, and Santiago Canel Soria Getting your Trinity Audio player ready... (Latest update May 14, 2026) The Platts global bunker fuel cost calculator shows how Platts price assessments for methanol, ammonia, LNG, bioblends and conventional oil-based fuels can be used to calculate the cost of marine fuels around the world, taking into account the EU Emissions Trading System and adjusted for energy density to put them on an equal footing. Click here to explore in full-screen mode. Methanol blend Shipping firms are struggling to acquire sustainable methanol due to its scarcity, and some industry participants suggest blending the green fuel with existing gray methanol could alleviate the shortage for now. The Platts sustainable-gray methanol price slider uses the month average prices of delivered sustainable methanol bunker and FOB gray methanol in the US Gulf plus logistics cost to show a representation of the blended price of marine methanol. Biofuel blend Bioblends are emerging as the top choice as an alternative marine fuel for conventional ships as regulators introduce new rules to lower greenhouse gas emissions from shipping. The Platts UCOME-VLSFO price slider uses the month average prices of FOB Straits used cooking oil methyl ester plus logistics cost and delivered 0.5%S marine fuel oil to show a representation of the blended price of biobunker fuels. LNG blend LNG, with its accessibility and competitive pricing, has long been the most used alternative marine energy for shipowners willing to invest in alternative propulsion technology. A growing number of companies operating LNG-capable ships are introducing bio-LNG into their bunker mix for deep decarbonization, and market participants suggest the more expensive green fuel could be blended with fossil LNG -- possibly through mass balance -- for lower fuel expenses. The Platts bio-gray LNG bunker price slider uses monthly average delivered bunker prices of bio- and fossil LNG in Rotterdam to show a representation of the blended price of marine LNG. Further reading: INTERVIEW: Ammoniaâs share may be 40% of global bunker fuel demand by 2050--Amogy CEO INTERVIEW: Japan's MOL sees Southeast Asia as long-term growth engine ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/120121-gas-rally-to-have-enduring-effect-on-european-power-beyond-near-term-platts-analytics</link><description>European power prices are forecast to ease from current record levels starting in 2023, but the current rally in gas will have enduring effects on the forward curve, according to S&amp;amp;P Global Platts Ana</description><title>Gas rally to have &amp;apos;enduring effect&amp;apos; on European power beyond near term: Platts Analytics</title><pubDate>01 December 2021 09:58:00 GMT</pubDate><author><name>Andreas Franke</name></author><content><![CDATA[ 01 Dec 2021 | 09:58 UTC Gas rally to have 'enduring effect' on European power beyond near term: Platts Analytics By Andreas Franke Highlights Prices to ease from 2023, but remain elevated Germany swings to imports, Great Britain to exports Italy moves to top, Spain becomes discount market European power prices are forecast to ease from current record levels starting in 2023, but the current rally in gas will have "enduring effects" on the forward curve, according to S&amp;P Global Platts Analytics. Its latest five-year forecast sees annual power prices dropping from average levels above Eur100/MWh in 2021 and 2022 to around Eur80/MWh for 2023-24 and down to around Eur60/MWh by 2026-27. For Germany, the five-year forecast average is now double compared to actual average prices over 2016-2020. "The gas-driven surge in power prices in recent months is likely to have enduring effects beyond the near-term," Platts Analytics head of European power analysis Glenn Rickson said. By 2023, the current elevated price situation will have mostly dissipated as gas storage stocks normalize and renewable penetration continues, Rickson said. "Closures of coal and nuclear capacity, particularly in Germany, add support to prices over the next two years and also increase power prices' sensitivity to gas prices and vice versa," he said. From a policy perspective, much of the noise is around accelerating decarbonization and limiting exposure to gas, while from an investment perspective, Platts Analytics expects greater appetite for low carbon flexibility, including storage, the report said. Wind to top mix from 2025 Great Britain is projected to lose its place as Europe's premium market to Italy thanks to offshore wind development and a narrowing in its carbon premium, the report said. Spain will become Europe's discount market on an annualized average basis from 2023, it said. Europe's biggest power market Germany, meanwhile, is forecast to swing to net imports by 2023. German gas-fired generation is forecast to rise above coal and lignite by 2025 for the first time ever. Across Europe, gas generation is set to dip from 2019's peak until 2023 before recovering to 2021 levels by 2027. Nuclear is forecast to fall almost 25% below 2021 levels by 2027 despite the start-up of Hinkley Point C. Wind capacity is forecast to grow by roughly 100 GW to 263 GW by 2027, with wind set to top the generation for the 10 markets from 2025 assuming average weather. Gains for offshore wind capacity will help swing Great Britain from net imports to a net export position. Finally, solar capacity across the 10 markets is forecast to almost double to 276 GW by the end of 2027. Platts Analytics' European power model incorporates 10 markets: Germany, France, Great Britain, Italy, Spain, Portugal, Belgium, Netherlands, Switzerland and Austria. Editor: Jonathan Fox ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/podcasts/oil-markets/012921-asia-cold-spell-fuel-oil-crude-lng-demand</link><description>This episode examines the impact of a cold spell in Asia on fuel oil, crude, and LNG demand, highlighting market responses. Learn more.</description><title>Cold spell drives oil resurgence in Asia&amp;apos;s power sector</title><pubDate>29 January 2021 12:55:00 GMT</pubDate><author><name>Eric Yep</name><name>Andre Lambine</name><name>Takeo Kumagai</name><name>Rajesh Nair</name></author><content><![CDATA[ 29 Jan 2021 | 12:55 UTC Listen: Cold spell drives oil resurgence in Asia's power sector Featuring Eric Yep, Andre Lambine, Takeo Kumagai, and Rajesh Nair The last few weeks saw temperatures in many parts of North Asia drop to record lows, and energy prices hit record highs. Platts JKM, the benchmark for Asian spot LNG prices, surged to $32.50/MMBtu, the highest since it was launched in early 2009. LNG freight rates hit unprecedented levels of nearly $300,000/day, trucked LNG in China rose to around $28/MMBtu, Japan's spot electricity prices hit 220 Yen/kWh, and the Platts Northeast Asian Thermal coal price hit $80/mt. The ripple effect was felt across a variety of power generation fuels and across the whole region as supply chains were disrupted. Utilities found themselves having to shift back to fuels that have been becoming rather obsolete in the region's power mix. S&amp;P Global Platts Senior Analyst Andre Lambine, Senior Editor Takeo Kumagai, and Managing Editor Rajesh Nair join Content Lead Eric Yep to delve deep in to the latest in Asia's oil and power sectors. Also available on: Spotify and Apple Podcasts View Full Transcript Cold spell drives oil resurgence in Asia's power sector ERIC YEP: Temperatures in many parts of North Asia dropped to record lows this winter. This meant higher demand for heating fuels, power shortages, and emergency fuel procurement by governments and utilities. Several energy benchmarks, including the Platts JKM benchmark for Asian spot LNG, hit record levels. The ripple effect was felt across a variety of power generation fuels and across the whole region as supply chains were disrupted. This meant that utilities had to shift to a fuel that has been becoming rather obsolete in the power sector in many countries, fuel oil and even direct burning of crude oil. The worst of the winter seasons likely over but utilities, fuel importers, and government regulators are still assessing the aftermath of the energy crisis. Hello and welcome to the S&amp;P Global Platts Oil Market Podcast - Asia edition. I'm Eric Yep, content lead for generation fuels in Asia. And today I'm joined by Platts experts to examine the recent surge in Asia's energy demand and its impact on oil. So to discuss in more detail, we have Andre Lambine, senior analyst with S&amp;P Global Data Analytics, Takeo Kumagai, senior editor with the oil news team, and Rajesh Nair, managing editor for Asia residual fuels. Thanks for joining this podcast, gentlemen. So Andre, let's start with you. Could you give us a sense of how the power situation changed in Asia? And what led to the energy shortages in the region? (01:33) ANDRE LAMBINE: Yeah. Thank you, Eric. Yes, there's a number of factors that contributed to the situation. So first of all, like you mentioned, it got cold, like really cold, in Northeast Asia, so the demand for heating and electricity increased. So all countries including China, Japan and South Korea, they needed more thermal fuels than earlier expected. This was especially important for demand for LNG, which fuels a large portion of the power markets in Japan and South Korea, while in China, it actually tends to go more into industry. But the higher regional demand for LNG imports came at a time when there were supply disruptions in the global LNG market in places like Qatar and Australia. And there were also shipping constraints through the Panama Canal impacting LNG produced in America. It was also cold in other places such as Europe, so demand was higher also there. So all these caused the Asian spot price of LNG to reach new all time highs. As the Asian markets struggled to obtain enough LNG, the higher demand for electricity also filtered through to the coal and oil markets. And what worsened the situation this winter was somewhat lower than normal inventories, which made companies rely on spot buying to a perhaps greater extent than normal. (02:48) ERIC YEP: Could you take us through how oil fits into the power mix in Asia? And what were the reasons that we saw something like gas-to-oil switching taking place? (03:00) ANDRE LAMBINE: Great questions. Oil is a relatively small part of the power mix in most Asian countries. For places in Northeast Asia like Japan, South Korea and Taiwan, it is usually around 1% or 2% of the power mix; while it is higher in parts of South Asia with about 3% for Pakistan and up to 15% for Bangladesh. However, typically, even if oil is not a large percentage of the power mix, it's an important part of the overall picture. Often oil is relatively expensive for use in power generation so it is used to help cover peak demand periods and is also used in places without good grid connectivity such as remote islands. Now, gas-to-oil switching is taking place because spot LNG has become more expensive than fuel oil and other oil products that can be used for power generation. Most LNG is imported on long term contracts, but buyers tend to top up with some additional spot LNG when needed. But not all LNG importing countries can switch from gas to oil-fired power generation because they do not have the sufficient unused oil-fired power plant capacity. So for example, South Korea only has about 2 GW of oil capacity, and some of that is usually already in use during winter so the upside is limited. However, many other countries have available oil-fired power plant capacities such as Japan and several countries in both ASEAN and South Asia. And there perhaps especially interesting is Bangladesh and Pakistan because the timing of the situation comes at a time or the year when these countries typically see lower power demands. This is due to lower need for cooling. So there is quite a lot of unused oil-fired power plant capacity available. (04:46) ERIC YEP: Hold that thought on Pakistan and Bangladesh. We will get back to you on that shortly. Let's go over to our Tokyo correspondent Takeo Kumagai, who is right in the thick of things in the middle of winter. And I hope Takeo that you you're not snowed in right now. But can you take us through Japan's power demand and how it has resulted in fuel switching towards oil? And how has the situation played out on your end? (05:14) TAKEO KUMAGAI: Sure, Eric-san. It's been a cold winter here, and we have seen an uptick in crude and fuel oil demand in Japan as some local power utilities rush to procure more oil to meet the upsurge in power demand from severe cold spells. Japanese refiners did respond to an emergency request from the power utilities to supply more direct burning crude and fuel oil in January, according to the head of Petroleum Association with Japan on January 21. Tsutomu Sugimori, however, said the refiners do not plan to increase their direct burning crude or fuel oil supply in February and March, during when the demand will still be in the midst of the winter demand season. Sugimori's remarks underlined Japanese refiners' difficulty to increase their fuel oil output at a time when they face strong kerosene demand for heating, which is also as a result of cold spells. And there is a shortage of coastal vessels for fuel transport in Japan, after seeing lackluster oil demand for power in recent years. Japan's largest refiner ENEOS also told us recently that it has seen its fuel oil demand far exceeding the planned supply volumes and the company would have to prioritize supplying to power utilities holding supply contracts because of supply constraints and tight vessel availabilities. Japan's immediate power demand, however, peaked on January 8, and electricity demand in the first half of January jumped by about 10% from a year ago, according to the Ministry of Economy, Trade and Industry. In line with the easing of power demand, Japan's oil-fired power plant run rates fell to around 25% as of January 17, down from around 64% on January 12, according to METI, after having peaked at just about 88% on January 8. (07:30) ERIC YEP: Very interesting how the demand situation is shaping up over there. Isn't it true that Japanese power utilities have been at the forefront of dialing back on oil-fired capacity per se over the last few years? Do you see the utilities procuring more crude and fuel oil in the coming weeks as well? (07:52) TAKEO KUMAGAI: Japanese power utilities have been mothballing their oil-fired capacities as they have shifted to gas-fired power generation in recent years. Despite the increased demand for power, Japan's JERA and Kyushu Electric, for example, did not have any immediate plans to restart the oil-fired units from their complete long-term planned shutdowns. However, we are hearing that some of Japanese by utilities such as Chugoku Electric and Shikoku Eelectric are working to procure more fuel oil from Japan and abroad, while Kansai Electric is working to procure crude oil from abroad, in addition to its domestic fuel oil procurements. Japanese power utilities used to take heavy sweet Indonesian crude, such as Minas, Cinta, and Dury for power generation. We heard that there has been a sharp increase in sport heavy sweet crude purchase inquiries from Japanese power utilities around Southeast Asia recently. However, we also heard that Japanese utilities will likely struggle to find any heavy sweet crude cargoes available for second half of January shipments in Southeast Asia. And we're better off for looking for fuel oil cargoes from Singapore for prompt imports. Now the focus is about how much more fuel and crude oil will be procured by Japanese by utilities by March in order to meet the winter demand. (09:34) ERIC YEP: Thank you. So we hope to be on top of the situation as it develops over the next few weeks and wishing you warm weather over there very soon. Let's move over to Rajesh, our resident guru on fuel oil markets. Rajesh, can you take us through how the increase in power demand has impacted fuel oil markets? And is there enough fuel oil available in the system from refiners and traders and storage to meet this increase in winter demand? (10:05) RAJESH NAIR: Hi Eric, for sure. Not so much a guru though. But first of all, the start of the year has traditionally always been good from a demand perspective for the Asian fuel oil markets, in that typically both buyers and sellers are usually looking to pile on product after destocking for the financial year end in December. Now incremental demand for low sulfur material from the utility sector, especially for markets that have traditionally relied instead on cleaner burning fuels like LNG, has prompted LSFO suppliers in Singapore, especially, to sit up and plan balances in January in a way that they haven't had to for most of last year when availability was ample. Incremental demand has in fact not only been limited to low sulfur fuel oil, but also for medium to high sulfur fuel oil from regional markets like Pakistan, Bangladesh, Sri Lanka, Philippines, and for this time of the year, also from the Middle East, especially Kuwait, as the state-owned KPC's Mina Abdullah refinery, which normally supplies product to meet domestic demand undergoes upgradation works. This so-called double whammy of demand from the regional utility market and from sellers looking to restock after running down inventories in December has somewhat tilted the demand-supply balances. Market sources estimate Western arbitrage fuel oil volume of just over 2 million metric tons to arrive in Singapore for January, down about 500,000 to 600,000 metric tons from what we saw coming in for December. No surprise then that Singapore's commercial onshore residue stocks have edged down for two consecutive weeks to 22 million barrels in the week ended January 20. And according to traders, stock held on floaters off Singapore waters is also being drawn down. So the overall market sentiment is bullish. No doubt, reflecting this sentiment, the Singapore Marine Fuels 0.5% Sulfur cargo markets premium to the Mean of Platts Singapore Marine Fuels 0.5% Sulfur assessment has hit a near 11-month high of $4.7/mt on January 21. Also the market structure, which is generally an indication of market sentiment, in the case of Singapore Marine Fuel 0.5% Sulfur swaps curve, the prompt-month market structure is currently trading at a near one-year high. So that sort of explains the overarching upbeat sentiment that's in the market at the moment, Eric. (12:41) ERIC YEP: Thanks, Rajesh. Can I check with you how other consumers of fuel oil are coping with the situation especially the marine and bunker fuel market here in Singapore and also other parts of Asia that rely very heavily on fuel oil for marine fuel? (13:02) RAJESH NAIR: Yeah of course, Eric. As I mentioned just now, January has witnessed a double whammy of sorts in terms of demand. Typically it's at the start of the year that you know, people would start looking at restocking and that's not only on the supply side, it is the case for the buyers as well. And this also coincided with the cold snap, which led countries like Japan, which hasn't traditionally relied on oil for a number of years now, to start looking at oil to meet its utility demand. Now, this is also coinciding with demand for bunkering. Let me explain. The mainstay demand center for fuel oil is the marine fuel market and will continue to be that. And as I said, the beginning of the year is traditionally good in terms of demand. We have seen steady demand from the end-user marine fuels market in January. In terms of the spot market demand though, on the whole so far this month, the demand has not been particularly fantastic and that's essentially on account of a surge in the flat price, which, as we speak, is at almost a one-year high. But that said, demand is still said to be robust, especially from buyers that have inked contracts for January supply. Now, aside of that, even for bunker markets from within the region, we have seen steady demand for product to be shipped out of Singapore to meet regional bunkering demand, especially South Korea, for instance, which is usually a balanced market, if not long, in terms of their domestic bunker demand. At least two out of the four refiners, as we know it, have been importing fuel oil from Singapore to meet their domestic bunker demand and even more so, because the refiners had cut run rates owing to poor middle distillate margins. We are also seeing a steady demand to supply product to bunker markets, like Hong Kong and also high sulfur fuel oil into China. So overall, the market sentiment is that of optimism. A surge in flat price, however, has meant that some of the sellers have been able to make determined offers in a bid to attract buying interest within the spot market itself. This has in turn led spot market differentials for Singapore low sulfur marine fuel to be rather range-bound, trading in the low to mid teen levels so far this month. But that said, looking forward, what we see is that the Singapore ex-wharf contracts for Marine Fuel 0.5% bunker supply for February-loading is currently being discussed at a premium of anywhere between $5 to $6/mt, up from around $2, $2.50 at which these contracts were inked for January supply. So yeah, on the end-user side, too the market sentiment looks generally upbeat. (15:52) ERIC YEP: Great overview, Rajesh. Thanks a lot. Let's sail over to South Asia. We can't fly in the current pandemic. Andre, take us through some of the fuel switching market fundamentals in South Asia and how is the situation playing out in Bangladesh and Pakistan? How do you see the power situation there shaping up? (16:14) ANDRE LAMBINE: So you know, to me, Bangladesh is a key lead indicator for gas-to-oil switching in Asia. And that's due to really good data availability, and also the composition of the power mix and a power plant capacities that leave room for oil. So what we have seen so far in January is that power demand has been higher. But the grid-connected generation of gas-fired power plants actually fell by about 1.5 GW on average year on year. At the same time, oil-fired power generation increased with the same amount so oil increased on the expense of gas. Bangladesh has had problems obtaining bids for recent spot tender for LNG and is likely short on gas, and we assume Pakistan is in a similar situation. So all these countries can do switching. Now oil-fired power plant capacity in Bangladesh is about 7 GW, and Pakistan has around 8 GW. While we do not think these countries will fully utilize the existing oil capacity, we assume switching to oil-fire power generation could reach a combined 4 GW for January, and this could go even higher in February. Existing long-term supply contracts for LNG usually come with little flexibility, so this could limit the switching. Some switching could also take place in March, but this situation is not as clear cut as for January and February. It will come down to power plant efficiencies and the margin will just not be as high as what we see for February. In general, power demand is likely to stay around normal for this time of year as the weather forecast has come down to normal levels for the next couple of weeks. (17:52) ERIC YEP: Thanks, Andre. Rajesh can I dial back to you know about this whole theme of oil-fired power generation capacity and the way it is being phased out over the last few years? Even here in Singapore we don't really burn oil for power generation anymore, although it's still happening in a lot of countries. Do you see the recent events this winter forcing a rethink among either refiners or fuel suppliers on fuel switching? And does fuel oil still have a future in Asia's power mix? (18:26) RAJESH NAIR: That's a very interesting question. One thing that the market might sort of want to do going forward, especially taking into consideration what is currently going on at the moment, is to perhaps better plan their balances going forward, especially when we are talking about going into peak winter season demand. As you rightly said, especially countries like Japan, which used to back in the day be a fair demand center for low sulfur fuel oil has completely switched to cleaner burning fuels. This year around it sort of was a bit of a jolt, so to speak, in terms of demand that arose from markets like Japan, and even for that matter, Korea, which, you know, we've seen at least three cargoes if not more, for utilities going into Korea so far this year. So this is all essentially incremental demand that we saw and very unlike what we would see, especially this part of the year. But that said, to answer your question, in terms of the fuel oil as a burning fuel within the burning mix, and as Andre sort of pointed, there is more than a handful of countries within this region which needs to up its power generation capacity. And as that capacity goes up, even as there is more reliance on cleaner burning fuels, we do see an opportunity for fuel oil to find that incremental demand going forward. And as such, even now when we talk about fuel oil demand into the utilities market, we're seeing pockets of demand which depending on the demand supply balances then can be rather strong positive for the market. Talking about markets like Pakistan and Bangladesh, you know, from where we've seen fairly steady demand for fuel oil, even Sri Lanka or even Philippines, the one giant demand center that I have so far missed out on talking about is, of course Saudi. Peak summer season utility demand for Saudi is estimated to be a little over 3 million mt a month and that is significant. And that is only the utility demand that we're talking about. Then, of course, we also have demand for industrial applications. Again, if you're talking about Saudi Arabia, there is a fair amount of fuel oil that goes into the desalination plants. So it doesn't look like at all that fuel oil as a burning fuel is going to be completely phased out anytime in the near or foreseeable future, Eric. (20:48) ERIC YEP: That was a fantastic overview, Rajesh. Thank you very much. I guess this whole situation highlights how critical the whole energy transition conversation in Asia is at the moment and how carefully both governments and companies would have to evaluate their dependence on individual fuels. It also highlights how the conversation around carbon emissions from fossil fuel burning can evolve over the next few years, especially if countries have to consider critical demand seasons, like winter, for instance. That is all that we have for today's podcast. Thank you very much for joining us. And thank you very much, Andre, Takeo and Rajesh for your insights. ]]></content></item><item><link>https://www.spglobal.com/market-intelligence/en/news-insights/research/european-energy-insights-october-2021</link><description>European Energy Insights October 2021 covers energy market trends, pricing dynamics, and regional supply-demand conditions.</description><title>European Energy Insights October 2021</title><pubDate>10 November 2021 18:30:00 GMT</pubDate><content><![CDATA[ Blog â 11 Nov, 2021 European Energy Insights October 2021 Here you will find a collection of this monthâs top European energy insights. Want to stay informed? Subscribe to receive our monthly insights directly to your inbox > Learn more about Market Intelligence Request Demo ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/coal/032321-australia-flooding-tightens-regional-thermal-coal-supply-supports-prices</link><description>Flooding in eastern Australia tightens thermal coal supply, bolstering prices as mining operations and supply chains face significant disruptions.</description><title>Australia flooding tightens regional thermal coal supply, supports prices</title><pubDate>23 March 2021 11:46:00 GMT</pubDate><author><name>Neka Liau</name><name>Jessie Li</name><name>Weng Yi-Le</name><name>Carina Li and Eric Yep</name></author><content><![CDATA[ 23 Mar 2021 | 11:46 UTC â Singapore Australia flooding tightens regional thermal coal supply, supports prices By Neka Liau, Jessie Li, Weng Yi-Le, and Carina Li and Eric Yep Highlights Thermal coal exports affected by disruption to deliveries, shipments Spot coal prices to jump on supply disruptions, Platts Analytics says Met coal participants wary of weather developments in Queensland Singapore â Asian thermal coal supply is expected to tighten due to the floods in eastern Australia that have disrupted rail freight, impacted loading operations and are likely to delay shipments in the coming days as weather conditions worsen, but the impact on metallurgical coal operations has so far been limited, according to analysts and sources. Tighter supply from the Port of Newcastle is supportive for thermal coal prices, and comes just ahead of India's usual strongest demand period over April and May, when buyers restock for the monsoon season, which usually runs from May to September. Other importers exposed to extreme Australian weather include South Korean utilities, which have already expressed buying interest in Indonesian coal following recent closures of nuclear reactors in the country, according to sources. They might be forced to look further afield to alternatives like Russian high calorific value coal. Chinese power utilities are not expected to have major requirements for coal, although some bullish sentiment has been noted from downstream consumers, sources said, while Japan has ample renewables electricity generation and generation fuel inventories coming out of the peak winter season, reducing its need for thermal coal. Spot coal prices to jump "The port of Newcastle handles around 70% of Australia's thermal coal exports, and around 15% of its met coal exports. The wet weather is expected to continue until March 24, and it could be the end of March before all railings to port return to normal," Matthew Boyle, S&amp;P Global Platts Analytics' lead analyst for Global Coal &amp; Dry Bulk Freight, said. Boyle said however that the Australian thermal coal export forecast for 2021 of 199 million mt had not been adjusted due to the floods or issues with coal shiploaders at the NCIG terminal, and coal stocks at ports were adequate to continue shiploading despite a lack of coal railings to port. "We expect coal producers will look to make up lost exports in the second quarter of 2021, so the overall impact on exports, when considered on an annual basis, will be limited," Boyle said. "We do however expect spot coal prices to jump on the supply disruptions," he said, adding that high calorific value thermal coal prices were already indicated above $90/mt FOB Newcastle and could climb to the $100/mt level on news of the floods by the end of March. "This would be a near-term resistance price level, and if breached, which we believe it could, would hit an almost two-and-a-half-year high," Boyle said. S&amp;P Global Platts assessed the price of Newcastle 5,500 NAR at $57.50/mt on March 23, up 50 cents on day. Muted impact on met coal Metallurgical coal market participants said there was minimal disruption to Bowen Basin production in Queensland state, but they will be monitoring higher water levels at rivers and creeks. Rainfall at mining sites in Central Queensland and ports is expected to continue for a few weeks amid the monsoon season. "We lost two or three days of production at both sites last week. I would expect to see similar falls this week," a coal producer said. An international trader said that there had not been "any material impact on mining and logistics" so far, but noted that it would "take time to fully assess the damage or rail washouts inland." "The weather disruption could make an already tight market even tighter," the trader added. The uptick in thermal coal prices has resulted in higher prices for other grades of metallurgical coal, mainly weaker grades of met coal like pulverized coal injection and semi-soft. This is because the pricing of these grades of coals are interlinked depending on their energy composition. As thermal coal prices move up due to the floods, a producer can also command higher prices for the pulverized coal injection and semi-soft. A Northeast Asian trader described the market for weaker coals as a "sellers' market" in the near term. Price spreads between premium hard coking coal and weaker metcoal grades have narrowed due to differing market dynamics --- the premium hard coking coal is cheaper due to ample supply as China has been blocking imports from Australia, while prices of pulverized coal injection and semi soft are higher due to the floods. S&amp;P Global Platts assessed Premium Low Vol Coking Coal, a premium hard coking coal, at $111.50/mt FOB Australia March 22, down $1/mt on day. The ratio between premium hard coking coal and pulverized coal injection stands at 96%, and 89% for semi-soft, based on Platts assessments basis FOB Australia March 22. Both ratios had been the highest since the indexes were launched in October 2011. Editor: Alisdair Bowles ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/033122-geopolitical-risk-dominates-outlook-for-europes-energy-carbon-markets-in-q2</link><description>Gas one incident away from fresh spikes Low nuclear, hydro weaken power resilience Demand downside risk for carbon market Already dazed from months of extreme volatility, Europe&amp;apos;s energy markets enter</description><title>Geopolitical risk dominates outlook for Europe&amp;apos;s energy, carbon markets in Q2</title><pubDate>31 March 2022 13:42:00 GMT</pubDate><author><name>Stuart Elliott</name><name>Andreas Franke</name><name>Frank Watson</name></author><content><![CDATA[ 31 Mar 2022 | 13:42 UTC Geopolitical risk dominates outlook for Europe's energy, carbon markets in Q2 By Stuart Elliott, Andreas Franke, and Frank Watson Highlights Gas one incident away from fresh spikes Low nuclear, hydro weaken power resilience Demand downside risk for carbon market Already dazed from months of extreme volatility, Europe's energy markets enter the second quarter of 2022 with no sign of a let-up in the daily turmoil brought on by the conflict in Ukraine. The gas market -- already bowing under the weight of record high prices -- is set for further unprecedented change as the EU looks to slash demand for Russian gas and new storage obligations shift trading dynamics. The TTF day-ahead price hit a new all-time high of Eur212/MWh ($233/MWh) on March 7, according to S&amp;P Global Commodity Insights assessments, a 1,190% increase year on year, as the fall-out from Russia's invasion of Ukraine on Feb. 24 continued to roil markets. Fundamentals of supply and demand have largely given way to price movements driven by the Ukraine war and the related gas-focused responses from both Europe and Russia. The radically changed geopolitical landscape has fed into the gas market, with the EU taking swift action on storage and supply security, imposing mandatory storage obligations on member states in a bid to avoid a repeat of concerns over stock levels this winter. European storage sites were filled to just 77% of capacity last summer, with facilities 26% full as of March 30, according to data from Gas Infrastructure Europe. The first regulatory phase under the EU's storage reforms will see member states obliged to fill storages to 80% of capacity by Nov. 1, 2022, with intermediate targets through the year that must also be met. The traditional gas injection season in Europe begins in April, but it remains to be seen whether there will be sufficient gas supply to help boost inventories at a time when Russian flows remain curtailed. The US has pledged an additional 15 Bcm of LNG this year to help Europe, with other suppliers such as Azerbaijan and Norway also pumping at maximum capacity. Russian deliveries via Ukraine have increased to their contractual maximum since Moscow's invasion as spot prices surged, making Russian gas delivered under long-term contracts more competitive. However, Russian flows through the Yamal-Europe line remain erratic and mostly at zero. Any impact from hostilities on the transit system in Ukraine would likely trigger more panic on European gas markets. EU leaders have also agreed to set up a joint gas procurement mechanism to present a more unified stance toward sellers, and details of the initiative are likely to emerge in Q2. The EU finds itself in a difficult position, however. It still needs Russian gas to fill storage sites through Q2 but has also pledged to cut demand for Russian gas by two thirds by the end of 2022. Analysts at S&amp;P Global Commodity Insights believe gas prices will remain supported by continued concerns over Russian supply reliability which, in turn, prompts other suppliers to target Europe to provide alternatively sourced gas. Norway continues to pump at maximum levels, regularly breaching the 350 million cu m/d export level to markets in Europe, while LNG is also expected to come in large volumes in Q2 after high supplies in Q1. "Platts Analytics forecasts continued strong LNG deliveries and record Norwegian gas production for Q2, with production permits increased, maintenance delayed, and gas over oil prioritization continuing," it said. Norway's Aker BP is pivoting toward gas at its Skarv field, while Equinor plans to maintain higher gas output at its Heidrun, Osberg and Troll fields after increased production permits were approved by the energy ministry. High prices are also leading to some European demand curtailments that are set to continue through Q2. "Industrial and power sector gas demand destruction and switching are also forecast to continue, with residential/commercial demand in Europe now trending below 2018-2021 averages," S&amp;P Global analysts said. Low nuclear hampers diversification Ramping up Europe's remaining coal plants could reduce Q2 gas-for-power demand by 6 Bcm in Europe's main markets, but long-term low nuclear generation is set to offset the bulk of these efforts. "Europe is about to head into a summer with significant risk of tightness due to low French nuclear availability and low hydro stocks in Southwest Europe which has the potential to see a feedback loop of regional power prices chasing each other higher in order to attract net imports," S&amp;P Global Commodity Insights' head of European power analysis Glenn Rickson said. S&amp;P Global forecasts a year-on-year decline in Q2 nuclear output of around 24 TWh, the energy equivalent of 4.5 Bcm of gas. Elsewhere, solar and wind capacity gains and the prospect of demand destruction due to high prices could help further offset the loss of nuclear. Nevertheless, France has become the premium market with Q2 baseload in a range of Eur250-300/MWh for much of the second half of March, EEX data showed. New French links to Italy (the 1.4 GW Piedmont-Savoy) and Britain (the 1 GW ElecLink) are to start commercial operations during the period. Closer to the conflict, Finland's new 1.6-GW Olkiluoto-3 nuclear reactor is set to produce some 3 TWh in Q2 ahead of commercial production in July, reducing imports of Russian electricity that climbed to 9 TWh in 2021. In summary, European power's ability to turn down gas demand this spring and summer is limited by relatively low hydro stocks, weak nuclear and supply constraints at coal and lignite plants. Anticipated demand destruction, with Q2 demand projected some 0.8% lower year on year assuming average temperatures, offers little hope for hard-pressed consumers enduring costs some way beyond their worst projections. "A return to business as usual is hard to imagine [with] the coming weeks and months likely to see a series of wide-ranging policy responses which will likely be as severe an intervention into Europe's power market design since power market liberalization began in the 1990s," S&amp;P Global's Rickson said. Downside risk for carbon Following a sharp drop in March linked to Russia's invasion of Ukraine, EU carbon prices have rebounded, leaving the outlook slightly bearish going into the second quarter of 2022. EU Allowance prices for December 2022 delivery rebounded to Eur78.38/mtCO2e at the close March 30, from a low of Eur58.19/mtCO2e on March 7. The rebound has left prices exposed to a slight downside risk going into Q2, with milder temperatures expected to limit energy demand. On the supply side, the market was also looking healthier after EU member states allocated 54% of the available pool of free allowances to industrial companies for 2022, according to European Commission figures released March 17. A total of 288 million allowances had been issued as of that date, from an eligible total of 533 million for 2022, the figures showed. Countries yet to allocate included Italy, Poland and Spain, and the volumes entering the market could limit upside for prices going into Q2. EUA prices are forecast to ease slightly to Eur77.20/mtCO2e on average in April, Eur75.40/mtCO2e in May and Eur73.60/mtCO2e in June, according to a forecast by S&amp;P Global Commodity Insights in its European Emissions Trading System Market Outlook released March 18. "The escalation of the Russia-Ukraine conflict has led to a dramatic fall in speculator and financial interest in the EU ETS market, as investors de-risk and take profits following near-record high EUA prices," S&amp;P Global said. The power sector has added bearish pressure on EUAs since escalation of the conflict, as EUAs are sold in favor of covering higher oil, gas and coal commodity prices, it said. Wider doubts over the macro-economic picture in Europe also represent a bearish risk factor for carbon prices moving into Q2. "There are concerns that EU industrial production will fall amid current high energy costs, with signals indicated by the glass and fertilizer sectors," S&amp;P Global said. "We expect power sector demand to weaken into summer 2022 with receding seasonal demand but expect uplift to winter 2022 prices with increased coal burn following reduced imports of Russian gas," it said. Upside risk factors include further disruption to natural gas supplies which could favor greater coal burn for power generation in 2022. Equally, the supply side could offer additional support for prices amid ongoing regulatory efforts to reform and expand the EU ETS, including a possible phase down of free allocation. Negotiations are ongoing among EU member states under the French presidency of the EU Council which ends on June 30. Those factors point to tighter supply over the long term, which could re-attract investor and compliance interest in carbon allowances. Editor: Daniel Lalor ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/080521-german-gas-generation-falls-35-coal-rebounds-as-margins-diverge</link><description>German gas fired power generation fell in July as record high European gas hub prices further eroded margins, while hard coal generation almost exceeded gas fired generation and lignite topped the Ger</description><title>German gas generation falls 35%, coal rebounds as margins diverge</title><pubDate>05 August 2021 15:29:00 GMT</pubDate><author><name>Thomas Schumacher</name><name>Neil Hunter</name><name>Andreas Franke</name></author><content><![CDATA[ 05 Aug 2021 | 15:29 UTC German gas generation falls 35%, coal rebounds as margins diverge By Thomas Schumacher, Neil Hunter, and Andreas Franke Highlights Lignite tops July mix TTF front-month hits 2008-high above Eur40/mt Year-ahead clean spark spread negative first time since 2019 German gas-fired power generation fell in July as record high European gas hub prices further eroded margins, while hard coal generation almost exceeded gas-fired generation and lignite topped the German power mix. TSO data aggregated by Fraunhofer ISE shows that gas generation totaled 3.3 TWh in July, down 35% year on year as gas prices hit the highest levels on record. July Generation Generation Type July output (TWh) Year-on-year change (%) Month-on-month change (%) Solar 7.01 -1% -12% Wind 6 -15% 34% Lignite 7.29 15% -8% Hard Coal 3.1 111% 16% Gas 3.29 -36% -19% Nuclear 5.52 30% 12% Biomass 3.32 -13% -5% Hydro 1.76 2% -13% Imports 1.07 135% 37% Other 0.39 129% 3% Source: Fraunhofer ISE Storage concerns heading into the winter gas season and ongoing supply constraints continue to support prices in Europe, with Dutch TTF gas prices climbing above Eur40/MWh. Fundamentals in Europe are just part of the reason global gas prices have hit significant highs, with JKM and Henry Hub prices hitting significant levels of $15/MMBtu and $4/MMBtu, which saw European LNG imports in July fall to their lowest levels since January. The quarter-ahead Dutch TTF gas contract climbed 15% in July, while EUAs went in the opposite direction. After hitting an all-time high of Eur57.87/MWh on July 5, the December 2021 EUAs contract shed 10% in the remainder of the month. This saw coal- and gas-fired power margins diverge, with the German quarter-ahead clean spark spread for a 50%-efficient CCGT hitting a three-year low by the end of the month. Conversely, the equivalent dark spread for 45%-efficient plants recently hit its highest levels on record, according to S&amp;P Global Platts data that dates back to 2017, despite an increase in coal prices. According to Platts assessment data, the quarter-ahead CIF ARA coal contract hit its highest levels since September 2011. Negative clean sparks Challenging conditions for German gas plants are priced to extend into 2022, as Platts year-ahead clean spark spread with CSS (50% efficiency) assessment turned negative on Aug. 4 for the first time since April 2019 as the TTF 2022 gas contract rose above Eur28/MWh. According to S&amp;P Global Platts Analytics' latest five-year forecast published Aug. 4, German gas-fired output will rise above the 2020 high from next year on the back of nuclear, lignite and coal closures, averaging around 9 GW throughout the forecast period. All six German reactors are set to shut by the end of 2022, while Germany has auctioned over 8 GW of coal closure compensation since December 2020, bringing 2022 capacity well below 15 GW. RWE is also set to shut another 2.5 GW of lignite unit, mainly linked to the Hambach mine, by the end of 2022. Germany's leading candidate to replace Chancellor Angela Merkel after the Sept. 26 election, Armin Laschet (CDU), has rejected calls by the Greens and its sister party CSU to re-negotiate coal exit dates. Laschet added, however, that higher carbon prices could lead to quicker-than-anticipated coal closures achievable by 2030 in Western Germany. Holding back Short-term prospects for gas-fired generation, meanwhile, may have taken another hit in August delivery, as lower Russian gas flows through Yamal in Germany have given prices one less reason to fall, leaving Europe further exposed to global gas price strength. After a consistent flow of 81 million cu m/d throughout summer, net imports at Yamal's Mallnow terminus have slipped to 49 million cu m/d. Both German and Polish transit networks have told Platts that this is due to market behavior, and no upstream issues have been reported on the Russian side. While aggregate German storage is now over half full, this is still well below the 89% fill this time last year, Gas Infrastructure Europe data showed. Gazprom's Rehden storage facility in Germany is just 12% full, after beginning summer at 9.5%. With little change in onward transport to Central and Southern Europe, German imports have been affected the most, at a time when as much gas as possible is needed for storage, and indeed for power generation. Also supportive of prices is an evident lack of winter volumes on the market that would be delivered by Nord Stream 2 if it wasn't forbidden from operating. A similar situation was seen ahead of the signing of the Russia-Ukraine transport accord, which saw short-term volumes collapse after the agreement, and winter prices supported before it. Nord Stream 2 has the potential to facilitate a major fuel switch towards gas in Germany, should its purpose not be to avoid costly transport through Poland and Ukraine, for which just a few years of operation would completely offset and provide a return on investment. However, without a U-turn by German regulator BNetzA on exemption from production-transmission unbundling, and further assent from the European Commission that Nord Stream 2 does not contravene the principles of energy union, fuel switching and price compression potential seem unlikely for some time to come, especially if non-contract Russian volumes to Germany continue to be withheld until said derogation is granted. Editor: Jonathan Fox ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/blog/energy-transition/043026-indias-power-and-renewables-market-demand-stalls-capacity-rises</link><description>India&amp;apos;s power sector reached a turning point in fiscal year 2025-26 (April 2025-March 2026), as record renewable capacity additions of 51 GW coincided with the first annual contraction in electricity demand since the pandemic. </description><title>India&amp;apos;s power and renewables market: Demand stalls, capacity rises</title><pubDate>30 April 2026 06:58:38 GMT</pubDate><author><name>Gautam Sood and Md. Jawed Alam</name></author><content><![CDATA[ Electric Power, Energy Transition, Nuclear, Renewables April 30, 2026 Indiaâs power and renewables market: Demand stalls, capacity rises Gautam Sood and Md. Jawed Alam Editor: Roma Arora Getting your Trinity Audio player ready... India's power sector reached a turning point in fiscal year 2025-26 (April 2025-March 2026), as record renewable capacity additions of 51 GW coincided with the first annual contraction in electricity demand since the pandemic. The unusual combination stemmed from prolonged monsoon conditions that suppressed cooling demand and accelerated clean energy deployment, according to Central Electricity Authority data and S&amp;P Global Energy CERA analysis. Energy demand contracts marginally Electricity demand in FY 2025-26 contracted 0.3%, falling to about 1,690 terawatt-hours from 1,695 terawatt-hours in FY 2024-25, according to CEA data. This muted demand was largely due to milder summer temperatures and the early onset of the monsoon, which reduced cooling requirements during peak demand months, according to CERA analysis. Looking ahead, CERA expects electricity demand to rebound 4.7%-5.4% between April and December. However, this outlook remains below earlier projections of 6.0%-6.6% for calendar year 2026, as GDP growth slows due to ongoing geopolitical disruptions stemming from the Middle East conflict, according to S&amp;P Global Market Intelligence. Renewables drive capacity expansions India's installed capacity reached 533 GW by March, rising 12.2% year over year from 475 GW, according to CEA data. Renewables drove this expansion, contributing 51 GW of the total 62.4 GW added during FY 2025-26. Installed renewable capacity reached 223.3 GW, up 29.5% year over year from 172.4 GW in March 2025. India is expected to add 38.5 GW of new capacity between April and December , with renewables accounting for 30.5 GW, according to CERA. Conventional capacity additions are projected at 3.7 GW of coal, 1.1 GW of hydro, 1.0 GW of nuclear and 2.2 GW of battery storage. Power exchanges gain market share Electricity trade through India's three power exchanges -- Indian Energy Exchange, Hindustan Power Exchange and Power Exchange India Limited -- reached about 158.7 TWh in FY 2025-26, accounting for about 9.4% of India's total electricity demand, according to the data compiled by CERA. This represented a strong year over year growth of nearly 16%, driven primarily by higher open access participation and increased power cost optimization by distribution companies. Thermal generation displacement Overall electricity generation in FY 2025-26 increased marginally by 0.2% year over year to 1,817 TWh, according to CEA data. Renewable energy generation surged 19.7% to 301 TWh from 252 TWh, increasing its share to 16.6% from 13.9% in FY 2024-25. This renewable surge displaced conventional generation. Coal-fired generation declined 3.9% year over year to 1,280 TWh. Gas-based generation fell by 17.4% to 26 TWh, accounting for just 1.4% of total generation. During the January-March period, the rapid expansion of renewable capacity translated into strong growth in renewable power generation. Renewable output increased by more than 21% year over year, reaching nearly 75 TWh, compared with 62 TWh, according to CEA data. As renewables continued to gain a larger share of the generation mix, coal-based generation declined modestly. Coal output fell by about 1.5% year over year to 337 TWh in January-March 2026, down from 342 TWh. Renewable momentum Activity in the renewable energy certificate market strengthened significantly during FY 2025-26, with traded volumes rising by 51% year over year to about 50 million certificates, according to IEX data. Prices softened modestly, declining by about 3% year over year but remaining broadly stable within the $3.6-$4.0/MWh range. In the January-March 2026 period, REC transactions increased at a slower 8% year over year to about 15.7 million certificates, according to IEX data, reflecting weaker short-term demand conditions. On the procurement side, renewable tendering activity remained robust during FY2026, with a total of 24â¯GW of capacity awarded through competitive bids. However, procurement momentum weakened in the January-March period, with awards falling to 7.6â¯GW, a 12% year over year decline. The slowdown reflects growing caution among procurers as curtailment risks and integration challenges become more pronounced, even as longâterm renewable capacity expansion targets remain unchanged. Curtailment represented 0.27% of the total variable renewable generation during the January-March 2026 period, according to NLDC data. Renewable energy curtailment rose sharply by about 200% year over year to 184â¯GWh, up from 61â¯GWh, indicating that while seasonal demand provided some support, underlying grid integration and flexibility challenges remained unresolved. Path forward India's power sector faces a delicate balancing act. The country must sustain renewable capacity additions -- CERA projects 30.5 GW between April and December 2026, representing 79% of total expected capacity additions, while simultaneously investing in transmission, storage and grid flexibility to ensure a reliable electricity supply. The sector has proven it can deploy renewable capacity at record speed, adding 51 GW in FY 2025-26 alone. The harder challenge now is building the ecosystem to effectively utilize that capacity. With Ashish Singla. Further reading: India Power and Renewables Market Briefing: Q2 2026 US-Israeli Conflict with Iran Essential Energy Intelligence for today's uncertainty. See What Matters > ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/energy-transition/102621-updated-climate-commitments-still-falling-short-of-global-temperature-goals-unep</link><description>New and updated climate commitments from governments still fall short of the effort needed to reach the goals of the Paris Agreement on climate change, the United Nations Environment Program said in a</description><title>Updated climate commitments still falling short of global temperature goals: UNEP</title><pubDate>26 October 2021 14:42:00 GMT</pubDate><author><name>Frank Watson</name></author><content><![CDATA[ 26 Oct 2021 | 14:42 UTC Updated climate commitments still falling short of global temperature goals: UNEP By Frank Watson Highlights Eight years left to almost halve emissions: UNEP Eyes on closing global 'emissions gap' as COP26 summit looms UNEP highlights potential for methane and carbon markets New and updated climate commitments from governments still fall short of the effort needed to reach the goals of the Paris Agreement on climate change, the United Nations Environment Program said in a report Oct. 26. Current commitments by countries leave the world on track for a temperature rise of at least 2.7 degrees Celsius this century -- well above a global goal to limit warming to 1.5 degrees C above pre-industrial levels. "Climate change is no longer a future problem. It is a now problem," said UNEP Executive Director, Inger Andersen. "To stand a chance of limiting global warming to 1.5 C, we have eight years to almost halve greenhouse gas emissions: eight years to make the plans, put in place the policies, implement them and ultimately deliver the cuts. The clock is ticking loudly," she said in a statement. The report found that countries' updated Nationally Determined Contributions -- and other commitments made for 2030 but not yet submitted in an updated NDC -- only take an additional 7.5% off predicted annual greenhouse gas emissions in 2030, compared with the previous round of commitments. Reductions of 30% are needed to stay on the least-cost pathway for 2 degrees C and 55% cuts for 1.5 C, it said. Coming ahead of the UN Climate Change Conference in Glasgow Nov. 1-12, UNEP's report found that net-zero emissions pledges could make a big difference. "If fully implemented, these pledges could bring the predicted global temperature rise to 2.2 C, providing hope that further action could still head off the most catastrophic impacts of climate change. However, net-zero pledges are still vague, incomplete in many cases, and inconsistent with most 2030 NDCs," UNEP said. To have any chance of limiting warming to 1.5 C, the world has eight years to take an additional 28 billion mt of CO2 equivalent greenhouse gases off global emissions, over and above what is promised in the updated NDCs and other 2030 commitments, it said. "To put this number into perspective, carbon dioxide emissions alone are expected to reach 33 gigatons [billion mt] in 2021. When all other greenhouse gases are taken into account, annual emissions are close to 60 Gt CO2e. "So to have a chance of reaching the 1.5 C target, we need to almost halve greenhouse gas emissions. For the 2 C target, the additional need is lower: a drop in annual emissions of 13 Gt CO2e by 2030," UNEP said. Focus on methane, carbon markets Methane emissions in particular offer a massive opportunity to curb the global temperature rise, UNEP said, as the gas is 80 times more potent than CO2 over a 20-year period. "Available no- or low-cost technical measures alone could reduce anthropogenic methane emissions by around 20% per year," UNEP said. Along with broader structural and behavioral measures, this reduction figure could be expanded to 45% per year, it said. "Carbon markets, meanwhile, have the potential to reduce costs and thereby encourage more ambitious reduction pledges, but only if rules are clearly defined, are designed to ensure that transactions reflect actual reductions in emissions, and are supported by arrangements to track progress and provide transparency," UNEP said. Closing 13 billion mt gap Highlighting the scale of action needed to achieve global temperature targets, global emissions from fossil fuel combustion are expected to reach 34.17 billion mt in 2040 under a September 2021 Reference case by S&amp;P Global Platts Analytics. That is almost 13 billion mt above the 21.25 billion mt forecast under Platts Analytics Two Degrees Outlook for 2040. Both scenarios are based on Platts Analytics' Global Integrated Energy Model. The emissions gap identified by UNEP, Platts Analytics, the International Energy Agency and dozens of think-tanks and industry groups, carries implications for a broad swathe of commodity markets because it implies that governments and industry will need to go significantly further in cutting emissions to avoid crossing temperature thresholds. Large-scale emissions abatement options include: Further displacement of coal and lignite for power generation in favor of natural gas, renewable energy and nuclear power A switch to electric and other low-carbon vehicles including fuel cell technologies and biofuels Hydrogen to displace gas in industry and buildings Biofuels and other low-carbon fuels in shipping and aviation Reducing methane emissions from venting, flaring and fugitive emissions Potential use of carbon capture and storage technologies The deployment of land-use projects and technology to absorb atmospheric carbon Energy efficiency programs in energy generation, industry, transportation, buildings and agriculture Editor: Kshitiz Goliya ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/agriculture/021722-crude-benchmarks-continue-to-rise-on-ukraine-russia-tensions</link><description>Crude price benchmarks climbed Feb. 16, with Dated Brent rising above $100/b, supported by continued tensions along the Ukrainian border.</description><title>Crude benchmarks continue to rise on Ukraine-Russia tensions</title><pubDate>17 February 2022 00:12:00 GMT</pubDate><author><name>Staff and Eric Yep</name></author><content><![CDATA[ 17 Feb 2022 | 00:12 UTC Crude benchmarks continue to rise on Ukraine-Russia tensions By Staff and Eric Yep Highlights Dated Brent rises above $100/b Crude futures later slip as US, Iran near agreement West skeptical as Russia says some troops withdrawn from border Crude price benchmarks climbed Feb. 16, with Dated Brent rising above $100/b, supported by continued tensions along the Ukrainian border. S&amp;P Global Platts assessed its Dated Brent benchmark at $100.795/b, up $3.14 on the day, and the highest since Sept. 4, 2014. American GulfCoast Select (AGS) was assessed at $94.85/b, up $1.37. Despite Moscow's claims it was withdrawing troops from the border, Western nations have continued to point out that the threat of conflict has yet to diminish, with NATO secretary-general Jens Stoltenberg warning Feb. 16 that Russia continues to increase troop numbers on the border. Crude futures fell following the assessments, after Iran's top negotiator Ali Bagheri Kani said via Twitter that the US and Iran were nearing an agreement in ongoing nuclear talks. At 2200 GMT, ICE Brent was trading at $91.79/b, down $1.49, while NYMEX WTI was trading at $90.62/b, down $1.45. The Russian Defense Ministry said Feb. 15 that it was pulling back some of its troops from the Ukrainian border after the completion of some planned military exercises. However, US President Joe Biden later said the troop movements were not verified. "An invasion remains distinctly possible," Biden said during a press conference. "Russian president Vladimir Putin's stated plans to 'partially' reduce troops near Ukraine Feb. 15, but uncertainty will persist as long as his intentions remain strategically ambiguous," Paul Sheldon, chief geopolitical adviser at Platts Analytics, said. "In any case, we still do not expect a notable curtailment of oil exports, either from US sanctions or Russia voluntarily holding back volumes." Trade -- Russian gas transport through Ukraine has been on the decline in recent years and collapsed at the start of 2022. Ukraine remains a key transit route for Russian gas to Europe, accounting for a little under 10% of Europe's gas demand in 2021. Under a five-year transit deal between Gazprom and Ukraine's Naftogaz in 2019, the Russian company agreed to send a minimum of 110 million cu m/d of gas via Ukraine to Europe under ship-or-pay terms in 2022. Gas deliveries via Ukraine at the key Velke Kapusany entry point fell sharply in January but recovered somewhat in February. Flows of 34 million cu m/d were seen Feb. 14 compared with January lows of 25 million cu m/d. Gas flows through the Nord Stream 1 pipeline have trended below capacity since Feb. 10, last seen near 1.7 TWh/d Feb. 14. -- Ukraine is a critical route for oil flows into Eastern Europe and the fringes of the EU. Ukraine moves Russian oil to Slovakia, Hungary and the Czech Republic. The country's transit of Russian crude for export to the EU was 11.9 million mt in 2021, down from 12.3 million mt in 2020, while oil transit to Belarus remained unchanged at about 800,000 mt. Last year, crude shipments via the southern branch of the Druzhba pipeline network included 5.2 million mt, or around 104,427 b/d, to Slovakia; 3.4 million mt, or around 68,279 b/d, to Hungary; and 3.4 million mt, or around 68,279 b/d, to the Czech Republic. -- Ukraine is one of the world's largest exporters of grains, with any disruption to supplies potentially impacting food security and prices. Ukraine accounts for around 13% of global corn exports, the fourth largest exporter in the world and Europe's largest by some way. Half of its exports go to the EU, with China being another major importer. The corn is used in animal feed, while the biofuel sector also takes a significant share. It is forecast to export 33.5 million mt for marketing year 2021-22 to June 30. The country accounts for around a tenth of global wheat exports, which have risen 27% so far in marketing year 2021-22 (July to end-June) to 16.1 million mt, as neighboring Russia increased its export taxes. Platts Analytics projected Ukraine will export 22.5 million mt of wheat in marketing year 2021-22. -- Ukraine is also the world's 13th-largest producer of steel and the fifth-largest exporter of iron ore by volume. Ukraine produced 21.4 million mt of crude steel in 2021, with 80% of its steel output exported. It exported 44.4 million mt of iron ore products in 2021 and imported 9.85 million mt of metallurgical coal and coke products. Ukraine raised 3.9 million mt of steel scrap, of which 616,000 mt was exported. Prices -- Oil prices first hit seven-year highs mid-January, spurred by a recovery in mobility levels, worries over spare capacity among key producing nations, slow progress in getting Iran's sanctions lifted and tensions over Ukraine. Prices for Russia's Urals crude, which ships via Ukraine, have increased since mid-December in line with global oil prices. Platts assessed Urals crude at $93.225/b Feb. 16, up $2.55 on the day. -- European gas prices have risen since mid-January as an attack by Russia against Ukraine could impact gas supplies. The benchmark European gas contract TTF day-ahead surged to a record Eur182.77/MWh Dec. 21 before falling to Eur61.28/MWh at the end of the year. By market close Feb. 16, the contract was at Eur68.075/MWh, Platts data showed. Any conflict impacting gas supplies into Europe could have knock-on impacts on power, carbon and coal prices. CIF ARA spot coal prices have risen 31% since the start of the year to be assessed by Platts at $177/mt Feb. 14. Over the year, the material has risen 173% in value. Prices in the EU Emissions Trading System hit a record Eur97.50/mtCO2e (December 2022 delivery) on the ICE Endex exchange Feb. 4, in part due to continued uncertainty over European gas stocks. The price had fallen to Eur92.87/mt by market close Feb. 14. -- Ukrainian corn prices have been rising on the back of strong global demand and Russian plans to impose export duties on grains. Ukraine FOB Black Sea corn export prices hit a seven-year high of $301/mt in May 2021. Prices then dipped to $254/mt in September but have risen steadily since to be assessed at $284/mt as of Feb. 16. Infrastructure -- Russia could close off Ukrainian ports due to its control of Crimea and Black Sea chokepoints. The Kerch Strait connects the Black Sea and the Sea of Azov and is used both ways, to supply soft commodities, and ship steel/pig iron and other raw materials from Mariupol. Russia's Azov and Rostov ports serve as both transshipment ports to load deep water vessels at the Russian port of Kavkaz and as loading points to make small parcel shipments of wheat, barley and corn to destinations in the east Mediterranean. Exports of both corn and wheat take place through a number of Ukrainian sea ports, including the southwestern Panamax-capable ports of Odessa, Pivdennyi and Chornomorsk, all of which are well away from the front line. However, they are all within easy reach of Crimea, which is currently under Russian occupation. -- The security of the Druzhba pipeline and ports are key for markets. Ukraine ships Russian oil to Slovakia, Hungary and the Czech Republic via the southern leg of the key 25 million mt/year Druzhba pipeline. Mariupol, Ukraine's main port in the Sea of Azov, is vital for pig iron and steel export from Ukraine and imports of steelmaking raw materials, particularly coking coal. In recent years, steel shipments from Mariupol have represented about a quarter of Ukraine's total exports in value terms. Any limitation of vessels through the Kerch Strait would likely affect supply routes used by Ukrainian mining and steel group Metinvest and other bulk shipping on the route. -- A cloud now hangs over the future of the Nord Stream 2 pipeline linking Russia with Germany. The future of the now complete Nord Stream 2 gas link could rest on affairs in Ukraine. EC President Ursula von der Leyen said Feb. 4 that Nord Stream 2 could not be "removed from the table" as far as sanctions were concerned and that Brussels had prepared a "robust and comprehensive" package of sanctions that it could impose on Moscow if Russia invaded Ukraine. US President Joe Biden said Feb. 15 that Nord Stream 2 "will not happen" if Russia invaded Ukraine. Platts Analytics has pushed its base case scenario for Nord Stream 2's startup to October 2022. Editor: Shashwat Pradhan ]]></content></item><item><link>https://www.spglobal.com/market-intelligence/en/news-insights/research/essential-energy-insights-october-2021</link><description>Essential Energy Insights October 2021 covers energy market developments and supply-demand dynamics across global oil, gas, and power sectors.</description><title>Essential Energy Insights - October 2021</title><pubDate>11 October 2021 18:30:00 GMT</pubDate><content><![CDATA[ Blog â 12 Oct, 2021 Essential Energy Insights - October 2021 Gain essential insights into top trends in the energy sector. Learn more about updates in ESG and Global power sectors. Learn more about Market Intelligence Request Demo ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/120821-germanys-new-government-to-speed-up-transition-via-fit-for-65-decarbonization-plan</link><description>Germany&amp;apos;s new coalition government under Chancellor Olaf Scholz plans to speed up Germany&amp;apos;s energy transition to achieve a 65% cut in CO2 emissions by 2030 on 1990 levels.</description><title>Germany&amp;apos;s new government to speed up transition via &amp;apos;Fit for 65&amp;apos; decarbonization plan</title><pubDate>08 December 2021 14:48:00 GMT</pubDate><author><name>Staff and Eric Yep</name></author><content><![CDATA[ 08 Dec 2021 | 14:48 UTC Germany's new government to speed up transition via 'Fit for 65' decarbonization plan By Staff and Eric Yep Highlights German power demand is forecast to increase to 680 TWh-750 TWh/year in 2030 Scholz coalition excluded any mention of the Nord Stream 2 project in its treaty Germany consumed 1.1 million b/d of diesel and gasoil in 2020 and 450,000 b/d of gasoline Germany's new coalition government under Chancellor Olaf Scholz plans to speed up Germany's energy transition to achieve a 65% cut in CO2 emissions by 2030 on 1990 levels. S&amp;P Global Platts reporters provide context for a country that is Europe's biggest importer of oil, gas and coal and biggest producer of electricity. Power Germany is Europe's largest wind and solar market with 120 GW capacity already installed, putting a strain on north-south power flows. Further additions may again result in negative hourly prices during offpeak days another reason for Germany's strong appetite for hydrogen. German power demand is forecast to increase to 680 TWh-750 TWh/year in 2030, up 16%-23% from pre-COVID levels in 2019. Germany is to exit nuclear generation by end-2022 while a first wave of coal closures has begun under an existing 2038 phaseout deadline. The coalition plans to boost the share of renewables in the generation mix from 65% to 80% by 2030. Phasing out coal "ideally by 2030" under the coalition agreement accelerates the need for flexible supply including new gas-fired plants that are hydrogen-ready for longer-term decarbonization conversions. German coal and lignite generation of 131 TWh for Jan.-Nov, 2021 is up 26% on year, while 2021 nuclear generation around 65 TWh is still covering 12% of power demand. Platts Analytics projects German year-ahead power prices to average around Eur70/MWh for 2023-2023, double the average price for 2016-2020. Platts assessed Platts assessed the cost of producing renewable hydrogen via PEM electrolysis in Europe at Eur16.01/kg Dec. 6 (Netherlands, including capex), based on front-month power, up fourfold since the start of the year. Natural gas Germany is the biggest gas consuming country in Europe by some distance, with demand of 87 Bcm/year. It is a modest gas producer with output in 2020 of 5 Bcm. Germany is Russian Gazprom's biggest export market with sales in 2020 of 45.8 Bcm -- a little over half of Germany's total gas demand. German gas is traded at the THE hub, which began operation in October following the merger of the Gaspool and NCG hubs. Since launch, the day-ahead THE price has averaged Eur85.08/MWh, a premium of more than Eur3/MWh over the benchmark Dutch TTF day-ahead price. Germany has one of the best connected gas markets in Europe, with direct links to imports from the Netherlands, Norway and Russia, as well as connections with other regional markets. The 55 Bcm/yr Nord Stream 2 pipeline from Russia was completed in September but awaits regulatory clearance before operation can start. The new coalition excluded any mention of the project in its coalition treaty. Based on previous declarations, the SPD is largely in favor of the pipeline, but the Green Party and FDP have previously called for the project to be halted. Germany has no LNG import infrastructure. Two terminals are under development: the 12 Bcm/year Stade and the 8 Bcm/year Brunsbuttel facilities. Related podcast: Nord Stream 2: No end in sight to long-running saga over controversial gas pipeline Oil Although oil consumption peaked in the late 1970s, Germany remains Europe's biggest oil consumer. Germany burned 2.12 million b/d of oil products last year, or 19% of the total demand in Western Europe, according to Platts Analytics. With almost no domestic production, almost all the country's oil needs are imported. In 2022, the country is expected to return to 2019 oil demand levels of 2.32 million b/d. Germany is also Europe's largest fuel market and refining hub. Germany consumed 1.1 million b/d of diesel and gasoil in 2020 and 450,000 b/d of gasoline, putting it ahead of both the UK and France. Europe's biggest refiner Rosneft is also set to become Germany's biggest refiner in 2025 after Shell shuts some units at its Rhineland refining complex. Platts assessed cracking margins for refining Russian Urals crude in the ARA hub at $2.375/b Dec. 6, down from $3.3/b at the start of the year. Like most of its European peers, Germany has seen sales of diesel and gasoline cars fall sharply since 2020 helped by incentives to promote electric cars. During the third quarter of 2021, registrations of new gasoline and diesel cars fell to 55% of total sales, with hybrid, plug-in and fully electric cars making up 44% of sales, according to sector association ACEA. For key biofuels, Platts assessed the spread between renewable diesel, or HVO, and ultra-low sulfur diesel in Europe at $1588.45/mt. The spread between biojet (SAF) and jet fuel was assessed at $1,776.43/mt on Dec. 6, Platts data show. Battery metals Germany aims to have at least 15 million electric vehicles by 2030, a goal the new coalition lifted from previous targets. German EV sales are expected to nearly double to 755,000 in 2021, according to Platts Analytics. This is expected to rise to 1.13 million in 2025 and 1.7 million in 2030. To meet increasing demand, seven EV battery gigafactories with a combined 246 GWh capacity are planned in Germany including Tesla's 100 GWh Gruenheide factory outside Berlin. Battery metal prices have been skyrocketing in 2021. Seaborne lithium carbonate and hydroxide prices reached almost daily record highs with Platts' assessments at $31,000/mt and $30.5000/mt CIF North Asia respectively. Similarly, European cobalt metal prices reached a three-year high of $31.25/lb IW Europe. Steel Germany's steel industry accounts for 30% of all CO2 emissions from industries and 6% of Germany's overall emissions. Steelmakers aim to cut emissions by a third by 2030 through changes in the manufacturing process estimated to cost Eur100 billion. Steel association WV Stahl welcomed plans by the coalition to support energy costs as the carbon-intensive blast furnace mills, among them Europe's biggest steelmaker Thyssenkrupp, are under pressure to stem the price of switching from coal- to hydrogen-based production while undergoing the transition from blast to electric arc furnace production. Platts daily HRC assessment has come down to Eur955/mt Dec. 6 since a record Eur1190/mt EXW Ruhr in June, but margins remain healthy at mills. Expected decarbonization costs for the European steel industry already changed pricing policies at mills and led steelmakers to introduce or plan carbon surcharges as extra costs on base prices. Petrochemicals Germany hosts some of the largest petrochemical companies in Europe. The sector will be seeking a level playing field with global counterparts on carbon emissions to prevent the risk of investment leakage. Germany is at the forefront of EU plans to reduce plastic waste pollution and increase the use of recycled plastic. Germany is well positioned with PET plastic bottle collection rates above 90%, but strong demand and exports means Germany is facing an uphill battle to ensure that 2025 mandates are met. Post-consumer PET bottle bales, the feedstock for recycled PET, have more than doubled in 2021 to Eur850/mt FD NWE Dec. 6, Platts data show. Hydrogen The new government plans to double Germany's electrolyzer capacity target to 10 GW by 2030. The outgoing government had already pledged Eur9 billion in support for electrolyzer and related projects at home and abroad. German hydrogen demand accounts for approximately 2% of current global consumption, or 1.6 million mt/year, almost all from unabated fossil fuel production, with demand concentrated in the refining and fertilizer sectors, according Platts Analytics. Demand could reach 2.2 million mt/year by 2030, Platts Analytics said in its European Hydrogen Long-Term Forecast in October. Platts Analytics Hydrogen Production Asset Database tracks a total of 640,000 mt/year of production capacity in Germany by 2030. GERMAN PRIMARY ENERGY MIX (%) Q1-Q3 2021 Q1-Q3 2020 Oil 32 35.6 Gas 26.3 25 RES 16.1 16.9 Lignite 9.1 7.5 Coal 8.4 7.2 Nuclear 6.4 6.1 Source: AGEB (Nov. 8, 2021) Editor: Andy Critchlow ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/122421-commodities-2022-ill-timed-year-of-european-plant-closures-clashes-with-gas-crisis</link><description>Explore the challenges of European plant closures in 2022 amid a gas crisis, analyzing the implications for energy supply and market dynamics.</description><title>Commodities 2022: ill-timed year of European plant closures clashes with gas crisis</title><pubDate>24 December 2021 09:00:00 GMT</pubDate><author><name>Andreas Franke</name></author><content><![CDATA[ 24 Dec 2021 | 09:00 UTC Commodities 2022: ill-timed year of European plant closures clashes with gas crisis By Andreas Franke Highlights 4 GW German nuclear to shut boosting coal despite closures Wind, solar output to rise 8 GW based on normal weather Platts Analytics sees 2022 gas-fired power hit 2014-low European power markets enter 2022 in crisis. There is no near-term path out of the current gas-driven super-inflation of prices, while another slew of coal and nuclear closures is poised to intensify Europe's reliance on price-setting gas-fired generation. The interconnected nature of European power systems makes this the case even for national markets with little gas-firing. Generation costs for a 50% efficient gas-fired power plant in Northwest Europe hit a record Eur287/MWh ($323/MWh) Dec. 17 for Q1 2022 compared to an average Eur43/MWh a year ago, S&amp;P Global Platts data show. This has lit a fire under forward contracts. German Cal-2022 baseload power, Europe's benchmark contract, had risen over 500% in 2021 to trade Dec. 21 above Eur300/MWh, exchange data showed. And this ahead of the closure of Germany's last three nuclear reactors by end-2022, taking 4-GW out of the market. France meanwhile faces another winter of record-low nuclear availability reflected in the front-month peakload contract, trading Dec.17 above Eur1,000/MWh on the EEX exchange. Demand key variable While a fall in gas prices and growth in renewables should ease the crisis next year, plant closures "will increase the power market's exposure to gas prices and we see the potential for the extreme prices seen in 2021 to be repeated in Q1 2022 overshadowed by French reactor delays," said Glenn Rickson, who heads up Platts Analytics' European power team. "Demand is a key uncertainty for 2022, with COVID risk only one factor at play," he said. Platts Analytics sees 2022 demand across the ten European markets it covers rise by around 2% or 5 GW on average in a year-on-year comparison. Nuclear is set to remain the single biggest source of electricity for the ten markets, but forecast to fall 4 GW to a record-low 65 GW hourly generation average. Wind output meanwhile is set to overtake that of gas in 2022, with hydro in fourth. Coal and lignite output is forecast to rebound only slightly to around 22 GW on average for 2022, despite record-high generation margins -- plant closures have severely diminished capacity over recent years, with only Germany and Poland maintaining significant fleets. Gas-fired generation was projected to dip to a 41 GW average, driven lower by poor spark spreads. Run times could see upside, however, reflecting variable demand and wind generation, the latter being below average in 2021. Dispatchable plant closures As noted, Europe's biggest power market Germany is set for a big shift in its supply-demand balance in the near terms with three reactor closures at the end of 2021 to be followed by a final three closures at end-2022, removing 8 GW or 12% of German supply in all. Meanwhile, barring a possible lifetime extension, Belgium's Doel 3 reactor is set to close in Oct. 2022, to be followed early 2023 by Tihange 2. In the UK, finally, there will be no reprieve for Hunterston B and Hinkley Point B reactors, both set for permanent closure during 2022. On the coal front, Germany has already shut 6 GW of hard coal in 2021 following closure compensation auctions with at least another 3 GW to follow in 2022 including the first wave of lignite closures capping combined capacity at 30 GW. Further out, the new government in Berlin plans to review the coal exit deadline of 2038, with the intention of bringing this forward to 2030 if possible. Other notable 2022 events include closure of Riverstone's 730 MW Rotterdam coal plant expected to shut in Q2 and closures of at least two more French coal units ahead of Presidential elections in April. EUROPEAN PLANT CLOSURES 2021/22 Plant MW Fuel Country Date Gundremmingen C 1300 Nuclear DE Dec. 2021 Brokdorf 1400 Nuclear DE Dec. 2021 Grohnde 1400 Nuclear DE Dec. 2021 Doel 3 1000 Nuclear BE Oct. 2022 Hunterston B 1000 Nuclear UK 2021/22 Hinkley Point B 1250 Nuclear UK July 2022 Hambach units 900 Lignite DE Dec. 2021 Neurath A 300 Lignite DE April 2022 Neurath D+E 1200 Lignite DE Dec. 2022 RDK7 500 Coal DE Summer 2022 Wilhemshaven, Mehrum 1500 Coal DE Dec. 2021 Rotterdam 730 Coal NL tba West Burton A 600 Coal UK Sept. 2022 La Spezia, Fusina 870 Coal ITA 2021 Litoral 1200 Coal ESP 2022 Emile Huchet 6, Provence 5 1200 Coal FRA 2022 Cordemais 1200 Coal FRA tba Source: S&amp;P Global Platts First new reactors Offsetting these debits, Europe's first EPR reactor in Finland is finally about to come online with first electricity to be produced in January 2022 and commercial operations to start in June. In France, fuel loading at the Flamanville 3 EPR is scheduled for end-2022, allowing for a 2023 start for the first new French reactor in a generation. On the gas front, new CCGT capacity is to start at Keadby 2 (GB), Landivisau (France), Agios Nikolaos (Greece) as well around 2 GW in Germany replacing coal at VW Wolfsburg and Herne 6. European wind power is set for a boost after sluggish growth, with UK offshore projects leading new additions while France is to bring online its first offshore wind farm at the 500 MW Saint Nazaire site. In all, Platts Analytics forecasts average wind and solar production in the ten European markets it covers to average at a record 64 GW in 2022 assuming average weather conditions, up from a 55 GW average in 2021 amid below average wind speeds across NW Europe. Finally, new interconnector commissioning between France and Italy and France and GB, will help integrate new renewables in 2022 while a booming battery storage sector in the GB should trim excessive balancing costs seen in recent months. NEW EUROPEAN POWER ASSETS 2022 NEW GAS-FIRED CCGTs MW Country Start Landiviseau 450 FRA Q1 2022 start Keadby 2 840 UK Q2 2022 start VW Wolfsburg 500 DE 2022 Herne 6 600 DE 2022 Agios Nikolaos 825 GR 2022 NEW REACTORS Olkiluoto 3 1650 FIN June 2022 COD Flamanville 3 1650 FRA Dec. 2022 fuel loading Mochove 3 471 SLO 2022 NEW INTERCONNECTORS Savoie-Piedmont 1200 FRA-ITA Q1 2022 ElecLink 1000 FRA-UK mid-2022 Source: Developers, S&amp;P Global Platts Editor: Henry Edwardes-Evans ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/podcasts/energy-evolution/032526-ontario-power-generation-leads-the-north-american-race-to-build-advanced-nuclear</link><description>When it comes to advanced nuclear generation, most North American power producers are in the study and development phases. But Ontario Power Generation is currently constructing the first of four small modular nuclear reactors at its Darlington facility, with the first 300-megawatt unit scheduled to complete construction and connect to the grid by 2030. The other three reactors are scheduled to be</description><title>Ontario Power Generation leads the North American race to build advanced nuclear</title><pubDate>25 March 2026 21:00:15 GMT</pubDate><author><name>Dan Testa</name></author><content><![CDATA[ Electric Power, Energy Transition, Nuclear, Renewables March 25, 2026 Ontario Power Generation leads the North American race to build advanced nuclear Featuring Dan Testa HIGHLIGHTS 300-MW unit connects to grid by 2030 Public utilities lead North American projects When it comes to advanced nuclear generation, most North American power producers are in the study and development phases. But Ontario Power Generation is currently constructing the first of four small modular nuclear reactors at its Darlington facility, with the first 300-megawatt unit scheduled to complete construction and connect to the grid by 2030. The other three reactors are scheduled to be completed in the mid-2030s, totaling 1,200 MW of firm capacity from advanced nuclear reactors. In this episode, Dan Testa speaks with OPG President and CEO Nicolle Butcher, from the sidelines of the CERAWeek by S&amp;P Global conference in Houston, about the state of the advanced nuclear project so far, how OPG selected this reactor design and why public power providers, like OPG in Canada and the Tennessee Valley Authority in the US, are taking the first steps to build advanced nuclear generation in North America. US-Israeli Conflict with Iran Essential Energy Intelligence for today's uncertainty. See What Matters > ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/061120-limited-support-for-blue-hydrogen-in-germany-green-potential-capped-by-res</link><description>Government backs green hydrogen, CFDs a lifeline for blue hydrogen Electrolysis to supply a sixth of 2030 demand due to power constraints Uniper CEO in national hydrogen council representing all secto</description><title>Limited support for blue hydrogen in Germany, green potential capped by RES</title><pubDate>11 June 2020 12:04:00 GMT</pubDate><author><name>Andreas Franke</name></author><content><![CDATA[ 11 Jun 2020 | 12:04 UTC â London Limited support for blue hydrogen in Germany, green potential capped by RES By Andreas Franke Highlights Government backs green hydrogen, CFDs a lifeline for blue hydrogen Electrolysis to supply a sixth of 2030 demand due to power constraints Uniper CEO in national hydrogen council representing all sectors Germany's national hydrogen strategy, presented June 10, focuses on kick-starting a green hydrogen economy based on the electrolysis of renewable energy, but there is a small opening for blue hydrogen. The strategy talks of a 'stakeholder debate' with the energy-intensive chemical and steel sectors on possible decarbonization methods other than green hydrogen using carbon capture and utilization (CCU) technology as well as carbon contracts for difference. Related interview: COVID-19 could delay Germany's subsidy-free renewables: Aurora And with Germany's ability to produce green hydrogen domestically constrained by renewable electricity volumes, there is room for blue hydrogen (steam methane reforming plus carbon capture) to grow if it can do so without the bulk of the subsidies on offer. The government plans a pilot carbon CFD program for steel and chemical sector projects, it said. That would subsidize the cost difference between a project's avoided CO2 emissions and the CO2 price in the European trading scheme (EUA), it said. Germany's 2030 climate law has set legally binding emissions targets for all sectors from power to transport and industry. The focus on green hydrogen in the strategy, however, should not be underestimated with Eur9 billion ($10 billion) in support, of which Eur2 billion would be for green hydrogen projects abroad. "The government's recognition that only green hydrogen from renewable sources is sustainable reduces the long term risk of fossil gas surviving through the backdoor," Felix Heilmann, researcher at climate think-tank E3G said. "At the same time, the long negotiations within the government regarding the potential for green hydrogen production in Germany illustrate the difficulties that countries which pin too many hopes on hydrogen will face," Heilmann said. Green hydrogen from the planned 5 GW of electrolyzer capacity by 2030 would only produce a sixth (14 TWh) of hydrogen demand by then, the strategy estimates. German hydrogen demand is set to almost double from 55 TWh to a forecast range of 90-110 TWh. The government expects CO2-free hydrogen derived from natural gas to play a role in other European hydrogen markets and, therefore, in Germany. Meanwhile German utility lobby BDEW has criticized the lack of a clear European certification process for green hydrogen, decarbonized gases and a trading system for such products. The BDEW was working on a relevant proposal, it said. National hydrogen council A new national hydrogen council (NHC) will be essential in the implementation of the strategy. The government has appointed a cross-section of 25 industry managers, scientists, unions, experts and environmental activists to the council. "Feeling the responsibility for being the only direct representative of the German large utilities in the NHC, I am delighted to make this expertise available to the Hydrogen Council," Uniper CEO Andreas Schierenbeck said. Schierenbeck has called for a technology-neutral approach to hydrogen. Uniper has a joint venture with Siemens involving its closed coal plant sites. "Hydrogen is the connecting element between the sectors and helps us as a society to avoid the billions of euros in damage caused in Germany alone by the destruction of the value of unused electricity from renewable energy sources," Schierenbeck said. Some 3%, or 6.5 TWh, of renewables were curtailed last year to keep the power grid stable, most of it wind during winter. The advisory NHC, comparable in composition to Germany's coal commission, includes company representatives from all industrial sectors such as BASF, Daimler, Linde, MAN, ThyssenKrupp/Salzgitter, Siemens and Viessmann alongside scientists, researchers, unions and environmental activists such as BUND and Klima Allianz. Germany's biggest power generator RWE, which on June 10 signed an agreement with steel maker ThyssenKrupp on a green hydrogen project, called for a quick implementation of the strategy. The GETH2 project would be based on a 100 MW electrolyzer at RWE's Lingen site with the hydrogen transported via pipeline by gas operator OGE (also represented in the NHC) to the Duisburg steel plant, supplying 70% of the plants demand to produce 50,000 tonnes of green steel annually. A June 5 study by Prognos for the energy ministry highlighted energy-intensive sectors such as steel and chemicals as essential for decarbonization, but with wholesale transformation only feasible in the 2030s due to massive energy demand. The hydrogen strategy's focus on green hydrogen would add approximately 20 TWh in additional demand for renewable power to feed the 5 GW electrolyzer capacity by 2030 with the government keen not to increase power sector emissions amid the coal-phase-out with the 2022 nuclear exit already reducing CO2-free electricity in Germany's power mix. Editor: Dan Lalor ]]></content></item><item><link>https://www.spglobal.com/market-intelligence/en/news-insights/research/essential-energy-insights-september-2021</link><description>Chile&amp;apos;s early bet on clean energy paid off. Now the government has offered up the country as a hydrogen laboratory to the world, with a goal of becoming one of the top three exporters by 2040.</description><title>Essential Energy Insights - September 2021</title><pubDate>12 September 2021 18:30:00 GMT</pubDate><content><![CDATA[ Blog â 13 Sep, 2021 Essential Energy Insights - September 2021 Chile's early bet on clean energy paid off. Now the government has offered up the country as a hydrogen laboratory to the world, with a goal of becoming one of the top three exporters by 2040. Learn more about Market Intelligence Request Demo ]]></content></item><item><link>https://www.spglobal.com/market-intelligence/en/news-insights/research/european-energy-insights-september-2021</link><description>European Energy Insights September 2021 highlights energy sector performance, commodity movements, and market developments in Europe.</description><title>European Energy Insights September 2021</title><pubDate>10 October 2021 18:30:00 GMT</pubDate><content><![CDATA[ Blog â 11 Oct, 2021 European Energy Insights September 2021 Here you will find a collection of this monthâs top European energy insights. Want to stay informed? Subscribe to receive our monthly insights directly to your inbox > Learn more about Market Intelligence Request Demo ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/123021-german-reactors-at-grohnde-brokdorf-gundremmingen-to-end-production-dec-31</link><description>German reactors at Grohnde, Brokdorf and Gundremmingen with a combined capacity of 4.2 GW are to end production on Dec. 31, with the units to be disconnected from the grid during the evening, transpar</description><title>German reactors at Grohnde, Brokdorf, Gundremmingen to end production Dec. 31</title><pubDate>30 December 2021 12:28:00 GMT</pubDate><author><name>Andreas Franke</name></author><content><![CDATA[ 30 Dec 2021 | 12:28 UTC German reactors at Grohnde, Brokdorf, Gundremmingen to end production Dec. 31 By Andreas Franke Highlights Wind surge deflates spot, Cal-22 near record-highs Final three German reactors to close by end-2022 Nuclear generated 65 TWh in 2021, 12% of demand German reactors at Grohnde, Brokdorf and Gundremmingen with a combined capacity of 4.2 GW are to end production on Dec. 31, with the units to be disconnected from the grid during the evening, transparency data shows. The 1.4 GW Grohnde and 1.5 GW Brokdorf units in northern Germany were scheduled to ramp down during the evening and to be disconnected from the grid around 22:30 local time, according to operator PreussenElektra. The 1.3-GW Gundremmingen-C in southern Germany is already ramping down, with production reaching close to zero by 16:30 CET and disconnection scheduled for 19:00 local time, according to operator RWE's transparency notes on EEX. Spot power prices for Dec. 31 plunged amid a surge in wind above 30 GW. Day-ahead baseload settled at Eur12.13/MWh, the lowest in five months and compared to a record-high Eur416.72/MWh just nine days ago, Epex Spot data shows. Five hours early Dec. 31 settled below zero. Germany's energy and environment ministers Robert Habeck and Steffi Lemke (both Greens) welcomed the closures in a joint statement Dec. 28. Plans to exit nuclear date back two decades to a first coalition of the SPD with the Greens bringing in production quota for reactors. In 2011 after the Fukushima nuclear accident, Germany decided to immediately close reactors built before 1980 and reverse a planned run-time extension for modern nuclear plants by setting mandatory closure dates. So far, only three modern reactors were shut, at end-2015, end-2017 and end-2019. The final six closures are in an unprecedented short period and coincide with coal and lignite plant closures. That, combined with record gas and CO2 prices, pushed German power prices to record highs, with Cal 2022 up fourfold this year closing Dec. 29 at Eur219.88/MWh, exchange data shows. German nuclear generated over 65 TWh of electricity in 2021, covering almost 12% of German power demand. Editor: Jonathan Fox ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/010522-dutch-2021-gas-fired-output-falls-as-coal-gains-bigger-share-in-power-mix</link><description>Gas fired power production in the Netherlands fell in 2021, as coal gained a larger share in the power mix, an analysis by S&amp;amp;P Global Platts showed Jan. 5.</description><title>Dutch 2021 gas-fired output falls, as coal gains bigger share in power mix</title><pubDate>05 January 2022 16:25:00 GMT</pubDate><author><name>Kira Savcenko</name></author><content><![CDATA[ 05 Jan 2022 | 16:25 UTC Dutch 2021 gas-fired output falls, as coal gains bigger share in power mix By Kira Savcenko Highlights Dutch gas-fired generation declines 18% on the year to 40.35 TWh Coal-fired production jumps 69% to 20.5 TWh Dutch gas-fired production to drop to 3.7 GW in 2022: Platts Analytics Gas-fired power production in the Netherlands fell in 2021, as coal gained a larger share in the power mix, an analysis by S&amp;P Global Platts showed Jan. 5. Dutch gas-fired generation declined 18% on the year to 40.35 TWh in 2021, according to data from Fraunhofer ISE, as record high prices made gas unattractive for power production. That boosted coal-fired production 69% on the year to 20.5 TWh, even as aggregate wind output increased on the year. Offshore wind generation jumped 73% to 8.25 TWh, more than offsetting a drop in onshore wind output. Biomass and waste output was down 7% and 5%, respectively, during the year. Aggregate Dutch power demand slipped to 106.5 TWh in 2021, from 108 TWh, a year earlier. January outlook Dutch gas burn in January has been sluggish, as mild weather leads to weak heating demand, with prices favoring coal over gas for electricity generation. Gas-fired generation averaged just about 2 GW Jan. 1-4, according to Fraunhofer, compared with more than 5 GW in January 2021. The Dutch TTF front-month and front-quarter gas contracts have remained firmly above corresponding Coal Switching Price indicators (CSPI) in recent weeks, data from S&amp;P Global Platts Analytics showed. That could discourage strong gas burn in the Netherlands during winter, as the new 50%-efficient gas-fired plants become unprofitable to run, compared with the 40%-efficient coal units. The older 45%-efficient gas plants fell out of favor, as they provided almost the same efficiency, particularly on the near curve, compared with the coal units. Platts Analytics expects Dutch gas-fired production to drop to 3.7 GW in 2022, from 6.4 GW in 2021, with November 2021 and December 2021 production based on scaled data, according to a most recent forecast from Dec. 16. The Netherlands has limited high-calorie gas availability to spare for power generation. Dutch aggregate gas storages were 36.1% full as of Jan. 3, firmly below 67.4%, a year ago, the most recent data from Gas Infrastructure Europe showed. This was driven by low stocks at the high-calorie Bergermeer storage site, where Russia's Gazprom holds considerable capacity, with the facility just 23.3% full Jan. 3. Stock levels of low-calorie gas -- mostly used for heating purposes -- were higher. The weather in the Netherlands is expected to stay milder-than-average until at least Jan. 11, according to CustomWeather, with temperatures in Amsterdam forecast to hold at 2 C above seasonal norms. That could keep heating demand lower, although an ongoing national lockdown in the Netherlands could force people to stay at home longer, driving up consumption. Dutch Power Generation (TWh) 2021 2020 % change Gas 40.35 49.38 -18 Hard Coal 20.5 12.1 69 Wind offshore 8.25 4.77 73 Others 15.78 23.46 -33 Nuclear 3.62 3.87 -6 Wind onshore 4.17 5.08 -18 Waste 3.05 3.22 -5 Solar 0.31 0.16 94 Biomass 0.13 0.14 -7 Source: Fraunhofer ISE Editor: Ankit Ajmera ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/093021-re-balancing-of-europes-gas-power-markets-seen-unlikely-in-q4</link><description>Gas stores at historically low levels French nuclear more robust on year CO2 auction supply to fall 30% on year A rapid re balancing of the European gas market looks an unlikely prospect in Q4 2021 as</description><title>Re-balancing of Europe&amp;apos;s gas, power markets seen unlikely in Q4</title><pubDate>30 September 2021 14:26:00 GMT</pubDate><author><name>Stuart Elliott</name><name>Andreas Franke</name><name>Frank Watson</name></author><content><![CDATA[ 30 Sep 2021 | 14:26 UTC Re-balancing of Europe's gas, power markets seen unlikely in Q4 By Stuart Elliott, Andreas Franke, and Frank Watson Highlights Gas stores at historically low levels French nuclear more robust on year CO2 auction supply to fall 30% on year A rapid re-balancing of the European gas market looks an unlikely prospect in Q4 2021 as prices continued to reach fresh record highs deep into September. With storage stocks at historically low levels for the time of year, Asia beating out Europe for LNG cargoes, and Russia continuing to keep a lid on exports, there is real concern that Europe could face gas shortages through Q4. One potential potential supply-side savior would be an early approval and startup of the Nord Stream 2 pipeline, which could bring much-needed gas into Europe before the end of 2021. But with the German regulator allowed to take up to four months -- to January -- to publish a draft decision, there is a real risk Nord Stream 2 will remain idle until well into 2022. The unprecedented market tightness has left producers other than Russia supplying as much gas as possible to the market, from the UK, to Norway, Algeria and Azerbaijan. Any unexpected disruption in the upstream in any of these countries could be disastrous for European balances in the absence of significant LNG supplies. S&amp;P Global Platts Analytics sees more LNG coming to Western Europe in Q4 than the same period of 2020, however, which could bring some relief. It forecast net imports of 224 million cu m/d in the October-December period, up from 193 million cu m/d in the fourth quarter of 2020. But with Platts JKM LNG price still at a premium to the TTF -- and the two benchmarks chasing each other ever higher to secure spare spot cargoes -- much will depend on the weather in the respective regions. A cold winter could spell "trouble" for Europe, France's Engie said late September. According to Platts Analytics, the market may need to balance on more demand destruction or substitution. "Beyond hoping for mild weather, there is no one clear solution to our balancing needs this winter, not even Nord Stream 2." It may turn out that Q4 will end up being a demand story in European gas, with gas-guzzling fertilizer plants already having been idled or production curtailed. "We forecast industrial gas demand destruction (especially fertilizers) and refineries switching from gas to liquids, as well as the final unprecedented source of flexibility which is gas-to-oil switching in the power sector," Platts Analytics said. While gas demand in the residential sector was expected to remain flat in Q4 versus the same quarter of 2020, Platts Analytics expects 14 million cu m/d of demand destruction and switching in the industrial sector, and 30 million cu m/d of gas giving market away to coal and oil generation in the power sector. Of course, not all European gas buyers are paying the current spot prices -- Russia's long-term contract holders have been in part protected from the price increases as their prices are calculated using a different formula. Some Russian long-term contracts are still partly indexed to oil, while others use a hybrid of short- and medium-term hub indexation, often with a time lag of 6-9 months. But with Russia seemingly linking approval of Nord Stream 2 with additional gas supply, it is coming under increasing pressure to act now to help supply the European market. The International Energy Agency said late September that Russia "could do more" to increase gas availability in Europe and help full storage sites, which remain low for the time of year, built to just 74% of capacity by Sept. 26. A cold winter could also tighten an already struggling supply outlook, with LNG continuing to be pulled to Asia by the sky-high JKM spot LNG price, which Platts assessed Sept. 30 at a record $34.47/MMBtu. Scope for coal switching Europe's power markets have tracked the gas rally closely, indicating any material correction would only come from a re-balancing in supply and demand. "A major factor behind the increased sensitivity of power prices to gas is coal and nuclear closures over recent years," Platts Analytics head of European power analysis Glenn Rickson said. Germany alone is set to retire 10 GW of coal and nuclear capacity in 2021. "There is some scope for coal capacity to return online as well as a limited amount of gas-to-oil switching this winter," Rickson said. Gas-fired generation's share in the power mix is set to fall below 20% in Q4 across the 10 markets modeled by Platts Analytics, with a 13 GW average year-on-year decline forecast. That would likely be offset by coal and lignite burn some 10 GW higher for the period, with Germany's remaining 15 GW of lignite plant maxed out. Marginal year-on-year gains for nuclear dispatch and wind and solar capacity would offset a lower hydro forecast, while Q4 power demand would be up 2% year on year based on average temperatures. "Germany's exposure to wind generation on the back of 4 GW nuclear closures by end-2021 will likely spur high price volatility in Q1-22," Sabrina Kernbichler at Platts Analytics said. More generally, new power cables may help subdue some of the volatility, with all eyes on operational testing of the NSL and Eleclink cables to the UK, following an enforced outage on the 2 GW IFA 1 link to France. UK nuclear output is forecast to average 5.8 GW in Q4, the lowest since 2008, while French nuclear output is forecast at 44 GW, a recovery on last year. The gas rally has lifted year-ahead power to a record Eur122/MWh in France, almost triple the regulated ARENH price at which EDF has to sell 100 TWh to domestic suppliers. While there is pressure to increase ARENH volumes for 2022, it has been resisted by the government. In summary, upside risk remains despite current high pricing, but a mild winter and strong wind generation after a disappointing first nine months could rapidly change that picture. EU carbon supported EU carbon futures contracts for December 2021 delivery are expected to trade at Eur59/mt in October and November and Eur60/mt in December, Platts Analytics forecast in its European Emissions Trading System Market Outlook Sept. 22. December 2021 EUA futures prices already rallied to a fresh intra-day high of Eur65.06/mt Sept. 27, suggesting demand remained strong from compliance entities and financials alike. "Rising gas prices continue to provide fuel switch price signals in favor of coal generation, with risk of demand destruction; non-emitting generation [was] robust in August but fell in early September to lift coal generation and support EUAs," Platts Analytics said. On the supply side, carbon auction volumes in Q4 are set to average at just under 45 million mt/month, down nearly 30% year on year, excluding UK volumes and after removals by the Market Stability Reserve. The sharp year-on-year drop in supply is partly driven by the inflated volumes over September to November 2020, which included additional volume from Poland and other sources. Upside risks for the carbon price outlook include ongoing tight natural gas markets in Europe, as described above. A possible downside risk could emerge from industrials selling free allocations of allowances who may decide to take advantage of current record-high prices. However, that factor may ultimately be mitigated by concerns over a longer-term shortage, prompting companies to hold on to any surplus volume. Editor: Daniel Lalor ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/122120-scottishpower-sets-up-hydrogen-business-targets-industry-transport-food</link><description>ScottishPower has set up a dedicated green hydrogen business with first projects launched next year to focus on high temperature industrial processes, heavy transport and food and drink sectors, the I</description><title>ScottishPower sets up hydrogen business, targets industry, transport, food</title><pubDate>21 December 2020 11:20:00 GMT</pubDate><author><name>Henry Edwardes-Evans</name></author><content><![CDATA[ 21 Dec 2020 | 11:20 UTC â London ScottishPower sets up hydrogen business, targets industry, transport, food By Henry Edwardes-Evans Highlights Follows parent Iberdrola's 600 MW electrolysis goal 'Significant contribution' to UK's 5 GW target Dedicated UK hydrogen strategy due early 2021 ScottishPower has set up a dedicated green hydrogen business with first projects launched next year to focus on high-temperature industrial processes, heavy transport and food and drink sectors, the Iberdrola-owned utility said Dec. 21. In November, Iberdrola outlined plans to develop 600 MW of electrolysis-based green hydrogen capacity in mainland Europe by 2025. "As we move towards Net Zero, electrification will only take us about 80%-90% of the way, what's left is a number of sectors and industry that will require further support," said Barry Carruthers, ScottishPower's hydrogen director. "We can take our expertise and knowledge in the development and operation of renewables and apply it to the roll-out of green hydrogen in areas where electrification can't reach," he said. Earlier this year ScottishPower, electrolysis company ITM Power and industrial gas company BOC announced a partnership to develop green hydrogen production facilities with clusters of refueling stations across Scotland. The partnership targets local authorities and others with fleets of heavy duty vehicles. It aims to supply hydrogen to the commercial market within two years. "The new hydrogen business will continue with this work and look to replicate its success with other partnerships over the coming years," ScottishPower said. It would look to work with the steel, petrochemicals, ammonia and distillery sectors, making "a substantial contribution" to the UK government's goal of 5 GW of low-carbon hydrogen production by 2030. "As with all new, emerging technologies, we need a mechanism from government to allow the investment needed to boost competition in green hydrogen," Carruthers said, referencing the UK's support for offshore wind, and the resultant cost efficiencies. Scotland is well-placed to run electrolysers using its vast wind power resource. In November, UK balancing costs exceeded GBP200 million, largely due to constraint costs on north-south transition lines caused by surplus wind power generation in Scotland. Using this excess wind generation would provide a low-cost feedstock to electrolysis assets while reducing network system costs. On Sunday, Dec. 20, UK wind generation peaked at 17.28 GW between 1300-1330 GMT, a new record, National Grid said. Wind represented 43.2% of the generation mix at the time. Scottish wind capacity stands at 9.5 GW, with a further 14 GW consented or in planning. Presenting the government's Energy White Paper Dec. 14, Secretary of State for Business Alok Sharma said "we will switch to new, clean fuels such as hydrogen for heat, power and industrial processes." A dedicated hydrogen strategy would be published in early 2021, he said. Working with industry, the government aimed for 5 GW of low-carbon hydrogen production by 2030, producing 42 TWh of hydrogen per year by then, with an interim target of 1 GW installed by 2025. Some GBP240 million would be available through the Net Zero Hydrogen Fund up to 2024/25, it said. "A variety of production technologies will be required to satisfy the level of anticipated demand for clean hydrogen in 2050. This is likely to include methane reformation with CCUS [carbon capture, utilization and storage], biomass gasification with CCUS and electrolytic hydrogen using renewable or nuclear generated electricity," the white paper said. The UK currently produces 27 TWh/year of conventional hydrogen. Editor: James Leech ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/energy-transition/092721-analysis-shift-in-energy-policy-in-spotlight-for-japans-leadership-change</link><description>Japan&amp;apos;s impending leadership change, which would typically not change the course of its energy policy, is in the spotlight due to a potential major shift in focus after the ruling Liberal Democratic P</description><title>Analysis: Shift in energy policy in spotlight for Japan&amp;apos;s leadership change</title><pubDate>27 September 2021 06:30:00 GMT</pubDate><author><name>Takeo Kumagai</name></author><content><![CDATA[ 27 Sep 2021 | 06:30 UTC Analysis: Shift in energy policy in spotlight for Japan's leadership change By Takeo Kumagai Highlights Japan set to decide strategic energy plan, NDC Renewables boost to be priority under new government Contrasting views on use of nuclear power Japan's impending leadership change, which would typically not change the course of its energy policy, is in the spotlight due to a potential major shift in focus after the ruling Liberal Democratic Party votes to elect a new president on Sept. 29. Four candidates -- Taro Kono, Fumio Kishida, Sanae Takaichi and Seiko Noda -- are running in the LDP's presidential election after Prime Minister Yoshihide Suga's abrupt announcement Sept. 3 that he would not re-seek the ruling party's leadership. Suga's decision not to contest paves the way for a new premier in October when the new cabinet will approve the country's new Strategic Energy Plan, as well as submit its Nationally Determined Contribution or NDC ahead of the 26th UN Climate Change Conference of the Parties (COP26) in Glasgow over Oct. 31-Nov. 12. The draft Strategic Energy Plan, Japan's principle energy policy, calls for non-fossil fuel power supply sources to account for roughly 60% by fiscal year 2030-31 (April-March). The draft NDC aims for a 46% cut in the country's greenhouse gas emissions by the same fiscal year. Both are currently undergoing a month-long public comment process until Oct. 4. Regardless of who becomes the next LDP president and premier, there is no turnaround in Japan's push for renewables as outlined in the draft Strategic Energy Plan, with its climate policies to be among the key priorities in its 2050 carbon neutrality pathway. "Climate policy should be equally or more important for the new Japanese leadership, relative to the Suga government," said Jane Nakano, senior fellow in the energy security and climate change program at the Center for Strategic and International Studies. "The Japanese public will be better served by a national leader who has a strong grasp of the magnitude of the climate challenge and an ability to proactively seize on some potential opportunities," Nakano said. "The Biden administration would welcome a new leader who shares its sense of urgency in addressing climate crisis, and work with the United States as partners." Nuclear policy Japan's nuclear power policy and renewables are among the key areas that could be approached and emphasized differently by each candidate. So far Kono, the minister in charge of administrative reform; Kishida, former chairperson of the LDP policy research council and foreign minister; Takaichi, former minister for internal affairs and communications and Noda, the LDP executive acting secretary-general, all agree on the need to utilize operable nuclear power plants to ensure Japan's stable energy supply. However, there is a distinctive difference between Kono and Takaichi's public stances on nuclear power policy, with the former advocating letting nuclear power plants phase out without newbuilds and the latter accelerating developments of small modular reactors and nuclear fusion reactors. "Should Taro Kono become prime minister, that would likely result in a big push for renewable power in Japan," said Henning Gloystein, director of global energy and natural resources at Eurasia Group. "And although he has recently moderated his well-publicized critical views on nuclear power, the atomic energy industry would almost certainly stall under a government led by him," Gloystein added. Japan, which has maintained a target share of 20%-22% nuclear power in the electricity mix by FY 2030-31 in the draft Strategic Energy Plan, has restarted only 10 nuclear reactors under new regulatory standards introduced in 2013 -- a sign that the country has made little progress in restoring public trust after the 2011 Fukushima nuclear crisis. "Currently, the life of Japan's nuclear power plant is 40 years and 60 years even after operational extension," Kono said during a Sept. 18 public debate among the LDP leadership candidates. "Nuclear power will gradually decrease as reactors reaching the life [of service limit] get decommissioned." Japan's current "biggest issue" with nuclear power is that it has not been able to decide how to process nuclear waste, Kono said at the time, calling for discussion on realistic processing methods. Nobuo Tanaka, former executive director of the International Energy Agency, agrees on the need for initiating serious discussions under a new cabinet to consider ways of processing spent nuclear fuel and fuel debris from the Fukushima crisis. "Japan's emerging significant issue is the spent nuclear fuel and the processing of fuel debris at Fukushima," said Tanaka, who is currently chairman of the Innovation for Cool Earth Forum's steering committee. "Japan will need to reduce nuclear waste from processing the spent fuel and reduce radioactive material from processing the debris." Serious discussions will be needed over the development of small modular fast reactors, which could be used for processing nuclear waste, as well as being used for industries and producing hydrogen for decarbonization, Tanaka said. Boosting renewables Kono's public remarks on phasing out coal, oil and natural gas, while maximizing and prioritizing renewables' introduction for 2050 carbon neutrality, also suggest a possible shift in Japan's energy policy focus. "In order to achieve the 2050 carbon neutrality and curb climate change, we need to stop coal and oil first and eventually make a break away from natural gas," Kono said during a Sept. 10 press conference. The Ministry of Economy, Trade and Industry's 2050 power source idea released last December included nuclear as a carbon-free source, together with fossil fuels, with carbon capture, utilization and storage, and carbon recycling, accounting for 30-40%, renewables for 50-60% and hydrogen and ammonia about 10%. "If Japan is serious about achieving its net zero emissions target by 2050, which we assume any new government will be, then the cuts to the country's thermal coal usage will have to start soon," Gloystein said. "Some of that will be replaceable via LNG, but even natural gas usage will need to gradually be dialed back to get near net zero." Editor: Wendy Wells ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/081821-eu-wind-solar-peak-at-123-gw-helping-to-ease-record-spot-power-prices</link><description>Wind and solar power generation across EU markets peaked at 123 GW Aug. 17 amid a spell in wind that helped ease record spot power prices, grid operator data aggregated by WindEurope show.</description><title>EU wind, solar peak at 123 GW helping to ease record spot power prices</title><pubDate>18 August 2021 11:01:00 GMT</pubDate><author><name>Andreas Franke</name></author><content><![CDATA[ 18 Aug 2021 | 11:01 UTC EU wind, solar peak at 123 GW helping to ease record spot power prices By Andreas Franke Highlights Rare surge in wind, YTD trails 2020 by over 10% Gas, coal generation costs exceed Eur100/MWh Aug. thermal gap at record-low: Platts Analytics Wind and solar power generation across EU markets peaked at 123 GW Aug. 17 amid a spell in wind that helped ease record spot power prices, grid operator data aggregated by WindEurope show. The brief surge in wind reduced demand for gas and coal generation with average generation costs for such plant now exceeding Eur100/MWh ($118/MWh), S&amp;P Global Platts data show. Generation cost for a 50% efficient gas plant rose above Eur117/MWh both for September and Q4 2021, boosting forward power contracts as fuel and carbon costs hit record highs. Excluding carbon, gas-fired generation costs across the Northwest Europe region were still around Eur96/MWh as TTF gas prices soared to Eur47/MWh, Platts data show. Spot power prices eased with August to date in Germany averaging around Eur75/MWh after July's Eur81/MWh average was the highest since 2008, exchange data show. September however settled at Eur97.62/MWh Aug. 17 on EEX with most European winter power contracts now above Eur100/MWh. According to Platts Analytics, below average wind load factors have contributed to the strength in power prices and the wider fuel and carbon complex for most of 2021 so far. High wind dispatch alone however would fail to bring prices in line with recent years, it said in a monthly report Aug. 12 testing a high wind scenario for winter. For the 10 markets modeled, Platts Analytics' base case scenario pegs average Q4 wind generation flat on year at 47 GW. Wind generation in Europe's five biggest markets was down 12% on year for the January to July period at a 32 GW average, according to Platts Renewables Tracker. Solar production was up only 1% on year averaging 15.9 GW across the five markets so far this year despite strong capacity growth leading to an all-time high in June. In addition, improved nuclear, robust hydro and easing pressure on demand in a year-on-year comparison have led to Europe's thermal gap (gas and coal) shrinking to a record-low this August, according to Platts Analytics. Europe's biggest power market Germany was on track for record-low combined gas/hard-coal generation averaging only 4.4 GW so far this August compared to a 6.4 GW average in April 2020, the previous low, grid data show. Overall Germany was set for the biggest on year increase in CO2 emissions since 1990 amid a rebound for lignite and strong gas demand in the first half of 2021, topping the energy mix for the first time ahead of oil, while the share of renewables fell due to low wind speeds. Editor: James Leech ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/coal/082721-factbox-china-takes-contingency-measures-to-shore-up-generation-fuel-supply</link><description>Factbox: China takes contingency measures to shore up generation fuel supply, ensuring energy security and stability amid market and geopolitical challenges.</description><title>Factbox: China takes contingency measures to shore up generation fuel supply</title><pubDate>27 August 2021 04:49:00 GMT</pubDate><author><name>Staff and Eric Yep</name></author><content><![CDATA[ 27 Aug 2021 | 04:49 UTC Factbox: China takes contingency measures to shore up generation fuel supply By Staff and Eric Yep China has carried out a series of contingency measures in the past few months to prevent coal and power supply disruptions, and curb price spikes amid peak summer demand and surging international prices. The measures underscore the government's role in Asia's generation fuels markets and prices. Steps to boost coal production and inventories will last well beyond the summer months into winter, and ease pressure on LNG demand. More stringent measures can be expected during the coming winter when fuel shortages peak. Prices **S&amp;P Global Platts JKM benchmark for spot LNG more than tripled from around $5.50/MMBtu in March to just under $18/MMBtu in the week of Aug. 21-27. **September thermal coal futures hit an all time high of Yuan 989.8/mt on China's Zhengzhou Commodity Exchange Aug. 23. **S&amp;P Global Platts Northeast Asia Thermal (NEAT) Coal Index hit an all-time high of $132.20/mt Aug. 26. Trade Flows **S&amp;P Global Platts Analytics expects China to become world's largest LNG importer in 2021, surpassing Japan by nearly 10%. Total Chinese LNG imports are expected to grow by more than 20% in 2021 versus 2020. **Over January-July, China's natural gas imports totaled 68.96 million mt, or 95.09 Bcm, up 24% from a year earlier, customs data showed. **China's natural gas demand is forecast to hit a record high 365-370 Bcm in 2021, up 37-42 Bcm, or 11.3%-12.8%, from realized consumption of 328 Bcm in 2020, the National Energy Administration said Aug. 21. **China's power consumption hit multiple record highs daily in July, rising 12.8% year on year, and posting a 15.6% increase for the first seven months of 2021, according to National Development and Reform Commission data. **China's power generation was above 4,645 TWh over January-July, up 13.2% year on year, but still lagged power consumption growth of 15.6% over the same period, data from the China Electricity Council showed Aug. 18. **In the first half of 2021, 1,702 TWh of electricity had traded in China's power trading centers in the first half of 2021, up 41.6% year on year, of which 1,377 TWh had traded via medium and long-term contracts, according to the CEC data. **China's coal imports dropped 19.7% year on year in the first half of 2021, while coal output grew 6.4% year on year, the CEC data said. **The CEC estimates China's total power generation capacity will reach 2,370 GW by end-2021, up 7.7% year on year. Out of this, coal-fired power capacity will stand at 1,100 GW, non-fossil fuel sources, including solar, wind, hydro, nuclear and biomass, will be around 1,120 GW. Contingency Measures **China's Inner Mongolia Shanxi, Shaanxi, Ningxia and Xinjiang provinces started 15 suspended coal mines with total production capacity of 43.5 million mt/year, or 150,000 mt/day of coal output, the NDRC said Aug. 13. **Inner Mongolia approved land use for 38 coal mines in Ordos City with total coal production capacity of 66.7 million mt/year, the NDRC said July 30. The province has applied for seven more coal mines, with production capacity of 120 million mt/year and projected output of 3.5 million mt/month, the NDRC said Aug. 11. **China plans to boost national coal reserves to around 600 million mt, or 15% of annual consumption, of which the government's dispatchable coal reserve will be no less than 200 million mt and the rest will be stored by companies, adjusted through inventories, the NDRC said July 16. **The NDRC and NEA agreed to extend trial operations of coal mines for one year and requested local governments speed up license approvals, the NDRC said Aug. 4. **The NDRC, NEA and the General Department of the National Mine Safety Supervision Bureau issued a notice to encourage coal mines to increase production, the NDRC said July 30. **On July 29, the NDRC approved a 20% increase in retail electricity tariffs during peak demand hours to improve the power supply. **The NDRC on July 28 asked major coal producers to prioritize thermal coal supplies to Henan province, mainly to 27 power plants and one coal reserve base, after devastating floods. Coal supplies to other flood hit areas like Hebei province and Yangtze River Delta were also ramped up, the NDRC said. **The NEA released 128,000 mt of coal reserves to southern China over July 16-18, the NDRC said July 28. On June 27, it announced plans to build up to 200 million mt of deployable coal reserves, with 100 million mt ready in 2021. **The NDRC issued notices to six major power generation companies to increase coal stocks equivalent to at least seven days of consumption by July 21, Shanghai based Jiemian News reported July 19. **China will release more than 10 million mt of coal from state reserves, adding to more than 5 million mt already released in past four batches in 2021, the NDRC said July 15. **In June, regulators visited major coal hubs and trading centers to investigate coal inventories and prices, and crack down on speculation and hoarding. Editor: Norazlina Jumaat ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/metals/120321-saudi-arabia-nigeria-kyrgystan-seek-investors-to-develop-their-mining-gdp</link><description>Saudi Arabia, Nigeria and Kyrgystan are seeking new investors to develop their mining GDP, government representatives told the Mines and Money conference in London this week. Saudi Arabia and Nigeria,</description><title>Saudi Arabia, Nigeria, Kyrgystan seek investors to develop their mining GDP</title><pubDate>03 December 2021 21:45:00 GMT</pubDate><author><name>Diana Kinch</name></author><content><![CDATA[ 03 Dec 2021 | 21:45 UTC Saudi Arabia, Nigeria, Kyrgystan seek investors to develop their mining GDP By Diana Kinch Highlights Saudi Arabia, Nigeria to auction mineral projects Kyrgystan wishes to open up to western investors Saudi Arabia, Nigeria and Kyrgystan are seeking new investors to develop their mining GDP, government representatives told the Mines and Money conference in London this week. Saudi Arabia and Nigeria, which both aim to use mining to reduce their economic dependence on oil, plan to proceed with a program of auctions of mineral deposits in the near future; and in the case of Nigeria next year, they said. Development of these resources may help overcome what is expected to be a supply gap in coming years for energy transition materials including lithium, copper, cobalt and rare earth elements, demand for which is rising rapidly for use in electric vehicle batteries and engines and windpower turbines, they said. "There is a significant risk of future undersupply," Khalid bin Saleh Al-Mudaifer, Saudi Arabia's vice minister of mining affairs of the kingdom's ministry of industry and mineral resources, told delegates at the event. It is crucial to maintain supply chains as a potential supercycle emerges in some mineral commodities, he said. Saudi Arabia, Nigeria and Kyrgystan propose to offer tax holidays or funding incentives and access to geological data to new mine investors. Saudi Arabian minerals 'underexplored' Saudi Arabia's Al-Mudaifer said the kingdom's mineral wealth is "largely underexplored" but that $50 million has over the last ten years been invested by the private and public sectors, including in development of phosphates and bauxite, allowing the country to become a global player in these areas. The kingdom also has reserves of copper, silver, tantalum, tin, niobium, zinc, uranium, iron ore and others. Overall, 130 exploration licenses and eight new mine exploitation licenses have recently been granted, he said. "Mining will be a third pillar of the Saudi economy after oil &amp; gas and petrochemicals and we have now launched a mining strategy with more than 37 initiatives," the vice minister said, noting the country is "on track" with its Vision 2030 social and economic development strategy, launched in 2016. "We want to reduce our mineral imports by 65%," he said, noting that the kingdom currently imports a number of minerals. The kingdom, a major oil producer, aims to derive 50% of its energy from renewables by 2030 and is building a 3 million mt green hydrogen plant, he said. The kingdom is to hold a Future Minerals Summit in Riyadh January 11-13, 2022 to discuss investment opportunities, Al-Mudaifer said. Nigeria: new discoveries Abdulrazaq Garba, director general of Nigeria's ministry of mines and steel development, noted that 17 new orebodies have recently been identified in the west African nation, rich in iron ore, hardrock lithium, tin, lead, zinc, copper and gold. "Mining in Nigeria is still very fresh, we're new in this area," Olamilekan Adegbite, minister of mines and steel development, told delegates. Some of Nigeria's minerals are found very near the surface, meaning that production costs can be low, for instance of just $600/oz for gold, he said. "We're also encouraging processors to come to Nigeria," he said. As much as 85% of the mining sector's activity in Nigeria is informal, there is limited government spending in the sector and formalization could bring benefits, said Hijiya Fatima Shinkafi, executive secretary of the country's Solid Minerals Development Fund (SMDF). There are many projects in Nigeria at the exploration stage and limited government spending in the sector, Shinkafi said. The SMDF is being set up with the aim of investing $500 million in the mining sector, which is expected to unlock $1 billion in third-party investments and financing. It is hoped that within five years mining revenues could grow ten-fold to account for 3% of Nigeria's economic wealth, she said in a presentation. Established projects in Kyrgystan Kyrgystan is seeking investors for various mine projects containing copper, gold, vanadium, rare earth elements, tantalum, niobium, molybdenum, iron ore and others, said Tengiz Bolturuk, CEO of the National Holding Company of Kyrgystan. The country has a new mining code based on a Canadian mining code and best international practices, he said. Chinese investors are interested in the Djetym magnetite iron ore 32-36% Fe project, which is sited about 150 km from the Chinese border, Bolturuk said. Drilling is expected to start at the Andash copper and gold deposit while the Kutessay rare earths deposit is at the pre-feasibility study stage and the Taldybulak molybdenum, copper and gold project, with reserves of 26,438 mt of copper, was previously drilled in the 1980s and 1990s, he said. "We would like to open up for western investors," Bolturuk told delegates. The country is also seeking investors in logistics, including water supplies and the internet, and has more than 200 small hydropower projects, he said. Editor: Tom Balcerek ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/031822-new-realism-set-to-slow-energy-transition-extend-thermal-generation-contourglobal</link><description>The current geopolitical turmoil will slow the energy transition and extend the role for generation based on lignite coal, nuclear and LNG, independent generator ContourGlobal said March 18 in an annu</description><title>New realism set to slow energy transition, extend thermal generation: ContourGlobal</title><pubDate>18 March 2022 10:25:00 GMT</pubDate><author><name>Henry Edwardes-Evans</name></author><content><![CDATA[ 18 Mar 2022 | 10:25 UTC New realism set to slow energy transition, extend thermal generation: ContourGlobal By Henry Edwardes-Evans Highlights Extended role for lignite, nuclear, LNG based generation Renewable developers being more selective about projects European power market moving towards more regulation The current geopolitical turmoil will slow the energy transition and extend the role for generation based on lignite coal, nuclear and LNG, independent generator ContourGlobal said March 18 in an annual results statement. At the same time, supply chain and financing pressures were being felt acutely in greenfield renewable energy development, the generator said. "A new realism about the geopolitics of electricity supply emphasizing the need for diverse sources of baseload generation and decreased reliance on Russian gas supports our view that we are in the midst of a lengthier transition which will see a larger than previously expected role for power generation based on lignite coal, nuclear and liquefied natural gas," ContourGlobal CEO Joseph C Brandt said. For the first time in seven years, meanwhile, developers with large pipelines of renewable energy projects were being more selective about which projects to progress. "Gone are the days when renewable developers boasted of enormous pipelines all of which were expected to be built," Brandt said. The dramatic increase in gas and power prices had led to a fundamental review of power market design, he said. "We have been saying for four years that the future of the European power generation market looked to be increasingly a regulated one with the abandonment of marginal cost pricing and its replacement with some form of a guaranteed regulated rate of return applied to the entire generation sector," Brandt said. Numerous policy proposals have been floated by European governments and the European Commission to reduce the impact of rising energy prices on consumers and businesses. "Such polices may alter the markets into which electricity from our plants is sold, impacting the profitability of uncontracted power plant such as [the 800-MW Spanish combined cycle gas plant] Arrubal," the company said. At the same time, the introduction of regulated pricing contained in recent proposals would positively impact ContourGlobal's European thermal fleet, it said. The generator reported 2021 thermal generation volumes up 47% year on year to 16.53 TWh, and renewable volumes up 5% to 5.01 TWh. Adjusted revenue of $1.73 billion was up 38% year on year while adjusted gross earnings were up 17% to $842 million. Net profit climbed 176% to $80 million. In Europe, ContourGlobal owns the 908-MW Maritsa East 3 coal plant in Bulgaria as well as the Arrubal CCGT. It has solar assets in Spain and Slovakia and wind farms in Austria. Globally it has 4.5 GW of thermal capacity and 1.8 GW of renewable capacity. Solar PV and solar CSP factors of 14% and 19% respectively were relatively stable year on year, as was an Austrian wind capacity factor of 23%. Editor: Alisdair Bowles ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/energy-transition/051622-fortescue-to-explore-turning-washington-coal-mine-into-green-hydrogen-facility</link><description>Fortescue Future Industries will explore the possibility of transforming a Washington coal mine that once supplied a 670 MW coal plant into a green hydrogen production facility, Fortescue has said.</description><title>Fortescue to explore turning Washington coal mine into green hydrogen facility</title><pubDate>16 May 2022 20:58:00 GMT</pubDate><author><name>Brandon Mulder</name></author><content><![CDATA[ 16 May 2022 | 20:58 UTC Fortescue to explore turning Washington coal mine into green hydrogen facility By Brandon Mulder Highlights Site ended surface coal mining in 2006 Facility would be part of hydrogen hub proposal Fortescue Future Industries will explore the possibility of transforming a Washington coal mine that once supplied a 670-MW coal plant into a green hydrogen production facility, Fortescue has said. Fortescue Future Industries, a subsidiary of the Australian iron ore company Fortescue Metals Group, entered into a binding exclusivity agreement announced May 13 with the Industrial Park at TransAlta, a non-profit formed to promote redevelopment of 4,400-acres in Lewis County formerly used for coal mining. Coal removal ended in 2006. The adjacent Centralia coal plant, owned by TransAlta, is slated to fully retire in 2025 after over 50 years of operation. In 2020 it retired its first power generation unit, bringing its capacity from over 1,300 MW to 670 MW. Fortescue said in a statement that it plans to employ the existing coal workforce in the proposed green hydrogen project. "FFI's goal is to turn North America into a leading global green energy heartland and create thousands of green jobs now and more in the future," said Chairman and Founder Andrew Forrest. "Repurposing existing fossil fuel infrastructure to create green hydrogen to power the world is part of the solution to saving the planet." Fortescue also announced that the proposed green hydrogen plant would be part of a bid to develop the region into the Pacific Northwest Hydrogen Hub using grant dollars from the Infrastructure Investment and Jobs Act passed last year. The company said it plans to apply for hydrogen hub grant funding with other regional stakeholders, including Puget Sound Energy, Washington Maritime Blue, Twin Transit and the Lewis County Energy Innovation Coalition. The infrastructure bill earmarked $8 billion for the Department of Energy to support the creation of at least four regional hydrogen hubs. Through a competitive application process, the bill requires the DOE to select at least one hub that uses fossil fuel as a feedstock, one hub that uses renewable energy as a feedstock and one hub that uses nuclear energy as a feedstock. It also requires each hub to focus on a different category of end-users â electric power generators, industrial users, the residential and commercial heating sector, and transportation. Fortescue CEO Paul Browning indicated in the company's announcement that green hydrogen produced out of the Pacific Northwest Hydrogen Hub would help decarbonize the region's transportation sector and heavy industries. "The electric power grid of the Pacific Northwest is one of the lowest carbon power grids in the world and can be used to produce green hydrogen, and could extend the region's low carbon leadership to hard to electrify sectors like long-haul trucking, ports, aviation, and heavy industry," Browning said. The Department of Energy closed its second request for information round for the hydrogen hub selection process March 21. It received over 300 responses, indicating a high level of interest. After a review of its 300-plus responses, the department will initiate a request for proposals, wherein regional groups will submit applications for the funding. It's not yet known when the department will issue the RFP. Other regions â like the US Gulf Coast, Southern California, the Rocky Mountain region, New York, West Virginia and the Washington area â have also signaled strong interest in federal hub funding. According to Platts price assessments, hydrogen produced using PEM electrolysis in Northwestern US fell to $4.20/kg (including capex) on May 13 since a high of $7.48/kg on May 3. Its $4.20/kg cost is the lowest price across the US as of May 13. Editor: Richard Rubin ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/blog/electric-power/081621-ctracker-coal-price-lng-power-weak-freight-gas-storage</link><description>High global gas and LNG prices are impacting the power mix in countries as far apart as Germany and Bangladesh. Plus, Middle East-China tanker freight rates, US gas prices and Asian refining.</description><title>Commodity Tracker: 5 charts to watch this week</title><pubDate>16 August 2021 09:35:00 GMT</pubDate><author><name>S&amp;P Global Platts</name></author><content><![CDATA[ 16 Aug 2021 | 09:35 UTC â Insight Blog Commodity Tracker: 5 charts to watch this week By S&amp;P Global Platts High global gas and LNG prices are impacting the power mix in countries as far apart as Germany and Bangladesh. Plus, Middle East-China tanker freight rates, US gas prices and Asian refining. 1. Coal surges in German power mix as wind drops, gas price soars What's happening? Lignite was the main source of electricity generation in Germany in the week to Aug. 8, with renewable generation sharply lower across the period. Margins for lignite and hard coal-fired generation stood at Eur12.24/MWh on Aug. 6 versus minus Eur13.77/MWh for gas-fired generation, ensuring coal ran ahead of gas where possible. Increased fossil-fired power in general is in part due to a below-norm year for wind speeds in Europe. On Aug. 12 Orsted reported an average offshore wind capacity factor of just 29% for H1 2021 vs a five year average in the UK of around 38%. What's next? With the gap between coal and gas generation spreads so wide there is every chance coal will continue to run ahead of gas. Ahead of the season change and an expected improvement in wind input, gas looks set to remain the price-setting unit, with front-month German power trading as high as Eur96.00/MWh, a 13-year high. On Aug. 11 German utility Uniper said its CO2 emissions had risen 19% in H1 due to a 45% hike in fossil firing year on year (see chart). It expected similar levels of coal generation for H2 2021, maintaining H1's higher carbon intensity. 2. High spot LNG prices could drive oil switching for power generation in South Asia What's happening? With the recent rise in spot LNG prices, HSFO is becoming cheaper than LNG for power generation in Asia. This price signal is strong and consistent from September to March, effectively covering the entire winter period. What's next? S&amp;P Global Platts Analytics expects countries in South Asia to take advantage of the situation and switch some volumes from imported spot LNG to oil for power generation. In Bangladesh and Pakistan there is a combined switching potential of about four LNG cargoes per month. Platts Analytics assumes initial switching will start in September and reach full potential a couple of months later. The volume to be switched also depends on top-line power demand, which could be at risk as both countries are under partial lockdown due to COVID-19. 3. Shipowners idle tankers amid weak VLCC freight on Persian Gulf-China route What's happening? China's high onshore stock levels and oil price have deterred the world's largest crude oil importer from chartering ships in the market. The weak VLCC market has left many VLCC owners with negative earnings for a prolonged period of time. Freight on the benchmark Persian Gulf to China route has traded in a very narrow range of Worldscale 31.5 to w33 this year. Although bunker prices have spiked, owners are unable to transfer the higher operating cost to charterers. To cut losses, some VLCC owners have decided to lay-up their ships â that is, temporarily idle and remove them from commercial service. This will result in some tonnage being removed from commercial operations till freight levels improve. What's next? According to Platts Analytics, stocks from inventories were drawn down in July and August in China, while fresh stock buildup is expected to resume later this year. On the flipside, with new coronavirus variants emerging, Platts Analytics has revised down growth for the third quarter of 2021 due to restrictions imposed in Asia in response to the resurgent virus. Due to the glaring imbalance between tonnage supply and loading demand, a strong recovery isn't expected in the short term even with the OPEC+ gradually easing production cuts. However, VLCC owners are pinning their hopes on small gains being made during the typically strong winter season that spurs crude demand. 4. Enduring US gas storage deficit fuels winter price rally at Henry Hub What's happening? US natural gas storage remains at a persistent deficit this summer with less than three months remaining for the current injection season. For the week ended Aug. 6, inventories are estimated at 2.776 Tcfâ178 Bcf, or nearly 6.5%, below the prior five-year average, according to the latest report from the US Energy Information Administration. For the coming two reporting weeks, Platts Analytics is forecasting injections to fall a cumulative 12 Bcf short of the historical average, further widening the inventory shortfall. What's next? Rising alarm in the forwards markets over this season's storage deficit is fueling a sustained rise in winter gas prices at the Henry Hub. For the peak-demand month of January 2022, gas prices have recently settled as high as $4.40/MMBtu. If realized, the upcoming January gas price would be the highest monthly average on record for the benchmark index in over seven years, S&amp;P Global Platts data shows. With annual production and supply gains forecast to outpace demand growth only narrowly this winter compared to last, Henry Hub forwards prices could see even more upward pressure in the weeks ahead. 5. Asian refiners see jet fuel as most profitable product post pandemic What's happening? Major Asian refiners are cautiously optimistic jet fuel sales will significantly boost their profit margins from the first quarter of 2022 as the companies broadly expect international flight routes to rapidly open up from February next year, anticipating over half of East Asia's population to be vaccinated by then. Out of 11 major Asian refiners surveyed by S&amp;P Global Platts, including PetroChina, SK Innovation, ENEOS, Idemitsu, Petronas, S-Oil, Pertamina, PTT and Formosa and others, seven expect Asia's oil product demand to climb back to 2019 levels by February-March 2022, while three companies see a full recovery happening by May-June 2022. What's next? Asian refiners are especially looking forward to reviving their jet fuel production and sales when the pandemic comes to an end as aviation fuel tends to yield stronger profit margins than other fuel products. The slew of movement restriction measures enforced across many states and countries across East Asia and the continued risk of a resurgence of COVID-19 cases will likely hamper steady production, sales and exports of middle distillate fuels for the remainder of 2021. However, as vaccination gathers pace in the region, this will eventually lead to full population mobility and active international travels by first quarter next year, trading and fuel marketing managers at four survey participant companies said. Reporting and analysis by Henry Edwardes-Evans, Vickey Du, Andre Lambine, Matthew Boyle, J Robinson, Philip Vahn, Surabhi Sahu and Jasper Chan ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/101320-solar-to-become-king-of-electricity-markets-iea-report</link><description>Solar energy is likely to become the leading solution to meet global growth in electricity demand, as governments around the world seek a recovery from the COVID 19 pandemic, the International Energy </description><title>&amp;apos;Solar to become king of electricity markets&amp;apos;: IEA report</title><pubDate>13 October 2020 08:29:00 GMT</pubDate><author><name>Frank Watson</name></author><content><![CDATA[ 13 Oct 2020 | 08:29 UTC â London 'Solar to become king of electricity markets': IEA report By Frank Watson Highlights Strong solar growth seen in all IEA's scenarios Solar PV 'consistently cheaper' than new coal, gas-fired power Investment needed to avoid grids becoming 'weak link' for power Solar energy is likely to become the leading solution to meet global growth in electricity demand, as governments around the world seek a recovery from the COVID-19 pandemic, the International Energy Agency said in its World Energy Outlook 2020 report released Oct. 13. The IEA's flagship report considered several scenarios, and all of them foresee significant growth in solar power as the technology falls in cost, and increasingly competes with other energy sources. "Renewables take starring roles in all our scenarios, with solar center stage," the IEA said in a statement. Supportive policies and maturing technologies are enabling very cheap access to capital in leading markets. Solar PV is now consistently cheaper than new coal- or gas-fired power plants in most countries, and solar projects now offer some of the lowest cost electricity ever seen, the Paris-based agency said. "I see solar becoming the new king of the world's electricity markets. Based on today's policy settings, it is on track to set new records for deployment every year after 2022," said IEA executive director Fatih Birol. "If governments and investors step up their clean energy efforts in line with our Sustainable Development Scenario, the growth of both solar and wind would be even more spectacular â and hugely encouraging for overcoming the world's climate challenge," said Birol. Grid investment needed However, strong growth of renewables needs to be matched with robust investment in electricity grids, the IEA warned, as insufficient investment would cause grids to become a "weak link in the transformation of the power sector," with implications for the reliability and security of electricity supply. Global energy-related CO2 emissions are set to fall by 7% in 2020 in the wake of the virus-induced slowdown, according to the IEA's analysis. "Global emissions are set to bounce back more slowly than after the financial crisis of 2008-2009, but the world is still a long way from a sustainable recovery," the IEA said. "A step-change in clean energy investment offers a way to boost economic growth, create jobs and reduce emissions," it said. This approach has not yet featured prominently in plans proposed to date, except in the European Union, the UK, Canada, Korea, New Zealand, and a handful of other countries, the IEA said. In the agency's Sustainable Development Scenario, the complete implementation of the IEA Sustainable Recovery Plan moves the global energy economy onto a different post-crisis path, it said. "As well as a rapid growth of solar, wind and energy efficiency technologies, the next 10 years would see a major scaling up of hydrogen and carbon capture, utilization and storage, and new momentum behind nuclear power," it said. Breaking the emissions trend Despite a record drop in global emissions in 2020, the world is far from doing enough to put them into decisive decline, the IEA warned. "The economic downturn has temporarily suppressed emissions, but low economic growth is not a low-emissions strategy â it is a strategy that would only serve to further impoverish the world's most vulnerable populations," said Birol. "Only faster structural changes to the way we produce and consume energy can break the emissions trend for good. Governments have the capacity and the responsibility to take decisive actions to accelerate clean energy transitions and put the world on a path to reaching our climate goals, including net-zero emissions," he said. A large part of those efforts would need to focus on reducing emissions from existing energy infrastructure, such as coal plants, steel mills and cement factories, the IEA said. "Otherwise, international climate goals will be pushed out of reach, regardless of actions in other areas," it said. Achieving a 40% reduction in global emissions by 2030 would require that low-emissions sources provide nearly 75% of global electricity generation in 2030, up from less than 40% in 2019, it said. It would also require that more than 50% of passenger cars sold worldwide would have to be electric, up from just 2.5% in 2019, it said. "Electrification, innovation, behaviour changes and massive efficiency gains would all play roles. No part of the energy economy could lag behind, as it is unclear that another would be able to move fast enough to make up the difference," the IEA said. Editor: Debiprasad Nayak ]]></content></item><item><link>https://www.spglobal.com/market-intelligence/en/news-insights/research/essential-energy-insights-november-2021</link><description>Essential Energy Insights November 2021 covers key developments in energy markets, including pricing trends and broader commodity sector performance.</description><title>Essential Energy Insights - November 2021</title><pubDate>14 November 2021 18:30:00 GMT</pubDate><content><![CDATA[ Blog â 15 Nov, 2021 Essential Energy Insights - November 2021 Gain essential insights into top trends in the energy sector. Learn more about updates in ESG and Global power sectors. Learn more about Market Intelligence Request Demo ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/060220-eu-needs-eur430-billion-to-scale-up-hydrogen-by-2030-trade-body</link><description>Scaling up the EU&amp;apos;s hydrogen sector by 2030 would cost around Eur430 billion ($480 billion), including around Eur145 billion of public support, trade body Hydrogen Europe said June 2.</description><title>EU needs Eur430 billion to scale up hydrogen by 2030: trade body</title><pubDate>02 June 2020 15:28:00 GMT</pubDate><author><name>Siobhan Hall</name></author><content><![CDATA[ 02 Jun 2020 | 15:28 UTC â Brussels EU needs Eur430 billion to scale up hydrogen by 2030: trade body By Siobhan Hall Highlights Includes around Eur145 billion public support 16.1 million mt/year demand possible by 2030 Focus on renewables, electrolyzers, grids, storage Scaling up the EU's hydrogen sector by 2030 would cost around Eur430 billion ($480 billion), including around Eur145 billion of public support, trade body Hydrogen Europe said June 2. The European Commission has said investing in hydrogen will help the EU become climate neutral by 2050 and also help kick-start EU economies after the coronavirus pandemic lockdowns. "We are ready to invest massively into the use of hydrogen," Hydrogen Europe said in a letter to EU commissioners on behalf of the CEOs of 93 of its member companies. These included Air Liquide, BP, Daimler, EDF, Enagas, Engie, Fluxys, Gasunie, GRTgaz, ITM Power, Ontras, Port of Rotterdam, Snam, Total, Uniper, Vattenfall and Verbund. The CEOs support EC plans to launch a public-private Clean Hydrogen Alliance later in June intended to help kick-start domestic clean hydrogen production and use. The alliance is to bring together governmental, institutional and industrial partners on similar lines to the European Battery Alliance set up in 2017. Costs breakdown Scaling up clean hydrogen production by 2030 will need an estimated Eur220 billion of investmnet, Hydrogen Europe said in a separate Green Hydrogen Investment and Support Report. Of this some Eur160 billion would be for renewables, and some Eur95 billion would have to come from public grants or subsidies. Hydrogen infrastructure and storage would need some Eur120 billion of investments, including Eur15 billion of public support, while hydrogen applications would need Eur90 billion, including Eur35 billion of public support to 2030. The report assumes 16.9 million mt of EU clean hydrogen demand by 2030, based on the Hydrogen Roadmap Europe paper published last year by the EU's Fuel Cells and Hydrogen Joint Undertaking, a private-public research initiative. Of this, an estimated 7.4 million mt would be green hydrogen produced from renewables -- 4.4 million mt in the EU and 3 million mt imported from North Africa and Ukraine. Clean hydrogen from electrolysis using other low carbon electricity such as nuclear, and natural gas with carbon capture and storage, would provide 8.2 million mt. The final 1.3 million mt would come from coal gasification with CCS. These production estimates are based on Hydrogen Europe's 2x40GW Green Hydrogen Initiative paper published in April. The investment report includes more detailed breakdowns of potential investments needed, such as Eur8 billion by 2030 to support 20 million mt of green steel production using 1 million mt of hydrogen. Around 25% of this should be covered by grants and subordinated loans, the report said. Other uses include hydrogen replacing or being blended with natural gas for household use, producing power for balancing the power grid, and being used as a transport fuel. Hydrogen Europe said the report was a "concrete road map" to help the planned Clean Hydrogen Alliance unlock the investment needed to scale up the EU hydrogen sector. The EC is expected to unveil a dedicated EU hydrogen strategy and an EU energy systems integration strategy at the same time as the alliance launch. Editor: James Leech ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/energy-transition/101921-south-korea-finalizes-2050-carbon-neutrality-roadmaps</link><description>South Korea has finalized its policy roadmaps to achieve the goal of carbon neutrality by 2050, focusing on restricting consumption of coal and LNG for power generation and replacing internal combusti</description><title>South Korea finalizes 2050 carbon neutrality roadmaps</title><pubDate>19 October 2021 04:25:00 GMT</pubDate><author><name>Charles Lee</name></author><content><![CDATA[ 19 Oct 2021 | 04:25 UTC South Korea finalizes 2050 carbon neutrality roadmaps By Charles Lee Highlights Presidential Committee adopts two final roadmaps Firm objective to achieve carbon neutrality by 2050 Coal, LNG's share in electricity mix will be lowered South Korea has finalized its policy roadmaps to achieve the goal of carbon neutrality by 2050, focusing on restricting consumption of coal and LNG for power generation and replacing internal combustion engine vehicles with hydrogen-powered and battery-based electric vehicles, government officials said Oct. 19. The Presidential Committee on Carbon Neutrality adopted two final roadmaps, with both of them calling for the end of coal use in power generation to achieve net-zero emissions goal by 2050. Two roadmaps While the two roadmaps all target net-zero emissions by 2050, they have different proposals in sectors like power supply, transportation, hydrogen, and carbon capture. "Under the firm objective of achieving carbon neutrality by 2050, the country will take flexible measures with the two roadmaps in hand to meet any possible circumstances down the road," a senior official at the presidential committee said. The first roadmap aims to scrap all thermal power production using fossil fuels such as coal, LNG and oil to have zero emissions in the electricity generation sector. The second roadmap calls for abolishing coal-fired power generation but will keep LNG as a flexible power source. However, the second plan seeks to boost carbon capture and storage and direct air capture capabilities so as to fully neutralize carbon emissions from natural gas-fired power plants. "Under the second roadmap, the power generation sector will produce 20.7 million mt of carbon dioxide equivalent in 2050, down 92.3% from 269.6 million mt in 2018, but all of emissions will be captured and stored effectively to make emissions zero," the official said. Coal, LNG targeted Under the both roadmaps, the portion of coal and LNG in the country's electricity mix will be lowered to 21.8% and 19.5% in 2030, respectively, compared with 41.9% and 26.8% in 2018, respectively, the official said. In contrast, share of renewable sources would jump to 30.2% in 2030, from 6.2% in 2018, while nuclear would edge up to 23.9% in 2030, compared with 23.4% in 2018. "Several coal-fired power plants will be transformed into LNG-based ones," the official said. When it comes to the transportation sector, the first roadmap targets to have more than 97% of vehicles to be hydrogen-powered or battery-based electric vehicles. The second roadmap aims to have 85% of EVs on the road with the remaining combustion-engine vehicles using environment-friendly fuels whose emissions will be neutralized by direct air capture capabilities. "The transportation sector would emit up to 9.2 million mt of carbon dioxide equivalent in 2050, down 90.6% from 98.1 million mt in 2018," the official said. Emissions by the industry sector that includes oil refinery, chemicals and steels will be reduced by 80.4% to 51.1 million mt of carbon dioxide equivalent in 2050, from 260.5 million mt in 2018. "Output of refined petroleum products in the country will be gradually reduced as oil demand is forecast to decline in line with the global push for carbon neutrality," the official said, noting the country's energy-intensive industry would face a major upheaval in decades to come. Plans revised "The two finalized roadmaps are revised, upgraded versions of the three 2050 carbon neutrality scenarios the government unveiled in August," the official said. The three scenarios, which aim to reduce the country's carbon emission by 96.3%, 97.3% or 100% by 2025 respectively, have sparked criticism both by businesses and environmental groups as ""threatening to industries" or "far-fetched and ambiguous." In the face of the criticism, the government has revised the three scenarios into two roadmaps to achieve carbon neutrality "in flexible manners," but the finalized roadmaps are unlikely satisfy both businesses and environmental groups. The presidential committee has also finalized a plan to drastically raise its goal to cut greenhouse gas emissions to 40% by 2030 against the national output level in 2018, from 26.3% previously, as part of its drive to phase out fossil fuels and achieve carbon neutral by 2050. The government will officially introduce its revised greenhouse gas reduction goal to the international community at the 26th UN Climate Change Conference in November, according to the presidential committee. Editor: Kshitiz Goliya ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/021924-uk-net-power-imports-edge-down-in-week-7-wind-generation-falls</link><description>UK average net weekly imports remain at 4.4 GW Total UK gas fired generation inches up to 9.7 GW Total UK wind generation down 9% The UK&amp;apos;s total net power imports inched down in the week ended Feb.</description><title>UK net power imports edge down in week 7; wind generation falls</title><pubDate>19 February 2024 14:05:00 GMT</pubDate><author><name>Abdul Sayeed</name></author><content><![CDATA[ 19 Feb 2024 | 14:05 UTC UK net power imports edge down in week 7; wind generation falls By Abdul Sayeed Highlights UK average net weekly imports remain at 4.4 GW Total UK gas-fired generation inches up to 9.7 GW Total UK wind generation down 9% Getting your Trinity Audio player ready... The UK's total net power imports inched down in the week ended Feb. 18 (week 7) to an average of 4.4 GW, while total UK wind generation edged down to 10.2 GW, according to Balancing Mechanism Reporting Service data released Feb. 19. The UK's net imports from France averaged 2.3 GW, falling 7% on the week, while net imports from Norway and Denmark saw increases of 39% and 34%, respectively. In contrast, net exports to both Ireland and Northern Ireland, increased to 0.3 GW each, up 9% and 21% respectively. Net imports from Belgium fell 15% to 0.7 GW, highest decline on the week, showed BMRS data. Gas-fired generation across the UK inched up to 9.7 GW. Meanwhile, total wind generation fell 9% on the week to 10.2 GW. Coal burn in the UK more than halved, down to 0.3 GW from 0.6 GW a week earlier. Nuclear power output saw a small rise, reaching 3.8 GW, while hydro power generation fell 14% to 0.7 GW in week 7. The UK day-ahead baseload power price averaged GBP63.06/MWh in Week 7, down almost 4% week on week, showed data from S&amp;P Global Commodity Insights. UK Power Generation Average (GW) 12-Jan to 18-Jan 05-Jan to 11-Feb 29-Jan to 04-Feb 15-Jan to 21-Jan Gas 9.7 9.6 7.4 6.8 Coal 0.3 0.6 0.7 0.3 Nuclear 3.8 3.7 3.7 2.9 Total Wind 10.2 11.2 14.6 16.5 Pump Storage 0.2 0.3 0.3 0.3 Hydro (Non Pump Storage) 0.7 0.8 0.7 0.8 OCGT 0.0 0.0 0.0 0.0 Other 0.3 0.4 0.3 0.3 Biomass 2.1 2.6 2.4 1.9 Net Imports/Exports 4.4 4.4 3.3 4.3 BORDER FLOWS France (IFR+IFA2+ElecLink) 2.3 2.4 1.2 2.1 Northern Ireland (Moyle) -0.3 -0.3 -0.2 0.0 Netherlands (BritNed) 0.5 0.5 0.2 0.1 Ireland (East-West) -0.3 -0.3 -0.2 0.0 Belgium (Nemo Link) 0.7 0.8 0.3 0.5 Norway (North Sea Link) 1.1 0.8 1.1 1.0 Denmark (Viking Link) 0.5 0.4 0.9 0.8 Source: BMRS Editor: Debiprasad Nayak ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/041923-total-us-nuclear-shutdown-would-increase-air-pollution-mortality-study</link><description>5,200 additional air pollution deaths a year could result Another 80,000 to 100,000 could die from climate impacts Energy plans must account for grid response to shutdowns The shutdown of all nuclear </description><title>Total US nuclear shutdown would increase air pollution mortality: study</title><pubDate>19 April 2023 16:50:00 GMT</pubDate><author><name>Steven Dolley</name></author><content><![CDATA[ 19 Apr 2023 | 16:50 UTC Total US nuclear shutdown would increase air pollution mortality: study By Steven Dolley Highlights 5,200 additional air pollution deaths a year could result Another 80,000 to 100,000 could die from climate impacts Energy plans must account for grid response to shutdowns Getting your Trinity Audio player ready... The shutdown of all nuclear power in the US would likely result in thousands of additional deaths from increased emissions from coal and other generating fuels, according to a recently published analysis by researchers from the Massachusetts Institute of Technology and University of California-Davis. The team developed an energy dispatch model of the US electricity sector, including both generation and the transmission-distribution grid, to quantify increases in emissions of carbon dioxide, nitrous oxides and sulfur oxides if all nuclear generation in the country were to be permanently shut. The research was supported in part by the US Environmental Protection Agency. "Although all nuclear power will not realistically shut down at once, and [neither] will all coal and nuclear power, this study identifies regions with high risk due to a system-wide response to closures," the researchers said in their report, published April 10 in the scientific journal Nature Energy. "The team fed the model available data on each plant's changing emissions and energy costs throughout an entire year. They then ran the model under different scenarios, including: an energy grid with no nuclear power, a baseline grid similar to today's that includes nuclear power, and a grid with no nuclear power that also incorporates the additional renewable sources that are expected to be added by 2030," MIT said April 10 in a statement on the study, which used air transport models to estimate exposure to those pollutants and reviewed epidemiological research to calculate deaths that could occur as a result. The analysis concluded that "the increase in air pollution would have serious health effects, resulting in an additional 5,200 pollution-related deaths over a single year," MIT said in its statement. If greater amounts of renewable power are integrated into the grid "as they are expected to by the year 2030, air pollution would be curtailed, though not entirely," still resulting in 260 additional deaths annually, it said. The researchers noted that "Black or African American communities â a disproportionate number of whom live near fossil-fuel plants â experienced the greatest exposure" to the additional emissions, MIT said. The researchers "calculated that more people are also likely to die prematurely due to climate impacts from the increase in carbon dioxide emissions, as the grid compensates for nuclear power's absence," the statement said. Those impacts could result in 80,000 to 160,000 additional deaths over 100 years, the authors said in their report. "Nuclear energy is a clean and reliable source of carbon-free energy. Every year, nuclear-generated electricity saves our atmosphere from more than 470 million metric tons of carbon dioxide emissions that would otherwise come from fossil fuels," John Kotek, senior vice president and policy development and public affairs at the Nuclear Energy Institute, commented April 11 on the analysis. "By keeping existing nuclear power plants online and deploying the next generation of reactors, we can help ensure our nation meets its decarbonizations goals while protecting the health of our communities." Economic impacts The potential economic damage due to climate and health impacts of a US nuclear phaseout was also assessed, with the researchers finding it would lead to costs between $50.4 billion and $220.2 billion annually, the authors said in their report. "We need to be thoughtful about how we're retiring nuclear power plants if we are trying to think about them as part of an energy system," Lyssa Freese, lead author of the analysis and a graduate student in MIT's Department of Earth, Atmospheric and Planetary Sciences, said in the statement. "Shutting down something that doesn't have direct emissions itself can still lead to increases in emissions, because the grid system will respond." Editor: William Freebairn ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/083122-france-rues-missed-opportunities-as-predictable-winter-shortages-loom</link><description>While most of Europe anticipates a challenging winter due to diminishing Russian gas supplies, nuclear giant France is bracing for problems that are mostly homemade.</description><title>France rues missed opportunities as &amp;apos;predictable&amp;apos; winter shortages loom</title><pubDate>31 August 2022 08:24:00 GMT</pubDate><author><name>Alex Blackburne</name></author><content><![CDATA[ 31 Aug 2022 | 08:24 UTC France rues missed opportunities as 'predictable' winter shortages loom By Alex Blackburne Highlights Corrosion issue undermines nuclear Competition for power imports looms 'Demand reduction messaging needed' Getting your Trinity Audio player ready... While most of Europe anticipates a challenging winter due to diminishing Russian gas supplies, nuclear giant France is bracing for problems that are mostly homemade. France, historically Europe's largest exporter of electricity, has an aging nuclear fleet that is severely underproducing, turning the country into a net importer for most of 2022 and raising the prospect of power shortages as the weather turns colder. A combination of planned maintenance and unexpected technical problems has shut more than half of state-controlled ElectricitÃ© de France SA's 56 nuclear reactors, which typically account for about 70% of France's power mix. Europe's gas crisis, combined with the nuclear outages and unprecedentedly low hydropower production, mean French wholesale electricity prices are forecast to surpass Eur1,000/MWh toward the end of this year and into next. Government measures have so far shielded consumers from surging energy bills â but at a massive cost to the public purse. This confluence of factors places France in a precarious situation as winter approaches, with controlled blackouts a real possibility. But market observers say that, rather than being down to misfortune, warning signs have been there for a long time. "We've known for decades that France consumes a lot of electricity in the winter," said Thomas Pellerin-Carlin, director of the Paris-based Jacques Delors Energy Centre, pointing out that the country favors electricity over gas for heating. The looming winter threat is "not only predictable but predicted," Pellerin-Carlin said in an interview. "Currently we're fine, but we know that the winter is going to be very hard." Unexpected outages France is not alone among European nations in bracing for a tough winter. Germany, for instance, is being hit hard by the impact of reduced gas supplies from Russia, while energy bills in the U.K. are rising to record highs. Even though France is much less reliant on Russian imports, it is having to burn more gas for power to compensate for its low levels of nuclear and hydro. Such a strategy is "usually quite costly but even more so now," said Murielle Gagnebin, senior associate at Agora Energiewende, a think tank. "We can say that France wasn't prepared for this critical level of situation." While France may not have been prepared, it has been warned repeatedly. Predictions of a tight winter this year have been spelled out multiple times since at least 2017 by RÃ©seau de Transport d'ÃlectricitÃ©, or RTE, the state-controlled operator of France's electric transmission grid. In a 2019 report, RTE predicted a power capacity deficit for the 2022/2023 winter, given the timeline of EDF's nuclear maintenance program and expected closure of nuclear and coal generation across Europe. It repeated the warnings in a 2021 report, prior to the gas supply crisis and before Russia's war in Ukraine. "We knew already ... that there will be less nuclear production," Pellerin-Carlin said. "What we did not know was the problem would be worsened by the corrosion issues." Twelve of EDF's reactors have been taken offline for investigations into possible stress corrosion. Initial analysis suggests the problem may be most acute at just 16 reactors in total, an EDF spokesperson said Aug. 23, but the utility intends to inspect its entire fleet. It is normal for EDF to undertake planned maintenance in the summer in preparation for the winter, with several reactors due to return into service in the coming months. The spokesperson said the current maintenance program was already "the largest since [the fleet's] construction" even before work was delayed by COVID-19 and the corrosion issues were identified. Nuclear generation in France was 22.8 GW on Aug. 23 compared to total fleet capacity of about 61 GW, according to analysis by S&amp;P Global Commodity Insights. The outages are expected to result in a â¬24 billion hit to EDF's earnings in 2022, with the government planning to nationalize the utility to shore up its balance sheet. While the nukes have been offline, France has had to rely on its neighbors for electricity. In July, it was a net importer to the tune of 4,114 MW on average per hour, according to research firm EnAppSys Ltd. That compares to net exports of 9,706 MW per hour in the same month last year. Going into the winter, France's continued reliance on imports is not a certainty. "The neighbors, they are as much in trouble as France because of the gas issue," said Clement Bouilloux, country manager for France at EnAppSys. "That's why it's extremely tricky for this winter." Demand reduction to come With a possible crunch point ahead, market observers point to missed opportunities to renovate France's old and energy-inefficient building stock and implement demand reduction measures. In 2008, the government outlined a strategy to reduce energy consumption in existing buildings by 38% by 2020 while undertaking major energy efficiency renovations on 400,000 buildings every year. Doing so would have saved 200 TWh over a decade. "There were active decisions to not renovate those buildings," Pellerin-Carlin said. Existing French laws that recommend not cooling buildings below 26 degrees C and call for offices and shops to turn all lights off one hour after closing are not being widely enforced, the researcher said. In today's energy crisis, the incumbent French government has moved to subsidize rising energy prices through its so-called tariff shield policy, which has resulted in far lower retail electricity and gas prices than its neighbors, even if wholesale prices are among the highest. The cost of doing so is about Eur15 billion to the government by the end of 2022, according to research firm Capital Economics, on top of the estimated Eur10 billion financial hit to EDF. "This money should be put into structurally changing consumption," Gagnebin said in an interview, calling for a "huge communication campaign for population and businesses, without being scary." The tariff shield will expire at the end of 2022 but will be phased out rather than ended abruptly, spokesperson Olivier VÃ©ran said in an Aug. 24 press conference. The government will present legislation in September to speed up energy infrastructure projects and outline a short-term plan to secure energy supplies for the winter. Pellerin-Carlin said inspiration for demand reduction measures can be taken from other countries. When Japan was faced with power outages after the Fukushima nuclear disaster in 2011, the government launched a massive campaign to save electricity. Measures included banning advertising billboards, switching off escalators, using less air-conditioning and running trains slower, which decreased peak demand by 20%. "If [France does] something of that magnitude, then we're good," Pellerin-Carlin said. "It's not yet on the agenda, but it's becoming increasingly likely that France will do something." Even with demand reduction, the risk of controlled blackouts still looms large. Bouilloux said power outages are a question of "when and where," adding that industrial consumers would be the first to be cut off. The scenarios also look very different in a mild winter and a cold winter. "That's where we're going to have more problems," Gagnebin said about the prospect of a cold snap. "The poorer you are, the less insulated your home is, so the more energy you need." Editor: Henry Edwardes-Evans ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/blog/energy-transition/090723-singapore-commodity-trading-climate-change-pavilion-lng-cnooc-nuclear-hydro-wind-solar</link><description>Commodity trading hubs have always been fluid as the center of gravity in oil and gas markets has constantly shifted. The current energy landscape will stress-test this fluidity, as we are seeing tect</description><title>Stress testing a commodity trading hub in a shifting oil and gas market</title><pubDate>07 September 2023 08:29:00 GMT</pubDate><author><name>Eric Yep</name></author><content><![CDATA[ 07 Sep 2023 | 08:29 UTC â Insight Blog Stress testing a commodity trading hub in a shifting oil and gas market By Eric Yep Getting your Trinity Audio player ready... In late August, Singapore's Temasek-backed natural gas company Pavilion Energy bought an LNG cargo from China's state-owned China National Offshore Oil Corp., in a yuan-denominated transaction, according to the Shanghai-based trading platform SHPGX that executed the deal. The deal was Pavilion Energy's first publicly reported purchase of LNG in yuan from a Chinese oil and gas major. It occurred against the backdrop of Beijing's push to boost the role of the yuan to compete with the US dollar, and sought the support of a widening gamut of countries to do so. Recently, Beijing's efforts to bring more countries closer to its sphere of influence underpinned the expansion of BRICS to include influential petrostates like Saudi Arabia, the UAE and Iran. Later in September, the G20 is likely to move ahead with the proposed inclusion of the African Union, a region key to trade growth and supply of critical minerals for energy transition. This US-China decoupling and resulting trade frictions are undoubtedly shaping the evolution of commodities markets and trading hubs like Singapore, well beyond just Chinese investor interest in energy assets on the table in the city state. The International Monetary Fund expects global fragmentation and trade restrictions to reduce global economic output by as much as 7% in the long term, or about $7.4 trillion in today's dollars. This is equal to the combined size of the French and German economies, and three times sub-Saharan Africa's annual output. But hubs don't just thrive on trade. Singapore has the clout to shield the forces that underpin global trade, helping resist what the Monetary Authority of Singapore has called a "geo-economic fragmentation." For instance, petrostates like Saudi Arabia, the UAE and Qatar -- with a growing share of oil and gas demand from India, China and increasingly Southeast Asia -- are keen on expanding their Singapore operations to diversify in the region. Commodity trading hubs have always been fluid as the center of gravity in oil and gas markets has constantly shifted. The current energy landscape will stress-test this fluidity, as we are seeing tectonic shifts not just in conventional fossil fuels but also new energy sources. Geopolitics of climate change and energy transition Trading houses and commodity firms are generally equipped to handle short-term disruptive events, with sophisticated risk assessment teams constantly modelling the probability of sudden market shifts. These firms also profit from the resulting volatility. But few companies are adequately prepared for broader changes that have deeper ramifications. The power wrangling between the US and China could disrupt energy markets for longer and more permanently than even the nationalization of Middle East oil assets almost half a century ago, that expelled Western oil majors from the region for exploiting reserves. And whether commodities traders can model the onset of the Anthropocene, a new geological epoch in the history of our planet characterized by human impact, is like asking dinosaurs to predict the ice age. Still, old energy hierarchies are set to give way to new ones, presenting opportunities for Singapore and Southeast Asia. For instance, it is now well understood that to unlock the full potential of renewable energy, areas with surplus renewables need to be interconnected with demand centers, over a sizeable geographic region through a modernized electricity grid and transmission system. Multiple energy sources such as wind, solar, hydro, and even nuclear and fossil fuels are needed to balance the grid with storage options. No single ASEAN country can do this on its own but what will work is a regional structure that mimics the EU's energy economy; one that cuts across countries, including sources such as French nuclear, Norwegian hydro, Germany's wind and solar and even legacy coal and gas. This is an opportunity to advance the decades old ASEAN Power Grid that has been in deadlock due to political hurdles and apprehensions about energy security. Singapore has already initiated some plans to import electricity from some ASEAN states but offers significant resources to take the grid forward. This is because an interconnected grid needs to be backed by a sophisticated power market and the active trading of forward electricity contracts to give price signals to grid-connected operators. The financial and commodities ecosystem for such a market, and combining it with fossil fuels and carbon trading, is offered by Singapore. A power trading hub also has its risks -- climate change driven extreme weather events such as droughts and typhoons in one corner of Vietnam could impact a hawker center in Yishun, Singapore. On the other hand, it allows other regions to step in with stable supply when one source collapses. It also opens the door for new fuels like hydrogen and ammonia, and power storage technologies. Climate foresight While geopolitics and energy transition alter power structures, the mitigation of near-term extreme weather events is still an imminent challenge, creating a vicious circle of cause and impact. Recently, the International Energy Agency noted Singapore's foresight in chartering the world's largest floating gas storage facility during the Russian gas crisis as a contingency plan. The think tank said Singapore's example reflected more stringent storage regulations adopted across key natural gas markets to ensure energy security. But shipping routes for LNG, which fuels almost all of Singapore's power generation, are increasingly impacted by unpredictable changes in weather. One of the largest growing suppliers of LNG to Asia is the US and the shortest shipping route is via the Panama Canal, a major transit hub that connects the Atlantic Ocean with the Pacific Ocean. The Panama Canal Authority has been forced to restrict vessel flows due to diminished freshwater levels, which the canal relies on for water supplies to move ships through the canal's locks. A continued lack of rainfall exacerbated the problem, impacting shipments of LNG and other energy commodities to Asia. Meanwhile, the Northern Sea Route in the Russian Arctic, which was untraversable for most of the year a few decades ago due to thick ice sheets, is becoming navigable around the year as the ice melts due to global warming. This has opened a new conduit for shipping fuels like oil and gas to Asia. S&amp;P Global Energy expects the confluence of crises in the early 2020s to have far-reaching consequences, while new drivers of energy transition focus more on industrial and economic security rather than the global climate. Renewable energy and battery usage outlooks are being supercharged and fossil fuel demand and emissions will rebound for a few years, but 'peak fossil' is approaching. However, as S&amp;P Global sees it, key markets (and the world) will not get close to net-zero emissions by 2050. A version of this article was first published in The Business Times. ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/061722-uaes-nuclear-regulator-grants-operating-license-for-countrys-third-reactor</link><description>The UAE s Federal Authority for Nuclear Regulation granted June 17 the operating license for the country s third reactor as the Gulf state forges ahead with producing clean energy ahead of its 2050 ne</description><title>UAE&amp;apos;s nuclear regulator grants operating license for country&amp;apos;s third reactor</title><pubDate>17 June 2022 15:36:00 GMT</pubDate><author><name>Dania Saadi</name></author><content><![CDATA[ 17 Jun 2022 | 15:36 UTC UAE's nuclear regulator grants operating license for country's third reactor By Dania Saadi Highlights Regulator to start looking at fourth license in Q4 Unit 4 in final stages of construction UAE already has two units in operation Getting your Trinity Audio player ready... The UAE's Federal Authority for Nuclear Regulation granted June 17 the operating license for the country's third reactor as the Gulf state forges ahead with producing clean energy ahead of its 2050 net zero emissions target. Nawah Energy Co., the operations and maintenance unit of Emirates Nuclear Energy Corp., received the license to operate the third of four units at the Barakah nuclear power plant located in the emirate of Abu Dhabi, FANR officials said in a press conference June 17. FANR expects to start looking at the operating license application for the fourth and final unit in the fourth quarter of this year, said Hamad al-Kaabi, UAE permanent representative to the International Atomic Energy Agency and FANR's deputy chairman. "Unit 4 is still in the final stage of construction," Kaabi said. "Once construction is complete, then the operator will inform the regulator that we are ready to be inspected." The UAE, the only Arab country currently producing nuclear energy for power generation, is developing nuclear power as it seeks to reduce its carbon footprint after committing to have zero emissions by 2050, the first country in the Middle East to make such a pledge. Barakah-1 started commercial operations in April 2021 after reaching 100% capacity in December 2020. ENEC said in March that Barakah-2 had begun commercial operations after being connected to the grid in September 2021. Once its four units begin operating commercially, Barakah will supply up to 25% of the UAE's power mix. By 2025, the Barakah plant will generate more than 85% of Abu Dhabi's clean electricity, making it the biggest contributor to reducing the emirate's carbon emissions by 50% by the middle of the decade, according to ENEC. Each of the four units in Barakah are South Korean-designed APR1400s. ENEC may develop more nuclear power plants locally and internationally in the future after bringing online all of the four 1.4 GW units that are currently planned, its CEO Mohamed al-Hammadi told S&amp;P Global Commodity Insights in March. ENEC has received interest from many countries to partner with them on the development of nuclear power generation, the CEO added, without disclosing the countries. FANR hasn't received any application yet to issue operating licenses beyond the four, he added. "If the government decided to pursue the expansion of the number of reactors, then we will start to look at this," said Kaabi. Under a strategy revealed in 2017, the UAE is targeting to generate 44% of its power from renewables, 38% from gas, 12% from clean coal and 6% from nuclear energy by 2050. However, officials have said the current power mix is under review. The UAE mainly uses gas for power generation now. Editor: Adithya Ram ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/010523-robust-supply-mild-weather-recession-drag-power-prices-down-to-pre-invasion-levels</link><description>European power prices have fallen to pre Ukraine invasion levels for winter contracts, as a combination of ample LNG supply, mild weather and a weak economy weighed on the market, while prices further</description><title>Robust supply, mild weather, recession drag power prices down to pre-invasion levels</title><pubDate>05 January 2023 15:43:00 GMT</pubDate><author><name>Kira Savcenko</name><name>Harry Weber</name></author><content><![CDATA[ 05 Jan 2023 | 15:43 UTC Robust supply, mild weather, recession drag power prices down to pre-invasion levels By Kira Savcenko and Harry Weber Highlights German front-month contract down 16% on year, front year up 63% NWE-delivered LNG derivatives flip to discount with JKM Greater supply and demand flexibility to prevent extreme spikes Getting your Trinity Audio player ready... European power prices have fallen to pre-Ukraine invasion levels for winter contracts, as a combination of ample LNG supply, mild weather and a weak economy weighed on the market, while prices further out were firmly higher on the year, analysis by S&amp;P Global Commodity Insights showed Jan. 5. In Germany -- the benchmark European power market -- the front-month price averaged below Eur180/MWh ($190/MWh) this year so far. This was 16% below the whole of January 2022 for the corresponding contract, before Russia's military invasion of Ukraine Feb. 24 that exacerbated already tight natural gas and power supply across Europe. Moreover, values at the front of the pricing curve have been consistently dropping in recent days across leading power markets, with the German front month trading at just Eur166/MWh Jan. 5. In contrast, far-end prices were firm and held above levels seen registered a year earlier. For instance, the German front-year contract averaged about Eur206/MWh this month so far, some 63% above January 2022. A similar pattern was observed at the European-benchmark-setting Dutch TTF natural gas hub and across other key European power markets. LNG, natgas price dynamics "The contango...is definitely driven by the weather and the availability of LNG with tanks [is] still very full. And [there's] a bit of demand destruction due to weak macro/recession," a NWE-based gas trader said. Indeed, Atlantic LNG prices have fallen as supplies of home heating and power plant fuel outpaced demand in recent weeks, amid warmer-than-expected winter temperatures in Europe. The delivered price of LNG into Northwest Europe fell Jan. 4 below $20/MMBtu to an eight-month low. That was a sharp turnabout from just months earlier, on Aug. 26, when DES Northwest Europe was assessed at a record high of $74.486/MMBtu. Against that backdrop, Northwest Europe delivered LNG derivatives for the prompt months have flipped to a discount to JKM derivatives for the same period, while the summer 2023 portion of the forward curve holds at a premium. Platts JKM is the benchmark price for spot delivered LNG into Northeast Asia. Market sources said that amid further weakening in the inland Dutch TTF gas hub price, differentials between European LNG and natural gas were narrowing to near parity as 2023 began. '99 problems' Nothing prevented gas prices -- and hence power -- from losing more value in coming weeks, provided storages remain full and demand low, market sources said. Yet far-curve prices could continue to retain their risk premium. The bottom of the range for the TTF front-month price is Eur52.34/MWh, while Eur50/MWh could be a psychological support level, according to the gas trader. The contract was seen trading at around Eur66/MWh Jan. 5 on ICE Webex. "[In] the long term it is the story of 'we have 99 problems, but we take them one at a time'...The problem...is next winter/refilling for next winter. That is yet to be sorted and highly dependent on how this winter is going to end up [storage] fullness-wise," the trader said, adding that the key drivers would be the weather and the economy, including the re-opening of China. Aggregate EU gas storage was more than 83% full Jan. 3, the most recent data from transparency platform AGSI showed. This was well up from less than 53% a year earlier. If net withdrawals continue at its Dec. 1 to Jan. 3 pace, storages will still be about 61% full by April 1, way above historical averages, analysis by S&amp;P Global showed. No more extreme spikes Nearer-term weather outlooks pointed toward mild weather conditions persisting into February, which reduced the risk of unseasonably low wind generation, with the German power front-month trading below where the day-ahead market has delivered over the past 90 days, according to S&amp;P Global lead power analyst Sabrina Kernbichler. Contracts delivering in Summer-23 and in Q4-23 continue to hold some risk premium given the less certain weather outlook and as Germany will lose some baseload run capacity with the nuclear exit in mid-April 2023. The German nuclear exit and low French nuclear generation will continue to expose the German market to price upside at times of low renewable generation, according to Kernbichler. S&amp;P Global analysts forecast that German demand will lag the 2017-21 average by about 6% in 2023. "Both power and gas markets are now better prepared to deal with any supply or demand shocks versus 2022 in our view as Germany and other European countries have brought back coal units in 2022 and as gas markets are on track to come out of Winter 22 with higher storage levels...and with additional LNG infrastructure," Kernbichler said. While S&amp;P Global expects German power and gas prices to remain volatile in 2023, greater power and gas supply and demand flexibility will prevent extreme price spikes, which should exert further downward pressure on summer 2023 and Q4 2023 prices closer to delivery. Editor: Kira Savcenko ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/060722-us-power-tracker-pjm-may-electricity-gas-prices-jump-nearly-200-on-year</link><description>PJM Interconnection wholesale power prices in May jumped as much as 40% from April and surged 188% from a year ago as natural gas prices climbed about 21% from April with higher power demand.</description><title>US Power Tracker: PJM May electricity, gas prices jump nearly 200% on year</title><pubDate>07 June 2022 20:44:00 GMT</pubDate><author><name>Jared Anderson</name></author><content><![CDATA[ 07 Jun 2022 | 20:44 UTC US Power Tracker: PJM May electricity, gas prices jump nearly 200% on year By Jared Anderson Highlights Forward power prices surge more than 300% Power prices for July above August Getting your Trinity Audio player ready... PJM Interconnection wholesale power prices in May jumped as much as 40% from April and surged 188% from a year ago as natural gas prices climbed about 21% from April with higher power demand. Forward power and gas prices were up more than 300% and 200%, respectively, from year-ago levels. PJM West Hub on-peak day-ahead power prices averaged $90.48/MWh in May, 188.4% above year-ago levels, and about 27% above April, according to PJM data. West Hub real-time on-peak power prices in May averaged $82.56/MWh in May, about 163% above the May 2021 average of $31.37/MWh and about 18% higher than April. Northern Illinois Hub on-peak day-ahead power prices were about 180% higher on year in May to average $78.77/MWh, which was around 41% above April. Real-time on-peak power prices at the hub averaged $77.26/MWh in May, about 145% above May 2021 and roughly 50% higher than April. AEP-Dayton Hub on-peak day-ahead power prices averaged $88.63/MWh in May, about 178% higher on the ear and 26% higher than April. The lowest annual power price increase among the major PJM hubs in May was the East Hub, where day-ahead on-peak prices were still nearly 162% higher to an average $68.11/MWh. On a monthly basis, PJM East Hub on-peak day-ahead power prices were about 17% higher in May than April. PJM's monthly on-peak day-ahead power prices, apart from Northern Illinois Hub, tracked spot gas prices that rose by a little over 20% in May. Gas prices at the Texas Eastern Transmission Hub averaged $7.35/MMBtu, 21% higher on month and about 218% higher than the May 2021 average of $2.31/MMBtu, S&amp;P Global Commodity Insights data showed. Prices at the Chicago city-gate averaged $7.79/MMBtu in May, about 183% higher on year and 22% above April. PJM power demand rose in May as temperatures increased, with peakload averaging 94,288 MW, or 9.4%, higher than the April average of 86,216 MW, according to PJM data. The average high temperature in PJM territory in May was 73.6 degrees Fahrenheit, up from an April average high of 60.7 F, according to CustomWeather data. The average low temperature in May was 52.7 F compared with an April average low of 43.9 F. The warmer weather led to increased indoor cooling demand with cooling degree days averaging 3.4 in May, up from a 0.4 average in April. Power generation fuel mix Coal-fired power generation in May gave away some market share to gas. As a share of the PJM total in May, coal-fired generation accounted for 18.8% of the generation fuel mix, down from 20.5% in April, according to PJM data. Gas-fired power generation accounted for 36.4% of the PJM fuel mix in May, up from 35% in April. Nuclear power accounted for 35.5% of PJM's fuel mix in May, up slightly from 33.5% in April. Hydropower generation was unchanged at 2.4% and wind power decreased, accounting for 4.3% of PJM's May generation fuel mix, down from 5.8% in April. Non-wind renewables were largely unchanged, accounting for 1.9% of the fuel mix in May compared with 2% in April. Forward power, gas prices PJM forward power prices rose to the triple digits across the board, with July trading above August in May, according to Platts M2MS data. PJM West Hub on-peak power prices for June averaged $117.42/MWh in May trading, about 266% above year-ago levels and about 33% higher than April. The July contract averaged $169.56/MWh, about 344% higher on year and 46% higher on month, while the August package averaged $149.30/MWh, up 313% on the year and about 37% in April. AEP-Dayton Hub on-peak power for June averaged $119.70/MWh during May trading, up about 261% on year and 37% in April. Forward power for June averaged $173.41/MWh, up 342% on the year and about 51% from April, and forward power for August averaged $151.95/MWh, up 309% on the year and about 41% from April. Northern Illinois Hub on-peak power prices for June averaged $112.43/MWh in May trading, up 269% on the year and 82% from April. The July contract averaged $164.02/MWh, up 350% on the year and 50% from April, and forward power prices for August averaged $143.49/MWh, an annual increase of 316% and about 41% from April. PJM forward gas prices followed a similar trend in May trading with the Platts Transco Zone 6 Non-New York for June averaging $7.34/MMBtu, up 224% on the year and 22% on the month. Forward gas prices for July averaged $7.59/MMBtu, up 212% on the year and 21% on the month, while forward gas for August averaged $7.57/MMBtu, up 219% on the year and about 21% on the month. Editor: Valarie Jackson ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/energy-transition/081922-eu-carbon-price-hits-all-time-high-of-eur9914mtco2e</link><description>Carbon allowance prices under the EU Emissions Trading System hit an all time high of over Eur99/mtCO2e Aug. 19, as a cut to auction supply in August combined with bullish demand.</description><title>EU carbon price hits all-time high of Eur99.14/mtCO2e</title><pubDate>19 August 2022 13:46:00 GMT</pubDate><author><name>Frank Watson</name></author><content><![CDATA[ 19 Aug 2022 | 13:46 UTC EU carbon price hits all-time high of Eur99.14/mtCO2e By Frank Watson Highlights All-time intra-day high for nearest December contract Fresh gains as tight supply adds to squeeze Drought conditions increasing need for gas-fired power Getting your Trinity Audio player ready... Carbon allowance prices under the EU Emissions Trading System hit an all-time high of over Eur99/mtCO2e Aug. 19, as a cut to auction supply in August combined with bullish demand. EU Allowance futures contracts for December 2022 delivery rallied as high as Eur99.14/mtCO2e ($99.70/mt) on Aug. 19 -- the highest intraday price ever recorded for the nearest-December futures contract on the ICE Endex exchange. That compared with a close of Eur96.53/mtCO2e on Aug. 18, according to Platts assessments published by S&amp;P Global Commodity Insights. The latest gains came amid a short-term supply crunch with monthly auction volumes down to 24.1 million mt in August, dropping 43% from July levels. On the demand side, drought conditions in Europe this summer have curtailed electricity generation from low carbon sources such as hydro-electric and nuclear, increasing the need for gas-fired generation, which raises CO2 emissions and demand for allowances. The high temperatures have also boosted summer cooling demand, raising the need for electricity in homes and commercial buildings, and supporting natural gas and coal prices in Europe, Platts Analytics said in a spotlight report Aug. 19. However, September could see carbon prices come under downward pressure as auction supply rebounds to normal levels, while bearish pressure builds from a weakening macroeconomic outlook, it said. Editor: James Leech ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/energy-transition/053024-china-launches-action-plan-for-industries-to-decarbonize-ahead-of-2025-deadline</link><description>Aims to speed up decarbonization in power, metals, refining, cement sectors To increase non fossil in energy consumption to 20% by 2025 Targets 5% cut in transportation sector&amp;apos;s carbon intensity by 20</description><title>China launches action plan for industries to decarbonize ahead of 2025 deadline</title><pubDate>30 May 2024 10:16:00 GMT</pubDate><author><name>Ivy Yin, Market Specialist - Energy Transition</name><name>Market Specialist - Energy Transition</name><name>Analyst Lucy Tang</name><name>Analyst Daisy Xu</name></author><content><![CDATA[ 30 May 2024 | 10:16 UTC China launches action plan for industries to decarbonize ahead of 2025 deadline By Ivy Yin, Market Specialist - Energy Transition, Market Specialist - Energy Transition, Analyst Lucy Tang, and Analyst Daisy Xu Highlights Aims to speed up decarbonization in power, metals, refining, cement sectors To increase non-fossil in energy consumption to 20% by 2025 Targets 5% cut in transportation sector's carbon intensity by 2025 from 2020 Getting your Trinity Audio player ready... China's State Council launched an action plan late May 29 to help the power and industrial sectors accelerate decarbonization and meet the 2025 targets of cutting energy intensity by 13.5% and carbon intensity by 18% from 2020 levels. Energy intensity measures energy consumption for each unit of GDP growth and carbon intensity measures carbon emissions for each unit of GDP growth. The targets were committed in China's 14th five-year plan, the overarching economic plan for 2021-2025. However, the country faces challenges in meeting these targets due to the pandemic, reduced GDP growths and increasing cases of extreme weather in the past three years. The council released the action plan that sets out more detailed targets and guidance for individual sectors to address these challenges. The energy intensity and carbon intensity must be cut by 2.5% and 3.9% in 2024 from the previous year's level, respectively, the State Council said. Notably, China needs to cut energy intensity by 2.7% and carbon intensity by 3.6% each year in 2021-2025 to be on track for meeting the 14th five-year plan targets. The council required emissions-intensive sectors highlighted in this action plan to collectively reduce energy consumption by 50 million mt of standard coal equivalents and cut CO2 emissions by 130 million mt year on year, for both 2024 and 2025. "We should make our maximum effort to meet the targets for energy conservation and carbon emission reduction in the 14th Five-Year Plan," the council said. Power sector China should have around 20% of energy consumption coming from non-fossil sources by 2025, and by the end of 2024, around 18.9% of energy consumption should come from non-fossil sources, the State Council said. By 2025, China's pumped hydropower storage capacity should reach 62 GW and utility-scale battery storage capacity should reach 40 GW, up from 51.3 GW and 25 GW, respectively, in 2023, to provide buffer power supplies that can effectively tackle renewable's intermittency and boost renewables consumption, according to the action plan. Non-fossil fuels should account for around 39% of China's total power supply by 2025, the council added. In 2023, coal still accounted for nearly 60% of the country's electricity supply, according to a report by the government-backed industrial association China Electricity Council. Metals China will continue to control crude steel output in 2024, prohibiting disguised capacity additions in the name of manufacturing machineries or ferroalloys and preventing the resurgence of "low-quality steel" capacity, the action plan showed. By the end of 2025, the State Council called for increasing the share of crude steel produced from electric arc furnaces to 15%, adding that 300 million mt of scraps should be recycled and reused. The council's action plan required the iron and steel industry to reduce its energy consumption by around 20 million mt of standard coal equivalent and cut CO2 emissions by 53 million mt during 2024-25. For non-ferrous metals, the State Council called for strictly controlling additions of copper smelting and aluminum production capacities. Notably, it required the electrolytic aluminum sector to use renewables for at least 25% of power consumption. The non-ferrous industry should reduce energy consumption by around 5 million mt of standard coal equivalent and cut CO2 emissions by 13 million mt during 2024-25, the action plan showed. Refining and petrochemicals Crude distillation units with refining capacities of no more than 40,000 b/d will be completely mothballed, and the primary refining capacity shall be capped at 20 million b/d by end 2025, the action plan showed. The State Council also called for strict controls over capacity additions for refining, calcium carbide, ammonium phosphate and yellow phosphorus. By 2025, over 30% refining capacities and production capacities of ethylene, synthetic ammonia and calcium carbide should outperform their industry-wide energy efficiency benchmarks. Capacities that underperform these benchmarks should either be retrofitted or phased out eventually. The refining and petrochemicals industry should reduce energy consumption by around 40 million mt of standard coal equivalent and cut CO2 emissions by 110 million mt during 2024-25, the council said. It also encouraged the use of green hydrogen to substitute coal in refining and petrochemicals production. Nuclear energy is also encouraged to supply steam and heat in large-scale refining and petrochemicals parks. Construction and transportation The cement industry should keep its clinker production capacity within around 1.8 billion mt/year by 2025, the action plan showed. Earlier in 2024, China initiated a consultation to enroll cement clinker producers into the country's compliance carbon market. The action plan required the whole building material industry to reduce energy consumption by around 10 million mt of standard coal equivalent and cut CO2 emissions by 26 million mt during 2024-25. The council has directed the transportation sector to cut its carbon intensity by 5% from the 2020 levels by 2025, calling for lifting of restrictions on purchasing electric vehicles and accelerating electrification of cargo trucks and ships on inland waterways. The decarbonization push in transportation and construction sectors and accelerated electrification will increase demand for copper and aluminum, sources said. Editor: Dan Lalor ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/082322-energy-security-meltdown-dominates-uk-leadership-contest</link><description>Energy policy is front and center in the race to succeed Boris Johnson as UK prime minister and head of the ruling Conservative Party, with North Sea oil and gas producers fearing renewed fiscal insta</description><title>Energy security meltdown dominates UK leadership contest</title><pubDate>23 August 2022 16:35:00 GMT</pubDate><author><name>Nick Coleman</name></author><content><![CDATA[ 23 Aug 2022 | 16:35 UTC Energy security meltdown dominates UK leadership contest By Nick Coleman Highlights Cushion of North Sea supply increasingly in question Fears mount of tax instability amid political turbulence Likely leader's low-tax stance fails to allay concern Getting your Trinity Audio player ready... Energy policy is front and center in the race to succeed Boris Johnson as UK prime minister and head of the ruling Conservative Party, with North Sea oil and gas producers fearing renewed fiscal instability and critics urging reform to fix deep-seated energy problems. As European energy prices skyrocket the UK is torn between those in industry and government calling for greater development of domestic energy, including oil and gas, and those demanding more punitive taxation of supposedly unfair energy sector profits and a quicker transition to renewables. The UK is better off than some in Europe thanks to its North Sea production, which still meets around half its gas needs and the equivalent of 80% of oil demand. But output has declined sharply in recent years, particularly during the pandemic, and the country has minimal gas storage capacity. An emphasis on wind generation, in combination with reduced coal and nuclear capacity, has made for an uncomfortably tight power supply situation, critics warn. Close ties with Norway provide reassurance; the northern neighbor has gone from meeting 27% of UK gas demand to 41% in the last decade, partly due to declining supply from the Netherlands. But Norway is looking to send some of its supply through a new pipeline to Central Europe, underlining the worries some have about the UK's energy underpinnings. Criticism has mounted of both past and present policy, while Scotland's devolved government has joined with opposition parties in London in growing skepticism toward the sector. Low-tax candidate On the face of it those arguing for oil and gas investment have little to fear from Liz Truss, the front-runner in the Conservative leadership contest. The poll of Conservative Party members is due to be completed by Sept. 5, with the winner expected to lead the country into the next election, due by early-2025. Truss is an avowedly low-tax politician and the same is true of Kwasi Kwarteng, current business secretary and her expected pick for chancellor of the exchequer. He has stressed the need to maximize North Sea production and now looks favorably on shale drilling, having resisted calls for a windfall tax on the sector earlier in the year. Kwarteng eventually had to give way when an "energy profits levy" was imposed by then-chancellor Rishi Sunak, now Truss' leadership rival, in May. The measure raised the headline tax rate for North Sea producers from 40% to 65%, and in fairness the industry response has been mixed. Industry group Offshore Energies UK was sharply critical and has warned of "untold damage" in the event of further windfall taxes, urged by the opposition Labour Party. Shell has also warned that an unstable tax regime jeopardizes both oil and gas investments and nascent transition projects such as carbon capture and storage that could take years to turn a profit. Others have been more accepting: TotalEnergies CEO Patrick Pouyanne has said the company can live with what he calls the UK's "active" tax rates, noting upstream taxes have historically been lowered as well as raised, dependent on oil prices; the French major is one of the largest North Sea gas producers. BP has also said it will continue to work on making the UK an energy transition showcase, anticipating it will invest GBP18 billion ($21 billion) in the country between now and 2030. Policy ambiguity Privately, however, critics in the industry argue the government has failed to provide either the fiscal or symbolic support needed to ensure continued investment. Johnson's wavering over the need for oil and gas during COP26 climate talks in Glasgow in 2021 is seen as emblematic, contributing to an atmosphere in which some of the biggest energy companies on the London Stock Exchange could end up relocating elsewhere, critics say. Uppermost among the concerns is a failure to ensure gas storage since the closure of the Rough storage site beneath the North Sea in 2017. The site is due to be reopened by utility Centrica as soon as this winter, but its capacity will be ramped up only gradually. Another concern is the failure to relaunch regular offshore licensing rounds after the process was put on hold in 2020 ahead of the COP26 climate talks. A revamped system is promised, but it is now over three years since the last round was launched. The picture is not clear-cut. UK oil and gas production has shown some signs of stabilizing after oil output plunged 17% in 2021. And Norway's Equinor has published plans for the 350 million barrel Rosebank oil project in the UK West of Shetland area, with a number of other projects moving toward approval. On the demand side, there are some signs the pain for consumers could start to ease in the next couple of years, although this will be cold comfort in the meantime. Analysts at S&amp;P Global Commodity Insights argued recently that extreme European gas prices are "increasingly unsustainable" and wholesale prices should start to ease due to faster-than-expected demand destruction in both Europe and Asia â a rival for LNG deliveries â and increases in stored gas. The UK situation should also be eased by new gas projects recently or soon-to-be started up, notably Tolmount and Seagull, as well as increases in wind capacity and greater coal consumption, they argued. None of which assuages the concern of critics in the industry, increasingly anxious about a potential change of government at the next election. "The government has put us in this peril by not supporting the North Sea properly in terms of gas," one energy industry banker told S&amp;P Global Commodity Insights, arguing Brexit had "completely distracted" the "political class." "Anyone making a long-term investment decision doesn't like instability," he underlined. Editor: Nick Coleman ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/062520-low-carbon-generation-exceeds-60-of-uk-generation-mix-in-q1-beis</link><description>Low carbon generation accounted for 62.1% of the UK generation mix in the first quarter, a record high, the Department of Business, Energy and said in a statistical update June 25.</description><title>Low carbon generation exceeds 60% of UK generation mix in Q1: BEIS</title><pubDate>25 June 2020 12:20:00 GMT</pubDate><author><name>Henry Edwardes-Evans</name></author><content><![CDATA[ 25 Jun 2020 | 12:20 UTC â London Low carbon generation exceeds 60% of UK generation mix in Q1: BEIS By Henry Edwardes-Evans Highlights Gas-firing down 26% on year, coal edges up Wind accounts for 30% of total generation Extended maintenance dents nuclear London â Low carbon generation accounted for 62.1% of the UK generation mix in the first quarter, a record high, the Department of Business, Energy and said in a statistical update June 25. Mirroring this, fossil fuel generation sank to an all-time low for a quarter of 35.4%, with a 26% drop in gas-fired generation. Record low carbon generation was due to high wind speeds and despite reduced nuclear. February recorded the highest average monthly wind speeds in the reported time series, while offshore wind capacity increased 18.5% from Q1 2019. Renewables generated 47% (40.8 TWh) of UK electricity in Q1, beating the previous quarterly record of 38.9% set in Q3 2019. Wind generated 30% (26 TWh) of UK power in Q1, 14.7% from onshore wind, 15.2% from offshore, the resource benefiting from higher wind speeds in February. Fossil fuel's share in UK generation dropped below 40% for the first time for any quarter. Gas generation was down 9 TWh compared with Q1 2019, while there was a last-gasp bounce in coal generation of 7.7% on the year as stocks at Fiddlers Ferry power station were run down ahead of the plant's closure at the end of March. Nuclear output for the period was down 5.8% year on year. An outage was completed at Heysham 1 while outages continued at Dungeness B, Hunterson B and Heysham 2 and started at Hinkley Point B. Total domestic production of 86.9 TWh was down 0.8% year on year, while final consumption of 78.3 TWh was down 1.8%. Consumption was lower in all sectors but with a larger decrease for the industrial sector, down 3.6% compared with Q1 2019. BEIS said the impact of the coronavirus on energy production and consumption was marginal for most fuels as the lockdown only came into effect on March 23. Finally, provisional calculations "show that 13.2% of final energy consumption in 2019 came from renewable sources, up from 12% in 2018, as measured against the UK's target to reach 15% by 2020 under the 2009 EU Renewable Directive," BEIS said. UK QUARTERLY GENERATION, EXCHANGES, CONSUMPTION (TWh) Q1 19 Q2 19 Q3 19 Q4 19 Q1 20 Coal 3.05 0.46 0.73 2.66 3.28 Oil 0.33 0.29 0.26 0.24 0.2 Gas 36.61 33.12 28.59 33.61 27.27 Nuclear 13.91 13.07 13.59 15.62 13.11 Hydro (natural flow) 1.82 0.93 1.44 1.75 2.46 Wind and solar 20.73 16.96 18.7 20.88 27.98 - of which, offshore 8.64 5.97 7.23 10.3 13.24 Bioenergy 8.92 9.07 9.03 10.29 10.41 Other fuels 1.63 1.52 1.55 1.66 1.73 Pumped storage 0.56 0.34 0.37 0.48 0.43 Total production 87.56 75.76 74.26 87.18 86.87 Imports 6.78 6.13 5.52 6.13 6.68 Exports 0.73 0.50 1.07 1.08 0.88 Final consumption 79.70 69.35 67.51 78.71 78.28 Source: BEIS Editor: Jonathan Dart ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/coal/062420-global-energy-demand-could-decline-6-in-2020-due-to-pandemic-iea</link><description>Global energy demand could decline 6% in 2020 due to the pandemic, highlighting significant impacts on consumption patterns and market dynamics, says IEA.</description><title>Global energy demand could decline 6% in 2020 due to pandemic: IEA</title><pubDate>24 June 2020 21:20:00 GMT</pubDate><author><name>Jared Anderson</name></author><content><![CDATA[ 24 Jun 2020 | 21:20 UTC â New York Global energy demand could decline 6% in 2020 due to pandemic: IEA By Jared Anderson Highlights Global power demand could fall 5% Platts Analytics sees less severe impact New York â Global energy demand is set to fall by 6% in 2020, the largest in 70 years, due to the coronavirus pandemic, an expert with the International Energy Agency said June 24, though S&amp;P Global Platts Analytics expects a more moderate impact. There could be a 6% reduction in total global energy demand in 2020 compared to 2019 as a result of coronavirus-related lockdowns, Peter Fraser, head of gas, coal and power markets at IEA, said during a webcast seminar hosted by IEA and non-profit Electric Power Research Institute. But not every fuel is going to be affected in the same way, Fraser said, with fossil fuels impacted more than non-fossil fuels. The international energy market watchdog estimates there will be a significant decline in coal demand because of impacts on developing economies and relatively low natural gas prices in more advanced economies, Fraser said. "The combination of those two factors are really hitting coal very hard," he said. In the case of natural gas, the impact will be somewhat more modest, with global demand for the fuel falling 4% in 2020 followed by a rebound in 2021 where it makes up all the lost ground, Fraser said. This is because gas is taking away business from coal in the power sector amid low prices, he said. The agency expects an 8% reduction in 2020 oil demand year-over-year, but a small reduction in nuclear demand, while renewables remain relatively unaffected. In terms of global power demand, the IEA is seeing a 5% reduction in 2020, which would be the largest since the US Great Depression in the 1930s, Fraser said, adding the US is largely in line with that estimate. However, Platts Analytics estimates the US will see a more moderate power demand impact from the pandemic in 2020. "US [Lower-48] loads have recovered and are close to the loads we would expect with current weather in the absence of the pandemic," Manan Ahuja, manager of North American power analytics and modelling, said in an email. Even with the mild winter, we had at start of the year, overall 2020 loads in the US will likely end up being about 2% lower year-over-year, Ahuja said, adding that assumes we have a normal summer and large-scale lockdowns do not happen again from a second wave of the coronavirus pandemic. Platts Analytics expects power demand will shrink by 1.2% on the year in 2020 across the major markets globally, also assuming normal weather and no significant second waves of infections, Bruno Brunetti, head of global power planning, said in an email. Emissions, other impacts Fraser said the IEA expects global energy-related carbon dioxide emissions to fall nearly 8% in 2020, the lowest level in a decade with reduced coal use contributing most, but experience suggests that a large rebound is likely post crisis. Other experts on the panel agreed. Tom Wilson, principal technical executive at EPRI, pointed out that world wars and earlier pandemics have not stopped greenhouse gas emissions growth. He asked, how many people have destroyed their cars because they have been using them less frequently? "Human suffering and economic collapse are not the way to reduce emissions," Wilson said. He has been researching broad societal themes and lasting impacts from the pandemic over the past few months and said the over-riding theme is the lasting impacts are likely things that already existed, but may be accelerated due to the pandemic. Examples include digitalization, the demise of brick and mortar retail and rising nationalism. Slowing trends include urbanization, shared economy and travel, Wilson said. One interesting behavioral change is increased working from home. Companies have been surprised at how effectively it is working, he said, with many finding themselves more nimble. However, it is less clear how working from home more might impact GHG emissions levels. "It's not a slam dunk that less commuting will reduce emissions," Wilson said. With regard to the financial sector, Morgan Scott, principal project manager for sustainability at EPRI, said her group has seen extensive growth in money flowing into ESG funds. EPRI is not sure exactly why there has been significant growth in those funds during a time of economic downturn, but something is happening around ESG performance, Scott said. Editor: Aastha Agnihotri ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/073123-with-new-nuclear-unit-now-operational-southern-company-turns-a-corner</link><description>Completion of Vogtle expansion could boost the company&amp;apos;s finances Analysts expect constructive outcome in rate recovery case Southern Company is edging closer to the removal of significant uncertain</description><title>With new nuclear unit now operational, Southern Company turns a corner</title><pubDate>31 July 2023 19:51:00 GMT</pubDate><author><name>Abbie Bennett</name></author><content><![CDATA[ 31 Jul 2023 | 19:51 UTC With new nuclear unit now operational, Southern Company turns a corner By Abbie Bennett Highlights Completion of Vogtle expansion could boost the company's finances Analysts expect "constructive" outcome in rate-recovery case Getting your Trinity Audio player ready... Southern Company is edging closer to the removal of significant uncertainty from its balance sheet as the first of two new units at its Vogtle nuclear plant reached commercial operation, the company said July 31, nearly 17 years after launching the expansion. "We're just thrilled to have the opportunity to move toward getting these units online and getting this project behind us and then focus on this company and getting the valuation we think we deserve," Southern Company President and CEO Chris Womack said in a recent interview with S&amp;P Global Commodity Insights. Cash generated from bringing both Vogtle units 3 and 4 into commercial service, the removal of some years-long penalties from delays and cost overruns, and finally realizing the full value of the expansion are net positives for the company, Womack said. "It gives us great cards to play as we look into the future to achieve all of our earnings targets." The two-unit Vogtle expansion, one of the largest infrastructure investments in the US power sector over the last two decades, is expected to add more than 2,200 MW of generating capacity once the second unit reaches commercial operation in either late in the fourth quarter or Q1 2024. Unit 3 enters commercial operation after Southern Company utility subsidiary Georgia Power delayed the in-service date in June to remedy a degraded hydrogen seal discovered during startup and preoperational testing. Commercial operation is a requirement before the company can begin recovering costs from ratepayers. That milestone will give Southern Compan the ability to reassess its capital budget and other opportunities, Womack said. The original two units at the Vogtle plant, just south of Augusta, Georgia, began operating in the late 1980s. Georgia Power, at 45.7%, owns the largest share of both the existing units and the new ones. Other owners include Oglethorpe Power Corp., which supplies power to Georgia electric cooperatives, at about 30%, although it is looking to exercise an option to reduce that share to cut costs; the Municipal Electric Authority of Georgia, which supplies power to 49 public power entities in Georgia, at 22.7%; and the city of Dalton, Georgia, at 1.6%. Southern Nuclear Operating Co. Inc. will operate the new units on behalf of the co-owners. Meeting financial targets "We have a wonderful opportunity to achieve our financial targets, our earnings targets, really extend this growth out to the future," said Womack, a former Georgia Power CEO who took over as president and CEO of Southern Company in May. Southern Company is likely to allocate more cash to its dividend as the project clears final hurdles, according to Morningstar analyst Travis Miller, but it may be some time before those benefits manifest. Miller estimated such changes are likely to occur in late 2024 or 2025 as cash flow picks up and regulatory penalties lift. Southern Company's "stock performance has really suffered relative to the rest of the industry over the last 10 years," Miller said in an interview. "Longtime [Southern Company] shareholders are used to better returns than what they've gotten during the last decade." Credit ratings Bringing both new Vogtle units online will significantly reduce financial risk for the company, which has seen a hit to its credit quality, said Gabe Grosberg, senior director of North American regulated utilities global infrastructure ratings for S&amp;P Global Ratings. Southern Company has a BBB+ rating and a stable outlook from S&amp;P Global Ratings after a one-notch downgrade in October 2021. Commercial operation for Vogtle Unit 3 is a significant milestone, but "we'd still want to see how events play out, how costs are recovered," Grosberg said. "Getting through this enormous project and its sizable risks, as the two downgrades over the past decade demonstrate, is certainly supportive of credit quality." Once both new units achieve commercial operation, S&amp;P Global Ratings will focus on subsequent rate case filings to "ensure they support credit quality," Grosberg said. "That's definitely a good point in time for us to review." Cost recovery As Vogtle Unit 4 begins its fuel load, following receipt of a 103(g) finding from the US Nuclear Regulatory Commission, the Georgia Public Service Commission is set to begin the prudency review for the entire expansion projectâdetermining how much Georgia Power can recover from ratepayers. Georgia Power's cost estimate for its share of the total project capital cost was $10.6 billion as of the company's most recent annual Form 10-K filing. Oglethorpe Power's budget for its interest in the two units, meanwhile, is $8.1 billion as of March 31, according to its most recent Form 10-K filing. Total cost estimates for the Vogtle additions are difficult to determine given variables like financing costs across the multiple owners, as well as $3.7 billion provided as a result of the bankruptcy of the original builder, Westinghouse Electric, but some estimates top $30 billion. Georgia Power will likely propose a prudency review in excess of the $7.3 billion previously determined reasonable in an earlier settlement with the PSC, according to S&amp;P Global Senior Research Analyst Dan Lowrey. Georgia Power's request is expected to be less than its total share of costs, Lowrey said. Georgia Power has already said it would not file for recovery of some costs, including the nearly $700 million its project partners won in a legal battle over cost sharing, Lowrey said. "Georgia Power has already written off a lot related to this project," Lowrey added. "There are certain costs I'm sure the PSC won't question, namely costs borne as a result of extraordinary circumstances brought about by the COVID-19 pandemic." Judging by the outcome of the prudency review for Vogtle's first two units, and given the overall constructive regulatory environment in Georgia, including multiple cost-recovery mechanisms, strong support for generation construction, and above-average returns on equity authorized for utilities, Lowrey said he expects a "fairly constructive outcome" to the review. While it remains a challenge for regulators across the country to balance macroeconomics and the pressure on customer bills against utility cost recovery and capex plans, Lowrey and Grosberg said they did not expect significant pushback from Georgia regulators, who have historically supported the project. "I would consider any pushback from the PSC to be mainly for show, especially given a special election is supposed to be scheduled for two commissioners this year," Lowrey said, pointing to a December 2022 rate-case decision where commissioners granted nearly all the revenue Georgia Power sought in the form of a multiyear rate increase of nearly $1 billion. Asked about the potential burden on customers, former CEO Tom Fanning, who now serves as chairman of Southern Company's board of directors, said in May that Southern Company and Georgia Power, along with other partners in the project, will carry the expansion expenses. Southern Company has written off more than $3 billion, Fanning said. Signals for the broader nuclear industry The Vogtle expansion reaching the finish line signals to the broader nuclear industry "that it's doable. We did something big and we were gonna get it done right," Womack said. The new Vogtle units are the first new nuclear capacity in the US since the Tennessee Valley Authority reached commercial operation of unit 2 at the Watts Bar Nuclear Plant in 2016, but that unit was originally developed in the early 1970s and abandoned while under construction in 1985. Construction restarted in 2007. "It's important, I think, for this country to be a leader, not just follow China and Russia, but show in this country how important nuclear is from an energy independence standpoint [and] also from a portfolio standpoint and the role that nuclear must play as we go forward," Womack said. The two new Vogtle units will replace some of the coal- and gas-fired power plants Georgia Power intends to retire by 2028. Editor: Valarie Jackson ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/061022-european-year-ahead-power-falls-from-record-highs-summer-contracts-rise</link><description>European year ahead power prices eased from record highs in the week to June 10 while summer contracts rebounded.</description><title>European year-ahead power falls from record-highs, summer contracts rise</title><pubDate>10 June 2022 13:19:00 GMT</pubDate><author><name>Andreas Franke</name><name>Kira Savcenko</name><name>Fatemeh Zahedi</name><name>Maxim Grama</name></author><content><![CDATA[ 10 Jun 2022 | 13:19 UTC European year-ahead power falls from record-highs, summer contracts rise By Andreas Franke, Kira Savcenko, Fatemeh Zahedi, and Maxim Grama Highlights German Cal dips after 60% jump EDF shifts schedules, eases winter risk Spain gas price cap to start June 14 Getting your Trinity Audio player ready... European year-ahead power prices eased from record-highs in the week to June 10 while summer contracts rebounded. The benchmark German Cal 23 contract fell 10% trading June 10 below Eur225/MWh after starting the week at a record Eur249/MWh, EEX data show. July rebounded after closing June 8 below Eur180/MWh, the lowest for a front-month since February. Front-month contracts are now just a third of levels seen three months ago, while year-ahead contracts are up around 50% since the outbreak of war Feb. 24. TTF front-month gas also bounced off three-month-lows below Eur80/MWh after a fire at the Freeport LNG terminal in Texas lifted July contracts to Eur84.65/MWh June 9, still down 3% over the fortnight, S&amp;P Global Commodity Insights data show. Coal into Europe for 2023 fell 2% to $219.75/mt by June 9, while EUA carbon allowances fell below Eur80/mt June 8 after the European Parliament rejected a reform of the EU ETS. On the spot, holidays across Europe eased demand amid rising temperatures and falling wind and hydro production. German wind fades German day-ahead averaged Eur168.50/MWh May 27-June 9, up 3.5% over the fortnight as low wind provided some support even as demand inched lower. July settled June 9 at Eur185.5/MWh on EEX, down 6% over the fortnight with summer contracts shedding risk premiums as supply disruption seemed less likely to market participants. The contract remained down over two weeks even as it received a boost June 9 after the explosion at the Freeport LNG terminal. "Still same fundamentals: high LNG and mild weather," a trader said. Further out, contracts remained firm on the risk of Russian supply disruptions and sub-optimal stores, the trader added. "Soaring prices by the end of the year are a fact...rumors of cold winter will circulate and push up prices," another trader said. EDF postpones Q1 outages French prices remain elevated due to record-low nuclear and fears of gas supply shortages in Europe. May's average dipped below Eur200/MWh, down 17% from April with only Italy averaging higher. Demand dipped below 42 GW May 27 to June 9 allowing France to maintain net exports with Italy receiving on average 2 GW over the fortnight, while the UK sent 1.5 GW to France, according to RTE data. Flows on the Spain-France interconnectors reversed southbound over the period that included the Whitsun holiday. Nuclear output averaged 27.3 GW in May, down 9% from April with monthly output hitting record lows for the past nine months. French hydro averaged 5.8 GW over the fortnight, while wind averaged 2.9 GW. Winter risk premiums eased slightly after EDF postponed planned maintenance at seven reactors early next year by 2-3 weeks with Q1 baseload trading June 10 at Eur515/MWh compared to levels around Eur550/MWh in late May. Spanish day-ahead averaged Eur190.05/MWh in May, little changed from April, but up 183% on year. Spain remained at discount to the rest of Europe mainly due to the gas-for-power price cap set to start June 14 after approval by the European Commission. Cal 2023 settled June 9 at Eur153.50/MWh, half of French levels Cal 23 values of Eur300/MWh-plus. "We [Spain] are getting ready for next winter, but if the winter is really cold is not going to help without the backup of Russia, there is a need for a solid backup plan," a Spanish trader said. The Eur40/MWh price cap on gas used in power generation is set to maximize power exports to France. Spanish solar soared 38% on year in May but at 3.2 TWh remains behind wind, down 2% at 4.6 TWh. Hydro fell 11% on year to 1.9 TWh, REE data show. Italy at summer premium In Italy, day-ahead settled June 9 at Eur203.56/MWh, about 8% below prices so far this month, GME data show. Prices were pressured by low levels in Sicily and Southern zones on some days. July baseload settled at Eur235.93/MWh June 9 on EEX, down just 1% over the two-week period. Prices continued to score some support from low hydro averaging just 4.9 GW June 1-9, down 33% on year, Terna data showed. Cal 2023 rose 2.5% over the fortnight to Eur211.64/MWh June 9 with Italian year-ahead baseload at a discount to both Germany and France. "Gas in winter keeps its risk [premium] at the moment. It's not finished," a trader said. UK discount narrows UK day-ahead power averaged GBP141.68/MWh month-to-date, up 14% from early May as wind power generation fell, S&amp;P Global data show. Warmer weather and the holiday weekend capped prices, while NBP gas remained at a discount to Continental hubs. A fire June 8 at Freeport LNG terminal provided bullish sentiment with around 20% of US LNG processing offline for at least three weeks. Market participants said that any longer outage would prove difficult to maintain healthy storage injections. NBP July gas jumped 17% June 9 with gains filtering through into power where July baseload rose 9%. As a result, the UK's discount over French front-month power narrowed to Eur27/MWh. UK gas generation averaged 15 GW so far this month despite a June 3 peak at 18.7 GW, BMRS data show. Wind averaged 3 GW, down 0.3 GW, while nuclear dipped to 5.5 GW. MONTHLY AVERAGE POWER PRICES (Eur/MWh) May average April average Q1 average Austria 184.49 186.22 213.23 Belgium 176.64 186.59 206.58 France 197.43 233.1 230.72 Germany 177.48 165.73 182.85 Great Britain* 149.64 210.52 238.71 Italy 230.06 245.97 248.09 Netherlands 181.37 195.2 206.22 Poland 140.49 124.21 134.04 Spain 187.13 191.52 228.41 Switzerland 197.07 227.49 244.68 Nordics (highest zone) Denmark (DK1) 171.86 163.64 155.63 Finland 132.66 79.36 91.41 Norway (NO2) 163.4 180.65 150.83 Sweden (SE4) 132.83 110.11 110.34 * GB converted by Platts to Eur/MWh Source: Epex Spot, OMIE, GME,S&amp;P Global Commodity Insights Editor: Henry Edwardes-Evans ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/podcasts/commodities-focus/100422-europe-energy-crisis-security-storage-power-gas-lng-oil-russia-ukraine-nord-stream</link><description>As gas supply disruptions send shockwaves across the world, the ability and capacity to store energy has come under close scrutiny.&amp;#xa;&amp;#xa;Associate Director Paul Hickin discusses with gas and power editors Stuart Elliott and Kira Savcenko whether Europe has enough energy in reserve to get through the winter, the challenges of providing sufficient back-up from both fossil fuels and alternative sources, the knock-on effects to the rest of the world, and whether we might experience dÃ©jÃ  vu this time n</description><title>Europeâ&amp;#x80;&amp;#x99;s energy crisis: is storage fit for purpose?</title><pubDate>04 October 2022 09:50:00 GMT</pubDate><author><name>Paul Hickin</name><name>Stuart Elliott</name><name>Kira Savcenko</name></author><content><![CDATA[ 04 Oct 2022 | 09:50 UTC Listen: Europeâs energy crisis: is storage fit for purpose? Featuring Paul Hickin, Stuart Elliott, and Kira Savcenko As gas supply disruptions send shockwaves across the world, the ability and capacity to store energy has come under close scrutiny. Associate Director Paul Hickin discusses with gas and power editors Stuart Elliott and Kira Savcenko whether Europe has enough energy in reserve to get through the winter, the challenges of providing sufficient back-up from both fossil fuels and alternative sources, the knock-on effects to the rest of the world, and whether we might experience dÃ©jÃ  vu this time next year. Useful price assessments: Dated Brent: PCAAS00 UK baseload front-month (GBP/MWh): AADGP00 TTF front-month (Eur/MWh): GTFTM01 More listening options: ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/lng/070822-high-gas-prices-crimp-indias-gas-fired-power-generation-demand-growth</link><description>High gas prices have forced around 25 GW of India&amp;apos;s gas fired power generation to idle and jeopardized natural gas infrastructure build out that was based on a sub $10/MMBtu price assumption, Akshay K</description><title>High gas prices crimp India&amp;apos;s gas-fired power generation, demand growth</title><pubDate>08 July 2022 12:39:00 GMT</pubDate><author><name>Eric Yep</name></author><content><![CDATA[ 08 Jul 2022 | 12:39 UTC High gas prices crimp India's gas-fired power generation, demand growth By Eric Yep Highlights Gas infrastructure based on sub-$10/MMBtu price 25 GW of gas-based power plants not operating Long-term LNG price also not sustainable at $100/b oil Getting your Trinity Audio player ready... High gas prices have forced around 25 GW of India's gas-fired power generation to idle and jeopardized natural gas infrastructure build-out that was based on a sub-$10/MMBtu price assumption, Akshay Kumar Singh, managing director and chief executive of Petronet LNG, said at a conference in Singapore. "We have never seen such type of volatility in the last 50 years," Singh said at the Asia Pacific LNG &amp; Gas Summit. Petronet LNG is India's main state-owned gas importer and supplier. India has an ambitious target to increase the share of natural gas in its primary energy basket from around 6.7% currently to 15% by 2030. This will require natural gas consumption to increase from around 45 million mt to over 150 million ton by 2030, Singh said. "We were heavily targeting dependence on LNG. And in fact, our assessment was that today our import is 50% LNG and 50% is domestic [gas]; and LNG's share would have gone to 75% by 2030," he said. "Pre-COVID everyone was talking about $5-$6/MMBtu and we were expecting the same thing in India. All the infrastructure development plan was happening based on the assumption that there will be a sustainable supply of natural gas at sub $10/MMBtu," Singh said. He said suppliers need to realize that if there is demand destruction and natural gas remains underground, some other form of fuel will replace gas which is not good for meeting net-zero targets. Gas shortages and high prices have forced large-scale switching to alternative fuels, including boosting coal-fired capacity and restarting of mothballed oil-fired power units in many Asian countries, in addition to energy rationing, power cuts and other contingencies. Out of India's annual consumption of around 45 million mt of natural gas, 25 million mt is LNG; and out of the future target of 150 million ton mt/year by 2030, the largest growth was expected to be from LNG in the range of 110 or 120 million mt/year, Singh said. "So LNG is going to be the main source of meeting our energy requirement in the near future and we can't be dependent on only spot [purchases]," Singh said. He said out of 25 million mt of LNG demand, a portfolio of almost 20 million mt is under long-term contracts and 5-7 million mt of demand is exposed to the spot market. "If the spot [volume] is at a reasonable price that increases the consumption of gas in our energy basket. We have a huge potential to increase the gas consumption. There is no dearth of consumers," Singh said. He said, however, around 25,000 MW of gas-based power plants that can consume 25 million mt of gas is not operating just because of high prices. Out of India's total power generation capacity of 403 GW as of May 31, 2022, only 6.2% or 25 GW is gas-fired while more than 52% is coal-fired, and the remaining is from renewables, hydro, nuclear and other sources, official data showed. India's LNG demand in particular is concentrated in the industrial and fertilizer sectors that account for over 75% of demand, and around 10% is used in the power sector. Domestic gas demand production is limited by poor hydrocarbon resources. Even the long-term contracted prices have risen to $14-$15/MMBtu from $5-$6/MMBtu because of crude prices above $100/b, and Henry Hub gas prices have risen above $9/MMBtu, he said. "The long-term price is also not looking sustainable as of today unless and until crude stabilizes around $70-$80/b," Singh added. "So the consuming nations are totally confused what to do," Singh said. Editor: Debiprasad Nayak ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/crude-oil/062623-fossil-fuels-stubbornly-dominating-global-energy-despite-surge-in-renewables-energy-institute</link><description>Oil, gas, coal remain at around 82% of global energy mix Wind, solar power hot reach 12% share of generation Oil&amp;apos;s dominance has been falling since 1970s Fossil fuels continue to meet more than 80% of</description><title>Fossil fuels &amp;apos;stubbornly&amp;apos; dominating global energy despite surge in renewables: Energy Institute</title><pubDate>26 June 2023 00:00:00 GMT</pubDate><author><name>Robert Perkins</name><name>Henry Edwardes-Evans</name></author><content><![CDATA[ 26 Jun 2023 | 00:00 UTC Fossil fuels 'stubbornly' dominating global energy despite surge in renewables: Energy Institute By Robert Perkins and Henry Edwardes-Evans Highlights Oil, gas, coal remain at around 82% of global energy mix Wind, solar power hot reach 12% share of generation Oil's dominance has been falling since 1970s Getting your Trinity Audio player ready... Fossil fuels continue to meet more than 80% of the world's energy needs despite a continued record growth rate of renewable energy in the wake of the COVID-19 pandemic, the UK-based Energy Institute said June 26. Global primary energy consumption grew by 1%, with global oil consumption rising almost 3 million b/d to 97.3 million b/d in 2022, 0.7% below 2019 levels, the EI said in its Statistical Review of World Energy. Together with gas and coal, fossil fuels made up 82% of the global energy mix, it said. Had Chinese demand recovered in line with the rest of the world, oil demand in the world's biggest import market would have been 1 million b/d higher, EI said, pushing fossil fuels to 83% of the global mix. Formerly BP's benchmark annual energy publication, the oil major handed the Statistical Review to the EI last year, 71 years after it was first published. EI has now partnered with KPMG and Kearney to produce the study. Fossil fuels accounted for 82% of primary energy in 2021, according to the previous annual review, down from 83% in 2019 and 85% five years ago. Oil's share of the global energy mix was around 33% last year although it has been falling steadily over the past four decades after hitting a peak of 50% in 1973, according to the data. In 2022, global natural gas demand declined by 3%, dropping just below the 4 Tcm mark achieved for the first time in 2021. Its share in primary energy in 2022 decreased slightly to 24% (from 25% in 2021). But coal demand continued to grow, rising 0.6% on 2021 to 161 Ej; the highest level of coal consumption since 2014, according to the EI. "The notion of new-normal post-COVID with energy growth discontenting from the long-term trends does not seem to be playing out," EI CEO Nick Wayth said in a presentation. Robust renewables Fossil fuel resilience in the energy mix comes despite record growth rates for renewable energy. In Europe, gas and coal consumption also saw a boost to fill the gap from lower nuclear power output in Germany and France, EI noted. Last year saw the largest-ever increase in wind and solar new build capacity, EI said, noting that, together, they reached a record 12% share of power generation, with solar up 25% and wind up 13.5%. Total renewable energy, excluding hydro, met 84% of net electricity demand growth in 2022, EI said. "The EI Statistical Review is essential reading for policymakers around the world trying to balance the energy trilemma," said Simon Virley, Head of Energy and Natural Resources at KPMG in the UK. "All aspects of the trilemma were put under severe strain in 2022. Despite record growth in renewables, the share of world energy still coming from fossil fuels remains stubbornly stuck at 82%, which should act as a clarion call for governments to inject more urgency into the energy transition." Although starting from a low base and running well behind most projections for clean energy levels needed to meet the Paris Agreement climate targets, the growth of renewable energy remained robust, EI said. "In terms of primary energy, renewables have contributed the majority of absolute growth on a net basis," Wayth said. "If you can continue the doubling of renewables energy every five to six years you get to a point where you do begin to displace fossil fuels." With global energy-related emissions up 0.8% last year, however, Virley said the world was falling behind on Paris Agreement commitments to limit warming. Referencing 2020's COVID-19 economic slowdown and a 5% decline in emissions, Virley said: "We need that rate of decline to be repeated every year for the next 30 years to be in line with Paris. It's not happening." Analysts at S&amp;P Global Commodity Insights forecast that fossil fuels made up 77% of the global energy mix last year, a level set to fall to 62% by 2050 under a reference case scenario. Editor: Jonathan Fox ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/crude-oil/011924-pakistans-fuel-oil-exports-hit-all-time-high-in-dec-as-domestic-utility-demand-falls</link><description>Fuel oil exports climb 37% on month in Dec Fuel oil consumption in Dec down 33% on year Pakistan&amp;apos;s fuel oil exports rose to an all time high in December amid declining demand from domestic utilities a</description><title>Pakistan&amp;apos;s fuel oil exports hit all-time high in Dec as domestic utility demand falls</title><pubDate>19 January 2024 05:45:00 GMT</pubDate><author><name>Koustav Samanta</name><name>Haris Zamir</name></author><content><![CDATA[ 19 Jan 2024 | 05:45 UTC Pakistan's fuel oil exports hit all-time high in Dec as domestic utility demand falls By Koustav Samanta and Haris Zamir Highlights Fuel oil exports climb 37% on month in Dec Fuel oil consumption in Dec down 33% on year Getting your Trinity Audio player ready... Pakistan's fuel oil exports rose to an all-time high in December amid declining demand from domestic utilities as the country focuses on alternate fuels such as gas and coal for power generation. The South Asian nation exported 135,551 mt of fuel oil in December, about 37% higher from 98,830 mt in November, according to data released Jan. 18 by Pakistan's Oil Companies Advisory Council (OCAC), which compiles data related to fuel consumption, imports and exports. Fuel oil exports in the six months ended Dec. 31, 2023 stood at 433,945 mt, up from an overall export volume of 276,979 mt during the fiscal year ended June 30, 2023, the OCAC data showed. Pakistan's financial year runs from July to June. Domestic consumption of fuel oil has been on a declining trend since long as the government has been encouraging electricity generation from other cheaper sources like coal, nuclear and regasified LNG, leaving huge stockpiles of fuel oil, said Muhammad Awais Ashraf, director research at Akseer Research. The country's fuel oil consumption has also fallen as a result of the government's plan to run tube wells in villages on solar power instead of fuel oil, Awais said. Fuel oil consumption dropped to 0.08 million mt in December, down about 33% year on year, OCAC data showed. Consumption in the six months ended Dec. 31, 2023 stood at 0.56 million mt, down about 61% on the year, the data showed. The decline in fuel oil usage was also reflected in the data on power generation. In the six months ended Dec. 31, about 1,353 Gwh electricity was produced from fuel oil-fired plants, down from around 3,185 Gwh generated during the same period a year earlier, official government data showed. As of Jan. 17, Cnergyico had fuel oil stocks of 56,250 mt, while PARCO had 50,000 mt, Attock Refinery about 18,300 mt, Pakistan Refinery about 12,900 mt and National Refinery around 2,213 mt, according to data provided by industry sources. Asia's supply of 180 CST high sulfur fuel oil is set to rise in 2024 amid structural changes in South Asian demand as the region pushes for cheaper or cleaner alternative fuels in power generation, possibly setting the stage for a sustained narrowing in the viscosity spread, S&amp;P Global Commodity Insights reported earlier. Alongside Pakistan, the changes have been also apparent in Sri Lanka and Bangladesh, where either fuel oil exports have been or are expected to rise, or imports plummet, as governments and power generating companies rely more on coal, nuclear, gas or LNG for electricity generation. Platts assessed the Singapore 180 CST HSFO cash differential over the Mean of Platts Singapore 180 CST HSFO assessment at $1.08/mt Jan. 18, hovering at its lowest level in a month amid sluggish demand and competitive offers for physical cargoes seen in the week that began Jan. 15. The Singapore 180 CST HSFO February-March market structure was assessed at $1.20/mt at the Asian close Jan. 18, down from $2.80/mt Jan. 17, S&amp;P Global data showed. The Asian HSFO market in general is expected to be sluggish in 2024 as more-than-adequate supplies and a steady decline in utility demand offsets incremental consumption by new scrubber-installed ships coming out of yards, S&amp;P Global reported earlier. Editor: Adithya Ram ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/021422-pjm-tracker-cooler-weather-higher-loads-boost-january-pjm-power-gas-prices</link><description>PJM Interconnection power prices in January jumped about 50% from December and roughly 100% from year ago levels with power demand around 8% higher in January as colder weather affected overall electr</description><title>PJM TRACKER: Cooler weather, higher loads boost January PJM power, gas prices</title><pubDate>14 February 2022 21:40:00 GMT</pubDate><author><name>Jared Anderson</name></author><content><![CDATA[ 14 Feb 2022 | 21:40 UTC PJM TRACKER: Cooler weather, higher loads boost January PJM power, gas prices By Jared Anderson Highlights PJM East spot power surges to $90.39/MWh Texas Eastern gas averages $9.92/MMBtu January coal-fired output jumps 72% PJM Interconnection power prices in January jumped about 50% from December and roughly 100% from year-ago levels with power demand around 8% higher in January as colder weather affected overall electric heating loads. PJM East Hub saw the highest January spot power prices. Real-time on-peak averaged $90.39/MWh, up 262% from January 2021 and 140% above the December average of $37.65/MWh. PJM East Hub day-ahead on-peak power prices averaged $75.02/MWh in January, nearly 200% higher on year and 86% above December. PJM West Hub day-ahead on-peak power prices averaged $71.63/MWh in January, 164% higher on year and about 73% higher on month. Moving farther west, AEP Dayton Hub January day-ahead on-peak power averaged $55.37/MWh, about 111% above year-ago levels and 41% higher on month. Northern Illinois Hub saw the lowest January spot power prices, with day-ahead on-peak prices at the hub averaging $47.38/MWh, about 92% higher on year and 37% higher on month. Texas Eastern Transmission natural gas prices surged in January to average $9.92/MMBtu, 248% higher on year and nearly 200% above the December 2021 average of $3.31/MMBtu. Chicago city-gates gas prices averaged $4.17/MMBtu in January, 65% higher than a year ago and about 16% higher on month. PJM peakload was 17% higher in January than December 2021, with peakload averaging 112,953 MW compared with an average of 96,900 MW in December, according to ISO data. "Our outlook for load growth in PJM is a decline over the next five years at around 0.3% in 2022 and 2023, before flattening out for the rest of the period," S&amp;P Global Platts Analytics said in a recent research note. January was considerably colder than December in PJM territory, with an average January low temperature of 20.8 degrees Fahrenheit compared with 36.1 F in December, according to CustomWeather data. Heating degree days averaged 36.5 in January, up from 21.3 in December. HDDs were 20% higher on year, Platts Analytics said. Power generation fuel mix "Coal output in January was up 72% compared to December due to the expected higher seasonal demand," Platts Analytics said. The incremental demand also lifted coal 24% year on year, "showing the region opted to tap into coal as gas-fired generation was up by only 2% year on year," the analysts said. Coal-fired power accounted for 27.4% of the fuel mix in January, up from 17.5% in December, according to PJM data. Gas-fired power accounted for 33.5% of the January fuel mix, down from 38.7% in December. "We anticipate a significant number of gas-fired generation units to be completed and operational in the 2022-23 time frame, with a slowdown starting in 2024," Platts Analytics said. Nuclear accounted for 31.4% of the fuel mix, down from 35.8% in December and hydropower was flat month on month. Wind power fell slightly, accounting for 3.9% of the January fuel mix from 4.7% in December. Forward power, gas prices Forward power prices were flat to lower on month during January trading. The highest price was PJM West Hub for February, which averaged $69.01/MWh, only about 2% higher on month, but 119% higher than where the package traded in January 2021, according to Platts M2MS data. PJM West power for March averaged $52.11/MWh and the April contract averaged $48.09/MWh. AEP Dayton Hub power for February averaged $60.55/MWh, a 3% decline on month but 103% higher than January 2021. The March contract averaged $48.42/MWh in January trading, 69% higher on year, and the April contract averaged $48.13/MWh, or 65% higher on year. Northern Illinois Hub power for February averaged $53.14/MWh in January trading, relatively flat on month and about 97% higher on year. The March contract averaged $41.57/MWh, 60% higher on year, and the April contract averaged $42.30/MWh which was 65% higher on year. Platts Transco Zone 6 non-New York gas prices for February averaged $7.27/MMBtu in January trading, which was about 8% higher on month and 115% higher on year. The March contract averaged $4.23/MMBtu, 63% higher on year, and the April contract averaged $3.42/MMBtu in January trading which was about 51% higher on year. "With gas prices expected to average around $3.40/MMBtu at M3 and around $2.80/MMBtu at Columbia, we anticipate coal-fired generation to decline in PJM through the next four years," Platts Analytics said. "On-peak power prices are expected to decline through 2024 before they reverse that trend in 2025 and stay flat in 2026, with these movements mainly driven by fluctuations in gas prices," the analysts said. Editor: Jared Anderson ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/energy-transition/102622-g7-price-caps-add-new-uncertainties-to-market-aramco-ceo</link><description>The Group of Seven&amp;apos;s plans to impose price caps on the export of Russian crude and products in December and February, respectively, will add a new layer of uncertainty to the oil market, Saudi Aramco&amp;apos;</description><title>G7 price caps add new uncertainties to market: Aramco CEO</title><pubDate>26 October 2022 14:28:00 GMT</pubDate><author><name>Jennifer Gnana</name></author><content><![CDATA[ 26 Oct 2022 | 14:28 UTC G7 price caps add new uncertainties to market: Aramco CEO By Jennifer Gnana Highlights Aramco CEO gives pessimistic view of market Aramco to invest $1.5 bil in 'inclusive energy transition' Japan, South Korea key markets for blue hydrogen Getting your Trinity Audio player ready... The Group of Seven's plans to impose price caps on the export of Russian crude and products in December and February, respectively, will add a new layer of uncertainty to the oil market, Saudi Aramco's CEO said Oct. 26 at a conference in Riyadh. "Depending on what's happening on Dec. 5 with the total embargo by the Europeans that they will implement on crude and in February of next year, when they will do on products, there is a lot of uncertainty that is shaping the markets," Amin Nasser told the Future Investment Initiative in the Saudi capital. G7 and the EU have agreed to impose restrictions on the seaborne transport of crude and products that originate from Russia, as a way to curtail Moscow's ability to earn energy revenue that could fund its ongoing invasion of Ukraine. Tanker owners, insurers and other marine service providers subject to their jurisdictions are expected to be prohibited from servicing Russian oil trade unless the barrels are sold below yet-to-be-defined price caps. Oil prices have remained elevated following the invasion in February, with Platts-assessed Dated Brent up 6.7% year on year at $91.555/b on Oct. 25. Nasser cited continued risks to the global economy and COVID-19 restrictions as weighing on demand for crude globally. "A combination of factors, rising interest rates, central banks, inflation-impact and all of these things [make for] a very pessimistic view of the markets," he said. Saudi Arabia's energy minister on Oct. 25 said the kingdom's supply of crude to Europe through Aramco's trading unit will remain "business as usual." "We are engaged with so many governments. Just to give you an example, Germany, Poland, the Czech Republic, Croatia, Romania and others. They are going through a phase of debottlenecking their supply chains and supply systems to ensure that we can come in," Prince Abdulaziz bin Salman said. Supplies into Europe from Saudi Aramco have nearly doubled from 490,000 b/d in September 2021 to 950,000 b/d during the same period this year. "Where would we be in the next few months? We will be the same. We will be the supplier to those who want us to supply them," the minister said. 'Flawed' energy transition Aramco's Nasser also spoke out against what he termed as a "flawed" energy transition plan, noting that the global economy was switching more toward polluting coal over lower-carbon intensive fuels. "Honestly, it's not really delivering. What we need is an optimal, realistic transition plan," Nasser told FII. "If you look at coal today, it's 8 million tons. This is the highest since 2015. The cost of coal -- barrel of oil equivalent -- is $60 to $80. So basically, we're transitioning to coal. It used to be $20 [per barrel of oil equivalent]," he added. The Aramco CEO previously likened global energy transition plans to "sandcastles" that were being washed away by the waves of reality. "Because when you shame oil and gas investors, dismantle oil- and coal-fired power plants, fail to diversify energy supplies (especially gas), oppose LNG receiving terminals, and reject nuclear power, your transition plan had better be right," Nasser said at a conference in Switzerland on Sept. 26. "Instead, as this crisis has shown, the plan was just a chain of sandcastles that waves of reality have washed away and billions around the world now face the energy access and cost of living consequences that are likely to be severe and prolonged." In Riyadh, he continued his criticism of most current energy transition plans noting that they were modeled after "a western point of view" that the rest of the world needed to follow. "No, it's not going to work like that. That's why everybody's moving to coal," Nasser said. Financing transition Saudi Aramco also announced plans for a $1.5 billion fund on Oct. 26 that facilitates "inclusive energy transition." The world's largest oil-exporting company will invest globally through its venture capital arm, Aramco Ventures, in "carbon capture and storage, greenhouse gas emissions, energy efficiency, nature-based climate solutions, digital sustainability, hydrogen, ammonia and synthetic fuels," it said in a statement. Aramco will continue to develop blue hydrogen, produced from the steam methane reformation of natural gas, with the fugitive carbon dioxide captured and sequestered. The gas is stored in the form of ammonia, which is the more easily transportable form of hydrogen. Aramco has earmarked Japan and South Korea as key markets for sale of blue hydrogen produced at its facility, Nasser said. "But for companies like Aramco, we need an offtake agreement for these projects, because these are costly projects and without an offtake agreement, you cannot grow that market big time," he added. Aramco plans to reach net-zero emissions by 2050. Editor: Shashwat Pradhan ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/061820-iea-outlines-three-year-plan-for-sustainable-recovery</link><description>Governments can spur economic growth and jobs at the same time as cutting greenhouse gas emissions, the International Energy Agency said Thursday in a $1 trillion per year pandemic recovery plan.</description><title>IEA outlines three-year plan for sustainable recovery</title><pubDate>18 June 2020 04:00:00 GMT</pubDate><author><name>Frank Watson</name></author><content><![CDATA[ 18 Jun 2020 | 04:00 UTC â London IEA outlines three-year plan for sustainable recovery By Frank Watson Highlights Government decisions to shape energy sector for decades to come IEA sees role for renewables, hydrogen, CCS, clean transport Support for oil, gas could be linked to cutting methane emissions London â Governments can spur economic growth and jobs at the same time as cutting greenhouse gas emissions, the International Energy Agency said Thursday in a $1 trillion per year pandemic recovery plan. The plan seeks to show governments how they can help their economies recover from the coronavirus pandemic at the same time as putting energy and other sectors on a track for lower carbon growth. "Our Sustainable Recovery Plan shows it is possible to simultaneously spur economic growth, create millions of jobs and put emissions into structural decline," the IEA said in the report released June 18. As they design economic recovery plans, policymakers are having to make "enormously consequential" decisions in a very short space of time, the Paris-based agency said in its World Energy Outlook special report. "These decisions will shape economic and energy infrastructure for decades to come and will almost certainly determine whether the world has any chance of meeting its long-term energy and climate goals," it said. The plan would require investment of $1 trillion/year globally in the 2021-2023 period, and provides policymakers with a roadmap to recovery. The plan outlines measures that governments can take across six key sectors: electricity, transport, industry, buildings, fuels and emerging low-carbon technologies. The plan sets out policies and targeted investments for each key sector, including measures designed to accelerate the deployment of low-carbon electricity sources such as new wind and solar, and increase the spread of cleaner transportation such as more efficient and electric vehicles and high speed rail. It also included measures to improve the efficiency of industrial equipment; make the production and use of fuels more sustainable; and boost innovation in technologies such as hydrogen, batteries, carbon capture utilization and storage and small modular nuclear reactors. Energy demand takes huge hit The coronavirus pandemic is expected to cut global energy demand by 6% overall in 2020 compared with 2019, the IEA said. By sector, oil demand is likely to drop by 8% year on year in 2020, while natural gas demand was expected to fall 4% and coal demand slide 8%, it said. Nuclear power output is expected to be down 2.5% in 2020, while electricity demand will likely fall 5% overall, and up to 10% in some areas, it said. As a result, investment in the energy sector in 2020 will experience its largest decline on record with a reduction of 20% â almost $400 billion â in capital spending compared with 2019, the IEA said. As economies recover from these massive demand impacts, governments can help steer the private sector to make investment choices that will support growth, jobs and long-term climate objectives, it said. The IEA's recovery plan can add 1.1 percentage points to global economic growth each year, and save or create about 9 million jobs per year over the next three years, if governments choose to follow the non-governmental agency's advice, it said. "It would also bring lasting benefits to the global economy because investment in new infrastructure, such as electricity grids and more energy efficient buildings and industries, would improve the overall productivity of both workers and capital," it said. In addition, the IEA's plan would cut global energy-related GHG emissions by 4.5 billion mt of CO2 equivalent by 2023 compared with where they would otherwise be, it said. The plan would also make 2019 the definitive peak in global emissions, and put them on a path toward achieving long-term climate goals, including the Paris Agreement, it said. "The Sustainable Recovery Plan is not intended to tell governments what they must do. It seeks to show them what they can do," the IEA said. The IEA's report â produced in collaboration with the International Monetary Fund â sets out how governments can deliver resilient and clean energy projects that are "shovel-ready," including a strong pipeline of new projects and tailored support for distressed industries such as the auto sector. Strengthening power grids, boosting clean energy The IEA's plan included recommended measures such as strengthening the resilience of electricity grids and integrating higher shares of renewables; accelerating wind and solar photovoltaic deployment; and modernizing and upgrading existing nuclear and hydropower plants. It also recommended support for biofuel industries if they meet sustainability criteria; and support for the upstream oil and gas sector could be focused on reducing methane emissions, while reducing inefficient fossil fuel subsidies also creates an opportunity, it said. Support for innovation and new technologies is unlikely to create a large increase in jobs or economic activity in the short-term, but could lead to the development of new sustainable industries over the long-term, including hydrogen, batteries, carbon capture, utilization and storage, and small modular nuclear reactors, the IEA said. Editor: Barbara Lorenzo Caluag ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/natural-gas/011023-us-power-tracker-harsh-weather-costly-natural-gas-boost-texas-power-prices</link><description>Higher Houston Ship Channel natural gas prices and heavier loads driven by harsher weather pushed Electric Reliability Council of Texas wholesale power prices higher in December on the month and year.</description><title>US POWER TRACKER: Harsh weather, costly natural gas boost Texas power prices</title><pubDate>10 January 2023 21:33:00 GMT</pubDate><author><name>Mark Watson</name></author><content><![CDATA[ 10 Jan 2023 | 21:33 UTC US POWER TRACKER: Harsh weather, costly natural gas boost Texas power prices By Mark Watson Highlights Forwards fall on month, rise on the year Power burn likely to decline in February Getting your Trinity Audio player ready... Higher Houston Ship Channel natural gas prices and heavier loads driven by harsher weather pushed Electric Reliability Council of Texas wholesale power prices higher in December on the month and year. February power forwards followed gas forwards lower on the month but was substantially higher on the year. And while combined wind and solar output in December was down on the month and year, the prices they were able to capture when they did produce were up significantly. Average day-ahead on-peak locational marginal pricesâranging from the mid-$60s/MWh to low $70s/MWh, were up between 33.7% and 56.3% across ERCOT's four main generation hubs compared with November, and up by 99.4% and 149.3% in comparison with December 2021 averages, according to S&amp;P Global Commodity Insights data. At the Houston Ship Channel, spot gas averaged $4.42/MMBtu in December, up 8.7% from November's $4.065/MMBtu and up 25.8% from December 2021's $3.514/MMBtu. However, at the West Texas Waha pricing point, gas prices were down both on the month and year, averaging $2.869/MMBtu in December, down 24.1% from November's $3.782/MMBtu and down 12.3% from $3.272/MMBtu in December 2021. Combined population-weighted average cooling and heating degree days in December were up 20.7% from November and up 73.1% from December 2021, according to CustomWeather data. Population-weighted temperatures averaged 51.7 degrees Fahrenheit in December, down 7% from 55.6 F in November and down almost 16% from 61.5 F in December 2021. Forward markets S&amp;P Global's M2MS forward curves showed ERCOT North Hub February on-peak power averaging almost $83.80/MWh in December, down from $89.62/MWh in November but up almost 47% from the $57.03/MWh that February 2022 power averaged in December 2021. Houston Ship Channel February gas averaged $5.676/MMBtu in December, down 17.6% from $6.885/MMBtu in November, but up more than 40% from the $4.052/MMBtu that February 2022 gas averaged in December 2021, before Russia's invasion of Ukraine disrupted global energy markets. Waha February gas averaged $5.444/MMBtu in December, down 5.6% from $5.766/MMBtu in November but up 39.6% from the $3.899/MMBtu that February 2022 gas averaged in December 2021. Given S&amp;P Global's forecast of gas-fired generation averaging 316.6 GWh/day in February and heat rates similar to February 2022, the power burn is likely to fall to an average of 2.6 Bcf/d in February from December's 3.7 Bcf/d and 3.5 Bcf/d in February 2021. The National Weather Service's forecast for January, February, and March weather, released Dec. 15, indicated enhanced chancesâ33% to 50% âfor above-normal temperatures across all regions except the Panhandle and the Oklahoma state line, where only slight chances for above- or below-normal temperatures prevail. Generation mix Amid December's mixed spot gas market and with much harsher weather, the share of gas-fired generation surged to 43.5% in December from November's 38.8% and 33.5% in December 2021, an S&amp;P Global analysis of ERCOT data shows. ERCOT data shows its gas fleet averaged 474.4 GWh/d in December, up from November's 403.6 GWh/d and 325.8 GWh/d in December 2021. The gas fleet's power burn was similarly strong, averaging 3.7 Bcf/d in December, compared with November's 3.4 Bcf/d and 3.1 Bcf/d in December 2021. In contrast with the strong performance of gas-fired generation, ERCOT's wind fleet share diminished to 25.4% in December from November's 28.9% and 31.8% in December 2021. Coal-fired generation's share also declined to 16.2% in December from 17.7% in November and 18.6% in December 2021. The ERCOT nuclear power fleet's share was 11.2% in December, up from 10.6% in November but down from 12.6% in December 2021. Solar power's share was 3.5% in December, flat with December 2021 but down from 4.2% in November. Renewable indexes On-peak renewable capture price indexes at the ERCOT North Hub, the market's most liquid location, rose substantially on the month and year, but systemwide renewable penetration indexes were generally down. Renewable capture price and penetration indexes reflected the price-taking nature of solar and wind resources in the ERCOT market. A renewable resource's capture price index is the price of electricity sold by a renewable resource at the time it is sold, which varies greatly in real-time. The ERCOT North Hub average wind capture price index in December averaged $47.90/MWh, up 37.4% from November's $34.87/MWh and up 157.4% from the $18.61/MWh that prevailed during December 2021's relatively light weather-driven power demand. The ERCOT wind fleet's systemwide renewable penetration index, at 21.6%, was down from November's 23.7% and 25.2% in December 2021. The ERCOT North Hub average solar capture price index in December averaged $44.14/MWh, up 7.4% from November's $41.11/MWh and up almost 49% from $29.66/MWh in December 2021. Solar's systemwide on-peak renewable penetration index, at 4.6% of total generation, was down from the 5.3% that prevailed in November but up from December 2021's 4.4%. Editor: Valarie Jackson ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/lng/093022-south-korea-outlines-crisis-response-for-winter-raises-gas-and-power-prices</link><description>South Korea will undertake crisis response measures to tackle the coming winter, including curbs on energy demand, raising gas prices for city gas and power sectors, securing LNG supply and boosting f</description><title>South Korea outlines crisis response for winter; raises gas and power prices</title><pubDate>30 September 2022 10:14:00 GMT</pubDate><author><name>Michelle Kim</name><name>Charles Lee and Eric Yep</name></author><content><![CDATA[ 30 Sep 2022 | 10:14 UTC South Korea outlines crisis response for winter; raises gas and power prices By Michelle Kim and Charles Lee and Eric Yep Highlights To reduce 10% of energy usage led by govertment facilities Raises natural gas prices for households, commercial users Electricity rates to rise by Won 7.4/kWh for fourth quarter Getting your Trinity Audio player ready... South Korea will undertake crisis response measures to tackle the coming winter, including curbs on energy demand, raising gas prices for city gas and power sectors, securing LNG supply and boosting finances of energy importers, according to statements made on Sept. 29 and Sept. 30. The measures are similar to contingency plans laid out by the likes of Japan and China, as well as Europe, where record high gas prices have drained cash reserves of gas and power companies and forced governments to intervene with bailouts and price caps. "With domestic energy supply highly dependent on imports and energy prices rapidly rising, Korea is suffering from a trade deficit despite robust exports," the Ministry of Trade, Industry and Energy said in statement Sept. 29. "Moreover, as fuel costs are not incorporated into price hikes in time, the losses of public energy companies are becoming more severe." It said the government is making preparations for winter while seeking to reduce domestic energy consumption and expand stable sources of energy supply. "Winter season energy supply will be secured early on, and the government, public energy corporations and private companies will be joining efforts for energy supply management through a joint emergency response system," MOTIE said. "The goal for the coming winter is to reduce energy usage by 10%, led by government and public institutions placing caps on heating temperatures," it said. All central and provincial public entities will be required to save energy by limiting indoor heating of buildings and switching off exterior lighting. The ministry said a more fundamental aim is to gradually raise energy prices and improve public companies' finances. It asked companies to monitor energy usage and commit to saving energy in preparation for winter, "as this crisis is expected to persist for a considerable length of time" and "a price adjustment is inevitable, starting with large-capacity users." Higher gas prices The government will raise natural gas prices for households and commercial users from Oct. 1 due to LNG import costs, MOTIE said Sept. 30. Natural gas prices for households will climb by Won 2.7/MJ (0.19 cents/MJ), or 15.9%, to Won 19.69/MJ from Oct. 1. Natural gas prices for commercial use will rise by Won 2.72/MJ, or 16.4%-17.4%, to Won 18.32-19.32/MJ. It marks the fourth increase in natural gas rates this year following a 7.0%-7.7% increase from July 1, a 1.8% rise from April 1 and an 8.4%-9.4% gain from May 1, which came after the country had frozen or lowered gas rates for three years. Platts JKM LNG climbed to an average of $47/MMBtu in the third quarter, from $10/MMBtu in the first quarter of last year and $24/MMBtu in July 2020, according to the ministry. Click here for the interactive The hike in gas prices is also inevitable due to the snowballing unpaid bills of state-run Korea Gas Corp, which could disrupt the country's LNG imports, it said. Unpaid bills refer to losses from failing to raise domestic prices to reflect LNG imports by Kogas. Unpaid bills of Kogas jumped to Won 4.5 trillion ($3.1 billion) as of end-March, from Won 1.8 trillion three months earlier due to sharp increases in import costs, according to the state utility. Higher power prices Separately, South Korea's state-run power utility KEPCO revised electricity tariffs to reflect adjusted fuel costs of Won 4.9/KWh and an additional tariff of Won 2.5/KWh effective in October, it said in a statement Sept. 30. This means electricity rates rise by Won 7.4/kWh for the fourth quarter. "We have decided to increase the electricity tariff to reflect higher global energy prices and power generation costs," the KEPCO statement said. The country's retail electricity price consists of a basic tariff and fuel cost, climate environment fee, as well as an adjusted unit fuel cost. The Korean government introduced the adjusted fuel cost component in 2021 to alleviate any losses that may be incurred by KEPCO during periods of high LNG prices. Electricity rates for industrial use would further rise by Won 11.9/kWh to Won 16.6//kWh from Oct. 1. It marks the third hike in the country's electricity tariffs this year following a Won 5/kWh increase for the third quarter and a Won 6.9/kWh rise for the second quarter. Hence South Korea's retail electricity and gas bills are likely to rise this winter amid record high LNG import costs, industry sources said. Editor: Jonathan Fox ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/natural-gas/022223-us-senate-energy-chair-offers-bill-to-bolster-european-north-american-energy-ties</link><description>Seeking to strengthen energy security partnerships between European and North American allies, US Senate Energy and Natural Resources Committee Chairman Joe Manchin is pushing legislation to bolster U</description><title>US Senate energy chair offers bill to bolster European-North American energy ties</title><pubDate>22 February 2023 22:29:00 GMT</pubDate><author><name>Maya Weber</name></author><content><![CDATA[ 22 Feb 2023 | 22:29 UTC US Senate energy chair offers bill to bolster European-North American energy ties By Maya Weber Highlights DOE would gain authority for more international efforts New direction for development finance organizations Getting your Trinity Audio player ready... Seeking to strengthen energy security partnerships between European and North American allies, US Senate Energy and Natural Resources Committee Chairman Joe Manchin is pushing legislation to bolster US Department of Energy authority and financing available for projects that could help ease reliance on Russian supplies. The West Virginia Democrat has introduced legislation, dubbed the North American Transatlantic Resource Security Partnership Act of 2023 (S. 458), alongside Senator Lisa Murkowski, Republican-Alaska, with both senators emphasizing a need to protect energy supplies and critical minerals from dependence on adversaries. "The United States is ready and able to be Europe's primary energy partner, and the additional authority this bill gives to the Secretary of Energy will help to make that partnership possible," Manchin said in a statement Feb. 22. Murkowski added that "[f]rom our own domestic production and exports, to the assistance our international development organizations can provide, no nation can do more to advance this cause than the United States." To support such efforts, the legislation would authorize $500 million for a new DOE and Department of Interior program intended to help allies and partner nations shift away from reliance on Russia for natural gas, oil, coal, critical minerals, nuclear fuel, isotopes and other technologies. The efforts could entail developing resources domestically, providing them to allies, offering loans or other financial assistance, or providing technical assistance. Yet another $500 million would be authorized for the program if Energy Secretary can certify to Congress that the Nord Stream 2 natural gas pipeline is permanently discontinued, according to text of the bill, introduced Feb. 15. Throughout the legislation, there is an emphasis on developing resources and production in the US. And amid debate over whether international development finance organizations should spurn fossil fuel investments, the legislation affirms support for natural gas infrastructure development. The bill also takes aim at securing supply chains in collaboration with Mexico, Canada and private industrial partners. The secretaries of energy and interior would be tasked with creating a new program, authorized at $200 million, to assure reliability of supply chains for energy production, mining, mineral processing and manufacturing. Development finance In an effort to counterbalance financial support for projects potentially available from adversaries, the lawmakers seek to boost development finance from US entities. The bill would expand the direction given to the US International Development Finance Corporation to make clear the organization can support "any type of energy" including fossil fuels, renewables and nuclear energy, as well as critical minerals development. Further, the US Export-Import Bank would set up a new strategic energy and minerals portfolio -- capped at $50 billion in aggregate amount of loan, guarantees and insurance. The portfolio would be focused on financing civilian nuclear infrastructure, natural gas infrastructure projects (including regasification projects) and critical minerals projects that may facilitate US exports. The legislation further includes a sense of Congress that it is in the highest US interest to develop the resources domestically, while also backing enhanced cooperation between the US, Mexico and Canada to increase energy production, improve energy efficiency and ease regulations to support cross-border activities. DOE loans and guarantees could be available to support research, development and commercialization, and a new US-Mexico-Canada Energy Center would also seek to foster collaboration. David Goldwyn, president of Goldwyn Global Strategies, and a former State Department and DOE official, said the bill's support for civilian nuclear development and gas infrastructure needed to back up renewables could send a "constructive" signal for the energy transition process. That said, Goldwyn noted there are hurdles to advancing legislation other than must-pass bills in the current Congress. As for European gas infrastructure development, "what's really missing" to support facilities, Goldwyn said, is a long-term commitment from European governments or European utilities to access the gas resources to replace Russian gas. Editor: Haripriya Banerjee ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/coal/081320-rwe-offsets-falling-coal-generation-with-res-as-h1-earnings-rise</link><description>RWE offsets falling coal generation with RES as H1 earnings rise, showcasing strategic shifts towards renewable energy sources and market adaptation.</description><title>RWE offsets falling coal generation with RES as H1 earnings rise</title><pubDate>13 August 2020 14:57:00 GMT</pubDate><author><name>Andreas Franke</name></author><content><![CDATA[ 13 Aug 2020 | 14:57 UTC â London RWE offsets falling coal generation with RES as H1 earnings rise By Andreas Franke Highlights H1 earnings up 18% as 9 TWh RES gain offsets 19.5 TWh less coal/gas 90% of 70-75 TWh of 2021 production hedged at Eur32/MWh margin CO2 hedged to 2030, focus on growing RES pipeline, offshore auctions London â Germany's biggest power generator RWE offset falling coal generation with new renewables and expects 2020 earnings at the upper end of the range forecast after earnings rose in the first six months despite falling power demand due to the coronavirus crisis, it said Aug. 13. RWE's fossil-fueled generation fell 19.5 TWh to 38 TWh in the first half led by German lignite and UK gas, it said. Renewables meanwhile rose 9.5 TWh to 15.4 TWh after it integrated E.ON's green assets, resulting in an overall 18% increase for adjusted group EBITDA to Eur1.8 billion ($2.1 billion), it said. Offshore wind earnings rose almost 20% to Eur585 million mainly due to strong winds in Q1 with the segment forecast to contribute nearly half of annual group earnings, now expected to be toward the upper end of the forecast range of Eur2.15 billion-Eur2.45 billion, it said. Earnings at its non-core unit of legacy German lignite and nuclear plants also doubled year on year to Eur310 million due to higher achieved margins, it said. Lignite and nuclear accounted for half of RWE's non-renewable power generation, but lignite output fell sharply to 14.3 TWh, averaging only 3.3 GW compared with 5.6 GW in H1 2019. RWE lignite plants have been hit by mining restrictions at Hambach since 2019 with the coal exit law now setting a clear path to close 2.7 GW by end-2022 to preserve the Hambach forest. Lignite, nuclear hedging secures margins RWE has been hedging output years in advance with 2020 margins around Eur3/MWh higher on year at Eur27/MWh despite EU CO2 prices hitting a 14-year-high in July. RWE is financially hedged carbon until 2030, but no longer provides hedged EUA CO2 prices, it said. German spot power prices plunged almost Eur15/MWh to average Eur23.40/MWh in the first six months as power demand fell 5% on the year due to the coronavirus. For 2021, the company had 70-75 TWh of planned lignite and nuclear production hedged at a margin of Eur32/MWh, slides for an investor presentation show. For 2022, hedged margins were stable at Eur32/MWh, but expected production volumes fell to 55-60 TWh, reflecting closure of one reactor and further lignite units with no overall change compared during Q2. For 2023, the company expects 40-45 TWh of lignite production hedged at a margin of Eur26/MWh after adjusting production plans to the coal exit law with only 7 GW lignite capacity remaining part of that unit after 2022. RWE CFO Markus Krebber told analysts that CO2 fuel switching prices would be less relevant in future. RWE Hedging Positions for German lignite &amp; nuclear (as of end-H1 2020) Year Expected Production Hedge margin Av Price Corresponding CO2 price (TWh) (Eur/MWh) Eur/MWh (end-2019)** Eur/mt (end-2019)** 2019 68* 24 29 5 2020 70-75 27 32 5 2021 70-75 32 40 8 2022 55-60 32 48 16 2023 40-45 26 Source: RWE H1 2020 presentation (*=actual production, **FY 2019 report) Renewables pipeline Company strategy is now firmly focused on expanding its wind and solar portfolio from 9 GW now to around 13 GW by end-2022. RWE plans to acquire a 2.7-GW RES project pipeline from Nordex for around Eur400 million -- mainly focused on France -- with some 500 MW expected to come online by 2025. Key focus will be offshore wind despite a gap emerging between 2022 when Germany's Kaskasi and Britain's Triton Knoll projects are expected to come online and 2025 with focus on auctions. Germany plans to auction some 10 GW of new projects for the 2025 to 2030 period with focus on the auction design proposals. CFO Krebber, set to take over as CEO in 2021, called for a rethink favoring so-called CfDs rather than the second component design proposed by the government to differentiate between zero-subsidy bids. RWE also focuses on hydrogen with plans to develop a 100-MW electrolyzer at Lingen as part of the GETH2 project, while RWE will also be part of the AquaVentus vision for an offshore hydrogen production cluster around the North Sea island of Heligoland. RWE has joined the European Clean Hydrogen Alliance, it said Aug. 11. RWE Generation (TWh) H1 2020 H1 2019 FY 2019 Lignite 14.3 24.7 48.3 Coal 2.5 8.2 14.2 of which Germany 1 2.5 4.7 NL* 1.5 5.3 8.8 GB 0 0.4 0.7 Gas 21.3 24.7 50.6 of which Germany 4.3 3 7.8 NL 5.4 2.9 6.6 GB 9.7 18 33.5 Nuclear 10 9.2 21.2 RES 15.4 5.9 16.4 of which offshore wind 3.7 1.4 Total 64.5 73.7 153.2 Source: RWE (*including biomass co-firing) Editor: Jonathan Dart ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/coal/062722-south-korea-to-raise-electricity-rates-to-reflect-spikes-in-fuel-prices</link><description>South Korea to raise electricity rates to reflect spikes in fuel prices, addressing cost pressures and ensuring energy supply stability in the market.</description><title>South Korea to raise electricity rates to reflect spikes in fuel prices</title><pubDate>27 June 2022 09:54:00 GMT</pubDate><author><name>Charles Lee</name></author><content><![CDATA[ 27 Jun 2022 | 09:54 UTC South Korea to raise electricity rates to reflect spikes in fuel prices By Charles Lee Highlights Raises rate by Won 5/kWh (0.4 cent/kWh) for Q3 Reflects spikes in prices of fuels such as LNG, coal Getting your Trinity Audio player ready... The South Korean government has decided to raise electricity rates by Won 5/kWh (0.4 cent/kWh) for the third quarter to reflect spikes in prices of fuels such as LNG and coal, the energy ministry and the state-run power monopoly said June 27. It marks the second hike in the country's electricity tariffs this year following a Won 6.9/kWh rise for the second quarter. The Won 5/kWh rise for Q3 was a result of efforts by the government and Korea Electric Power Corp to minimizes electricity rate hike due to mounting inflationary pressure, the Ministry of Trade, Industry and Energy said. "The hike of the electricity fee is expected to cost around W1,535 more for a four-member household on average per month," the ministry said in a statement. "The government tried to keep the increase rate at a minimum level given its impact on inflation," it said. In May, South Korea's consumer prices jumped 5.4% on the year, the fastest rise in almost 14 years and a pickup from a 4.8% spike the previous month. Kepco has called for a rise by Won 33.6/kWh in the adjusted unit fuel cost -- a key part of the country's electricity rates -- for Q3 to reflect sharp rises in fuel costs. But the government rejected the request, just allowing for a Won 5/kWh increase. For Q2, the government froze the adjusted unit fuel cost, approving only a Won 6.9/kWh rise in reserves for climate change. The country's electricity tariff consists of basic rate, basic fuel cost, adjusted unit fuel cost that reflects quarter-to-quarter change, and reserves for climate change. Rise in fuel costs Kepco's costs of fuels such as LNG, coal and oil were averaged at Won 582.9/kg, or Won 80.2/kWh, for the past three months until May, up 72% from Won 338.87/kg, or Won 46.6/kwh, averaged for the full year until November 2021, according to Kepco's notice. The state utility's purchasing cost of LNG averaged at Won 1,023.16/kg over March-May, compared with Won 1,157.83/kg for three months earlier from December last year to February. Coal purchasing cost rose to averaged Won 257.28/kg over March-May, from Won 218.5/kg for three months earlier. Coal-fired power plants account for about 40% of South Korea's electricity mix, and LNG-fired power plants are responsible for around 25%, while nuclear reactors satisfy around 30% of demand. The remaining comes renewables and oil. The country's electricity rate has long been frozen despite spikes in fuel costs. Kepco was allowed to raise rate by Won 3/kWh in Q4 last year, which marked the first increase in the electricity rate since November 2013. Kepco has introduced flexible electricity rates linked to global fuel prices such as LNG, coal and fuel oil, starting 2021, in a move to improve its profitability. It previously charged an electricity rate under a fixed-rate electricity billing system. Under the new system, the billing system of electricity is revised every three months, depending on movements in the global prices of the fuels. But the government has refrained from raising electricity rate due to concerns about inflationary pressure and political motivation such as elections. As a result, Kepco reported a record yearly loss of W5.86 trillion last year. "Kepco will seek every possible measure, including selling assets and restructuring, to minimize rate hike factors and to improve our financial structure of more than Won 6 trillion," the state utility said. Editor: Kshitiz Goliya ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/energy-transition/020222-wind-solar-resources-should-be-removed-from-pjm-capacity-market-p3-trade-group</link><description>A PJM Interconnection power generators trade group said it is concerned about the viability of PJM s capacity markets because wind and solar resources have been acquiring capacity obligations greater </description><title>Wind, solar resources should be removed from PJM capacity market: P3 trade group</title><pubDate>02 February 2022 22:30:00 GMT</pubDate><author><name>Jared Anderson</name></author><content><![CDATA[ 02 Feb 2022 | 22:30 UTC Wind, solar resources should be removed from PJM capacity market: P3 trade group By Jared Anderson Highlights Wind, solar capacity overvalued: P3 Entire fleet needs capacity reevaluation: AEE A PJM Interconnection power generators trade group said it is concerned about the viability of PJM's capacity markets because wind and solar resources have been acquiring capacity obligations greater than what they can deliver, but other stakeholders say all resources need capacity reevaluation. Recent actions by PJM and the Federal Energy Regulatory Commission "have served to materially destabilize the market," the PJM Power Providers Group, or P3, said in a letter to PJM's board of managers that the grid operator shared with stakeholders Feb. 2. P3 lists a dozen members on its website, including Calpine, Vistra, Tenaska, NRG, LS Power and others. It is a market-focused group that owns 67 GW of generation. PJM told stakeholders this past summer that it has over-accredited certain intermittent resources hundreds of megawatts of capacity that do not meet PJM's capacity resource requirements because these resources are not deliverable at peak times, P3 said. "The erroneously awarded resources can only provide approximately 50% of the purported capacity rating that PJM is purchasing in the capacity auctions to be paid for by customers," the group said. Accredited wind and solar power MWs "supported by non-deliverable energy" have been included in and cleared in previous capacity market auctions and currently are included in the supply stack for the upcoming 2023-2024 auction, the letter said. Approximately 50% of the total wind power capacity offered into the auction has been accredited this way and PJM has not provided any metric regarding solar power, according to P3, which went on to say that half of the wind MWs and an unknown portion of the solar MWs offered "provide no reliability" because they are not supported by deliverable energy as required to qualify as a generation capacity resource. The groups suggests that PJM should remove these wind and solar resources from the upcoming capacity auction. "The only logical remedy under the circumstance is to remove these MWs from the supply stack for the 2023-24 planning year as well as subsequent auctions, until these resources are physically deliverable in the same way required of every other resource in the PJM system," P3 said. Thermal resource valuation PJM has spent roughly two years developing Effective Load Carrying Capability, or ELCC, methodology to value the capacity contributions more accurately from solar, wind, storage, hydropower, and other resources. PJM developed the ELCC methodology in response to the rapid growth of renewable energy and energy storage resources that are intermittent and thus typically have lower capacity factors than thermal resources such as coal, natural gas, oil, and nuclear power. Despite the rapid growth of renewables, however, the capacity valuation used for thermal resources that account for 93% of PJM 's installed capacity -- a methodology which is based on estimated forced outages, or EFORd -- has not been updated in decades, a large group of stakeholders has argued. In response, PJM's board said in October that it is important to investigate the capacity valuation of all resources. PJM is currently doing so within a Resource Adequacy Senior Task Force. Additionally, most of the other US wholesale power markets run by independent system operators are dealing with capacity valuation issues as more renewable energy resources enter the various generation fuel mixes. Jeff Dennis, general counsel and managing director of the trade group Advanced Energy Economy, agreed in a Feb. 2 phone call that all resources must be evaluated with the same methodology, but he said P3's letter leaves out some important details. "Treating all resources on a level playing field with respect to the accreditation of their capacity value is needed," Dennis said. "Notably, this letter fails to acknowledge that the capacity accreditation methodology applied to thermal resources has not been reevaluated for quite some time, even as extreme weather has shown vulnerability in those resources and their fuel supplies," he said. "To fairly discuss capacity accreditation, it must be done for the entire fleet," Dennis said. "The letter asks the PJM Board to get ahead of that process and completely remove wind and solar resources from the market immediately, which would have massive consequences for advanced energy companies, increase costs to consumers who would be forced to buy duplicative capacity, and harm state and customer clean energy goals," he said. The capacity auction for delivery year 2023-2024 has been delayed from January to June 2022. Editor: Rocco Canonica ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/energy-transition/091622-indonesia-to-allow-new-coal-fired-power-plants-under-specific-conditions</link><description>Indonesia has issued a presidential decree asking the energy ministry to prepare a road map for the retirement of coal fired power plants, but it has also opened the door for new coal plant approvals </description><title>Indonesia to allow new coal-fired power plants under specific conditions</title><pubDate>16 September 2022 05:31:00 GMT</pubDate><author><name>Anita Nugraha</name></author><content><![CDATA[ 16 Sep 2022 | 05:31 UTC Indonesia to allow new coal-fired power plants under specific conditions By Anita Nugraha Highlights Aim to halt coal-fired power generation by 2050 Conditional development of new coal fired power generation Earlier plan was to fully halt new coal plant approvals Getting your Trinity Audio player ready... Indonesia has issued a presidential decree asking the energy ministry to prepare a road map for the retirement of coal-fired power plants, but it has also opened the door for new coal plant approvals under certain conditions, reversing a previous proposal to halt them. In 2021, ministry officials had stated in a parliamentary hearing that the government will cease approvals of new coal-fired power plants, and only plants that that have started construction, or have already been approved will go ahead. The new presidential decree that takes effect from Sept. 13 stipulates that the broader plan to halt coal-fired power by 2050 stands and new approvals will continue to be prohibited, unless they meet certain conditions regulated by the government. The first condition states that new coal-fired power plants should be integrated with industries that focus on boosting value for the country or with strategic national projects that create jobs or boost economy growth. The second condition is that within 10 years of the coal power plant officially starting operations, the project must commit to reduce greenhouse gas emission by 35% compared with Indonesia's average coal plants emission in 2021, by deploying new technologies, using carbon offsets, and building new renewable energy power generation. According to the third condition, the new coal power plants must halt operation by 2050 at the latest, the presidential decree said. The decree also aims to accelerate the development of new renewable power projects. Indonesia has committed to reduce greenhouse gas emissions to achieve net zero emissions by 2060 or sooner, Energy and Mineral Resources Minister Arifin Tasrif said Sept. 15. "For this reason, efforts are needed to mitigate climate change by reducing carbon emissions (decarbonization) but while maintaining energy security," Tasrif said. To increase the share of renewable energy in the power sector, state-owned power company Perusahaan Listrik Negara or PLN, must speed up the retirement of its coal fleet by replacing it with renewable energy supply, end electricity purchase contracts from other coal-fired power generators and assess electricity supply and demand issues in the long run, he said. Under the decree, the government may provide fiscal support through the state budget for the early retirement of coal-fired power plants and boost renewable energy. Indonesia has abundant renewable energy potential with a total capacity of around 3,000 GW, including 24 GW from geothermal. During the last five years, new renewable power plants have continued to increase but the pace remains slow. "The potential of new renewable energy will be utilized as much as possible to accelerate the energy transition. In 2060, the capacity of new renewable energy generation is targeted to reach 700 GW from solar, hydro, wind, bioenergy, marine, geothermal, including hydrogen and nuclear," Tasrif added. Editor: Surbhi Prasad ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/033123-european-power-prices-edge-up-on-cold-start-to-april-french-strike-extension</link><description>European power prices edged up in late March as colder, calmer weather forecasts combined with renewed French nuclear availability issues, but prior to this prices had fallen to 18 month lows.</description><title>European power prices edge up on cold start to April, French strike extension</title><pubDate>31 March 2023 13:23:00 GMT</pubDate><author><name>Kira Savcenko</name><name>Fatemeh Zahedi</name><name>Daria Dabiri</name><name>Maxim Grama</name><name>Andreas Franke</name></author><content><![CDATA[ 31 Mar 2023 | 13:23 UTC European power prices edge up on cold start to April, French strike extension By Kira Savcenko, Fatemeh Zahedi, Daria Dabiri, Maxim Grama, and Andreas Franke Highlights German April recovers above Eur100/MWh French Cal 24 moves above Eur200/MWh Italian, British net power imports keep rising Getting your Trinity Audio player ready... European power prices edged up in late March as colder, calmer weather forecasts combined with renewed French nuclear availability issues, but prior to this prices had fallen to 18-month lows. German April power traded March 31 around Eur110/MWh after settling March 20 at Eur95.38/MWh, a level not seen since Aug. 2021, EEX data showed. In France, nuclear risk premiums reemerged for next winter as strikes by EDF workers delayed reactor maintenance with year-ahead power rising above Eur200/MWh and Q1 2024 above Eur400/MWh. Gas, coal and carbon allowance prices also rebounded with strikes impacting LNG sendouts in Europe's biggest LNG import nation at three French import terminals. Platts, a unit of S&amp;P Global Commodity Insights, last assessed TTF front-month gas at Eur43.28/MWh on March 30. The contract was assessed below Eur40/MWh on March 20 for the first time since July 2021. European coal prices followed with CIF ARA year-ahead rebounding to $142.50/mt despite little pressure on demand as falling gas generation costs sidelined older coal units with overall prices seen converging. Carbon allowance prices inched slightly higher, but remained below record-highs seen early March. High wind, low demand In Germany, day-ahead averaged Eur89.7/MWh March 17-30, down 16% over the fortnight and some 57% below the same period last year, exchange data showed. April baseload settled at Eur104.96/MWh March 30 on EEX, up 3% over the fortnight. Bearish pressure from robust wind generation and a seasonal decline in demand were the main downward drivers offset by ongoing strikes in France. "Too little of the risks was priced in," a trader said, citing French nuclear along with the EU's initiative on joint gas purchases as bullish drivers. TTF April gas rebounded above Eur45/MWh March 31, up 8% from levels seen two weeks earlier. "Most of the bearishness was just priced in. That's why the front was only below Eur40/MWh two times," the trader added. Further out, German Cal-24 power settled at Eur143.63/MWh March 30, up 5% compared to two weeks ago with its discount to France widening as French forward prices rallied. French forwards rally French prompt prices were mostly bearish this March despite strikes by French energy workers going into a fifth week with EDF extending the walkouts to April 6. "There's still the French nuclear reactors that haven't started their outage and are pushing their restarts later into September and the ones that are still waiting to return," a trader said. Nuclear output fell 19% in March to average 34 GW, according to RTE. In addition, concerns about extra inspections required by safety regulator ASN after EDF disclosed three new cracks on March 6 added bullish moment for next winter. French Q1 2024 traded March 31 above Eur400/MWh, up over 80% since March 6, EEX data showed. Calendar 2024 rose 46% during the same period to Eur216/MWh. "People are reluctant to sell due to pending news from ASN, so naturally the price and risk premium will creep up," another trader said. French day-ahead averaged Eur112/MWh in March, down 25% from February as demand fell 12% to average 53 GW. "All down due to fundamental factors," a Swiss trader said. "Temperatures are briefly below average but they recover, so no reason for panicking. It is spring now." Gas-fired generation fell 34% to 4.7 GW with strikes also impacting French gas, coal and hydro plant. Wind meanwhile rose 53% to average 7 GW following a new record above 16 GW, while combined wind and solar peaked March 31 around 21 GW. Despite reduced nuclear, France was seen mostly as a net exporter sending power to Italy, Switzerland and Britain. Spanish cap extension In Spain, power prices were bearish during March, as high wind and mild temperatures curbed consumption. An extension to the gas-for-power price cap to end-2023 added to the bearish sentiment. Market participants however showed conflicting views on the relevance of the cap. Some suggested with the current reduced gas prices the need for the cap has diminished, while others argued the winter season still holds the risk of high gas prices if Europe faces supply issues. Average day-ahead prices declined 33% to Eur89.61/MWh for the month of March, OMIE data showed. Similarly, the April contract settled at Eur76.88/MWh on March 30, down 30% from the last day of February. Gas generation fell 38% to 3.6 TWh, while wind output rose 26% to 8.6 TWh, REE data showed. Italian imports near 6 GW Italian day-ahead averaged Eur130.78/MWh in the second half of March, down 9% over the fortnight amid mild weather and strong imports. Wind generation fell 1 GW to 2.7 GW, while solar rose 0.6 GW to 3.2 GW, Terna data showed. Hydro generation was flat averaging 2.4. GW, while thermal generation fell 1.8 GW to average 15.9 GW. Net imports increased 0.6 GW to average almost 6 GW, with flows from France rising to 2.4 GW. Swiss imports remained at 2 GW. April was last seen trading at Eur133.75/MWh March 31, down 4% from March 1. British imports near 4 GW Average UK day-ahead baseload fell 17% month-on-month in March to average Eur114.72/MWh, down from Eur139/MWh in February, S&amp;P Global data showed. Wind averaged 8.6 GW, down 12% from February, according to BMRS data. Gas generation averaged 11.4 GW in March, up 1% on the month, while nuclear rebounded to 4 GW. Net imports rose 6% to 3.8 GW. French imports rose 42% to average of 1.7 GW amid frequent swings on the 4 GW of transmission capacity. Belgian imports reached 0.6 GW, while Dutch flows averaged 0.8 GW. Norwegian imports ramped down 8% to 1.1 GW after Norway restricted flows on the NSL link. Editor: Henry Edwardes-Evans ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/062222-higher-pjm-energy-market-prices-may-have-led-to-lower-capacity-auction-bids</link><description>PJM Interconnection capacity auction clearing prices for delivery year 2023/2024 came is lower than prices for the past 10 auctions with experts suggesting higher energy market prices, recent rule cha</description><title>Higher PJM energy market prices may have led to lower capacity auction bids</title><pubDate>22 June 2022 19:56:00 GMT</pubDate><author><name>Jared Anderson</name></author><content><![CDATA[ 22 Jun 2022 | 19:56 UTC Higher PJM energy market prices may have led to lower capacity auction bids By Jared Anderson Highlights Capacity prices lowest in 10 auctions Power prices higher in energy market Getting your Trinity Audio player ready... PJM Interconnection capacity auction clearing prices for delivery year 2023/2024 came is lower than prices for the past 10 auctions with experts suggesting higher energy market prices, recent rule changes and a shorter timeframe to delivery could have contributed to the price drop. The capacity auction clearing price for most of the PJM footprint was $34.13/MW-day compared to $50/MW-day for the 2022/2023 auction held in June 2021. That was the third lowest clearing price in PJM's capacity market history, with only the 2012/2013 and 2013/2014 delivery years clearing lower at $16.46/MW-day and $27.73/MW-day, respectively. PJM does not have much insight into how market sellers determine their unit-specific offers, Stu Bresler, senior vice president of market services, said during a June 21 conference call with reporters. However, he noted that commodity price "spreads are up â spark spreads, dark spreads, quark spreads â are all up, especially in the forward markets, and so directionally you would expect if market sellers are anticipating higher net revenues in the energy market that they would be able to offer less in the capacity market." Morris Greenberg, senior manager of North America power analytics with S&amp;P Global Commodity Insights agreed, saying in a June 22 email: "I think the major factor in the low clearing prices was gains in expected energy revenues and in the case of renewables, [renewable energy credit] revenues as well." He said PJM Tier 1 REC prices are currently around $23-$24/MWh, up from about $15/MWh at the time of the last auction. "The compressed schedule between the auction and the delivery period may have had an impact as well, as it did last year," Greenberg said. Auctions are usually held three years in advance of the delivery year and the 2023/2024 auction was originally scheduled to be held in May 2020, but auctions had been suspended while the Federal Energy Regulatory Commission considered approval of new capacity market rules, PJM said in a statement. "In general, prices are in a reasonable range, we expected a relatively low clearing price for this auction (as well as the next auction in December) compared to the last few years, which makes sense given the energy market conditions," Bill Dugan, director of optimization for wholesale services at Customized Energy Solutions, said in a June 21 email. He cited Dominion's decision to remove all its Virginia resources from PJM's capacity market, and how "relatively long" the PJM market remains. The MAAC and BGE zones remain constrained as expected, "while ComEd is no longer constrained and appears to be long as of now," Dugan said. Rule changes, cleared resources Analysts with Regulatory Research Associates, or RRA, a group within S&amp;P Global, forecast clearing prices for the 2023/2024 delivery year as low as $25/MW-day, driven by several factors including a more restrictive market seller offer cap. The purpose of a market seller offer cap is to "remove the double-counting of any costs, such as large maintenance costs, that a generator includes in its offer," RRA noted in its first-quarter 2022 Market Intelligence Power Forecast, adding that the cap also "significantly limits the bid potential for generators." There was an increase of 5,315 MW from existing nuclear units that did not clear in the previous auction, PJM said, adding that solar resources increased 25%, from 1,512 MW to 1,868 MW, while the number of wind resources clearing was down 434 MW to 1,294 MW. The decrease in wind resources clearing the auction reflected a decrease of wind resources that offered in, the grid operator said. "Renewable energy clearing decreased a bit this year in terms of new entry, which does make sense in terms of lower price expectations, delays in solar resources coming online, Effective Load Carrying Capability implementation lowering capacity ratings, and the relative timeline of this auction," Dugan said. Natural gas-fired resources clearing the auction increased by 1,685 MW, with more efficient combined-cycle units clearing 3,627 MW more than the last auction and combustion-turbine units down 1,012 MW, according to PJM, which added that combined-cycle units cleared a total of 48,030 MW in the auction and combustion-turbine units 19,080 MW. "Cleared capacity of steam units (primarily coal) was down 7,186 MW to 27,682 MW, tracking with a decrease of 7,813 MW offered into the auction as a result of coal retirements," PJM said. There was also a 716-MW decrease in demand response resources that cleared. It was generally predicted capacity prices would be lower, which can dissuade potential DR participants, Peter Cavan, director of market development at Convergent Energy + Power, said in a June 22 email. Electric Power Supply Association president and CEO Todd Snitchler said in a June 22 statement he was concerned about reliability over the longer term as baseload resources retire. "While the auction's low capacity clearing price represents a savings for customers in the short term, these results portend real concerns over adequate compensation for resources needed to support reliability in all conditions and looking forward," Snitchler said. Editor: Derek Sands ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/080223-us-power-tracker-pjm-gas-fired-power-output-up-on-year-power-forwards-decline</link><description>Gas fired power generation up 11% on year Forward power prices for October averaged $37.18/MWh Natural gas fired generation continues to surge in PJM Interconnection, rising more than 8% and reaching </description><title>US POWER TRACKER: PJM Gas-fired power output up on year, power forwards decline</title><pubDate>02 August 2023 20:06:00 GMT</pubDate><author><name>Jared Anderson</name></author><content><![CDATA[ 02 Aug 2023 | 20:06 UTC US POWER TRACKER: PJM Gas-fired power output up on year, power forwards decline By Jared Anderson Highlights Gas-fired power generation up 11% on year Forward power prices for October averaged $37.18/MWh Getting your Trinity Audio player ready... Natural gas-fired generation continues to surge in PJM Interconnection, rising more than 8% and reaching record levels in July, while forward power prices declined 64% on year and forward gas prices declined 77%. "Year-to-date, gas-fired generation has climbed 11% over the same period in 2022," S&amp;P Global power market analysts said in their latest North American Electricity Short-Term Outlook. "Most of the natural gas gains have come at the expense of coal in PJM. Year-to-date, coal-fired generation was down about 34% after another 14% decline in July," the analysts said. Texas Eastern spot gas prices averaged $1.59/MMBtu in July, down almost 76% from the July 2022 average of $6.59/MMBtu, according to S&amp;P Global data. However, spot gas prices increased by around 17% in July on month due largely to warmer summer weather and higher peakloads. Platts Transco Zone 6 Non-New York on-peak forward gas prices for August, September and October were down about 77% compared with the same period last year. Forward gas prices for August averaged $1.58/MMBtu in July trading, down 76% on year and about 9% on month. Forward gas for September averaged $1.27/MMBtu, down about 78% on year and down less than 1% on month, and forward gas for October averaged $1.24/MMBtu, down about 78% on year and down almost 2% on month. PJM West on-peak forward power prices for July averaged $47.18/MWh compared with actual on-peak day-ahead July power prices of $46.81/MMBtu. PJM West power forwards for August averaged $48.58/MWh in July trading, while forward power for September averaged $40.67/MWh and forward power for October averaged $37.18/MWh. For full-year 2023, Public Service Enterprise Group is forecasting nuclear power generation output of 30 TWh to 32 TWh and has hedged approximately 95% of this production at an average price of $31/MWh, executives said during the investor-owned utility's second quarter earnings call. On-peak power prices at the PJM Western Hub ticked higher in July 2023 supported by stronger electricity demand and higher natural gas prices, the power market analysts said. "Expectations for annual average power prices in 2023 remain relatively lower as the market continues to appear well-supplied throughout the year," the analysts said, adding that "on-peak power prices at PJM Western Hub are projected to average around $41/MWh in 2023." Power generation fuel mix Gas-fired power accounted for 47.3% of the PJM fuel mix in July, up from 45.8% in June and 43.9% in July 2022 when prices were about 76% higher, according to PJM data. Coal-fired power accounted for 17.2% of the PJM fuel mix in July, down from 20.6% in July 2022. Nuclear power accounted for 29.1% of the July fuel mix, down from 34.3% in June and 29.4% in July 2022. Hydropower accounted for 1.9% of the fuel mix, up from 1.7% in June and 1.7% in July 2022. Wind power output declined in July, accounting for 1.3% of the generation mix compared with 2.6% in June and 1.9% in July 2022. Spot power, gas price dynamics PJM East on-peak day-ahead power prices increased the most of the major trading hubs in July, due largely to a brief heatwave at the end of the month that pulled up the daily averages. On-peak day-ahead power prices at the hub averaged $153.62/MWh on July 27 when the average high temperature across the PJM footprint was almost 92 degrees Fahrenheit, according to CustomWeather data. On-peak day-ahead power prices at the hub averaged $189.09/MWh on July 28 when high temperatures across PJM averaged about 94 degrees F. The monthly average day-ahead power price at the hub was $58.04/MWh which was 171% higher on month and down about 47% on year. Spot Texas Eastern gas prices increased around the heatwave, averaging $1.97/MMBtu on July 26 and $1.93/MMBtu July 27 compared to the monthly average of $1.59/MMBtu. Power demand was 23% higher in July on month with peakload averaging 127,120 MW, compared with 103,397 MW in June. Peakload during the heatwave on July 27 and 28 averaged 145,979 MW. Editor: Richard Rubin ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/blog/energy-transition/121223-commodity-tracker-4-charts-to-watch-this-week</link><description>Battery metals prices could have reached a bottom after positive indications from the Chinese government.</description><title>Commodity Tracker: 4 charts to watch this week</title><pubDate>12 December 2023 04:37:00 GMT</pubDate><author><name>S&amp;P Global Energy</name></author><content><![CDATA[ 12 Dec 2023 | 04:37 UTC â Insight Blog Commodity Tracker: 4 charts to watch this week By S&amp;P Global Energy Getting your Trinity Audio player ready... Battery metals prices could have reached a bottom after positive indications from the Chinese government. The focus also is on the Hinkley Point C nuclear plant, food and beverage price inflation and developments around the voluntary carbon credit market. 1. Battery metals prices look to reach bottom What's happening? The Platts battery metals assessments have been in a continued downtrend for two months, remaining at historical lows on weakening demand and worsening sentiment in the battery metals industry. Chinese domestic lithium carbonate spot prices started to bottom in the week of Dec. 4, led by rising lithium carbonate futures on the Guangzhou Futures Exchange, after remarks by an official of the Economic Committee of the Chinese People's Political Consultative Conference Dec. 4 that the country's sales of electric vehicles are expected to account for more than 50% of total new car sales by 2025-26. What's next? Market sources expect prices to reach a bottom soon while a rebound in spot prices remains to be seen. Sources worry that the sudden stabilization in domestic prices is driven by financial market speculation rather than a change in downstream fundamentals as oversupply persists. 2. Symbolic moment looms for UK's Hinkley Point C nuclear plant What's happening: French-owned EDF Energy is preparing to lift the huge reactor lid into place on its 1.6-GW Unit One EPR nuclear facility at Hinkley Point C in Somerset, southwest England. Wind and rain allowing, the 10-hour operation will be carried out by Big Carl, the largest crawler crane in the world, capable of lifting 5,000 tonnes at a radius of 40 m. The lift presents EDF with an opportunity to update the market on the beleaguered project, delayed by COVID-19 and running massively over budget. S&amp;P Global analysts now assume Unit One to be online sometime in 2028, with Unit Two following in 2029. What's next: Currently, Hinkley Point C's adjusted-for-inflation strike price of GBP128/MWh looks like reasonable value for money in a UK wholesale market where expensive gas sets the price most of the time. By 2028, however, S&amp;P Global Energy analysts forecast power prices to average below GBP80/MWh, with gas-firing greatly reduced by offshore wind growth. Affordability is just one aspect of the trilemma, with new nuclear seen as needed for security of supply and sustainability. And with the UK an enthusiastic signatory at COP28 of a declaration to triple global nuclear capacity by 2050, two more reactor units at Sizewell C in Suffolk would appear to be a minimum requirement for the country's ambitions and not, as some commentators believe, a ceiling. 3. Food &amp; Beverage Price Index at highest point since mid-2022 What's happening: S&amp;P Global Energy Food &amp; Beverage Price Index increased by 2.1% month on month to 113.6 points in November, which represents the first monthly increase since July and the highest point for the index since July 2022. El Nino-related weather extremes continued to support prices, with dry weather interrupting the planting of various crops in Brazil, notably soybeans. Drought concerns also continue to hang over West Africa, Southeast Asia and Australia, which are key producers of crops including cocoa, sugar, rice and wheat. What's next: International agencies typically agree that El Nino will last until at least second-quarter 2024. With the Southern Hemisphere's planting season ending, the market would have to wait a few months to fully understand what damage, if any, the weather extremes that El Nino brings has occurred. Meanwhile, Northern Hemisphere farmers will hope for a swift end to the phenomenon ahead of their planting season. 4. Voluntary carbon credit demand gets boost from oil company What's happening? In a year when the voluntary carbon market has come under scrutiny and buyers remain cautious in their purchases, retirements of credits from the VCM increased by 56% month on month in November to over 14 million mt, of which more than half was constituted by nature-based avoidance credits, which have been the target of several integrity attacks since early 2023. Beneficiary data published on the Verra registry highlights that more 6 million mt have been retired by international oil company Shell, almost entirely from the scrutinized category. The company had previously signaled a move away from the VCM. What's next? While retirements usually ramp up toward the end of the year as companies seek to show progress against their net-zero targets, buyers may be more cautious this year as they await the outcomes of discussions on Article 6.4 of the Paris Agreement expected at COP28. Reporting and analyses by Laura Varriale, Dana Agrotti, Henry Edwardes-Evans and Peter Storey. ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/natural-gas/012722-us-northeast-power-demand-gas-and-power-prices-elevated-with-storm-approaching</link><description>ISO New England s Jan. 27 short term power demand forecast shows projected peak load reaching 19,250 MW on Jan. 29, which is close to the grid operator s expected winter power demand peak of 19,710 MW</description><title>US northeast power demand, gas and power prices elevated with storm approaching</title><pubDate>27 January 2022 21:42:00 GMT</pubDate><author><name>Jared Anderson</name></author><content><![CDATA[ 27 Jan 2022 | 21:42 UTC US northeast power demand, gas and power prices elevated with storm approaching By Jared Anderson Highlights ISO-NE peakload forecast: 19,250 MW Jan. 29 Region could get over a foot of snow ISO New England's Jan. 27 short-term power demand forecast shows projected peak load reaching 19,250 MW on Jan. 29, which is close to the grid operator's expected winter power demand peak of 19,710 MW, as a winter storm approaches the region. US Northeast power and gas prices are spiking again as a nor'easter approaches and is likely to dump significant snow accumulations on the Boston and New York City metropolitan areas. Temperatures in Boston are expected to reach a high of 22 F Jan. 29 with a low of 12 F the same evening, according to the National Weather Service. Prior to the winter, ISO-NE projected power demand to peak at 19,710 MW during average winter weather conditions and at 20,349 MW under below-average conditions. ISO-NE peakload averaged 16,364 MW in December 2021 and 16,795 in January 2021. Peakload has averaged 17,472 MW through Jan. 26, 2022, according to ISO data. ISO-NE internal hub real-time power prices around 3 pm Jan. 27 were $153.05/MWh and day-ahead prices at the hub were $153.25/MWh, according to the grid operator's website. Day-ahead on-peak power prices at the hub have averaged $107.71/MWh year to date and $175.88/MWh over the past two weeks. Platts Algonquin city-gates natural gas prices have averaged $13.26/MMBtu year to date. The average price at the hub over the past two weeks was $23.07/MMBtu. "Winter storm watches have been issued from the mid-Atlantic to southeastern New England in advance of a nor'easter that is set to charge up the East Coast Friday night into Sunday with full-blown blizzard" conditions in eastern New England, AccuWeather said in a Jan. 27 report. "Eastern New England and the eastern tip of Long Island, New York, is where you have a very good probability of getting more than a foot of snow," Bernie Rayno, AccuWeather chief on-air meteorologist, said. Heavy snow is possible with total snow accumulations of 10 to 16 inches possible in portions of eastern and northeastern Massachusetts and Rhode Island, the National Weather Service said. Winds could gust as high as 50 mph, according to the Winter Storm Watch. Based on power generator surveys submitted Jan. 25, 18.29 million gallons of oil were consumed for power generation from Jan. 18 through Jan. 24, including 6.75 million gallons of distillate fuel oil and 11.53 million gallons of residual fuel oil, according to ISO-NE's latest 21-Day Energy Assessment Forecast and Report. "This past week [Jan. 17 to Jan. 21] saw extensive use of stored energy, including LNG and fuel oil due to the colder temperatures," the grid operator said in the report. Much colder-than-normal air is expected for the rest of January and extended runs of stored fuels continue to be expected, with recent generator survey responses indicating that "some fuel oil replenishment has been planned, though the planned replenishment is less than was consumed in the previous week," the grid operator said in the report. "Of particular concern is the depletion of residual fuel oil with no replenishment expected or reported," ISO-NE said. The ISO-NE power generation fuel mix consisted of 47% natural gas, 20% nuclear, 16% oil, 10% renewables, 4% hydropower and 3% coal around 3 pm Jan. 27. New York market conditions New York City may receive heavy snowfall of 6 to 12 inches Jan. 29, AccuWeather said. The National Weather Service had a Winter Storm Watch in effect from Jan. 28 to Jan. 29, calling for total snow accumulations of 6 to 12 inches with winds gusting as high as 45 mph. "A winter storm system moving up the coast has the potential to deliver heavy snow, gusty winds, and create dangerous travel conditions across downstate locations this weekend, especially in Long Island, New York City and the Mid-Hudson Region," Governor Kathy Hochul said in a statement. New York Independent System Operator peakload is forecast to reach 21,214 MW Jan. 29 when temperatures are expected to hit a low of 16 F, according to the National Weather Service. The grid operator's peak winter demand forecast is 24,025 MW under normal weather and the extreme winter weather scenario showed that peak demand could increase to as much as 26,230 MW. NYISO peakload averaged 19,660 MW in December 2021 and 20,361 MW in January 2021. Real-time New York City Zone J power prices were $152.79/MWh around 3:30 pm and Zone J day-ahead prices were $169.68/MWh. On-peak day-ahead Zone J prices year to date have averaged $93.66/MWh. Over the past two weeks, on-peak day-ahead prices at the hub averaged $170.30/MWh amid colder weather. Editor: Adithya Ram ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/blog/electric-power/073024-ctracker-france-nuclear-biodiesel-us-natural-gas</link><description>The Paris Olympics are not the only reason to keep an eye on France this week; the country is on track to exceed nuclear output expectations for July.</description><title>Commodity Tracker: 6 charts to watch this week</title><pubDate>30 July 2024 11:30:00 GMT</pubDate><author><name>S&amp;P Global Energy</name></author><content><![CDATA[ 30 Jul 2024 | 11:30 UTC â Insight Blog Commodity Tracker: 6 charts to watch this week By S&amp;P Global Energy Getting your Trinity Audio player ready... The Paris Olympics are not the only reason to keep an eye on France this week; the country is on track to exceed nuclear output expectations for July. S&amp;P Global Energy editors are also examining the potential impact of the EU's plans to impose antidumping duties on Chinese biodiesel imports, as well as the bloc's coal demand amid weak industrial activity. Canadian natural gas exports to the US, Indian steel imports and Asian paraxylene prices are also in focus. 1. French nuclear output seen in upper range of forecast after July exceeds expectations What's happening? Europe's biggest power generator EDF sees 2024 French nuclear output in the upper range of its 315 TWh-345 TWh forecast after reactor availability improved significantly compared to 2022 and 2023, the utility said July 26. Analysts at S&amp;P Global Energy in June lifted their forecast to 342 TWh, while the July output is on track to exceed the monthly output forecast, boosting year-to-date output for the first seven months to 205 TWh. Improved nuclear lifted French power exports to record highs despite transmission capacity restrictions on its eastern borders during the spring. What's next? A developing heat wave this week could impact output at some of EDF's river-based reactors. EDF already warned about restrictions at its Golfech nuclear power plant in southwest France. Focus is also on the "imminent" start of France's new 1.6-GW Flamanville-3 reactor and months of test production before full operations are planned to start this winter. EDF does not yet include output from the new reactor in its full year estimate range. A key focus for the next few months will be the new border transmission restrictions that may hinder nuclear production. French power for August delivery fell 25% since grid operator RTE warned about the restrictions on July 24, exchange data show. 2. EU moves to protect domestic biodiesel market from surging imports What's happening? The EU announced July 19 long-awaited plans to introduce provisional antidumping duties of up to 36.4% on imports of Chinese biodiesel imports, responding to allegations that rising imports at "artificially low prices" had seriously harmed the bloc's own growing renewables sector. China exported around 2.1 million mt of FAME/renewable diesel in 2023, according to S&amp;P Global Energy data, with sources estimating around 90% of the supply directed to Europe. Challenged by cheap imports, suppliers have announced plans to pause investment in European biofuel operations. Neste, Europe's largest producer, reported its deepest quarterly losses in over a decade in the second quarter. What's next? The EU is expected to formalize its provisional antidumping duties Aug. 16, with definitive measures expected to follow in February 2025. Stakeholders hope that the move will provide investment certainty to producers in Europe at a pivotal moment for building out its production capacity to meet Fit for 55 targets. Some lobbyists have called for further intervention, however, expressing concerns lingering about alleged fraudulent waste-based feedstock sourced from China for European domestic biodiesel production. For China, the move creates a more challenging market environment, prompting efforts to scale domestic biodiesel demand growth to reduce its export reliance. 3. Low Canadian natural gas prices lifting exports to US What's happening? Net flows of natural gas from Canada to the US are on the rise as high storage inventories continue to weigh heavily on cash and forward prices in Western Canada. Exports have averaged around 5.7 Bcf/d since April 1, around 700 MMcf/d higher year over year, according to Energy data. What's next? With forward markets pricing AECO-C in Alberta at less than $1/MMBtu for the rest of the summer, strong flows to the US are likely to continue. The imports have dampened the effect of production cuts in the US, which is also dealing with a large storage surplus. The Canadian market is expected to tighten in 2025 with the commissioning of the 14 million mt/year LNG Canada project. 4. EU's coal demand declines further amid weak industrial activity, higher renewables capacity What's happening? The International Energy Agency estimated EU's coal demand to fall below 300 million mt by 2025 as countries within the bloc continue to phase out coal-powered plants in the face of increasing adaption of renewable sources and nuclear. The region's weak industrial activity and stagnating growth in power demand are also playing a crucial role in lower coal dependence. What's next? The weakening of coal demand is also reflected in the sharp year-on-year drop in imports as Europe's share in global coal trade continues to falter. Turkey is expected to surpass the region's demand this year. After the volatility witnessed in the coal trade in recent years, the European-delivered thermal coal prices in the physical and financial markets have been stable. 5. Indian mills expected to brace for higher steel imports in July What's happening? India's steel imports are expected to surge to a seven-year high in July, to reach 1.6 million mt, driven by increased inflows from China. China has overtaken South Korea as the leading steel exporter to India, comprising 43% of the South Asian country's total steel imports during January to July. India, however, is facing challenges in both its domestic market and the export sector, with its domestic prices falling from Rupees 52,800/mt in July 1 to Rupees 50,200/mt July 26. What's next? Domestic steel mills are requesting government support such as safeguard measures against imports from China and Vietnam. With lackluster domestic demand during the monsoon season and a decline in exports due to a retreat of demand from EU during the summer, domestic steel prices continue to be a concern for Indian mills amid increasingly more competitive seaborne offers. Related content: Trade Review: Asian steel, scrap prices to see limited support in Q3 as tepid demand, export challenges weigh 6. Asia paraxylene prices tumble on supply pressure What's happening? Asian paraxylene prices sank to a year-to-date low of $993/mt CFR Taiwan/China July 30 as spot supply continued to rise while regional demand struggled to keep up. PX values were last seen lower Dec. 19, 2023, according to Platts data, when prices were assessed at $991.50/mt. Platts is part of Energy. Buying interest in Asia continues to stutter amid growing worries surrounding China's persistently delayed economic recovery and a sluggish downstream polyester market. Recent supply disruptions in Asia also failed to provide any major upside to spot PX prices. What's next? With the highly anticipated pull of PX into the gasoline blend pool ahead of the US summer driving season fizzling out, hopes for any turnaround in spot prices remains bleak. Furthermore, downstream activity in China during the second half of 2024 shows limited capacity given weak domestic demand. With the downstream markets looking slow, the impact will be felt on upstream PX prices as well with sharper drop in values expected. Reporting and analysis by Andreas Franke, Kelly Norways, Killian Staines, Vaibhav Chakraborty, Shuocheng Ni, Pankaj Rao ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/energy-transition/041123-south-korea-revises-2030-target-for-greenhouse-gas-emissions</link><description>South Korea revised its 2030 targets for greenhouse gas emissions April 11 under which major polluters of energy intensive manufacturers, such as oil refiners, chemical companies and steelmakers, are </description><title>South Korea revises 2030 target for greenhouse gas emissions</title><pubDate>11 April 2023 05:34:00 GMT</pubDate><author><name>Eric Yep</name><name>Charles Lee</name></author><content><![CDATA[ 11 Apr 2023 | 05:34 UTC South Korea revises 2030 target for greenhouse gas emissions By Eric Yep and Charles Lee Getting your Trinity Audio player ready... South Korea revised its 2030 targets for greenhouse gas emissions April 11 under which major polluters of energy-intensive manufacturers, such as oil refiners, chemical companies and steelmakers, are given reduced burdens on the back of a bigger role of nuclear to power Asia's fourth-biggest economy. The National Basic Plans for Carbon Neutrality and Green Growth was approved by a cabinet meeting on April 11, which is the final step before its implementation across the country, according to the prime minister's office. The final version adjusted targets for two sectors -- lowering the target for the industrial sector while raising the target for the power production sector, with the country's total reduction target kept unchanged at 436.6 million mt of CO2 equivalent by 2030, or 40% from 2018 levels. Under the plan, industries will be allowed to emit 230.7 million mt in 2030, more than 222.6 million mt set previously in the nationally determined contributions target unveiled in October 2021. It marks an 11.4% reduction from 260.5 million mt that the industrial sector emitted in 2018, compared with a 14.5% cut seen in the 2021 target. The Presidential Commission on Carbon Neutrality and Green Growth that mapped the target cited "difficulties in the supply of raw materials and technology prospects" as a reason for easing burdens for industries. In contrast, the emissions target for the country's electricity production sector has been tightened to emit 145.9 million mt in 2030 from 149.9 million mt in the 2021 plan. It marks a 45.9% reduction from 269.6 million in 2018, up from 44.4% in the 2021 target. The final plan also calls for the transport sector to reduce emissions to 61 million mt by 2030, unchanged from the 2021 target, which is a 37.8% reduction from 98.1 million mt in 2018. To meet the tougher target for the power production sector by 2030, the government will increase electricity generation from nuclear power plants and reduce coal-based power production. "We will accelerate the conversion of clean energy by reducing coal power generation and expanding the generation of nuclear power plants and renewable energy," the commission said. The country will also expand carbon capture, utilization and storage, or CCUS, to help meet its 2030 target. It plans to secure spaces to capture and store 1 billion mt of CO2 by 2030. The revised emission target comes under South Korea's new president Yoon Suk-yeol who took office in May last year with a pledge of reviving the nuclear power sector by reversing his predecessor's nuclear phase-out policy and supporting the country's major manufacturers. Under Yoon's push, South Korea plans to boost the portion of nuclear in its power mix to 32.4% in 2030 and further to 34.6% in 2036, compared with 27.4% in 2021 and 23.4% in 2018. Renewable sources will be responsible for 30.6% of power generation in 2036 after 21.6% in 2030, rising from 7.5% in 2021 and 6.2% in 2018. On the contrary, the share of coal in power production would be lowered to 19.7% in 2030 and 14.4% in 3036, from 34.3% in 2021 and 41.9% in 2018. Additionally, LNG's share in power would be cut to 22.9% in 2030 and to just 9.3% in 2036, compared with 29.2% in 2021 and 26.8% in 2018. "South Korea will actively use renewable energy sources and nuclear power plants and come up with a feasible and balanced energy mix amid the country's efforts to reach carbon neutrality," the Ministry of Trade, Industry and Energy said in a separate statement. Editor: Ankit Rathore ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/081022-us-power-tracker-heavy-loads-pricey-gas-boost-midcontinent-iso-prices-in-july</link><description>Most Midcontinent Independent System Operator wholesale power prices in July surged to levels more than twice July 2021 levels, driven by heavier peakloads, stronger natural gas prices and a month to </description><title>US POWER TRACKER: Heavy loads, pricey gas boost Midcontinent ISO prices in July</title><pubDate>10 August 2022 17:13:00 GMT</pubDate><author><name>Mark Watson</name></author><content><![CDATA[ 10 Aug 2022 | 17:13 UTC US POWER TRACKER: Heavy loads, pricey gas boost Midcontinent ISO prices in July By Mark Watson Highlights September on-peak forwards in triple digits Cooling-degree days up 15.3% from July 2021 Power burn up in July, likely up in September Getting your Trinity Audio player ready... For access to all regions of the US Power Tracker series, join Platts Dimensions Pro. Most Midcontinent Independent System Operator wholesale power prices in July surged to levels more than twice July 2021 levels, driven by heavier peakloads, stronger natural gas prices and a month-to-month decrease in wind output, and September forwards averaged in triple digits, more than 2.5 times year-ago levels. Day-ahead on-peak locational marginal prices in July averaged in a range of the mid-$70s/MWh to more than $110/MWh across the 15-state footprint that stretches from Canada to the Gulf Coast, S&amp;P Global Commodity Insights price data shows. In July 2021, those prices were all in the low to mid-$40s/MWh. In June, they ranged ranged from the mid-$60s/MWh to more than $115/MWh. Driven by high temperatures, peakloads averaged 104.9 GW in July, up 5.5% from June's 99.4 GW and up 2.4% from July 2021's 102.4 GW, according to MISO data collected by S&amp;P Global. July's population-weighted average cooling-degree days were 42% higher than June's and 15.3% higher than July 2021's CDDs, CustomWeather data shows. Population-weighted temperatures averaged 75.6 F in July, up 4.9% from June's 72.1 F and up 1.9% from July 2021's 74.2 F. At the Chicago city-gates, spot gas averaged $6.816/MMBtu in July, down 8.1% from June's $7.42/MMBtu but up almost 89% from July 2021's $3.608/MMBtu. Henry Hub spot gas averaged $7.104/MMBtu in July, down 7.7% from June's $7.694/MMBtu but up by more than 87% from July 2021's $3.795/MMBtu. Generation mix Despite higher gas prices, MISO's gas-fired generation average daily output surged to almost 785.5 GWh in July from June's 691.3 GWh and July 2021's 609.6 GWh. This was enough for the gas fleet to have a share of more than 39% in July, up from 37.5% in June and less than 32% in July 2021. Power burn was also strong, averaging 4.9 Bcf/day in July, up from less than 4.4 Bcf/d in June and less than 4 Bcf/d in July 2021. The coal fleet also produced at higher levels in July, averaging 754.7 GWh/d in comparison with June's 691.3 GWh/d and July 2021's 609.6 GWh/d, representing shares of 37.6%, 33.7% and 44.5%, respectively. Nuclear power came in third, producing 252.2 GWh/d in July, down slightly from June's 253 GWh/d and down substantially from July 2021s 265.5 GWh/d, representing shares of 12.6%, 13.7% and 6.5%, respectively. MISO's wind fleet output was down on the month but up on the year, producing 167.3 GWh/d in July, compared with June's 253 GWh/d and July 2021's 124 GWh/d, representing shares of 8.3%, 11.8% and 6.5%, respectively. Forward markets In forward markets, September power and gas packages were down on the month but up sharply from what September 2021 packages averaged in July 2021. For example, Indiana Hub September on-peak power averaged about $120.25/MWh in July, down 2.6% from $123.50/MWh in June but more than 170% higher than the $44.50/MWh that the September 2021 package averaged in July 2021. Louisiana Hub September on-peak power averaged more than $112/MWh in July, down 2.8% from about $115.35/MWh in June but up 162.5% from the $42.70/MWh that the September 2021 package averaged in July 2021. Chicagocity-gates September gas averaged $6.842/MMBtu in July, down 5.7% from June's $7.255/MMBtu but up 88.9% from the $3.623/MMBtu that September 2021 gas averaged in July 2021. Henry Hub September gas averaged $7.102/MMBtu in July, down 6.2% from June's $7.57/MMBtu but up 87.2% from the $3.793/MMBtu that September 2021 gas averaged in July 2021. Despite higher gas forwards, Platts Analytics forecasts MISO gas-fired generation to produce at levels equivalent to 532.5 GWh/d in September, up 22.4% from September 2021 levels, which, assuming similar heat rates, would have MISO's gas fleet burning almost 3.9 Bcf/d in September. The National Weather Service on July 21 forecast enhanced chances â 33% to 50% -- for above-normal temperatures in August, September and October across virtually all of the MISO footprint. Editor: Richard Rubin ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/061323-us-power-tracker-moderate-iso-ne-power-prices-expected-this-summer</link><description>Gas prices expected down considerably on year Summer power demand could reach 26,421 MW The ISO New England on peak Mass Hub forward power price summer strip for June, July and August averaged $59.54/</description><title>US POWER TRACKER: Moderate ISO-NE power prices expected this summer</title><pubDate>13 June 2023 21:16:00 GMT</pubDate><author><name>Jared Anderson</name></author><content><![CDATA[ 13 Jun 2023 | 21:16 UTC US POWER TRACKER: Moderate ISO-NE power prices expected this summer By Jared Anderson Highlights Gas prices expected down considerably on year Summer power demand could reach 26,421 MW Getting your Trinity Audio player ready... The ISO New England on-peak Mass Hub forward power price summer strip for June, July and August averaged $59.54/MWh in May trading, down from the summer 2022 forward power price strip of $115.42/MWh. ISO-NE on-peak power prices are expected to average $41/MWh in 2023 according to S&amp;P Global Commodity Insights power market analysts. "With gas markets rebalancing and production outpacing demand, delivered natural gas prices in New England are projected to average around $3.32/MMBtu in 2023, down from over $9/MMBtu in 2022," the power market analysts said in a recent research note. "As a result, we project on-peak power prices to continue to moderate throughout the year with an average of $41/MWh in 2023," the analysts said. The Mass Hub on-peak forward power price for June averaged $44.86/MWh in May trading, down nearly 51% from $91.04/MWh a year ago, according to Platts M2MS data. The monthly average power price for June was down about 2% on month. The Mass Hub July on-peak forward power price averaged $76.87/MWh in May trading, down 44% on year and down 1.43% on month, and forward power for August averaged $56.89/MWh, down 52% on year and down about 5% on month. With natural gas-fired power accounting for over 50% of the ISO-NE power generation fuel mix, gas prices heavily impact power prices. Algonquin on-peak forward gas prices for June, July and August averaged $5.52/MMBtu in May trading, down from an average of $8.02/MMBtu for the corresponding period last year. The highest summer forward gas price is in July at $4.49/MMBtu, down about 45% from $8.23/MMBtu a year ago. "We are seeing a fairly stable outlook heading into the summer," Dan Dolan, president of trade group New England Power Generators Association, said in a June 13 email. "There are no major retirements or additions expected this summer with the last year of Mystic [the 1,413-MW gas-fired power plant] and [the 800-MW offshore] Vineyard Wind project expected to come online in a little less than a year." Power generation fuel mix ISO-NE has over 30 GW of incremental power generating capacity, mostly wind power, in its interconnection queue, though many projects ultimately withdraw, according to the grid operator. Gas-fired power accounted for 51.8% of the ISO-NE power generation fuel mix in May, down from 58.9% in April and 55.5% in May 2022, according to ISO data. Nuclear power supplied 20% of the May generation mix, up from 13.8% in April and down slightly from 20.3% in May 2022. Hydropower accounted for 10.7% of the May fuel mix, down from 12.4% in April, and up from 10.1% in May 2022. Wind and solar power accounted for most of the remainder of the generation mix in addition to fractional volumes of coal, oil and other renewables. Spot power, gas price dynamics Temperatures were slightly above the historical average in May and electric cooling demand began to kick in. The average May temperature across the ISO-NE footprint was 58.6 degrees Fahrenheit compared with the historical average of 57.4 degrees F, according to CustomWeather data. Heating degree days averaged 6.5 in May as cooler temperatures stuck around, but with a few days nearing an average of 70 degrees F, cooling degree days averaged 0.5. Despite the warmer temperatures compared with April, power demand was 1% lower in May. Peakload averaged 12,916 MW compared with 13,024 in April. Peakload was down 8% from May 2022. This summer, under typical weather conditions, power demand in New England is forecast to reach 24,605 MW, and above-average summer temperatures, like an extended heat wave, could push demand up to 26,421 MW, which would tighten supply margins, the grid operator said June 1. The Boston Zone saw the highest on-peak day-ahead power prices in May, which averaged $21.92/MWh, down about 67% on year and down almost 14% on month. Editor: Richard Rubin ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/energy-transition/071422-extreme-heat-propels-more-chinese-provinces-peak-power-loads-to-record-highs</link><description>Extreme heat is sweeping across China with peak power loads hitting record highs in more provinces recently, putting pressure on the grid as well as raising concerns about the supply of power generati</description><title>Extreme heat propels more Chinese provinces&amp;apos; peak power loads to record highs</title><pubDate>14 July 2022 10:46:00 GMT</pubDate><author><name>Staff and Eric Yep</name></author><content><![CDATA[ 14 Jul 2022 | 10:46 UTC Extreme heat propels more Chinese provinces' peak power loads to record highs By Staff and Eric Yep Highlights Record temperatures logged by 71 national weather stations Power loads in Zhejiang, Jiangxi, Jiangsu hit record highs China's power consumption to grow 5%-6% in 2022 Getting your Trinity Audio player ready... Extreme heat is sweeping across China with peak power loads hitting record highs in more provinces recently, putting pressure on the grid as well as raising concerns about the supply of power generation fuels, such as coal, natural gas and LNG, market sources said. Record high temperatures were recorded by 71 national weather stations over June 13-July 12, with the highest exceeding 40 degrees Celsius in many cities, state-owned media People's Daily said July 14. A heatwave in eastern China pushed electricity loads in Zhejiang, Jiangxi and Jiangsu provinces to record highs earlier this week, according to local government announcements and state media. Jiangsu and Zhejiang are China's second- and third-largest power consumption provinces, just behind Guangdong. The peak power load in Zhejiang and Jiangxi reached record highs of 101.9 GW and 29.587 GW on July 11, respectively, while the highest electricity load in Jiangsu also hit a record of 121.42 GW on July 12, they said. The sharp increase in household power consumption is being driven by the use of air conditioning and cooling systems, as well as recovering industrial power use as outbreaks of COVID-19 slowed in some provinces. Zhejiang's industrial power consumption has recovered to March levels, and its total power consumption increased 4.06% year on year over the January-June period, the provincial government said July 12. Zhejiang's peak power load is expected to reach around 106-107 GW this year, an increase of 5.8%-6.8% year on year, it said, noting that tight global energy supply and high energy prices have put pressure on the government to ensure local energy supply. The provincial government said it would ensure that at least 15 days of coal inventory for local power plants and boost efforts to secure natural gas, and lock in prices and volumes for 1 GW of additional gas-based power generation during peak summer. The Jiangsu Development and Reform Commission expects hot weather to continue for days this summer, which would keep the province's power load high for a while, resulting in tight power supply in the region. "We will closely monitor the balance of electricity supply and consumption, urge local power generators to maintain stable and full power generation, as well as increase power procurement from other regions to ensure supply," Jiangsu's planning body said July 12. Strong power demand China's power consumption is expected to grow around 5%-6% in 2022, with national power supply and demand generally balanced, trade body China Electricity Council said in its China Electric Power Industry Annual Development Report 2022, released July 6. It said some provinces in eastern, central and southern regions may have tight electricity supply during peak hours. China's Central Meteorological Observatory maintained its high temperature orange alert at 6 am local time on July 14, warning that temperatures in Jiangsu, Zhejiang, Sichuan, Chongqing and Shaanxi provinces would top 40 C on the day. The peak power load in Henan, Shandong and Ningxia provinces had hit record highs last month due to a heatwave. So far, many provinces, including Zhejiang, Anhui, Liaoning, Shandong, Heilongjiang, Shanghai, Inner Mongolia, Henan, Ningxia, Guangdong and Yunnan have issued guidelines for "orderly" electricity consumption to prevent power outages, according to domestic media. Editor: Manish Parashar ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/032824-infographic-european-gas-carbon-power-solar-capacity-coal-nuclear-hydro-germany-eu-lng</link><description>Our latest infographic illustrates supply and demand shifts for European gas power in Q2 2024. Discover the latest market dynamics and potential shifts. </description><title>Infographic: Bearish Q2 signals hold sway for European gas, power markets</title><pubDate>28 March 2024 15:00:00 GMT</pubDate><author><name>Andreas Franke</name></author><content><![CDATA[ 28 Mar 2024 | 15:00 UTC Infographic: Bearish Q2 signals hold sway for European gas, power markets By Andreas Franke Getting your Trinity Audio player ready... Europe is entering its "gas summer" with prices back at what could be considered normal levels and with gas storage stocks in robust health. Another mild winter and weak demand have left the EU's gas storage sites filled to 59% of capacity, while demand in the EU and UK is set for a 3.7% year-on-year decline in Q2 2024, according to forecasts from S&amp;P Global Commodity Insights. Meanwhile, electricity demand across ten core markets is forecast to rise 1.7% with Europe's power markets entering spring in the best supply shape since 2020. Solar output is forecast to exceed gas-fired power generation for the first time in Q2. Carbon prices are expected to show more resilience finding stability just above Eur60/mtCO2e after EU Allowances fell close to three-year lows. The European Commission is expected to release 2023 EU ETS verified emissions data on April 3 with S&amp;P Global analysts forecasting a drop of 11% year-on-year. Read the full feature: Bearish Q2 signals hold sway for European gas, power markets (subscriber content) Click here to see the full-size infographic ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/podcasts/commodities-focus/090720-downside-risk-gas-supply-rebounds-demand-recovery-falters</link><description>S&amp;amp;P Global Platts journalists discuss European gas, power and carbon market trends going into the third quarter of 2020. The markets saw price support in June as economies began to emerge from coronavirus lockdowns â&amp;#x80;&amp;#x93; but any faltering in demand or rebound in gas flows could undermine these trends, as could a modest uptick in French nuclear availability. &amp;#xa;</description><title>Downside risk if gas supply rebounds, demand recovery falters</title><pubDate>09 July 2020 11:25:00 GMT</pubDate><author><name>Henry Edwardes-Evans</name><name>Stuart Elliott</name><name>Andreas Franke</name><name>Frank Watson</name></author><content><![CDATA[ 09 Jul 2020 | 11:25 UTC â London Listen: Downside risk if gas supply rebounds, demand recovery falters Featuring Henry Edwardes-Evans, Stuart Elliott, Andreas Franke, and Frank Watson S&amp;P Global Platts journalists discuss European gas, power and carbon market trends going into the third quarter of 2020. The markets saw price support in June as economies began to emerge from coronavirus lockdowns â but any faltering in demand or rebound in gas flows could undermine these trends, as could a modest uptick in French nuclear availability. Related infographic: Click here to see full-size image. ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/010824-us-power-tracker-pjm-forward-power-prices-remain-lower-on-year-with-gas-prices-down</link><description>Forward power for Jan down 55% year on year Spot gas prices down 81% year on year PJM Interconnection three month forward power prices remained well below year ago levels in December, trading as forwa</description><title>US POWER TRACKER: PJM forward power prices remain lower on year with gas prices down</title><pubDate>08 January 2024 22:05:00 GMT</pubDate><author><name>Jared Anderson</name></author><content><![CDATA[ 08 Jan 2024 | 22:05 UTC US POWER TRACKER: PJM forward power prices remain lower on year with gas prices down By Jared Anderson Highlights Forward power for Jan down 55% year on year Spot gas prices down 81% year on year Getting your Trinity Audio player ready... For access to all regions of the US Power Tracker series, subscribe to Platts Connect. PJM Interconnection three-month forward power prices remained well below year-ago levels in December, trading as forward natural gas prices were down by as much as 70% year on year and the fuel accounted for about 42% of PJM's December power generation fuel mix. Spot gas prices were down over 80% year on year. PJM West Hub on-peak forward power prices for January, February and March averaged $48.51/MWh in December trading, down from a three-month forward average of $99.64/MWh a year ago, according to Platts M2MS data. Forward power at the hub for January averaged $53.45/MWh, down 55% year on year from an average of $118.33/MWh and down 15% month on month. Forward power for February averaged $50.69/MWh, down 52% from $106.45/MWh a year ago, and the forward package for March averaged $41.40/MWh, down 44% from $74.15/MWh last year. Forward power prices at other liquid trading hubs like AEP Dayton and Northern Illinois were down by similar levels in December trading. Forward gas prices were down even more sharply than power, with Transco Zone 6 Non-New York prices for January averaging $4.21/MMBtu, a nearly 70% decline year on year from $13.77/MMBtu and down 27% month on month. Forward gas for February averaged $3.91/MMBtu in December trading, down 70% from $12.87/MMBtu a year ago. And forward gas for March averaged $2.05/MMBtu, a 64% decline year on year from $5.65/MMBtu. Power generation fuel mix Coal-fired power accounted for 15.2% of PJM's December power generation fuel mix, up from 13.9% in November and down from 21.1% in December 2022, when gas prices were higher, and coal was more competitive. Gas-fired power accounted for 42.3% of the fuel mix in December, up from 42.1% in November and 37.4% in December 2022. Nuclear power accounted for 34.4% of the PJM generation mix in December, down from 35.2% in November and up from 33.0% in December 2022. The remainder of PJM's generation mix was supplied by smaller volumes of hydropower, wind power, non-wind renewables and other resources, according to ISO data. Spot power, gas price dynamics PJM power demand in December was 5% higher than November, with peakload averaging 98,818 MW compared with an average of 94,553 MW a month earlier. PJM peakload averaged 106,179 MW in December 2022, when a severe winter storm impacted the region around the Christmas holiday. Cooler December weather month on month helped increase power demand, with temperatures across the PJM footprint averaging 42.8 degrees Fahrenheit in December compared with an average of 45.9 F in November, according to CustomWeather data. The historical average temperature for December is 37.2 F. Heating degree days averaged 21.7 compared with a historical December average of 27.8. PJM West Hub on-peak day-ahead power prices averaged $33.22/MWh in December, down 62% year on year and down 20% month on month. Spot power prices at the hub averaged $87.43/MWh in December 2022. Texas Eastern spot gas prices averaged $1.97/MMBtu in December, down 81% from an average of $10.43/MMBtu a year ago. Spot gas prices at the hub were down about 8% month on month from an average of $2.13/MMBtu in November. Editor: Derek Sands ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/033123-europes-q2-2023-energy-supply-concerns-ease-on-healthy-stocks-lower-demand</link><description>Europe is headed into the second quarter and the key summer storage filling season in much better shape than many had expected, with stocks still healthy and LNG deliveries relatively strong.</description><title>Europe&amp;apos;s Q2 2023 energy supply concerns ease on healthy stocks, lower demand</title><pubDate>31 March 2023 14:07:00 GMT</pubDate><author><name>Stuart Elliott</name><name>Andreas Franke</name><name>Eklavya Gupte</name><name>Hassan Butt</name></author><content><![CDATA[ 31 Mar 2023 | 14:07 UTC Europe's Q2 2023 energy supply concerns ease on healthy stocks, lower demand By Stuart Elliott, Andreas Franke, Eklavya Gupte, and Hassan Butt Highlights Q2 LNG imports seen down on year Stronger renewables shrink thermal gap Carbon market focused on auction volumes Getting your Trinity Audio player ready... Europe is headed into the second quarter -- and the key summer storage filling season -- in much better shape than many had expected, with stocks still healthy and LNG deliveries relatively strong. A mild winter -- fortuitous and well-timed given the loss of significant volumes of Russian pipeline gas -- helped keep a lid on demand. And prices, while still historically high, are well down from August's record levels, with injection demand likely to be relatively muted this summer given the high level of stocks as Europe exits winter. Platts, part of S&amp;P Global Commodity Insights, assessed the benchmark Dutch TTF month-ahead price at Eur43.28/MWh on March 30, down from an all-time high of almost Eur320/MWh in late August. However, EU member states remain tied to mandatory storage filling targets and prices may have to stay high to continue to attract LNG cargoes. "The weaker price environment in Europe since late February is a 'false comfort' and masks a hyper-sensitive new reality for European gas markets," Alun Davies, Senior Director at S&amp;P Global Commodity Insights, said. "Gas prices must stay high enough to sustain LNG deliveries into Europe and constrain European demand sufficiently to allow gas storage to reach targeted levels through the summer," Davies said. Traders also believe the current European gas price could be a floor. "We are in a crucial period and the following weeks will determine the price movement," a European trader said. "Technically, we seem to have reached a bottom." Another EU-based trader said that while prices had come down, there was still some upside risk. "The bears are out there -- but you may want to call this still hibernating," the trader said. Much in the second quarter will depend on the rate of storage filling, with EU storage sites still filled to 56% of capacity as of March 28. EU member states are obliged to reach 90% fullness by Nov. 1. According to S&amp;P Global forecasts, European sites are forecast to be 67% full by the end of June. And if there is a rush to fill storage sites earlier rather than later this summer, there could be a lack of injection demand headed into the third quarter. The level of demand in other sectors will also be key, especially in the price-sensitive industrial sector, which is seen as a major swing area of consumption. S&amp;P Global forecasts that total EU 27+UK gas demand will average 799 million cu m/d in the second quarter, down 6% compared with 848 million cu m/d in Q2 2022. LNG supplies to Europe over the summer will also be key, as will any uptick in Chinese spot LNG buying that could see cargoes diverted away from European markets. S&amp;P Global forecasts that European LNG imports -- while still historically high -- in the second quarter will be lower year on year as a result of the more comfortable storage situation and lower demand. As part of the EU's efforts to strengthen supply security, its new gas demand aggregation and joint purchasing platform AggregateEU is set to be up and running by mid-April, with the first joint purchasing tender to follow in May. EU member states will be required to aggregate a minimum of 15% of the EU-mandated 90% storage target for 2023, with at least 24 Bcm of gas demand already submitted to AggregateEU. This includes additional gas demand aggregation from Ukraine, Moldova and Serbia. Joint purchasing of gas, however, will remain voluntary. The platform's matching algorithm will take shape through a series of rolling tenders, while gas purchase agreements will then be done outside of the platform. Once agreed, the EU can appoint either a "central buyer" or a larger buyer acting on behalf of smaller ones to facilitate the joint purchasing process. Related infographic: Europe's Q2 2023 energy supply concerns ease on healthy stocks, lower demand Near-term power bearish European power prices enter the second quarter of 2023 at their lowest level since summer 2021. With demand weak, feedstock prices weak and renewables strengthening there is no sign yet of last year's volatility. Power demand for the quarter is forecast to fall by 3.5% year on year, according to S&amp;P Global analysts, with only modest upside risk from late cold snaps or early heatwaves. Meanwhile, rising wind and solar capacity combined with improved hydro conditions are forecast to reduce Europe's demand for fossil generation by 21 GW in the period. Within this shrinking thermal gap, new gas units have started to sideline older coal units. Falling gas and rising carbon prices have seen a return of coal-to-gas switching, but volumes at play are fairly limited. With Germany on course to close its remaining three reactors in April, meanwhile, the sector's focus will double down on French nuclear availability, with S&amp;P Global seeing ongoing strikes cutting 1.5 GW from average second-quarter output. Elsewhere, Finland will finally see the 1.6-GW Olkiluoto-3 reactor start commercial operation. Meanwhile, the impact of Europe's solar boom, with more than 40 GW added last year, is already being felt; Germany and Spain lead the pack, with bearish midday price trends anticipated to accelerate through the second quarter. S&amp;P Global forecasts solar in 10 European markets to match average gas-fired generation in the second quarter. France is expected to return to net export status as weak domestic demand combines with relatively improved nuclear output, despite strikes and knock-on maintenance delays. A repeat of last year's exports from Britain and Iberia seems unlikely amid much smaller gas hub differentials, removing Spain's advantage under the country's gas for power cap. While spring fundamentals appear to be generally bearish, more bullish factors could loom later in the summer, S&amp;P Global's head of European power analysis Glenn Rickson said. "After an unusually dry and hot summer last year and with climate (as opposed to just weather) risk a growing concern, the market is naturally concerned about a repeat performance for the coming summer, not helped by reviving concerns around French nuclear as a result of ongoing strikes and low snowpack in the Alps, which has led to concerns over hydro dispatch," he said. A summer stress test scenario, assuming a heatwave, would lift average summer demand (April to September) by 3% and result in 18 GW of additional gas and coal generation. This could yield a baseload power price increase of up to Eur15/MWh in August, Rickson said. Carbon volatility European carbon prices are likely to remain volatile into the second quarter of 2023, with the market particularly sensitive to bullish technical factors balanced by worries over the global economy. Carbon permits under EU's Emissions Trading Scheme have oscillated between Eur83-101/mtCO2 in the first quarter, with prices seen likely to stay in a similar range in the second quarter. Increased investor interest and steady annual compliance demand will be balanced by macroeconomic concerns and quicker coal-to-gas switching in power production, according to analysts. Prices are also likely to get some support in the immediate term from slightly higher gas and power prices in Europe. Into the third quarter, meanwhile, the European Commission has confirmed that allowance auctions under the REPowerEU deal are expected to commence from July, which may put some pressure on prices as more allowances come into the market. "For our EUA price view, lower-than-expected auction volumes (compared with our previous forecast) brought forward in 2023 may keep monthly average prices higher than our current forecast this year, but we still expect a bearish trend in Q2 as participants prepare for increases in the monthly auction volume from July," said S&amp;P Global carbon analyst Michael Evans. Editor: Jonathan Fox ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/energy-transition/030123-uae-to-release-hydrogen-strategy-in-march-seeks-investor-participation</link><description>The UAE will announce its national hydrogen strategy for 2050 and 2030 later this month, and will offer private investors the chance to participate, the future energy director of the country s ministr</description><title>UAE to release hydrogen strategy in March, seeks investor participation</title><pubDate>01 March 2023 07:02:00 GMT</pubDate><author><name>Claudia Carpenter</name><name>Dania Saadi</name></author><content><![CDATA[ 01 Mar 2023 | 07:02 UTC UAE to release hydrogen strategy in March, seeks investor participation By Claudia Carpenter and Dania Saadi Highlights NEOM green hydrogen gets funding Windmills heading to Fujairah UAE also investing overseas Getting your Trinity Audio player ready... The UAE will announce its national hydrogen strategy for 2050 and 2030 later this month, and will offer private investors the chance to participate, the future energy director of the country's ministry of energy and infrastructure, Nawal Yousif, said March 1. The national hydrogen strategy will be separate from the revised 2050 energy mix plan, Yousif told S&amp;P Global Commodity Insights on the sidelines of the World Hydrogen MENA conference in Dubai. The details of the strategy will be released later this month, she said, declining to give the targets for hydrogen until the plan is released. She said one project that is being worked on is windmills for Fujairah, on the UAE's east coast. The UAE has already spent $43 billion on all kinds of renewables projects, and another $50 billion in 40 other countries including Jordan, she said. The total spend is projected to be $163 billion by 2050 and another $50 billion over the next decade in 70 countries, she said. The UAE has pledged to reach net zero emissions by 2050, the first country in the Middle East to make such a commitment. The UAE's renewables power firm Masdar, in which Abu Dhabi National Oil Co. has a stake, plans to produce as much as 1 million mt/year of green hydrogen by 2030 as OPEC's third biggest producer seeks to hit zero emission by 2050. The development of up to 1 million mt/year of green hydrogen is equivalent to saving more than six million mt of CO2 emissions, ADNOC and Masdar said in a Dec. 8 statement. The UAE is developing projects globally as it seeks to have a 25% global market share in low-carbon hydrogen projects by 2030. Dubai will host the UN Climate Change Conference (COP28) starting Nov. 30. In October 2022, the UAE signed a partnership agreement with the US to help mobilize $100 billion in investments to develop 100 GW of clean energy projects globally by 2035. In 2017, the UAE set energy mix targets of 44% clean energy, 38% natural gas, 12% clean coal, and 6% nuclear by 2050 to meet the country's economic and environmental goals. That is now being revised. Dubai's sole utility recently announced that it was switching a coal plant to gas to lower emissions. NEOM project In Saudi Arabia, renewables developer ACWA Power is working with Air Products and the futuristic city NEOM for an $8.5 billion green hydrogen project. Financing agreements were signed by the NEOM Green Hydrogen Co. (NGHC) with a financing consortium for the project, Air Products said March 1 in a statement to the Saudi exchange. NGHC is a joint venture between ACWA Power, with a 33.3% stake, Air Products and NEOM Co., it said. The NEOM green hydrogen project includes development, financing, design, engineering, completion, ownership, operation and maintenance of a green hydrogen and green ammonia facility in the NEOM region of Saudi Arabia, with a 30-year green ammonia offtake contract with Air Products. Funding includes $1.5 billion from the kingdom's National Development Fund on behalf of National Infrastructure Fund, and $1.25 billion from the Saudi Industrial Development Fund, ACWA Power said. The remainder is from First Abu Dhabi Bank, HSBC, Standard Chartered Bank, Mitsubishi UFJ Financial Group, BNP Paribas, Abu Dhabi Commercial Bank, Natixis, Saudi British Bank, Sumitomo Mitsui Banking Corp., Saudi National Bank, KFW, Riyad Bank, Norinchukin Bank, Mizuho Bank, Banque Saudi Fransi, Alinma Bank, APICORP, JP Morgan, DZ Bank, Korea Development Bank and Credit Agricole, ACWA Power said. "The market is huge, we need to go after this," Andrea Lovato, global head of hydrogen at ACWA Power, told the Dubai conference. The NEOM project will produce 200,000 mt/year of hydrogen, or 600 mt/day, by 2025, while global demand is projected to be 520 million mt/year over the next 20 years, he told S&amp;P Global. "We're going to need a lot of NEOM projects to meet the demand," he said. Editor: Debiprasad Nayak ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/051622-iberian-gas-price-cap-to-lift-spanish-gas-generation-rbc</link><description>Iberian gas output seen rising 20 TWh/yr on exports Generator subsidy seen to average Eur64/MWh: analyst Spain power swung to discount to France on nuclear risk Iberia&amp;apos;s new price cap on gas for power</description><title>Iberian gas price cap to lift Spanish gas generation: RBC</title><pubDate>16 May 2022 12:53:00 GMT</pubDate><author><name>Gianluca Baratti</name></author><content><![CDATA[ 16 May 2022 | 12:53 UTC Iberian gas price cap to lift Spanish gas generation: RBC By Gianluca Baratti Highlights Iberian gas output seen rising 20 TWh/yr on exports Generator subsidy seen to average Eur64/MWh: analyst Spain power swung to discount to France on nuclear risk Iberia's new price cap on gas for power could lift domestic CCGT burn by around 20 TWh/year, analysts at RBC said. Resulting potential gas savings in France were estimated at 4 Bcm/year and may have been "the ultimate reason for the European Commission agreeing with this measure", RBC analyst Fernando Garcia said in a note, adding that Spanish gas exports to France could reach 7 Bcm/year over the year ahead. "All Iberian integrated utilities should benefit from an increase in the load factor of their CCGTs given the significant gap between Spanish and French electricity prices going forward," Garcia said. Spanish gas at the PVB hub for June was assessed by Platts at Eur74.65/MWh ($77.6/MWh) on May 13, down 8% on the day, S&amp;P Global Commodity Insights data showed, with the price cap starting at Eur40/MWh. Gas generation in Spain and Portugal was 105 TWh in 2021 with the fleet underutilized. A limiting factor would be the 2.8 GW interconnector capacity to France, Garcia noted. France traditionally exports to Spain, especially during the summer. But record-low nuclear in France and expectations of the measure approved May 13 have already seen net flows swing northbound. Spain net exported 0.8 TWh in April to France compared to 1 TWh net imports in February before Spain and Portugal proposed the measure for the first time. Generator subsidy The gas price cap "is actually a subsidy paid to thermal producers: CCGTs, coal and cogeneration", which RBC calculates at an average Eur64/MWh. The measure could mean wholesale prices in Iberia average around Eur140/MWh in the period, Garcia estimated. "We calculate electricity bills would fall by half of that amount for those consumers," RBC said. The measure will come into force once it has been approved by the European Commission, which could take up to two weeks. The Eur40/MWh cap will increase by Eur5/MWh/month after six months to end the period at Eur70/MWh resulting in an average of Eur48.80/MWh over the 12 months. Overall, the measure should not have any impact on Iberian utilities that sold electricity forward, although it might be positive for companies that are short in generation compared to supply (especially given the low hydro scenario) and negative for companies long in generation versus supply, Garcia said. Under the conditions of the mechanism, gas generators will receive the difference between the day-ahead price and the cap divided by 0.55. Consumers that benefit from the reduction will pay the adjustment amount. Additional congestion revenues from the cross-border auction between France and Spain will be used to reduce the cost of the measure. "We believe these revenues will be equivalent to the price differential between France and Spain," Garcia said. "The new regulation would trigger an important reduction in the power prices in Iberia and an increase for the electricity exports to France," he said. Editor: Daniel Lalor ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/coal/032323-japans-kansai-electric-to-restart-takahama-no-4-reactor-march-24-after-automatic-shutdown</link><description>Japanâ&amp;#x80;&amp;#x99;s Kansai Electric will restart the Takahama No. 4 reactor after a temporary shutdown, signaling a return to stable nuclear energy supply.</description><title>Japan&amp;apos;s Kansai Electric to restart Takahama No. 4 reactor March 24 after automatic shutdown</title><pubDate>23 March 2023 02:57:00 GMT</pubDate><author><name>Takeo Kumagai</name></author><content><![CDATA[ 23 Mar 2023 | 02:57 UTC Japan's Kansai Electric to restart Takahama No. 4 reactor March 24 after automatic shutdown By Takeo Kumagai Highlights Kansai Electric finishes cable works for No. 4 Takahama reactor To restart No. 1, No. 2 Takahama reactors June-July Unclear about restart of No. 2 Maizuru coal-fired unit Getting your Trinity Audio player ready... Japan's Kansai Electric said March 23 it plans to restart the 870 MW No. 4 Takahama nuclear reactor March 24 and resume power generation the following day after a Jan. 30 automatic shutdown. An approval by Japan's Nuclear Regulation Authority March 22 paved the way for Kansai Electric to restart the No. 4 Takahama reactor in Fukui prefecture. The NRA's approval of the root cause and steps taken after the Jan. 30 automatic shutdown means Kansai Electric had to complete only one more step, reporting to Fukui prefecture, before restarting the unit, a Kansai Electric spokesperson said earlier March 23. The company has already completed works to change the route of cables that had caused issues over March 9-16 and confirmed safety after subsequent monitoring over March 17-22, the spokesperson said. Restarting the No. 4 Takahama reactor would mean Kansai Electric has five nuclear reactors in operation, joining the 826 MW No. 3 Mihama, 870 MW No. 3 Takahama, 1.18 GW Ooi No. 3 and 1.18 GW Ooi No. 4 nuclear reactors. Kansai Electric also plans to restart power generation at the 826 MW No. 1 and 826 MW No. 2 Takahama nuclear reactors on June 3 and July 15, respectively, for the first time under Japan's new regulatory standards introduced in 2013 following shutdowns for scheduled maintenance in 2011. The restarts of the No. 1 and No. 2 Takahama reactors would also mark the country's second and third nuclear reactors to see over 40 years of commercial operations following NRA's approvals in 2016, along with Kansai Electric's 826 MW No. 3 Mihama nuclear reactor, which was restarted in 2022. Coal outage It remains unclear when Kansai Electric will be able to restart the the 900 MW No. 2 coal-fired unit at Maizuru power plant in Kyoto prefecture, which was shut late March 21 due to the malfunctioning of a wastewater treatment unit. The shutdown came after the company restarted the unit March 20 using only coal as feedstock as it is still investigating the cause of a March 14 fire. Kansai Electric has identified overflow wastewater from recent firefighting activities in addition to that from power generation as resulting in the malfunction at the wastewater treatment unit. At the time of the fire, Kansai Electric was in the midst of carrying out planned repair works at the 900 MW No. 1 Maizuru coal-fired unit, which remains shut for resumed works until July 22. The shutdowns of both 1.8 GW Maizuru coal-fired units means Kansai Electric has lost all of the operable coal-fired power generation capacity over the two units. The company has not been looking for spot LNG cargoes in the wake of the fire and was still not looking for additional supplies, according to market sources. Coal-fired power accounts for 12% of Kansai Electric's 14.566 GW of operable thermal power generation capacity, with LNG and oil accounting for 62% and 26%, respectively. The local fire department and Kansai Electric confirmed at the time that the fire at the biomass-fuel supply facilities late March 14 had been extinguished by early morning March 15. Editor: Wendy Wells ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/lng/011223-south-korea-to-cut-lng-in-power-mix-to-93-in-2036-sharply-raises-role-of-nuclear-energy</link><description>South Korea will raise its share of nuclear energy in the country s power mix to 34.6% in 2036 from 32.4% in 2034 and 23.4% in 2018 while sharply cutting roles of LNG and coal, in line with national e</description><title>South Korea to cut LNG in power mix to 9.3% in 2036, sharply raises role of nuclear energy</title><pubDate>12 January 2023 15:30:00 GMT</pubDate><author><name>Charles Lee</name></author><content><![CDATA[ 12 Jan 2023 | 15:30 UTC South Korea to cut LNG in power mix to 9.3% in 2036, sharply raises role of nuclear energy By Charles Lee Highlights Nuclear energy to form 34.6% of power mix in 2036 Coal's share to be reduced to 19.7% in 2030 Getting your Trinity Audio player ready... South Korea will raise its share of nuclear energy in the country's power mix to 34.6% in 2036 from 32.4% in 2034 and 23.4% in 2018 while sharply cutting roles of LNG and coal, in line with national efforts to reduce carbon emissions and power production costs, the Ministry of Trade, Industry and Energy said Jan. 12. Under the 2022-2036 Basic Plan for Power Supply, the share of LNG in the country's power mix will be lowered to 22.9% in 2030 and further to just 9.3% in 2036, compared with 29.2% in 2021 and 26.8% in 2018, the ministry said. The Basic Plan also calls for cutting the share of coal in the power mix to 19.7% in 2030 and 14.4% in 2036, from 34.3% in 2021 and 41.9% in 2018. The portion of nuclear energy in its power mix would rise to 32.4% in 2030 and further to 34.6% in 2036, compared with 27.4% in 2021 and 23.4% in 2018. Renewable sources will be responsible for 30.6% of the power generation in 2036 and 21.6% in 2030, up from 7.5% in 2021 and 6.2% in 2018. The move is part of the country's push to reduce its greenhouse gas emissions by 44% from 2018 levels by 2030 and reach carbon neutrality by 2050, according to the MOTIE. "South Korea will actively use renewable energy sources and nuclear power plants and come up with a feasible and balanced energy mix amid the country's efforts to reach carbon neutrality," the MOTIE said in a statement. The new power mix plan would add momentum to the nuclear-focused energy policy by President Yoon Suk-yeol, who has vowed to revive the nuclear power sector by reversing his predecessor's nuclear phase-out policy. On Dec. 7, South Korea started commercial operations at the Shin Hanul-1 nuclear reactor with a capacity of 1.4 GW. The 1.4 GW Shin Hanul-2 reactor is scheduled to start up in September this year. South Korea is currently running 25 nuclear reactors with a combined capacity of 24.65 GW. The MOTIE projected South Korea to need a total of 143.9 GW of power capacity by 2036 to meet maximum power demand of 135.6 GW and manageable demand of 118 GW for the year. New power production facilities would be largely renewables-based, the capacities of which would rise to 108.3 GW in 2036 from 29.2 GW in 2022. Nuclear capacity would rise to 31.7 GW in 2036 from 24.7 GW in 2022. Despite a smaller role in the power mix, LNG's power production capacity is set to climb to 65.6 GW in 2036, from 41.3 GW in 2022, which would be ready to operate when power demand rises in the peak seasons of winter and summer. A total of 28 aging coal power plants will be converted to LNG power plants by 2036. The capacity of coal-fired power plants would be 27.1 GW in 2036, down from 38.1 GW in 2022, according to the Basic Plan. To meet the target, a total of 17 coal-fired power plants will be retired while plans to build three large coal power plants would be scrapped, which will reduce the country's coal-fired power plants to 41 in 2030, from 58 currently. "The country will push for power generation from hydrogen and ammonia, which would help reduce shares of LNG and coal," the MOTIE said, adding that the combined share of hydrogen and ammonia in the power mix would be 2.1% in 2030 and 7.1% in 2036, compared with none currently. Editor: Adithya Ram ]]></content></item><item><link>https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/120522-us-power-tracker-november-pjm-power-prices-decline-forwards-higher-on-year</link><description>PJM Interconnection power prices declined in November on month and on year, while forward power prices declined on month but remained higher on year with prices near or above $100/MWh for January and </description><title>US POWER TRACKER: November PJM power prices decline, forwards higher on year</title><pubDate>05 December 2022 21:36:00 GMT</pubDate><author><name>Jared Anderson</name></author><content><![CDATA[ 05 Dec 2022 | 21:36 UTC US POWER TRACKER: November PJM power prices decline, forwards higher on year By Jared Anderson Highlights Power prices averaged close to $55/MWh Winter forwards around $100/MWh Getting your Trinity Audio player ready... For access to all regions of the US Power Tracker series, subscribe to Platts Dimensions Pro. PJM Interconnection power prices declined in November on month and on year, while forward power prices declined on month but remained higher on year with prices near or above $100/MWh for January and February. "Wholesale power prices in November settled below our projections as natural gas prices moderated," S&amp;P Global Commodity Insights power market analysts said in a recent research note. PJM Northern Illinois Hub on-peak day-ahead power prices averaged $49.09/MWh in November, which was down almost 6% on year and 11% on month. On-peak real-time power prices at the hub averaged $48.36/MWh during the month, down about 29% on year and about 11% on month. AEP-Dayton Hub on-peak day-ahead power prices averaged $56.34/MWh in November, a decline of about 13% on year and down about 31% on month. On-peak real-time prices at the hub averaged $53.92/MWh, which was about 20% lower on year and down almost 40% on month. PJM West Hub on-peak day-ahead power prices averaged $58.53/MWh in November, down about 16% on year and almost 13% on month. PJM East Hub on-peak day-ahead power prices averaged $49.94/MWh in November, down about 5% on year and about 14% on month. Spot Platts Texas Eastern gas prices averaged $4.62/MMBtu in November, down about 4% on year and roughly flat on month. Year-to-date, electricity demand has grown by more than 1% in 2022 and is on pace to finally eclipse pre-pandemic levels, according to S&amp;P Global. PJM power demand increased in November as temperatures cooled heading into winter. Peakload averaged 93,489 MW in November, almost 10% higher than the October average of 85,066 MW, according to ISO data. PJM power demand was down about 1% on year in November. The November average high temperature across the PJM footprint was 56.1 degrees Fahrenheit, compared with an October average high of 64.2 degrees F, according to CustomWeather data. The November average low temperature was 39.9 degrees F, compared with an October average low of 46.3 degrees F. The cooler weather increased heating degree days from an average of 9.4 in October to an average of 16.8 in November. Power generation fuel mix Coal-fired power generation accounted for 15.6% of the PJM power generation fuel mix in November, up from 12.8% in October and 15.4% in November 2021, according to ISO data. Gas-fired power accounted for 39.5% of the PJM fuel mix in November, down from 44.1% in October and 40.3% in November 2021. Nuclear power supplied 35.2% of the PJM generation mix in November, up slightly from 34.3% in October and 35% in November 2021. Hydropower accounted for 1.7% of the fuel mix, up from 1.3% in October and down from 2.0% in November 2021. Wind power increased to account for 5.7% of the PJM generation mix in November, up from 1.3% in October and 2.0% during the corresponding period a year ago. Non-wind renewables supplied 1.4% of the PJM fuel mix in November, down from 1.6% in October and flat with the non-wind renewables contribution from November 2021. Forward power, gas prices PJM West on-peak forward power prices for December averaged $87.26/MWh in November trading, which was down almost 8% on month and up by about 19% on year, according to Platts M2MS data. Forward power prices for January 2023 at the hub averaged $127.97/MWh in November, down about 8% on month and up about 37% on year. And forward power for February 2023 averaged $118.22/MWh, which was down about 3% on month and 35% on year. AEP-Dayton Hub forward power prices for December averaged $81.11/MWh in November trading, down about 8% on month and up nearly 18% on year. Forward power for January 2023 averaged $110.22/MWh in November, up almost 31% on year, and forward power prices for February 2023 averaged $99.50/MWh, about 29% higher on year. Northern Illinois Hub forward power prices for December averaged $73.37/MWh in November trading, down about 10% on month and up around 27% on year. Forward power for January 2023 averaged $93.36/MWh, which was a roughly 16% decline on month and about 31% higher on year. And forward power for February 2023 averaged $88.86/MWh, a monthly decline of about 9% and roughly 33% higher on year. Platts Transco Zone 6 Non-New York forward gas prices for December averaged $8.15/MMBtu in November trading, which was mostly flat on month and about 26% higher on year. Forward gas for January 2023 traded at an average of $13.41/MMBtu in November, flat on month and about 51% higher on year. And forward gas for February 2023 averaged $12.78/MMBtu, which was also largely flat on month and about 48% higher on year. "In this November short-term outlook, we have trimmed back expectations for winter power pricing modestly based on the evolving natural gas market dynamics," the S&amp;P Global Analysts said. Editor: Benjamin Morse ]]></content></item></channel></rss>