Singapore OKs planned 1.75GW Australia power imports

Market: Electricity, Natural gas
22/10/24

Singapore's energy regulator Energy Market Authority (EMA) has granted conditional approval to Australian firm Sun Cable to import 1.75GW of low-carbon electricity from Australia into Singapore, EMA said today.

The conditional approval "recognises that Sun Cable's [Australia-Asia PowerLink renewable generation and transmission] project can be technically and commercially viable," said Singapore's second minister for trade and industry, Tan See Leng, adding that the approval will facilitate the continued development of Sun Cable's project. Sun Cable's planned commercial operation is expected to be after 2035.

Sun Cable will need to validate its technical and commercial plans further to advance the project, as well as secure all requisite approvals from relevant jurisdictions, including countries through which subsea cables will pass.

The conditional approval is a step forward in helping Australia "export clean, cheap renewables generated in Australia directly to southeast Asia," said the country's minister for climate change and energy, Chris Bowen on 22 October at the Singapore International Energy Week. The project will be a "meaningful complement to the Asean power grid" when it is completed, Tan added.

The project, which involves up to 5.75GW of solar power capacity in Northern Australia and the potential export to Singapore via a 4,300km subsea cable, also received federal environmental approval in August.

Low-carbon electricity imports are part of Singapore's overall strategy to decarbonise the power sector, which currently accounts for 40pc of its carbon emissions. EMA is seeking to import around 6GW of low-carbon electricity by 2035. The authority has so far secured 2GW of conditional licences for imports from Indonesia, 3.6GW of conditional approvals comprising 1.4GW from Indonesia, 1GW from Cambodia and 1.2GW from Vietnam.

By Tng Yong Li

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25/10/24

Pennsylvania drilling drops to 17-year low

New York, 25 October (Argus) — Pennsylvania oil and natural gas drilling this week fell to the lowest in 17 years, signaling dimming producer sentiment in the second-largest US gas producing state. The number of rigs drilling for oil and gas in Pennsylvania this week fell to 12, the lowest since July 2007, as the state's rig count lost one from a week earlier and fell by 10 from a year earlier, according to oil field services company Baker Hughes. There were 101 gas-directed rigs in the US this week, down by 16 from a year earlier, implying that the majority of the gas-rig decline was due to the drop in Pennsylvania, where wells produce plentiful dry gas but little crude and natural gas liquids (NGLs). The 17-year-low rig count in the regional gas-producing powerhouse, home to the prolific Marcellus shale, is due to three factors: expectations of lower US gas prices after the 2024-25 winter heating season, a lower share of currently more profitable crude and NGLs in Pennsylvania's output compared to nearby West Virginia and Ohio, and the June start-up of a new gas pipeline in West Virginia , where some Pennsylvania production may have shifted. Rig counts reflect expected prices roughly six months in the future, accounting for the lag between when the drilling of a well begins and when its production is sold. The April 2025-March 2026 strip price at the Leidy Line trading hub, a bellwether for Marcellus shale output in northeast Pennsylvania, was $2.63/mmBtu, according to Argus forward curves. Prices for crude and NGLs in 2024 have been more resilient than US gas prices, which have languished after a warmer-than-normal 2023-24 winter left the US gas market oversupplied. This price dynamic may be why the other two main Appalachian gas producing states have not mirrored Pennsylvania's drilling slowdown. The Ohio rig count rose by one this week to 10, the same number as a year earlier, while the West Virginia rig count was unchanged at 10, up by three from a year earlier. Drilling productivity has also improved dramatically in the past 17 years, surging to 21 Bcf/d (595mn m³/d) in July from 471mn cf/d in July 2007, according to the US Energy Information Administration. Above-average temperatures were expected to blanket the US from November to January, according to the National Weather Service, portending another winter with lower gas demand. By Julian Hast Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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UK summer LNG imports at long-term low

25/10/24

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25/10/24

UK summer LNG imports at long-term low

London, 25 October (Argus) — The UK received the fewest number of LNG cargoes in April-September since 2008, when it had just one commissioned LNG import terminal. The UK's three LNG terminals — 5.6mn t/yr Dragon, 15.6mn t/yr South Hook and 14.8mn t/yr Isle of Grain — together received 24 cargoes in April-September, down from 41 over the same period in 2023 and 104 in 2022. The UK's summer LNG imports were previously below 30 only twice since all three facilities have been on line — in 2018 and 2019 when 26 and 28 LNG deliveries were completed, respectively. The origin of the UK's LNG was also the least diverse since 2017, coming from just five countries. Dragon received exclusively US cargoes, while South Hook took cargoes from the US and Qatar. Isle of Grain received LNG from the US, Algeria, Norway and Peru. The UK received LNG from six countries in 2023, 2021 and 2020, and from nine countries in 2018 and 2019. Its most diverse summer of supply was in 2022, when the country received LNG from 10 countries. South Hook — owned by a joint venture between Qatargas, ExxonMobil and Total — was the only terminal to receive Qatari LNG this summer, while in previous years all three UK terminals had taken Qatari cargoes. And South Hook received just five Qatari cargoes in April-September, the lowest since the commissioning of all three terminals. This was down from 12 in summer 2023 and 39 in 2022. Qatar had constituted more than half of the UK LNG mix in 2019-20 and was the dominant supply source in 2010-17. Part of the reason for slower Qatari deliveries to South Hook may have been the effective closure of the Suez Canal route. All five Qatari vessels that delivered to the UK went the longer way around the Cape of Good Hope. The need for a change in route — triggered by Yemen's Houthi militants' attacks on ships — almost doubled the journey time. And no firms hold long-term Qatari contracts that specify UK ports as the exclusive destination point. Europe's demand for LNG was consistently weak over the summer because of low injection demand and strong Norwegian pipeline supply. Asian demand, in contrast, was strong enough to keep the arbitrage between the Atlantic and Pacific basins mostly open. And the NBP front-month market held below the TTF on all but one day over the summer, which priced out UK terminals relative to those in continental Europe. The additional buildout of LNG import capacity in northwest Europe since 2022 has significantly reduced the UK's role as an LNG transit country. In the 2022 and 2023 summers, when more LNG arrived in the UK, exports to continental Europe through the Interconnector and BBL pipelines were much higher. Interconnector flows to Belgium fell to 21.2mn m³/d in April-September, from 29.2mn m³/d in 2023 and 54.6mn m³/d in 2022. BBL deliveries to the Netherlands were roughly unchanged from a year earlier but fell by around 5mn m³/d from 2022. The Argus NBP everyday price held below the TTF throughout the past summer, apart from five days in late April and one day in early May. In addition, British consumption continues to decline. UK demand — excluding storage injections — fell to 98.1mn m³/d in April-September, from 109.5mn m³/d over the same period in 2023, 130.6mn m³/d in 2022 and 142.8mn m³/d in 2021. The continuing decline in domestic production was mostly offset by higher Norwegian pipeline deliveries. Norwegian flows to the UK through Gassco infrastructure averaged 64.6mn m³/d in April-September, up from 38.8mn m³/d in summer 2023 and 63mn m³/d in 2022. By Alexandra Vladimirova Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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Mexico’s opportunity to clear energy transition woes

25/10/24

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25/10/24

Mexico’s opportunity to clear energy transition woes

New York, 25 October (Argus) — Mexico's new President Claudia Sheinbaum has a chance at the UN's Cop 29 climate conference next month to show that the country wants to catch up to the cleaner energy transition, despite her recent constitutional reforms seen as delaying the shift. With less than a month until the conference starts, it is not clear yet if Sheinbaum will attend the summit or who will be part of the Mexican delegation in Baku, Azerbaijan. The previous administration, that ended on 30 September, had planned to send the former foreign minister alongside a group of youth ambassadors for climate in Mexico. The energy ministry, led by Luz Elena Gonzalez, did not reply to Argus ' requests for information about Mexico's plans for Cop 29. Mexico's participation in previous climate summits during the administration of former President Andres Manuel Lopez Obrador had been minimal as the previous government put little effort into being well represented. Sheinbaum promised to lead the country into a fast and just energy transition. During her inauguration speech, Sheinbaum promised the country will reach 45pc renewable electricity generation by 2030 and implement an ambitious energy transition plan but she did not provide a timeline. In contrast, Sheinbaum has sent more worrying signals to private investors than positive ones because of her decision to move forward with controversial constitutional amendments that show a different picture regarding energy transition and climate. Mexico committed to reducing greenhouse gas emissions by 35pc by 2030 at Cop 27 in Egypt but energy and climate analysts say there has not been any updated information to track the advances on this pledge. "If we look at her agenda, one of Sheinbaum's priorities is the transition to clean energy before 2030," said researcher Ana Lilia Moreno at think tank Mexico Evalua. "But Sheinbaum's energy strategy proposes a centralization of the electricity sector, creating great uncertainty about the rules for the investments coming from the private sector." Private-sector renewable companies appear willing to finally put an end to the impasse experienced during the previous administration. But the energy reform approved by congress, which puts state-owned Pemex and CFE at the center of the energy sector, alongside with the amendments that will overhaul the judicial branch, create an upsetting business environment in Mexico, they say. Investors remain worried that Sheinbaum will continue with her predecessor's energy policies. But the government is committed to not destroy the private energy sector with the reform, but to complement it, said Altagracia Gomez, head of the government's business advisory council. "The priority is to strengthen Pemex and CFE but not at the expense of private companies," said Gomez. The government is now working on legal modifications to implement the reform. These changes will clarify how the government plans to ensure CFE generates 54pc of Mexico's electricity, leaving 46pc to the private sector. But investors hope to see something far away from the energy reform passed in 2021, which was defeated in the supreme court. Slow progress The share of clean electricity in Mexico's power mix was 24.3pc in 2023, according to energy ministry data. Mexico's nationally determined contribution (NDC) includes a target to increase renewables capacity to 40GW by 2030, but development of new clean energy capacity since former President Andres Manuel Lopez Obrador took office in 2018 has been limited. Mexico's total renewable capacity is around 20GW, which it will need to triple over the next six years to reach its target of 43pc of renewable energy in its generation mix by 2030. By Edgar Sigler By Mexico installed power capacity GW Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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Moldovan gas liquidity increase to be slow: BRM Est

25/10/24

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25/10/24

Moldovan gas liquidity increase to be slow: BRM Est

London, 25 October (Argus) — Gas trading liquidity on Moldova's BRM Est platform will "certainly increase" but it is likely to be a slow process, BRM Moldova country manager Ion Lupulescu told Argus . One of the main issues inhibiting stronger participation from international companies is the need for them to set up a local legal entity, which entails "considerable operational costs", Lupulescu said. This is an unnecessary condition that "complicates the process and prevents the formation of liquidity in the wholesale market", he said. The lack of fully-enacted balancing market laws is another key limiting factor for liquidity, according to Lupulescu. Moldovan transmission system operator (TSO) Vestmoldtransgaz has proposed some provisional balancing rules but many aspects are still yet to be resolved, Lupulescu said. BRM proposed that the balancing platforms used in Romania should be offered to the Moldovan TSO free of charge, but Vestmoldtransgaz is yet to make a decision on this. The use of BRM's balancing platform would simplify the process by allowing the TSO and market participants to sell and buy the required quantities in real time, according to Lupulescu. Balancing in Moldova is done at the end of the month rather than each day at present, in a "very rudimentary procedure" without a balancing platform that is open to network users, Lupescu said. This process is influenced by the working method agreed by Vestmoldtansgaz with TiraspolTransgaz, the TSO from Transnistria, he added. Full balancing legislation is scheduled to be implemented in August 2025. The provision of clearing services is also on the agenda, with these services often being seen by trading firms as critical to ensuring the viability of trading, particularly in relatively small and illiquid markets. BRM has its own clearing service in Romania but is unable to provide this to its Moldovan subsidiary because there is no Moldovan legislation to enable it, Lupulescu said. BRM plans to offer these services first on the spot market and then as soon as possible on the term market, but this will only happen when the government enables it, potentially in the second half of 2025, he said. Despite these difficulties, there are some positive signs for BRM Est liquidity for the future, notably the obligation for large companies to procure their gas on the free market from the start of 2025. This will drive the development of the retail gas market in Moldova, although liquidity will only increase if there are "more active traders on the wholesale market", Lupulescu said. Lupulescu expects Moldovan consumption to increase in the coming years, but said this will depend on investments from industrial users, economic development and energy efficiency measures, among other factors. Once Moldovan legislation aligns with EU laws, BRM hopes to start offering further services for products such as green gases and guarantees of origin, if there is market demand. The first spot transaction was carried out on BRM Est's platform on 30 September and the country's largest supplier Moldovagaz completed its first spot transactions last week . Liquidity has increased over the past five days, with around 20 GWh/d traded by companies buying gas on BRM in Romania and then trading this gas on BRM Est's spot market, Lupulescu said. Prices averaged around €39.70/MWh, he said — lower than Argus' assessment of the TTF day-ahead market which averaged €41.01/MWh on 21-24 October. By Brendan A'Hearn Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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India’s Petronet calls Dahej regas tariff “reasonable”

25/10/24

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25/10/24

India’s Petronet calls Dahej regas tariff “reasonable”

Mumbai, 25 October (Argus) — India's state-run LNG terminal operator Petronet LNG has called its regasification tariff as "reasonable" at its 17.5mn t/yr Dahej terminal on the west coast after consumers' concerns that the firm was charging one of the highest rates in the world, it said in a press conference. Petronet charges 62.91 rupees/mn Btu ($0.75/mn Btu) to regasify the fuel received at its Dahej terminal, the country's largest such facility, with plans to increase it by 5pc every year. But the firm also expects an "upward revision" to the rates going ahead, it said in a separate analyst call on 24 October. The tariff is part of the contractual obligation of capacity booking of customers, the management said, adding that the demand for natural gas in the country is not determined by regasification charges, but instead driven by international gas prices. "Even if you tweak it by 5pc or 10pc, that is not going to change the consumer pattern of natural gas," chief executive officer Akshay Kumar Singh said in the press conference. The higher tariff at Dahej terminal also compensates for lower capacity utilisation at Petronet's 5mn t/yr Kochi terminal, the board explained. The Kochi terminal has kept its capacity utilisation below 25pc since its commissioning in 2013, but the board expects the situation to improve in the coming years as the 16mn m³/d Kochi-Bangalore pipeline comes online by March 2025. Additionally, the country's gas regulatory board Petroleum and Natural Gas Regulatory Board (PNGRB) plans to lay a new pipeline south from Kochi, it announced in a separate statement issued on the same day. The bidding for the pipeline closes on 18 February 2025, the regulator added. The new project will take years to be ready, Petronet CEO Akshay Kumar Singh said in the earnings call. The southern 425-km long Kochi-Kanyakumari-Thoothukudi gas pipeline would be the crucial link between Petronet's Kochi and state-run refiner Indian Oil 5mn t/yr Ennore LNG import terminal, according to the pipeline regulator. The proposed pipeline, which has an initial capacity of 6mn m³/d, will begin from the southern state of Kerala before entering the neighbouring state of Tamil Nadu, where Indian state-controlled refiner IOC's Ennore facility is located. The pipeline will enhance the availability of natural gas in the southern part of the country, further supporting the development of the city-gas distribution business in the region, the regulator added. Most of the country's existing gas pipeline infrastructure is in the western and northern parts of the country. Kochi LNG has a 1.44mn t/yr long-term agreement for LNG from Australia's Gorgon LNG project. It may sign more term contracts for the fuel once the pipes are laid. Capacity expansion plans Petronet remains committed to commissioning the expanded 5mn t/yr capacity addition at Dahej, Singh said, adding that this would take the entire capacity of the terminal to 22.5mn t/yr by March 2025. Petronet commissioned two storage tanks , each with a capacity of 180,000 m³ at Dahej in September, taking the total to eight storage tanks. The company is also in the process of building a 2.5km jetty that can accommodate Q-Max LNG tankers as well as receive propane and ethane beside LNG, Singh added. Petronet also plans to build a new 5mn t/yr import facility in Gopalpur on the east coast, with commissioning expected by 2027, Singh said. The company is in the final stages of acquiring land from the Odisha state government and has sought bids to build a jetty, Singh said. It had previously planned for a 4mn t/yr floating storage and regasification unit but had to abandon the idea after demand for the units rose following Europe's LNG terminal capacity additions to compensate for cuts in Russian gas supplies. By Rituparna Ghosh Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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