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Cop 29 president Babayev sets out summit action plan

  • Market: Emissions, Natural gas
  • 20/09/24

The goals might be broadly welcomed, but climate groups want to see progress on fossil fuel consumption, writes Georgia Gratton

The president-designate of the UN Cop 29 climate summit, Azeri ecology and natural resources minister Mukhtar Babayev, this week set out 14 initiatives and a detailed agenda for the conference, drawing little-addressed topics into the spotlight, but skating over some of last year's Cop outcomes.

Most tangibly, Babayev's letter, sent to parties to UN climate body the UNFCCC, listed a handful of pledges that echo the broadly popular declarations launched at last year's Cop 28 by that summit's UAE presidency.

Babayev set out a two-pronged declaration, which seeks to scale up global energy storage capacity to 1.5TW by 2030 and add or refurbish more than 80mn km of power grid by 2040. A separate proposed pledge aims to "commit to green energy zones and corridors", to maximise sustainable energy generation and ensure "cost-effective transmission over large distances and across borders". And the summit will aim to tackle the barriers — including regulatory, technical and financial ones — to a global "clean hydrogen" market.

The Cop 29 presidency also aims to address "the growing problem of methane from organic waste", it said. Methane — a potent greenhouse gas — is often a focus at Cop summits, although typically with an eye to the largest emitters, the agriculture and fossil fuel industries. Global methane emissions from agriculture and fossil fuels stood at 142mn t and 118mn t, respectively, in 2023, whereas waste was responsible for 71mn t, IEA data show.

Babayev wants governments to commit to targets to cut methane from organic waste and more countries to sign the Global Methane Pledge. The pledge, launched in 2021 at Cop 26, asks signatories to cut methane emissions by at least 30pc by 2030, from 2020 levels. Azerbaijan signed the pledge in March this year.

These goals are likely to be broadly welcomed, but environmental groups will also be watching for progress on fossil fuel consumption. Babayev's letter avoided mention of the key agreement reached at last year's Cop 28 — to transition away from fossil fuels — although it did make multiple references to the first global stocktake, the main outcome document from Cop 28.

Feeling the heat

Azerbaijan is a natural gas exporter, and keen to build on this. The majority of the country's income is from the energy sector, with oil and gas accounting for 90pc of exports and a third of its GDP, according to the World Bank, which lists Azerbaijan among the countries that have most to lose from the transition.

Babayev noted that Cop 29 — set for 11-22 November in Baku — will be the first Cop hosted in the Caucasus region. He flagged the "extreme heat [and] water scarcity" the region faces, but also pointed to its wind and solar power potential. And he provided more details of a planned $1bn climate fund, which will be capitalised by fossil fuel-producing countries and companies.

"We believe that countries rich in natural resources should be at the forefront of those addressing climate change," Babayev said, noting that the direction came from Azerbaijan's president, Ilham Aliyev. The fund will be a public-private partnership, with "concessional and grant-based support to rapidly address the consequences of natural disasters" in developing countries, Babayev said. It will "provide offtake agreement guarantees for small and medium-sized renewable energy producers and first-loss capital for green industrial projects", with a focus on food and agriculture, he said.

Babayev has already said climate finance will be the "centrepiece" in Baku. The planned fund, and any other advances on climate finance, are likely to prove the mark of success for Cop 29.


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25/10/24

Pennsylvania drilling drops to 17-year low

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
News
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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Moldovan gas liquidity increase to be slow: BRM Est


25/10/24
News
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
News
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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World on track for ‘catastrophic’ temperature rise: UN


24/10/24
News
24/10/24

World on track for ‘catastrophic’ temperature rise: UN

London, 24 October (Argus) — The world is set for a "catastrophic temperature rise" of up to 3.1°C above pre-industrial levels, unless there is a "G20-led massive global mobilisation to cut all greenhouse gas (GHG) emissions", the UN Environment Programme (Unep) said today in its Emissions Gap 2024 report. It is still "technically possible" for the world to meet the 1.5°C temperature goal set out in the Paris climate agreement, but only with significant effort, the report found. If current commitments for 2030 are met, temperature rise would be limited to 2.6°C-2.8°C above pre-industrial levels. The Paris agreement seeks to limit warming to "well below" 2°C and preferably to 1.5°C. The 2.6°C scenario is based on the "full implementation" of countries' current national climate plans, known as nationally determined contributions (NDCs). But "continuing with current policies only would lead to 3.1°C of warming", Unep said. Countries are due to submit updated NDCs, which would cover a timeframe up to 2035, by February next year. And they "must collectively commit to cut 42pc off annual GHG emissions by 2030 and 57pc by 2035… and back this up with rapid action" in the next round, or the 1.5°C goal "will be gone within a few years", Unep said. The emissions cuts needed are relative to 2019 levels, but GHG emissions reached a record high of 57.1bn t/CO2 equivalent (CO2e) in 2023. To get on track to keep global warming below 2°C, GHG emissions must fall by 28pc by 2030 and 37pc by 2035, both from a 2019 baseline, the report found. The global average temperature for the 12 months from October 2023 to September stood at around 1.62°C above the pre-industrial average, according to EU earth-monitoring service Copernicus. It is "almost certain that 2024 is going to be the warmest year on record", Copernicus added. Invest and implement To ensure that warming is limited to below 2°C by 2030, annual emissions should be 14bn t/CO2e lower than the rate implied by current unconditional NDCs. This refers to elements of the plan that a country pledges to carry out with no external support, whether technical or financial. To hit the target of limiting warming to 1.5°C, annual emissions should be 22bn t/CO2e lower than current unconditional NDCs suggest over the same timeframe. There is "technical potential" for GHG emissions cuts of up to 31bn t/CO2e and 41bn t/CO2e in 2030 and 2035, respectively, the report found. This would "bridge the gap to 1.5°C in both years", and cost less than $200/t of CO2e, it added. Increased deployment of solar and wind power could provide 27pc of the total GHG reduction potential in 2030 and 38pc in 2035, Unep said. And "action on forests" — which are key carbon sinks — could deliver around a fifth of the potential in both timeframes, it added. Electrification and efficiency measures in the transport, buildings and industry sectors would also cut GHG emissions. But a "minimum six-fold increase in mitigation investment" is needed for the world to reach net zero emissions, the report found. The estimated incremental investment is between $900bn and $2.1 trillion annually over 2021-50. This would "bring returns in avoided costs from climate change, air pollution, damage to nature and human health impacts", Unep said. Members of the G20 group of countries, which are responsible for the majority of global emissions, are off track to meet their current goals and must "take the lead by dramatically increasing action and ambition" in new NDCs, Unep said. G20 members, without the recent addition of the African Union as a permanent member, accounted for 77pc of emissions in 2023. The outlook has worsened since last year's Emissions Gap report, which flagged a temperature rise of 2.5°C-2.9°C. By Georgia Gratton Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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