Viewpoint: Australian LNG exports to slide in 2024
Australia's LNG exports are set to decline in 2024, as an increasingly complex regulatory environment frustrates producers' plans to offset field declines by backfilling projects.
Shipments from the world's third largest seaborne gas exporter are set to fall to 81mn t in the year to 30 June 2024 and further to 79mn t in the 2024-25 fiscal year, compared with 82mn t in 2022-23, according to Australia's Office of the Chief Economist.
Australian independent Woodside Energy is likely to take one 2.5mn t/yr train of its five-train, 16.9mn t/yr North West Shelf LNG off line in 2024, while fellow domestic operator Santos' 3.7mn t/yr Darwin LNG will sit idle as it prepares for backfill from the $3.6bn Barossa field, scheduled for first gas in 2025.
But the firms, Australia's largest listed gas exporters, face headwinds as they grapple with an environmental movement aiming to curtail Australia's fossil fuel exports.
Litigation by climate activists has delayed Barossa and the $12bn Scarborough field, Woodside's Carnarvon basin project to fill a second 5mn t/yr train at Pluto LNG.
Barossa's field drilling and laying of most of the gas export pipeline (GEP) have been paused all year, following a federal court ruling that Santos must hold consultations with native title holders regarding underwater cultural heritage.
A challenge to the Barossa GEP environmental plan (EP) is likely to lead to a delay in Barossa's completion, with Santos previously advising that first gas during the first half of 2025 was contingent on completing the laying of the GEP in 2023 and commencing drilling activities. It now appears neither can proceed before January 2024.
But Woodside received fresh approvals for seismic testing at Scarborough on 1 December.
Both firms have appealed for legislation to clarify EP requirements. But "times have changed" and industry must improve consultation and engagement, federal Labor resources minister Madeleine King has said. This is despite the government promising a review of offshore regulations. King's office has not detailed a timeline for the conduct of the review.
In a year marked by significant policy interventions in the energy market, Canberra also announced changes to taxes on gas export profits which are yet to pass parliament, with both the centre-right opposition Coalition and left-wing Green Party calling for compromises to pass the bill in 2024.
Australia's three east coast LNG projects will likely see supplies of onshore coal-bed methane rise after three consecutive La Nina years caused wet weather disruptions, with a 9pc forecasted rise in January-March exports.
Upstream production at Santos' 7.8mn t/yr Gladstone LNG reached a record 692 TJ/d in January-June 2023, while the upstream operator of the 9mn t/yr Australia Pacific LNG recently said output would be at the upper end of the 680-710PJ estimate for the year to 30 June 2024.
But with southern Australia increasingly reliant on Queensland gas owing to field depletion in Victoria's Bass Strait, the federal government could seek further domestic supply under its Domestic Gas Security Mechanism, despite recently securing 300PJ of extra gas until 2030
The Northern Territory (NT) government's approval of hydraulic fracturing in May has led to the commissioning of an engineering study for the proposed 6.6mn t/yr NTLNG plant — likely to be completed in the first half of 2024.
Fellow NT independent Empire Energy is aiming for a final investment decision on its 25 TJ/d Carpentaria pilot project early next year. But construction remains contingent on establishment of commercial flow rates from the untapped Beetaloo gas basin.
Elsewhere in the region, the 5.6mn t/yr Papua LNG in Papua New Guinea (PNG) is likely to reach final investment decision in early 2024 ahead of an early 2028 production start, while the 6.9mn t/yr ExxonMobil-operated PNG LNG facility expects to receive first gas from the Angore field in 2024.
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Chinese importers seek five LNG cargoes for Jun-Sep
Chinese importers seek five LNG cargoes for Jun-Sep
Shanghai, 15 May (Argus) — Five Chinese importers, mostly second-tier buyers, are each seeking one LNG cargo for June-September delivery, according to an official notice published by China's national pipeline operator PipeChina on 15 May. The five importers are PipeChina, Chinese independent ENN, Hong Kong-listed city gas firm China Resources Gas, Hong Kong-based Towngas and state-owned China Gas. PipeChina and ENN have indicated a target price of at most $9.50/mn Btu for their intended cargoes, both for delivery to PipeChina's 6mn t/yr Tianjin terminal. China Gas has indicated a target price of at most $9.30/mn Btu for delivery to PipeChina's 6mn t/yr Beihai termial. China Resources Gas and Towngas have both indicated a target price of at most $9/mn Btu for delivery to PipeChina's 2mn t/yr Yuedong and Tianjin terminals, respectively. This consolidated requirement came about because of a need for PipeChina to better leverage on its infrastructure advantages and, at the same time, meet the varying needs of gas importers and consumers in the country. But this requirement comes at a time when spot LNG prices are still somewhat higher than the importers' targeted prices. But the importers can choose not to buy if offers are not within their expectations. The front-half month of the ANEA, the Argus assessment for spot LNG deliveries to northeast Asia, was last assessed at $10.485/mn Btu on 15 May. Chinese importers mostly perceive spot prices below $9-9.50/mn Btu for June-September deliveries to be unattainable for now because there is strong buying interest from south and southeast Asia in particular. Indian state-controlled refiner IOC most recently bought LNG for delivery between 22 May and 15 June at around $10.60/mn Btu, through a tender that closed on 14 May. Thailand's state-controlled PTT most recently bought three deliveries for 9-10 July, 16-17 July and 22-23 July through a tender that closed on 13 May , at just slightly above $10.50/mn Btu. The most recent spot transaction was Japanese utility Tohoku Electric's purchase of a 10-30 June delivery at around $10.55/mn Btu through a tender that closed on 14 May . This is at least $1/mn Btu higher than Chinese importers' indications. Summer requirements have so far been muted but concerns among buyers about potential supply disruptions remain. Malaysia's 30mn t/yr Bintulu LNG export terminal suffered a power loss on 10 May, but this issue may have been resolved as of early on 15 May, according to offtakers. Some unspecified upstream issues may still be affecting production at the Bintulu facility, resulting in Malaysia's state-owned Petronas having to ask some of its buyers for cargo deferments, according to offtakers. Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Q&A: Brazil adds Asian indexation for flexible gas
Q&A: Brazil adds Asian indexation for flexible gas
Sao Paulo, 13 May (Argus) — Three years after the natural gas market liberalization in Brazil, the number of consumers migrating from regulated supply has slowly increased and more flexible pricing mechanisms adopted. Argus spoke to Alessandro di Domenico , president of gas and power trader Delta Geração, about the current state of the market. Excerpts follow. Explain Delta's supply contract with Bolivia through 2026 despite Bolivia's gas production decline. The decline in production will happen because there is less investment [in Bolivia] than a few years back. But there are still some volumes that can supply the Brazilian market, especially in flexible contracts in the liberalized market. There is some gas that was being directed to Argentina and is now available. Even with the decline in Bolivia production, we will continue to have natural gas in the short-term. Besides that, the Rota 3 pipeline project [in Brazil's southeast] is close to being completed, which will bring more gas from pre-salt fields, leaving the market with more supply. This boosts the growth of the liberalized market. Delta is positioning itself to meet those demands and will sign other supply contracts soon. What types of contracts has Delta and others signed in the liberalized market? These are interruptible contracts. Their innovation relies on flexibility. Volume and duration are flexible. This allows us to meet clients almost back-to-back. How are these flexible contracts priced? They are competitive with the regulated market and are connected to international parity prices. Contracts are using Brent, Henry Hub and [Japan-Korea marker LNG spot prices]. How has the market progressed since 2021? This market was born rigid and is now gaining flexibility, in baby steps. In the beginning, there were only three consumers: Acelen, Brazilian steelmaker Gerdau and petrochemical group Unigel. Now we have companies in the cellulose business, metallurgy and automotive industry, which are all gas-intensive. So, in the future, there will be a big movement depending on state regulations, because that is an important axis of articulation for the mobility the liberalized market requires. State regulations play a very important role in allowing smaller entities to enter the market. By Rebecca Gompertz Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Sao Paulo state seeks biomethane boost
Sao Paulo state seeks biomethane boost
Sao Paulo, 13 May (Argus) — Brazil's Sao Paulo state is seeking to capitalize on growing demand for renewable energy, announcing a series of measures to increase biogas and biomethane production across various sectors, including sugarcane, waste management firms and waste agriculture. As Brazil's largest sugar and ethanol producing state, Sao Paulo has substantial potential to leverage existing infrastructure and resources — especially vinasse, a byproduct of ethanol production — to increase biomethane output. To boost output, the state government will streamline environmental licensing for new projects through new rules that should attract investment, according to the state's environment undersecretary for energy and mining, Marisa Barros. The focus will initially be on the sugar and ethanol industry, which can produce 30mn m³/d of biogas. Biogas contains 50pc methane, which can be processed into biomethane, a drop-in substitute for natural gas. The state is also seeking to attract investment in biogas production from animal waste, which can produce up to 5mn m³/d. The government estimates that roughly 190,000 farms in the state can install biodigestors to produce biogas, which would contribute to lower emissions in the state. The state agriculture secretary also approved the use of the Sao Paulo agribusiness expansion fund (Feap) for investments in biodigestors as well as new solar power installations. And earlier this year state regulatory agency Arsesp stipulated a discount on distribution fees for biomethane sold on the wholesale market. Brazil's energy research company EPE sees significant potential for the sugarcane industry to expand biomethane production, in part because it has the advantage of having many mills adjacent to existing gas distribution infrastructure. In addition to selling the renewable gas on the wholesale market, many mills are using biomethane in their own operations and to substitute diesel in their trucks and machinery, contributing to lower fuel costs and emissions. Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Banks’ 2023 fossil fuel funding rises to $705bn: Study
Banks’ 2023 fossil fuel funding rises to $705bn: Study
London, 13 May (Argus) — Fossil fuel financing by the world's 60 largest banks rose to $705bn in 2023, up by 4.8pc from $673bn in 2022, with the increase largely driven by financing for the LNG sector. This brings the total funding for fossil fuels since the Paris agreement was signed in 2015 to $6.9 trillion. The 15th annual Banking on Climate Chaos (BOCC) report was released on 13 May by a group of non-governmental and civil society organisations including the Rainforest Action Network and Oil Change International, and it analyses the world's 60 largest commercial and investment banks, according to ratings agency Standard and Poor's (S&P). Funding had previously dropped in 2022 to $673bn from $742bn in 2021, but this was because higher profits for oil and gas companies had led to reduced borrowing. JPMorgan Chase was the largest financier of fossil fuels in 2023 at $40.9bn, up from $38.7bn a year earlier, according to the report. It also topped the list for banks providing financing to companies with fossil fuel expansion plans, with its commitments rising to $19.3bn from $17.1bn in 2022. Japanese bank Mizuho was the second-largest financier, increasing funding commitments to $37bn for all fossil fuels, from $35.4bn in 2022. The Bank of America came in third with $33.7bn, although this was a drop from $37.3bn a year earlier. Out of the 60 banks, 27 increased financing for companies with fossil fuel exposure, with the rise driven by funding for the LNG sector — including fracking, import, export, transport and gas-fired power. Developers have rallied support for LNG projects as part of efforts to boost energy security after the Russia-Ukraine war began in 2022, and banks are actively backing this sector, stated the report. "The rise in rankings by Mizuho and the prominence of the other two Japanese megabanks — MUFG [Mitsubishi UFG Financial Group] and SMBC [Sumitomo Mitsui Banking] — is a notable fossil fuel trend for 2023," the report said. Mizuho and MUFG dominated LNG import and export financing, providing $10.9bn and $8.4bn respectively, to companies expanding this sector. Total funding for the LNG methane gas sector in 2023 was $121bn, up from $116bn in 2022. Financing for thermal coal mining increased slightly to $42.2bn, from $39.7bn in 2022. Out of this, 81pc came from Chinese banks, according to the report, while several North American banks have provided funds to this sector, including Bank of America. Some North American banks have also rolled back on climate commitments, according to the report. Bank of America, for example, had previously committed to not directly financing projects involving new or expanded coal-fired power plants or coal mines, but changed its policy in late 2023 to state that such projects would undergo "enhanced due diligence" and senior-level reviews. The report also notes that most banks' coal exclusions only apply to thermal coal and not metallurgical coal. Total borrowing by oil majors such as Eni, ConocoPhillips, Chevron and Shell fell by 5.24pc in 2023, with several such as TotalEnergies, ExxonMobil and Hess indicating zero financing for the year. The BOCC report's finance data was sourced from either Bloomberg or the London Stock Exchange between December 2023 and February 2024. UK-based bank Barclays, which ranks ninth on the list with $24.2bn in fossil fuel funding, said that the report does not recognise the classification of some of the data. Its "financed emissions for the energy and power sectors have reduced by 44pc and 26pc respectively, between 2020-23," it said. In response to its increase in financing for gas power, "investment is needed to support existing oil and gas assets, while clean energy is scaled," the bank said. By Prethika Nair Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
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