Banks’ 2023 fossil fuel funding rises to $705bn: Study

  • Market: Coal, Natural gas
  • 13/05/24

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.


Sharelinkedin-sharetwitter-sharefacebook-shareemail-share

Related news posts

Argus illuminates the markets by putting a lens on the areas that matter most to you. The market news and commentary we publish reveals vital insights that enable you to make stronger, well-informed decisions. Explore a selection of news stories related to this one.

News
17/05/24

Brazil's Rio Grande do Sul reallocates gas supply

Brazil's Rio Grande do Sul reallocates gas supply

Sao Paulo, 17 May (Argus) — Natural gas supply in Brazil's Rio Grande do Sul had to be redistributed because of the historic floods in the state, with diesel potentially making its way back as an power plant fuel to leave more gas available for LPG production. Gasbol, the natural gas transportation pipeline that supplies Brazil's south, does not have capacity to meet demand from the 201,000 b/d Alberto Pasqualini refinery (Refap), state-controlled Petrobras' Canoas thermal power plant and natural gas distributors in the region, according to Petrobras' then-chief executive Jean Paul Prates said earlier this week. The Santa Catarina state gas distributor has adjusted its own local network to meet peak demand in neighboring Rio Grande do Sul via the pipeline transportation network. The Canoas thermal plant is running at its minimum generation at 150GW, with 61pc coming from its gas turbine. The plant was brought on line to reinstate proper power supply after transmission lines in the south were affected by the floods. Petrobras plans to use a diesel engine to increase power generation. The current approved fuel cost (CVU) for diesel in the Canoas plant is of R1,115.29/MWh. Petrobras is also operating Refap at 59pc of its maximum installed capacity, at 119,506 b/d. Heavy showers in Rio Grande do Sul since 29 April brought unprecedented flooding to the state, causing a humanitarian crisis and infrastructure damage. The extreme weather has left 154 people dead, 98 missing and over 540,000 people displaced, according to the state's civil defense. By Rebecca Gompertz Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Find out more
News

Japan’s Jera to handle 35mn t/yr LNG until FY2035-36


17/05/24
News
17/05/24

Japan’s Jera to handle 35mn t/yr LNG until FY2035-36

Osaka, 17 May (Argus) — Japan's largest LNG importer Jera plans to maintain its LNG handling volumes at no less than 35mn t/yr until the April 2035-March 2036 fiscal year. Rising renewable power supplies and the possible return of more nuclear reactors are likely to pressure LNG demand from Japan's power sector. Jera consumed 23mn t of LNG in 2023-24, down by 3pc on the year, although it handled 35mn t through its global operations during the same year. But Jera needs to secure sufficient LNG supplies to adjust for imbalances in electricity supplies and ensure power security, through more flexible operations. It is also looking to further promote LNG along with renewable electricity in Asian countries, while helping to reduce their dependence on coal- and oil-fired power generators. The 2035 target for LNG is part of Jera's three pillars of strategic focus, along with renewables as well as hydrogen and ammonia , which was announced on 16 May to spur decarbonisation towards its 2050 net zero emissions goal. The company plans to invest ¥5 trillion ($32bn) for these three areas over 2024-36. Jera also aims to retire all supercritical or less efficient coal-fired units by 2030-31 . This would help achieve the company's target of cutting CO2 emissions from its domestic business by at least 60pc against 2013-14 levels by 2035-36. By Motoko Hasegawa Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

News

Chinese importers seek five LNG cargoes for Jun-Sep


15/05/24
News
15/05/24

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.

News

Q&A: Brazil adds Asian indexation for flexible gas


13/05/24
News
13/05/24

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.

News

Sao Paulo state seeks biomethane boost


13/05/24
News
13/05/24

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.

Business intelligence reports

Get concise, trustworthy and unbiased analysis of the latest trends and developments in oil and energy markets. These reports are specially created for decision makers who don’t have time to track markets day-by-day, minute-by-minute.

Learn more