Gazprom cuts supply to some Turkish private importers
Russia's state-owned Gazprom yesterday cut gas deliveries to all Turkish private-sector importers except Bosphorus Gaz and Shell's Turkish subsidiary because of arbitration-related payments, market participants said.
Gazprom said in its most recent financial prospectus published in late June that it is currently part of proceedings involving Akfel Gaz, Kibar Enerji and Enerco Enerji. None of the firms were available for comment.
A Swedish court in June dismissed Akfel's appeal against a Stockholm arbitration ruling on a price revision in its long-term Russian gas contract, while Enerco's appeal is listed for 7-10 September. No hearing dates have been agreed so far for Kibar, Avrasya and Bati Hatti's appeals.
Akfel Gaz, Bosphorus Gaz, Kibar Enerji and Shell Enerji imported a combined 200.4mn m³ from Russia in April, with Botas receiving the rest of total Russian receipts of 2.51bn m³, data from regulator EPDK show.
Avrasya Gaz last imported Russian gas in March, while Bati Hatti and Enerco have not received any Russian gas since January 2019 and December 2018, respectively.
Seven private companies and Botas have long-term contracts with Gazprom for a total of 14bn m³/yr through the Turkish Stream line, of which 8bn m³/yr will expire by the end of this year. Negotiations are still ongoing with no outcome so far, market participants said.
Private-sector receipts have been below combined take-or-pay obligations of 11.2bn m³/yr in recent years. They were 4.14bn m³ last year, excluding a minimal amount of spot supply.
Only Bosphorus Gaz and Shell Enerji exceeded their take-or-pay obligations last year. The former received 2.29bn m³ in 2020 out of its 2.5bn m³/yr long-term contract with Gazprom, while the latter imported 213mn m³ under its 250mn m³/yr deal.
Botas wants to buy gas from private sector
Botas at the beginning of this week requested offers from private-sector companies for gas supply until the end of the year.
But Gazprom cutting deliveries to some private-sector companies would leave the private sector with less gas available for sale.
Offers were expected to be slightly above Russian import costs, market participants said.
Botas had imported 4bn m³ by mid-June — the full annual amount under its contract for deliveries through the line — and is now taking make-up gas through the Turkish Stream line, some market participants said.
The slowdown in Russian imports has coincided with limited Iranian receipts over maintenance, slower Azeri take since mid-April following the expiration of Botas' 6.6bn m³/yr contract for gas from the Shakh Deniz 1 and weak LNG deliveries.
And less gas imported by the private sector comes at a time of strong anticipated demand. Market participants expect high gas demand from the power sector to continue until the end of the year, thanks to lower hydroelectric reserves and high overall power demand.
To offset this, Botas has launched an LNG tender for 15 cargoes for August-December. Botas' supply share to utilities has increased since June.
And Turkish companies may be able to take some additional Azeri supply, with the Turkish regulator offering spot import capacity at Azeri entry points for August only and August-December on 28 July.
Import capacity of 2.93mn m³/d will also be offered for August at Malkoclar on the Turkish-Bulgarian border.
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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.
APA defers FID for Australian gas pipeline's stage 3
APA defers FID for Australian gas pipeline's stage 3
Sydney, 13 May (Argus) — Australian pipeline operator APA has deferred a final investment decision (FID) for stage 3 of its planned east coast grid expansion, given potential rule changes for the South West Queensland pipeline (SWQP). APA is pushing back the FID by about 6-12 months to the first-half of 2025, and was likely initially planning to make the FID this year. The operator postponed the FID because of recent action by the Australian Energy Regulator (AER), which said it might recommend rule changes for the SWQP. A review was announced in February and is not expected to be completed until November at the earliest, APA said. The firm opposes any further regulation of the SWQP , maintaining that it does not return excessive profits. APA said the lack of a single arbitration case involving the facility since such a regime was instituted in 2017 is evidence that its customers accept present arrangements. "We've probably got around six to 12 months at the very most for us to work through and hopefully there's no change to regulation, but basically the time frame is we need to get started pretty much early next year on building stage 3," APA's chief executive Adam Watson said on 9 May. If the AER decides to make the lightly regulated SWQP subject to reference price regulation, an access arrangement would need to be determined which will take 2-3 years to complete, APA said. This means any changes would be instituted in the fiscal year to 30 June 2028. The SWQP can carry 440 TJ/d (11.75mn m³/d) in a westerly direction from Wallumbilla to the Moomba hub, from where gas can enter the APA-operated Moomba-Sydney and Epic Energy-owned Moomba-Adelaide pipelines for transport to southeastern facilities. Expanding the capacity of pipelines allowing the north-south transit of gas is considered critical to avoiding shortfalls owing to the depletion of Gippsland basin fields this decade. Stage 1 of APA's east coast grid expansion was completed in 2023, with stage 2 also now operational in line with guidance. These two stages increased capacity by 25pc, allowing about 50 TJ/d more gas to flow on the SWQP to southern markets, with similar increased volumes expected from stages 3 and 4. By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
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