First Trans-Balkan Pipeline gas auction tomorrow

Spanish Market: Natural gas
28/05/25

The first monthly auction for the integrated capacity product on the Trans-Balkan Pipeline will be held on 29 May, the transmission system operators (TSOs) of Ukraine, Moldova, Romania, Bulgaria and Greece jointly announced this morning.

The integrated capacity product, which the operators are naming Route 1, will be offered as a "special" product for June-October in order to help Ukraine reach its goal of importing roughly 5bn m³ of gas in preparation for the next heating season. The Route 1 product will bundle together capacity at Kulata/Sidirokastro, Negru Voda/Kardam, Isaccea/Orlovka, Kaushany and Grebenyky. Users will not be able to access national virtual trading points (VTPs) or national exit points in the countries along the route, except for Ukraine. Firms must have obtained licenses allowing for access to the transmission systems in all five countries in order to be eligible.

The first auction for this new product, covering the month of June, will take place on 29 May at 07:00 UTC (07:00 GMT) on the Regional Booking Platform, offering just over 31 GWh/d of capacity. Subsequent auctions will take place on the fourth Monday of each of the following months. The allocation mechanism will be a Uniform Price Auction, and the cost will be the sum of the monthly reserve prices applied by each of the operators at the relevant interconnection points, discounted by 25pc at all points except Isaccea entry, Kaushany exit and Grebenyky entry, where a 46pc discount is already applied by the Ukrainian TSO. The amount of capacity to be offered at subsequent auctions will be the minimum available firm capacity at each of the interconnection points along Route 1 after completion of the rolling monthly auctions that take place on the third Monday of each month. If any relevant point's monthly auctions are still ongoing at the start of the fourth Monday, the Route 1 auction will be cancelled.

Holders of Route 1 capacity must cumulatively nominate at the Greek entry points of Agia Triada, Nea Mesimvria, Amfitriti and Kipi at least as much as they notify Greek TSO Desfa they intend to deliver to Ukraine. Otherwise, Desfa will approve the lesser of the sum of the entry nominations at these points and the volume notified by the user to Desfa. These rules specifically prohibit entry nominations at Kulata/Sidirokastro, where Greek buyers of Russian gas import their supply, from being counted for use in the Route 1 product and do not allow nominations from the Greek VTP. Several trading firms suggested these rules significantly favour physical LNG importers, dominated by just a few large companies in Greece.

The route's indicative reserve price is €6.15/MWh, excluding volume fees, and roughly €7.00/MWh after accounting for the fees. But this price does not include the LNG regasification and entry costs of the Revithoussa and Alexandroupolis terminals.

At the most recent close, Argus assessed the Greek day-ahead price at a €6.48/MWh discount to its Slovak counterpart, suggesting that after accounting for tariffs in Slovakia, there would be a greater price incentive to use the Route 1 product than to export from Slovakia at Budince. But Argus does not assess Greek front-month prices, meaning this calculation is not fully representative of the calculations that firms may be doing for the auctions on 29 May.

The introduction of the new product is expected to increase utilisation of the regional TSOs' existing infrastructure, which in turn should raise revenues for the operators and "thus lead to a reduction in transportation tariffs to the benefit of users", the TSOs said.

By Brendan A'Hearn

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02/06/25

India’s Torrent Power signs LNG supply deal with BP

Mumbai, 2 June (Argus) — India's Torrent Power has signed a long-term LNG deal with BP, with Torrent receiving six LNG cargoes a year in 2027-36 under a tender that was issued in July 2024, sources tell Argus . This is BP's first LNG supply deal with an Indian major, which is heard to be priced at 10.99pc slope to Brent, the lowest heard for India in the recent years, sources said. Torrent Power will receive a total of 410,000 t/yr of LNG on a delivered basis at the 17.5mn t/yr Dahej LNG terminal on India's west coast, assuming an LNG cargo of 68,000t. Under the deal, BP will supply cargoes mostly during the summer, with an option that allows Torrent Power to adjust the volume and timing of deliveries. Torrent Power is set to utilise two cargoes each for its gas-based power generation with a combined capacity of 2730MW, a city gas distribution business under Torrent Gas, as well as merchant power and gas trading, sources close to the deal said. The firm was last in the market seeking 14 LNG cargoes for delivery in July 2025-May 2030 in a tender that is scheduled to close on 4 June. The combined deals would help Torrent Power to secure its overall gas needs to meet peak power demand during the summer. BP is set to secure supplies for the deal from its 3.4mn t/yr Coral South FLNG offshore Mozambique and from Oman LNG's 11.4mn t/yr Qalhat facility, sources added. The deal is likely to bolster BP's expansion in India's gas market, especially as its exploration business with Reliance Industries (RIL) weakens as output has started to decline from the KG-D6 eastern offshore block, which produces a third of India's domestic natural gas. RIL reported output from KG-D6 at 26.7mn m³/d in January-March, down by 11pc on the year and by 5pc on the quarter, as per its latest earnings presentation. In a separate deal, BP is also set to supply 4-6 LNG cargoes a year to India Gas Solutions (IGS), another joint venture with RIL that focuses on sourcing, marketing and transporting natural gas in India, sources tell Argus . LNG supplies under the deal are expected to start in 2028, wherein IGS would use Torrent Power's regasification capacity at the Dahej import terminal to import the cargoes, it added. IGS is currently marketing and contracting domestic HPHT gas from RIL's KG-D6 block to downstream city gas distribution entities. LNG supplies under IGS are expected to be redirected towards RIL's 1.36mn b/d Jamnagar refinery, which receives 7-8mn m³/d of HPHT gas from the KG-D6 block. By Rituparna Ghosh Send comments and request more information at [email protected] Copyright © 2025. Argus Media group . All rights reserved.

Australia will not impose retrospective gas reservation

02/06/25

Australia will not impose retrospective gas reservation

Sydney, 2 June (Argus) — Any domestic gas reservation system imposed on Australia's eastern market will not be imposed on existing projects, energy minister Chris Bowen said, as Australia moves closer to importing LNG to its southern states ahead of a forecast supply gap. The federal government is reviewing a suite of policies on capping prices and restricting exports on a quarterly basis in 2025 to address the upcoming gas shortage, and this review may recommend a reservation policy on new gas fields. Australia's opposition party, which lost the 3 May election, had proposed taxing spot LNG exports from the three projects operating at Gladstone harbour on Australia's Pacific coast as part of efforts to limit exports and reserve more gas for the domestic market. But such a policy would not be adopted by the re-elected Labor government, the energy minister told ABC television on 1 June. "We have a very clear matter of principle that we don't agree with sovereign risk, we don't agree with retrospective policy actions," Bowen said. The comment comes after Victoria state, which has discouraged the use and drilling of gas in recent years, approved a proposal by Australian refiner Viva Energy to build an LNG import terminal near its existing facilities near the city of Geelong. Weaker gas consumption and a series of subsidies to keep coal-fired power stations operating for longer in southern states has improved the eastern grid's supply for the next four years, the Australian Energy Market Operator said in March. Australia's most advanced import facility, the 130 PJ/yr (3.4bn m³/yr) Port Kembla Energy Terminal operated by Squadron Energy, will now begin operating in 2027 at the earliest , with the 170,000m³ Hoegh Galleon floating storage and regasification unit to remain in service in Egypt until May 2026. By Tom Major Send comments and request more information at [email protected] Copyright © 2025. Argus Media group . All rights reserved.

ExxonMobil upbeat over Guyana arbitration

31/05/25

ExxonMobil upbeat over Guyana arbitration

New York, 31 May (Argus) — ExxonMobil is confident of prevailing in an international arbitration case over a share of Guyana's vast offshore oil riches that has pitted the top US major against smaller rival Chevron. "We are confident the judges will go in our favour," senior vice-president Neil Chapman said as the private hearing wrapped up in London last week. The three-person arbitration panel at the International Chamber of Commerce is expected to give its ruling within two to three months in relation to the contractual dispute that has held up Chevron's pending $53bn acquisition of US independent Hess. Speaking at the Bernstein 41st Annual Strategic Decisions Conference in New York last week, Chapman said such contractual disputes are not uncommon in the oil industry, but they are normally resolved in private. ExxonMobil is the operator with a 45pc stake in the Stabroek block off the coast of Guyana, where an estimated 11bn bl of oil equivalent have been discovered over the past decade. Both it and Chinese state-controlled CNOOC, which has a 25pc holding, have asserted a right of first refusal over the 30pc interest owned by Hess. That stake is the key attraction in Chevron's planned takeover of Hess, which will address concerns over the company's long-term growth prospects and help narrow a gap with ExxonMobil. The case is also being closely watched by oil and gas lawyers and could have a bearing on how future contracts are drawn up. Hess and Chevron have argued that a right of first refusal does not apply in the event of a corporate takeover. The arbitration has delayed the takeover, which has already won approval from US anti-trust regulator the Federal Trade Commission as well as Hess shareholders. ExxonMobil's Chapman played down concerns about whether relations with the other parties would suffer as a result of the long-running squabble. Hess has been a "very good partner" in Guyana and "in terms of operations, in terms of investments, we're 100pc aligned", he said. Fight for your right ExxonMobil argues that little would change if Hess ended up winning the arbitration case and Chevron went on to complete its acquisition. "We believe strongly you have to protect your contractual right, the Chinese believe the same thing and that's why we went to arbitration," Chapman said. "If the judges decide that's not the case, then we get a new partner," he added. Under such a scenario, it would be business as usual. "We have partnerships with Chevron all over the world. It's been no change in terms of how we're working together at all," Chapman said. Chevron has previously warned that the Hess acquisition could be derailed if the arbitration case sides with ExxonMobil.But such is Chevron's optimism that it will close the deal that the company snapped up almost 5pc of Hess shares at a discount on the open market in the first quarter. The move reflects Chevron's conviction in "our confidence in the successful arbitration outcome", chief financial officer Eimear Bonner said in March. Chevron's chief executive Mike Wirth has similarly expressed confidence in Hess' position on a number of occasions. "This has been studied extensively, and we feel like they clearly have the right side of this argument, and we look forward to closing the deal," he said earlier in the year. Hess' core argument is that such pre-emption rights do not apply because of the structure of the merger and language in the relevant clause. "Chevron and Hess believe that ExxonMobil's and CNOOC's asserted claims are without merit," Hess said in a filing in April, adding that it plans to "vigorously defend" its position before the tribunal. By Stephen Cunningham Guyana: Stabroek block Send comments and request more information at [email protected] Copyright © 2025. Argus Media group . All rights reserved.

Uncertainty prevails over unbooked German gas storage

30/05/25

Uncertainty prevails over unbooked German gas storage

London, 30 May (Argus) — German gas storage bookings for the current storage year have picked up in recent weeks, but large volumes of unbooked space combined with an unclear role of the state leave big question marks over the filling campaign this summer. Germany started the storage year with at least 107TWh of unbooked storage capacity, out of a technical capacity of 247TWh ( see data and download ). An inverted THE summer 2025-winter 2025-26 spread through most of the winter created no incentive to book capacity. But storage bookings have picked up in recent months, especially in May, with about 12.2TWh of storage space booked during the month, up from 5.5TWh in April and about 350GWh in March ( see bookings graph ). The THE summer 2025-winter 2025-26 spread has normalised since the beginning of April, which has re-established an incentive for traders to book storage space ( see prices graph ). In addition, the German government at the beginning of May lowered the legal 1 November fill level mandate to 80pc for most sites and 45pc for some slow-cycling aquifer sites and depleted fields. A lower stockfill mandate has contributed to the increased attractiveness of storage space, as it affords more flexibility to capacity holders. What happens with unbooked capacity? There remains at least 88.6TWh unbooked despite the uptick in bookings, and it remains unclear who would fill the space if it remains unsold. The German gas storage act stipulates that German market area manager THE can book storage space if needed to fill gas storage sites to the legal level as a last resort. The Inzenham, Wolfersberg and Frankenthal sites remain completely unbooked so far, and THE may have to book some space to hit the 1 November target, according to current legislation. THE has previously confirmed to Argus that it will only intervene at the point at which it is physically impossible for the market to fill the storage site on its own terms even if injecting at capacity. In addition, THE may treat unbooked capacity at partially booked sites separately to allocated space. Most storage contracts pass on the storage targets to each capacity holder, suggesting that targets may still be missed at partially booked sites if firms only inject to the legal minimum. Remaining unbooked capacity at sites would then also have to be filled to 80pc or 45pc to ensure compliance with the site's target. It is also unclear what injection capacity THE could make use of in the case of partially-booked sites, in order to fill unbooked space. If THE can take over all a site's injection capacity, it could start injecting considerably later than if it could only use the injection capacity proportionally allocated to the unbooked space. In the latter case, the market area manager would have to start intervening soon at some storage sites. At the 11.5TWh Breitbrunn site — a slow-cycling site with an 80pc target because of its location in Bavaria — THE might have to step in around mid-June to reach 80pc by 1 November for the 5.31TWh unbooked capacity, assuming an injection curve for the site in line with the German average as provided by Entsog. The site is currently filled to about 24pc of capacity, or 50pc of all booked capacity at the site, according to GIE transparency data. The largest source of market uncertainty remains the 44.7TWh Rehden site, where only 894GWh is booked for the current storage year. The site now makes up about 50pc of unbooked storage space in Germany, and only 2pc of the site's capacity is allocated. THE would have to start filling the site in mid-August to reach the 45pc target, taking Rehden's specific injection curve and 18.5 days of maintenance in October into account. But the German state has made a lot of noise recently that it does not want the market to rely on the state to fill storage this summer. But at the same time, THE's legal requirement to fill storage if market parties fail to do so remains intact, the market area manager confirmed to Argus recently. Possible injections profiles point to remaining risk for 3Q tightness Germany's cavern-heavy storage profile allows firms to delay a large part of storage injections far into the third quarter, especially if the market and state continue their "game of chicken" over unbooked capacity. Germany needs to inject about 77.6TWh before 1 November to hit its target for every site, with five sites already above target, which would equate to a 500 GWh/d injection rate if spread evenly over the summer. The forward curve suggests an incentive to boost injections early in the summer, but it would be technically possible to delay 70TWh of injections until after 1 August and even 32.3TWh after 1 October, taking the Entsog average injection curve for each storage site ( see theoretical injections profile graph ). In that case, it would be theoretically possible for injection demand to peak at 2.6 TWh/d at the end of October. But 53.2TWh of the overall volume would have to be injected into unbooked capacity, if all capacity holders only fill to their mandated level. Assuming that THE takes over injections for all unbooked capacity at each site and only has proportional injection capacity available, this would still result in backloaded injection demand. This would be concentrated in September and October, with THE-controlled injection demand peaking at about 900 GWh/d in late October ( see THE injections profile graph ). Market participants have already warned of potential market tightness in late summer, given Norwegian maintenance scheduled during the period and possibly higher Asian cooling demand pulling LNG away from Europe . Delayed market-based injections, or any possible THE intervention, is likely to exacerbate this situation. By Till Stehr THE summer-winter spreads €/MWh German booked storage capacity and storage bookings by month TWh Injections profile for unbooked capacities GWh/d Theoretical injections profile GWh/d Send comments and request more information at [email protected] Copyright © 2025. Argus Media group . All rights reserved.

Brazil's GDP growth slows to 2.9pc in 1Q

30/05/25

Brazil's GDP growth slows to 2.9pc in 1Q

Sao Paulo, 30 May (Argus) — Brazil's economy grew at an annualized 2.9pc in the first quarter, as slowing consumption and factory output offset a rebound in farming activity. Growth in gross domestic product (GDP) decelerated from 3.6pc in the previous quarter and was off for a second quarter from 4pc in the third quarter of 2024, according to government statistics agency IBGE. Agriculture grew by an annual 10.2pc in the first quarter, more than offsetting a 1.5pc contraction in the last quarter of 2024. The increase in the sector was led by good crop performance and a rise in the outlook for the 2024-25 crop , IBGE said. The industrial sector expanded by 2.4pc, slightly slower than 2.5pc in the prior quarter. Manufacturing decelerated to an annual 2.8pc in the first quarter from 5.3pc in the previous quarter. Electricity and gas, water and sewage management increased by 1.6pc following a 3.5pc contraction in the last quarter of 2024. The sector was led by higher residential demand, IBGE said. The oil, natural gas and mining industries grew by 0.2pc following a 3.6pc contraction. The sector's gain was led by oil and gas exploration, but was slowed by a drop in iron ore mining, IBGE said. Construction decelerated to an annual 3.4pc from 5.1pc in the previous quarter. Household consumption decelerated to 2.6pc from 3.7pc in the earlier quarter, while government spending eased to 1.1pc from 1.2pc. Exports rose by 1.2pc from a 0.7pc contraction in the previous quarter, while imports decelerated to 14pc from 16pc. Brazil posted higher vehicles, oil products and agriculture exports, while the country's imports were led by transport equipment, machinery and chemicals, IBGE said. Gross fixed capital formation — which measures how much companies increased their capital goods — decelerated to an annual 9.1pc from 9.4pc. By Maria Frazatto Send comments and request more information at [email protected] Copyright © 2025. Argus Media group . All rights reserved.

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