Narrow spreads could bring gas storage closures

: Natural gas
25/11/26

Narrow and at times inverted seasonal spreads have weighed on the uptake of capacity and profitability of Europe's slower-cycling storage facilities, which has led to applications to close sites, and may lead to more in the coming years.

TTF summer-winter spreads for gas year 2026-27 and 2027-28 have improved in recent months but remained narrow at -€0.97/MWh and at -€1.25/MWh, respectively, at the last close (see summer-winter spread graph). And the 2028-29 summer-winter spread closed at -€1.185/MWh. Narrower and even inverted summer-winters spreads limited storage capacity bookings in Europe last year.

The 16.5TWh Rough storage site in the UK closed in 2017 because of high operational costs, before reopening during the energy crisis of 2022. At the time of operator Centrica's closure application, the front-summer contract was at a 6.78p/th — €2.56/MWh — discount to the following winter contract across the month of June. The spread between these two contracts had held at an average -4.615p/th or -€1.72/MWh throughout 2016.

Since the reopening of the site, Centrica has repeatedly called for regulatory support to "upgrade and redevelop" the facility, while the profits from its storage-focused subsidiary plummeted last year. It has also stressed the need for a "regulatory support model" from the government to prevent Rough's closure given its low profitability.

While fast-cycling sites retain a comparative advantage in their capacity to provide quick injections into the grid in moments of peak demand, and allow firms to take advantage of short-term price differentials the inflexibility of slow-cycling sites limit the attractiveness of purchasing and making use of capacity.

The slow-cycling 45TWh Rehden storage site is struggling to sell storage capacity for the second year in a row.

The site has a maximum 353 GWh/d firm injection capacity and 543 GWh/d firm withdrawal capacity, giving it a churn rate — injection and withdrawal capacity relative to its storage size — of 1.75. This is the fourth-lowest churn rate of any storage site in Germany, and below the 4.9 average rate in the country. Comparatively, the Rough storage site has a 103 GWh/d and 126 GWh/d firm injection and withdrawal capacity, with a 1.25 churn rate. This is below the 8.46 average rate in the UK.

Rehden's operator Sefe Storage was only able to sell 30pc of capacity ahead of this winter, after it had to adjust the "product structure" by increasing injection capacity on offer but reducing storage capacity to 24.6TWh. Sefe Storage also indicated in August that it would need government intervention to be able to fill the site to legally-required levels. The company pointed to "unfavourable market conditions" and an "exceptional market situation" as their reason behind its failure to sell storage capacity.

The "facility has not been in as high demand on the market as other storage facilities in Germany" [BMWE told Argus](https://direct.argusmedia.com/newsandanalysis/article/2758349). "Rehden no longer has the same significance for security of supply as it did previously" because of changes in gas supply since 2022, including the expansion and heavy use of LNG, the ministry added.

"There are currently no plans to close UGS Rehden," Sefe said when asked for comment on the matter.

And the operator of slow-cycling Breitbrunn applied in October for approval to decommission the site on 31 March 2027 after it had struggled to sell capacity this summer. The site has a technical capacity of 11.5TWh, of which only 6.8TWh was booked for the 2025-26 storage year.

Breitbrunn has 69 GWh/d of firm injection capacity and 144 GWh/d of firm withdrawal capacity, with 1.48 churn rate, making it the slowest cycling site in Germany.

Bayernugs also announced its intention to close its 4.1TWh Wolfersberg storage site — with a 2.36 churn rate. The site has been unable to sell any capacity over the past storage year and has not sold any capacity for the coming storage year so far.

The Uelsen, Inzenham-West, Frankenthal and Schmidhausen storage sites in Germany all have a churn rate below 2, making them the slowest-cycling and potentially most-at-risk sites in the country.

That said, any storage closure must receive receive government approval beforehand. A possible decommissioning of the Breitbrunn storage site "would not jeopardise the security of supply in Bavaria, Germany or our neighbouring countries", the German economy and energy ministry BMWE told Argus. A good supply balance in Germany and the connection of Austrian storage facilities Haidach and 7Fields to the German grid further support this conclusion, the ministry added.

In the Netherlands, the government has yet to take a decision regarding operator Nam's phase-out plan for the 59.3TWh Norg low-calorie site. Nam envisions a halt to summer injections and the drawdown of stocks during the winter as part of the plan. The closure of the Norg storage site has been projected as part of plans to phase out large underground gas infrastructure in the Groningen region.

The site has a maximum 449 GWh/d firm injection capacity and 733 GWh/d firm withdrawal capacity, with a 1.71 churn rate.

Storage closures in Europe might nevertheless allow governments to produce or use the remaining cushion gas as emergency stocks.

By Lucas Waelbroeck Boix

TTF summer-winter spreads €/MWh

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25/12/04

Golden Pass LNG approved to receive cool-down cargo

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LNG to fill the gap as Seoul pledges faster coal exit

25/12/03

LNG to fill the gap as Seoul pledges faster coal exit

South Korea is scrambling for alternatives to coal-fired power to maintain sufficient base-load capacity, writes Evelyn Lee London, 3 December (Argus) — South Korea's pledge to phase out coal-fired power generation by 2040 has thrown its energy strategy into sharp focus, exposing a looming 40GW capacity gap. With nuclear expansion stalling and renewables facing infrastructure hurdles, LNG has become the most likely bridge to fill the potential shortfall. South Korea has formally confirmed its plan to retire 40 out of its 61 existing coal-fired units by 2040, following its declaration during the UN Cop 30 climate summit in Brazil last month to join the Powering Past Coal Alliance (PPCA) — a coalition of countries committed to ending coal use for power generation. The phase out timeline for the country's remaining 21 units — some of which were built relatively recently — will be determined through public consultation taking into account economic and environmental feasibility, and a detailed phase-out strategy is expected to be finalised next year, the PPCA says. This aligns with Seoul's intention to establish its 2026-40 long-term power plan by the end of next year. The firm phase-out pledge leaves South Korea scrambling for alternatives to maintain sufficient base-load power capacity. Its current long-term power plan covering 2024-39 was established in February under the previous administration of then-president Yoon Suk-Yeol. It earmarked 28 aging coal-fired units with a combined 14.1GW of capacity for conversion to LNG, and 12 units with 6.8GW of capacity to transition to carbon-free generation, such as pumped storage, hydrogen or ammonia co-firing, all by 2038. The current administration under President Lee Jae-Myung has indicated it does not intend to allow plants to switch to ammonia co-firing , signalling a decisive break from earlier strategies that sought to keep coal in the mix under a low-carbon guise. In line with this, Lee's administration in October cancelled the second round of a clean hydrogen power generation bidding market, which would have subsidised hydrogen and ammonia co-firing under 15-year contracts. Seoul searching An accelerated coal phase-out alongside a ban on approving new nuclear reactors has led to growing expectations that South Korea will lean more heavily on gas-fired plants to maintain its power system at least until renewables capacity catches up. The current electricity plan stipulates building two new 1.4GW reactors and continued use of expiring reactors, resulting in nuclear capacity rising to 35.2GW in 2038 from 26.1GW in 2025. But the Lee administration has ruled out building new reactors, although construction of reactors already under development can proceed as planned. The government has approved the restart of the 650MW Kori reactor 2, in line with the president's stance that expiring reactors may continue operating if safety standards are met. But even with these measures, Seoul must identify more than 40GW of replacement capacity by 2040, based on information currently available. This is roughly equivalent to the country's entire coal-fired fleet, which has accounted for around 28pc of total power output this year. The government aims to expand South Korea's renewable energy capacity to 100GW by 2030 from a previous target of 80.9GW and current capacity of 37.9GW, but its renewables rollout continues to be constrained by insufficient transmission capacity upgrades, mainly driven by local opposition. A law to accelerate grid projects came into force on 26 September, but progress is now being held up by local governments, which are reluctant to approve project permits in a bid to maintain positive public opinion ahead of municipal elections in June next year. Persistent grid bottlenecks have increased the country's reliance on gas-fired generation in recent years, as these plants are located close to the main demand centre around Seoul. Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

UK gas output continues to defy forecast decline

25/12/03

UK gas output continues to defy forecast decline

London, 3 December (Argus) — Production from the UK continental shelf (UKCS) inched up on the year in September, in contrast to the North Sea Transition authority's (NSTA) projected fall in output this year from last production. Gas output on the UKCS was 71.24mn m³/d in September, NSTA data show, up marginally from 71.17mn m³/d a year earlier. Output was varied across the country's largest production hubs, with higher production at Britannia and Arran balancing the decline at other fields. Production rose significantly on the year at Arran to 2.1mn m³/d in September, up from 0.1mn m³/d a year earlier. Similarly, there was sharp increase at Britannia to 2.1mn m³/d from 0.2mn m³/d a year earlier, because of heavy works in September 2024 at the two fields. Harbour Energy, the operator of the Britannia, experienced an "unusually high number of planned shutdowns" in 2024 . Meanwhile, production declined at the UK's largest fields — Culzean, Elgin, Franklin, Cygnus, Bruce and Tolmount — with the biggest production decrease at Bruce. Bruce production fell to 2.8mn m³/d from 4.4mn m³/d a year earlier. Marginally higher production coupled with lower domestic consumption on the year meant that UKCS output met a larger share of demand than in September 2024. UK demand fell to 107.4mn m³/d in September, from 116.4mn m³/d a year earlier. UK output in September met 66pc of demand, including exports to Ireland at Moffat, up from 61pc a year earlier. Production in 2025 revised up The NSTA increased its projection for production for 2025 and 2026 in its biannual forecast released in November. The NSTA forecast that net gas production will continue its decline, but remain higher than previously forecast in 2025 and 2026. The regulator expects net production of 24.6bn m³ — or 67.4mn m³/d — this year. This is up from its estimation of 24.5bn m³ in March, equivalent to 67.1mn m³/d. The NSTA also revised its net gas production figure for 2026 to 21.3bn m³, up from 21.2bn m³ in the previous forecast (see forecast table) . The NSTA revised its expected decline on the year in 2025 to 9.6pc from the previously projected 10pc. But the decline rate remains unchanged at 12pc for 2026-50. And the NSTA's projections for production in 2025-30 fall by an average of 2.3bn m³/yr. The regulator projects that the average unit cost of gas and crude oil together will increase to £19.80 barrels of oil equivalent (boe) this year, from £19.50/boe in 2025. And it expects this cost to increase in the following years, moving up to £20.80/boe by 2030. In its Autumn Budget, the UK government retained the energy profits levy on oil and gas profits until its scheduled end date of 31 March 2030 . Alongside the budget, the government published its North Sea Future Plan, which outlined that the government will not issue new oil and gas exploration licences in the North Sea, but it will encourage firms to produce gas from areas adjacent to operating fields . Production may surpass 2025 forecast Implied production data suggest that UK production may decline even lower than the revised NSTA forecast states. UKCS production totalled 21bn m³ in January-September. And based on the NSTA's projection of a total production of 24.6bn m³, this leaves 3.6bn m³ to be produced in October-December, or 39.1mn m³/d, based on NSTA data. But implied production — based on gas delivered to the national transmission system — was 79.8mn m³/d in October-November, or 4.87bn m³, already surpassing the projected annual figure for 2025. And if the 9.6pc production decline rate is applied to actual average output of 85.43mn m³/d in October-December 2024, this would equate to an output of 77.23mn m³/d during this period, which also suggests higher total annual production of 28.1bn m³. Operators expect strong production at certain hubs in December, further suggesting potential for production to surpass the NSTA projections. UK North Sea producer Ithaca Energy expects strong production in December on the back of new wells coming on line. An infill campaign at its Cygnus field is continuing, Ithaca said in its third-quarter results earlier this month, with the first of four wells expected to achieve production early this month . Similarly, the operator of the Bruce hub, Serica Energy, said in its third-quarter results last month that it expects strong output from Bruce in the last two months of the year . By Aleksandra Godlewska UK production forecast bn m³ November forecast March forecast October 2024 2024 27.4 27.2 26.3 2025 24.6 24.5 23.6 2026 21.3 21.2 20.3 2027 18.4 18.4 17.5 2028 16.2 15.9 15.6 2029 13.9 13.8 13.7 2030 12.2 11.9 12.1 2031 10.7 10.4 10.8 2032 9.4 9.2 9.7 2033 8.2 8.1 8.7 2034 7.1 6.9 7.5 2035 6.0 5.9 6.5 — NSTA Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Saudi Arabia brings giant Jafurah gas project onstream

25/12/03

Saudi Arabia brings giant Jafurah gas project onstream

Dubai, 3 December (Argus) — Saudi state-controlled Aramco has begun production from the first phase of the giant Jafurah natural gas project, the finance ministry said late on Tuesday. In its 2026 budget statement, the finance ministry listed the phase one start-up as one of Saudi Arabia's achievements in 2025. It didn't specify a date, but it is likely to have been in the past few days. It said production began at 450mn ft³/d, which is two and a half times the rate at which Aramco had long projected. With in-place reserves of 229 trillion ft³ (6.87 trillion m³) of raw gas and 75bn bl of condensate, Jafurah is the largest unconventional gas field in the Mideast Gulf and represents a major pillar of Aramco's ambitious gas expansion plans. Aramco has yet to announce the start up. It previously said it expects to lift sales gas output ꟷ or net production ꟷ to 650mn ft³/d by the end of 2026 in phase one. It is unclear if this stronger-than-anticipated start-up rate could translate into a higher end-2026 target. A second phase is scheduled to come on stream in 2027, to lift production to 2bn ft³/d by the end of the decade, Aramco has said. Aramco has an ambitious programme to expand gas production by more than 80pc by the end of the decade, relative to a 2021 baseline of 9.2bn ft³/d. This implies output of at least 14.7bn ft³/d by 2030, with Jafurah delivering more than one-third of the increase. Jafurah will also produce about 420mn ft³/d of ethane and 630,000 b/d of NGLs and condensate as by-products by 2030. The ethane and NGLs will be sent to the Riyas fractionation plant, which is being built as part of the phase two development. The condensate will be sent to the Juaymah terminal, where Aramco is expanding its storage and export facilities. By Nader Itayim Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Australia’s Victoria to miss renewable power targets

25/12/03

Australia’s Victoria to miss renewable power targets

Sydney, 3 December (Argus) — Australia's second-largest state by population Victoria will meet its 2025 renewable energy goal, but is likely to miss future targets due to slow development, the state's auditor-general said today. Delays to key projects risk future electricity shortages, according to the Managing the Transition to Renewable Energy report published on 3 December, highlighting difficulties reaching the state Labor government's targets ( see table ). Three coal-fired stations, the 1,480MW Yallourn, 2,210MW Loy Yang A, and 1,200MW Loy Yang B generators produce about 59pc of the state's electricity, but the former two are scheduled to close in 2028 and 2035 respectively. Meeting the 2030 target requires fast-tracking two major projects under the Victorian Transmission Plan. This includes the A$3.2bn ($2.1bn) Victoria-New South Wales (NSW) Interconnector West (VNI West) delayed from 2028 to 2030 in July and the Western Renewables Link also due to be completed in 2030. The delay means Victoria will lack access to the 2,200MW Snowy 2.0 pumped hydro project in New South Wales (NSW) when it is completed in late 2028, after Yallourn closes. Canberra's Capacity Investment Scheme (CIS) is critical to reaching 65pc renewables by 2030 but private firms must build and connect Victoria's full CIS allocation in the next four years with additional state support, the report said. Achieving the 2030 goal also relies on electricity demand not growing faster than anticipated. Transmission projects are unpopular with many landholders and regional communities due to land use conflict issues. Victoria has moved to neutralise opposition by legislating accelerated pathways for new projects. But Victoria will meet its 2.6GW storage target by 2030 because sufficient new battery capacity is planned, the auditor-general said. Offshore wind fail Victoria is aiming to replace much of its coal-fired capacity with offshore wind projects but the sector has stuttered after permitting for a key support facility was rejected by federal authorities in 2024 . Under an optimistic scenario, Victoria may build 2GW of offshore wind capacity by 2033 but further delays are possible, the report said. The state's energy department has not adequately considered risks transitioning supply from fossil fuels to renewables, including the full extent of projects delays and weather variation, the auditor-general found. Long-lasting high-pressure systems prevalent in May-October could reduce wind generation for days on end, limiting both battery charging and imports of power. Gas-fired generation is at risk from gas supply shortfalls , meaning the current pipeline of generation and storage projects could be insufficient to offset Yallourn's closure. The report comes two days after a regulator determined that the 2,880MW Eraring coal-fired facility in NSW, the nation's largest, would likely need to be kept on line beyond its planned retirement in 2027 . By Tom Major Victoria's renewable energy targets 2020 2025 2030 2032 2035 2040 Renewable total (%) 25 40 65 - 95 - Offshore wind power (GW) - - - 2 4 9 Energy storage (GW) - - 2.6 - 6 - — Victorian government Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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