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BP confirms shift to two‑segment structure
BP confirms shift to two‑segment structure
London, 9 June (Argus) — BP confirmed today that it will reorganise its business into two segments — Upstream and Downstream — from 1 July. The Upstream segment will combine BP's oil and gas regions, covering exploration, development and production. It will also include upstream joint ventures, alongside the company's renewable natural gas and carbon capture and storage businesses. The Downstream segment will include refining, terminals and pipelines, as well as BP's mobility and convenience retail operations. It will also cover biofuels, aviation and hydrogen, and include the company's remaining 35pc stake in its Castrol lubricants business. BP's Supply, Trading & Shipping function will operate across both segments, supporting "delivery and value creation across the integrated system", the company said. Its renewable power businesses — including solar and offshore wind, where BP is pursuing an asset-light model — will sit within the Technology function. The reorganisation was trailed shortly after new chief executive Meg O'Neill joined the company in April . Focusing BP around two distinct segments "is an important step in accelerating delivery" and will "reduce complexity and strengthen execution", O'Neill said today. The move brings BP's structure closer to that of US peers Chevron and ExxonMobil. O'Neill previously spent more than two decades at ExxonMobil. BP is currently organised into three main segments — Gas & Low Carbon Energy, Oil Production & Operations, and Customers & Products — alongside an Other Businesses and Corporate segment. The company said the new structure will clarify accountabilities and enable "faster, more effective" decision-making. O'Neill has previously said that moving BP's refining into a dedicated downstream segment, from the largely upstream Production & Operations business, would allow leadership to better "maximise value from the front of the refinery all the way to the end-customer". BP said Gordon Birrell, currently executive vice-president of Production & Operations, will lead the new Upstream segment. Customers & Products head Richard Harding will serve as interim head of Downstream until a permanent executive vice-president is appointed. By Jon Mainwaring Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.
Irish firm plans 600MW green H2 energy storage project
Irish firm plans 600MW green H2 energy storage project
London, 9 June (Argus) — Irish developer Net Zero Energy (NZE) plans to build a 600MW long-duration energy storage (LDES) facility that will convert surplus renewable power into hydrogen, store it underground, and dispatch electricity during periods of peak demand. The Rathrush Green Energy Park, in Carlow county, would cost around €2bn ($2.31bn) to develop. The plant is designed to generate up to 600MW for 70 hours — enough to cover 10pc of Ireland's peak electricity demand , NZE said. The LDES site will use surplus wind and solar electricity to power electrolysers to produce renewable hydrogen, which will be compressed and stored in lined rock caverns. Gas turbines will then burn the hydrogen to generate power for grid dispatch. The plant will connect to the grid through a 220kV substation, and draw process water from a nearby wastewater treatment facility. NZE is running a public consultation and plans to file a planning application by the end of 2026. NZE previously developed a 4.6MW battery energy storage system (BESS) and assisted in permitting and grid connection for the Kelwin 26MW BESS site . Separately, Ireland's department of climate, energy and environment has opened a call for evidence on geological hydrogen storage to inform future regulatory frameworks for underground storage. The consultation, which covers salt caverns, depleted gas fields, aquifers and lined rock caverns, closes on 17 July. By Chingis Idrissov Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.
South Korea’s fundamental fuel economics and policy
South Korea’s fundamental fuel economics and policy
London, 8 June (Argus) — The dynamic between thermal coal and LNG in South Korea's energy mix is more relevant than ever in the wake of the Mideast Gulf war, with surging prices, supply disruptions and evolving government policy all dictating the shape of South Korea's electricity generation. Generation margin advantage Coal has maintained substantial cost advantages over gas-fired generation since the US/Israel-Iran war began. On 6 March, thermal coal generation costs in South Korea were estimated at 75.83 won/kWh, compared with W216.22/kWh for LNG. Argus' NAR 5,800 kcal/kg thermal coal assessment rose by $19/t to $115.63/t cfr South Korea on 6 March, while northeast Asia (ANEA) front-month spot LNG prices more than doubled over the same period to $23.665/mn Btu from $10.715/mn Btu . April: Full switching to coal In April, South Korea demonstrated substantial fuel switching away from gas to coal. South Korean coal burn averaged 15GW in April, up by 42pc from around 10.6GW in 2025. Gas generation was down by 6.2pc, equivalent to an LNG demand cut of approximately 110,000t. This marked the first full month without any Qatari LNG deliveries following the outbreak of the Middle East war. May-June: Persistent coal support, constrained gas burn Despite ongoing government efforts to preserve LNG stocks, coal's dominance continued. Gas-fired output fell to 15.9GW for the rolling four-week average over 27 April–24 May 2026, down by 4.4pc on the year, while coal-fired output rose by 16.5pc to about 15GW over the same period. However, at least six LNG cargoes were diverted to South Korea in May, signalling spot demand driven by summer temperatures. Structural constraints on fuel switching South Korea's ability to fuel-switch away from gas is constrained by persistent grid bottlenecks. New renewable, nuclear and coal-fired power plants in coastal areas lack sufficient grid capacity to transfer power to urban demand centres. This structural constraint has kept a higher floor for gas-fired output, particularly during off-peak hours. Coal's balancing role During the spring shoulder season (typically March–June), South Korea implements countermeasures forcing generators to run coal-fired units at minimum levels to maintain grid stability. Coal-fired plants require higher minimum stable output than gas-fired units, making them far less flexible when solar output spikes in the middle of the day. As a result, gas-fired plants have been relied on as the main balancing power source during peak renewable generation hours. Policy and energy transition The South Korean government previously pledged to phase out coal entirely by 2040 but shifted to a more flexible stance following Middle East energy disruptions. By 14 April, the government signalled the possibility of delaying its coal exit plan in response to the war in the Middle East, although it simultaneously reaffirmed its commitment to expand renewables to 100GW by 2030. Near-term outlook and summer 2026 demand South Korea is forecast to experience a hotter-than-normal summer in June–August, with its meteorological agency indicating over a 50pc chance of above-average temperatures. This could increase power demand and LNG requirements. But the country faces tighter structural supply dynamics. Nuclear availability is scheduled to fall to 19.4GW in June–August from 20.1GW a year earlier, assuming the Wolsong reactors under maintenance stay off line. Coal-fired capacity will gradually return from maintenance, with 4.7GW set to have returned by the end of May, but this will only partially offset the government's ability to switch away from gas. Gas tariff and electricity price pressures are likely to persist, encouraging continued reliance on coal where operationally feasible. S Korea 40% coal switching price S Korea 44, 40% DS, 58% SS Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.
UK Rego auction sells 84pc on offer, reopening 8 Jun
UK Rego auction sells 84pc on offer, reopening 8 Jun
London, 5 June (Argus) — Around 84pc of UK renewable guarantees of origin (Regos) from compliance periods 24 (CP24) and 25 (CP25) traded on the E-power exchange over the past two days, with the auction set to continue next week. The auction opened on Thursday and continued on Friday, with 150GWh of CP24 Regos left unsold and expected to be offered on 8 June, when the sale reopens. Around 760GWh of CP24 Regos — which covers April 2025-March 2026 — have sold so far out of 910GWh on offer. Biomass comprised the majority of offered volumes at 334GWh, followed by offshore and onshore wind at 234GWh and 166GWh, respectively. Prices were between the auction reserve of £0.02/MWh and £0.10/MWh, with offshore wind realising the highest price. These were both above and below Argus ' assessments for CP24 non-biomass and biomass Regos of £0.05/MWh and £0.04/MWh, respectively, on 4 June. There was also a small lot of 5.6GWh from CP25 generation — spanning April 2026-March 2027 — on offer on Thursday, which cleared almost immediately. Onshore wind Regos accounted for the largest share at 2.7GWh, which cleared at the highest weighted-average price of £0.28/MWh, while 407MWh of solar Regos cleared at an average of £0.26/MWh. Biomass and biogases accounted for the rest and traded at the reserve price of £0.20/MWh. These were significantly below Argus ' assessments of £0.59/MWh and £0.39/MWh for non-biomass and biomass CP25 Regos, respectively, on 4 June. The share of certificates sold in E-power's auctions has steadily increased this year, rising from 21pc in February to about 60pc in April . This month's auction is the last one to offer CP24 Regos before the UK fuel mix disclosure deadline on 1 July. By Gian Remnant Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.
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