S Korea takes Kori reactor 4 off line

: Coal, Electricity, Natural gas
25/08/05

South Korea took the 950MW Kori reactor 4 off line on Tuesday, ahead of the expiry of its operational permit.

The permit expires on 6 August, operator Korea Hydro and Nuclear Power (KHNP) previously said. KHNP has not commented officially on the halt, but company data show output began falling early on Tuesday, and that it had stopped altogether by the end of the day.

KHNP has been seeking to extend the licence and minimise output curtailments after former president Yoon Seok-Yeol reversed his predecessor's plans to phase out nuclear energy. The halt might indicate that the administration of Lee Jae-Myung, which took office in June, is taking a different stance. That said, KHNP lists the reactor as being off line for maintenance, rather than retired.

Without Kori 4 and based on KHNP's maintenance schedule for other plants, South Korean nuclear availability is at 18.9GW this month, against 20.8GW of actual nuclear output a year earlier. Weaker nuclear output is likely to boost coal-fired generation this month, as the Korea Power Exchange (KPX) seeks to reduce the wholesale electricity price, a market participant said. KPX wholesale power prices averaged 128 won/kWh in January-June, supported by government restrictions on coal-fired generation that boosted the call on gas. Wholesale prices averaged W125/kWh a year earlier, KPX data show.

KHNP wants to extend life of the 650MW Kori reactor 2 and 950MW Kori reactor 3, which were taken off line in April 2023 and September 2024, respectively, when their permits expired. Neither has yet secured an extension, with South Korea's recent political instability muddying the picture.

By Evelyn Lee

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.

25/12/05

US LNG margins tighten on higher Henry Hub prices

Houston, 5 December (Argus) — A narrowing spread between US and European LNG prices and high freight rates in the Atlantic basin have pushed the front-month indicative long-term LNG contract cost above the spot Gulf coast fob price for the first time in two years. But the premium over the spot price will likely be brief, and limited flexibility in annual delivery plans will likely leave export schedules unchanged, with the impact solely on profit margins rather than fundamentals. A steeper backwardation in the US' Henry Hub forward curve compared to the northwest European LNG forward curve beyond February, as well as a steep backwardation in charter rates, means US LNG offtakers likely will not need to alter export plans. Liquefaction fees are also considered a sunk cost, and the Henry Hub remains comfortably below European LNG prices to more than cover the shipping cost between the two markets. This means there is still a strong financial incentive to maximise US LNG export volumes. The indicative long-term LNG contract price — 115pc of Henry Hub plus a $3/mn Btu liquefaction fee — has exceeded the Argus Gulf coast (AGC) spot fob price since 28 November, climbing to a premium of 69¢/mn Btu on 4 December. That premium came with the front-month Henry Hub price at a nearly three-year high of $5.06/mn Btu on forecasts for cold weather and US LNG exports at a record high. At the same time, the front-month NW Europe LNG des price was at $8.83/mn Btu, the lowest since May 2024, with warmer-than-normal weather forecast in Europe and EU underground storage well-supplied. A surge in freight rates, primarily driven by higher Atlantic basin loading demand, including at the 27.2mn t/yr Plaquemines plant, widened the spread between the AGC fob price and delivered spot prices in northwest Europe. The spread grew to 96¢/mn btu on 24 November, near the peak of the freight rally, up from 28¢/mn Btu in mid-October (see spread chart) . The wider spread pushed the AGC fob price for January loading below the indicative long-term LNG contract price for the same month. Forward freight rates are in steep backwardation in the first quarter of 2026, which is reflected in a tighter AGC-NW Europe spread over that span, as are Henry Hub futures contracts. This puts AGC prices above the indicative long-term contract prices from March through June (see forwards chart) . Although exports are unaffected because of liquefaction costs being considered sunk, the dynamic highlights the tightening margins for US LNG as a supply wave brings more liquefaction capacity on line through the end of the decade. The AGC fob's premium over the long-term indicative contract averaged $4.11/mn Btu through 4 December this year, down from $4.63/mn Btu, $5.37/mn Btu and $20.13/mn Btu in 2024, 2023 and 2022, respectively (see margins chart) . By Tray Swanson AGC-NWE spread and freight rates Tighter margins for US LNG $/mn Btu Indicative long-term contract forwards vs LNG spot prices $/mn Btu Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Eni and BP plan deepwater well in Libya in 1Q

25/12/05

Eni and BP plan deepwater well in Libya in 1Q

London, 5 December (Argus) — BP and Italy's Eni will drill a long-planned deepwater exploration well offshore Libya in the first quarter of 2026, a source at state-owned NOC told Argus . It is the most anticipated well since international oil companies, also including Spain's Repsol, Austria's OMV and Algerian state-owned Sonatrach, resumed exploration efforts late in 2024. "The first ultra-deepwater exploration well in Area C is scheduled in 2026," block operator Eni told Argus . NOC said the well is scheduled for January. The planned well is offshore Libya's Sirte Basin oil and gas heartland and targets a gas prospect. Eni and BP started a three-well exploration campaign in late 2024. The first well was drilled on their Area B in the Ghadames basin, but the NOC source said this yielded no commercial quantities of oil and gas. Eni and BP plan another exploration well on Area B in 2026, the source said. Any discoveries could be tied into Eni's nearby facilities. The two firms also hold the close by Area A. Eni is Libya's largest oil and gas producer by volume and is leading the country's exploration revival. It is currently drilling an offshore exploration well in Area D, close to its existing offshore production facilities. It will drill another after this is completed, the source said. IOCs were forced to abandon their exploration efforts in 2014 as the Libya's security situation deteriorated. Firms are returning because NOC lifted force majeure on these plans in 2024. "The companies are genuinely eager to explore," the source said. "This isn't just about them having to fulfill their contractual commitments." Repsol is drilling the third of a nine-well exploration campaign in the onshore Murzuq basin. So far, one of these has proven "successful", the source said. Discoveries will be tied into the Repsol-led 300,000 b/d El Sharara field. NOC has announced six new onshore discoveries this year, including one from OMV and one from Sonatrach . Exploration revival Libya has said it will announce winners of its first upstream licensing round in almost two decades in the first quarter of 2026. Firms including ExxonMobil, Chevron, Shell, BP, TotalEnergies and Eni have been shortlisted to participate in the licensing round. ExxonMobil , Chevron , Shell and BP have also signed bilateral preliminary agreements with NOC that could see them explore new areas and even develop existing onshore fields. The exploration programmes and licensing round are primarily aimed at boosting reserves and extending plateau production once Libya reaches its output goals, but discoveries could surprise to the upside. Libya aims to boost crude production from about 1.4mn b/d to 2mn b/d and gas production from about 1.2bn ft³/d (12.4bn m³/yr) to 4bn ft³/d over the next few years. By Aydin Calik Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Golden Pass LNG approved to receive cool-down cargo

25/12/04

Golden Pass LNG approved to receive cool-down cargo

Houston, 4 December (Argus) — QatarEnergy and ExxonMobil's 18.1mn t/yr (2.4bn ft³/d) Golden Pass LNG export terminal in Texas received federal approval today to unload a cool-down cargo, a key step in commissioning the plant. The Federal Energy Regulatory Commission granted the project's request to introduce hazardous fluids into various systems and receive the cool-down cargo. The 174,000m³ Imsaikah has been holding offshore Texas' Port Arthur since 29 November after departing QatarEnergy's 77mn t/yr Ras Laffan export terminal with a cargo on 27 October. The vessel's LNG will be used to cool down Golden Pass' equipment for its start-up process. The three-train project also has federal approval to introduce fuel gas to train 1 and train 1's gas turbine. Feedgas flows to Golden Pass have yet to materially rise. Pipeline nominations on 4 December were just over 8mn ft³, in line with daily flows since mid-October. Flows to LNG plants can be revised later in the day. The project's developers anticipate the facility will start production by the end of the year or in early 2026, with each of its three trains coming on line in six-month intervals. By Tray Swanson Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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.

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

S Korea takes Kori reactor 4 off line

Related news posts

US LNG margins tighten on higher Henry Hub prices

US LNG margins tighten on higher Henry Hub prices

Eni and BP plan deepwater well in Libya in 1Q

Eni and BP plan deepwater well in Libya in 1Q

Golden Pass LNG approved to receive cool-down cargo

Golden Pass LNG approved to receive cool-down cargo

LNG to fill the gap as Seoul pledges faster coal exit

LNG to fill the gap as Seoul pledges faster coal exit

UK gas output continues to defy forecast decline

UK gas output continues to defy forecast decline

Argus North American Long-Term Electricity Forward Curves

Argus North American Long-Term Electricity Forward Curves

Argus North American Long-Term Electricity Forward Curves

Argus North American Long-Term Electricity Forward Curves

Argus Carbon

Argus Low Carbon Hydrogen Strategy Report

Argus International Coal Forward Curves

Business intelligence reports