New South Korean reactor awaits permit decision
South Korea's nuclear safety commission will tomorrow decide whether to grant an operational permit for the country's new Shin Hanul 1 reactor.
The 1.4GW reactor is already several years delayed, but operator Korea Hydro and Nuclear Power (KHNP) had expected it to be completed this month.
The start-up of Shin Hanul 1 now seems likely to be further postponed, even if approval is granted tomorrow. Local South Korean media outlets reported that the reactor would start at the end of March 2022 if an operational permit is granted on 9 July, but this could not be confirmed by Argus.
South Korea has 23.25GW of installed nuclear capacity, which would rise to 24.65GW when Shin Hanul 1 starts. In addition, the 1.4GW Shin Hanul 2 reactor currently has a completion date of May 2022, although the potential delay to Shin Hanul 1 has cast uncertainty over this timeline.
South Korea is also constructing two more 1.4GW reactors, Shin Kori 5 and 6, which are currently expected to be completed in March 2023 and June 2024, according to the KHNP website.
But the country is also planning to decommission 11 reactors with a combined capacity of 9.45GW over 2023-34. The first of these are expected to be the 650MW Kori 2 and 950MW Kori 3 reactors in April 2023 and September 2024, respectively.
Short-term outlook uncertain
The short-term outlook for South Korean nuclear availability remains clouded by an unplanned outage at the 1.4GW Shin Kori 4 reactor, which tripped on 29 May and is still off line.
Excluding Shin Kori 4, four nuclear reactors are already scheduled to be off line for all of July, with shorter outages planned at another six reactors. This will reduce the country's nuclear availability to 15.5GW for the month of July, assuming Shin Kori 4 remains off line, which would be down by 2.5GW on the year from actual generation of 18.4GW in July 2020.
The shortfall in nuclear availability will compound an expected rise in power demand, meaning more fossil fuels will be drawn into the mix this month compared with a year earlier. The Korea Power Exchange (KPX) predicted a 6pc year-on-year increase in power demand this month, which would equate to an additional 3.8GW in overall power generation.
Combined generation from coal and gas could therefore grow by around 5.7GW on the year, according to Argus analysis, from 39.2GW (25.2GW coal and 14GW gas) in July 2020.
Capacity restrictions across the state-owned Kepco coal-fired fleet may ease this month compared with July 2020, and average load factors are likely to increase amid stronger power demand and from last year's low base during the pandemic. Two new private coal-fired units have also started operations in recent months, potentially boosting available coal capacity for the peak cooling period.
But the upside for coal could be tempered by stronger gas-fired generation, as domestic gas prices are currently more competitive with coal for power than they were a year earlier.
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Japan’s Renova starts Miyagi biomass power plant
Japan’s Renova starts Miyagi biomass power plant
Tokyo, 28 March (Argus) — Japanese renewable power developer Renova started commercial operations today at its 75MW Ishinomaki Hibarino biomass-fired power plant in northeast Japan's Miyagi prefecture. The power plant is designed to consume an undisclosed volume of wood pellets and palm kernel shells (PKS) to generate around 530 GWh/yr of electricity. Renova originally targeted to start up the power plant in May 2023 but postponed the start-up multiple times. Renova has been forced to delay the start-up schedules at several of its power plants. It previously targeted to begin commercial operations of the 75MW Omaezaki biomass power plant this month but postponed it to July, as the final adjustment of boiler and turbine units is taking longer than expected. It delayed the launch of the 74.8MW Tokushima Tsuda biomass power plant in September before it began commercial operations in December 2023 . Japan imported 1mn t of wood pellets during January-February, up by 14pc from the same period in 2023, according to the finance ministry. PKS purchases fell by 24pc to 466,186t. By Nanami Oki Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Hampton Roads may have space for Baltimore coal exports
Hampton Roads may have space for Baltimore coal exports
Houston, 27 March (Argus) — Terminals in Hampton Roads, Virginia, may have some available capacity to take rerouted coal shipments from Baltimore, Maryland, despite increasing exports from a year earlier for the seventh consecutive month in February. Coal loadings at Hampton Roads reached an estimated 3.31mn short tons (st) (3mn metric tonnes) last month, rising 7.8pc from February 2023, according to the Virginia Maritime Association. Still, historic Hampton Roads export data going back to 1993 showed that combined shipments from the three terminals in the region peaked at 5.48mn st in April 2012, which is nearly 66pc higher than last month's exports. This suggests that Hampton Roads terminals may have capacity to load additional coal volumes that were originally booked to ship out of terminals upstream from the Francis Scott Key Bridge in Baltimore, which collapsed on Tuesday morning, closing the Port of Baltimore for an indefinite period of time. The two Baltimore coal terminals cut off by the bridge collapse, Consol Energy's Consol Marine Terminal and CSX's Curtis Bay Coal Piers, have a combined export capacity of about 34mn st. Railroad Norfolk Southern (NS), which operates the Lamberts Point terminal at Hampton Roads, said today it is working with impacted international customers and port partners to "provide alternate routing solutions." "Ports on the east coast are resilient and have the capacity to serve the flow of freight," NS said. Lamberts Point terminal handled 1.19mn st of coal in February, a 20pc jump from February 2023. Despite this increase, that is still down from the 2.18mn st exported from the terminal in April 2012. Dominion Terminal Associates (DTA) exported 1.24mn st of coal in February from the Hampton Roads area, which is down 30pc from April 2012, while exports from the nearby Pier IX terminal were down 53pc to 727,023st last month. DTA's co-owners, Alpha Metallurgical Resources and Arch Resources, and Pier IX's owner Kinder Morgan all did not respond for immediate comment. By Anna Harmon Hampton Roads coal exports in 2012 st Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
RMKO, Atlas to develop Sumatra coal crushing plant
RMKO, Atlas to develop Sumatra coal crushing plant
Manila, 27 March (Argus) — Indonesian coal mining contractor RMKO has partnered with domestic producer Atlas Resources to develop a coal crushing plant and other supporting mining infrastructure in south Sumatra. The crushing plant and other facilities are targeted for completion by the second half of this year, said RMKO, which is a subsidiary of coal logistics firm RMK. The plant will be built at Atlas' Mutara hub, which consists of five separate concessions in the Musi Rawas and Musi Banyuasin regency in south Sumatra and has coal reserves totalling 85mn t. Atlas has already acquired a road construction permit that will connect Mutara to the Sriwijaya Bara logistics jetty 137km away. The coal crushing plant is expected to boost coal transportation from mines to clients outside the region, the company said. RMKO will construct and operate the coal crushing plant that will have a capacity of 650 t/hr. Other services will include stockpile management, loading services and plant maintenance. The 36bn rupiah ($2.28mn) plant will be funded by RMK with Atlas paying back the investment through coal production equivalent to 200,000 t/month for five years, as well as the cost of operations and maintenance services, RMKO said. By Antonio delos Reyes Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Electrification key to cut UK offshore emissions: NSTA
Electrification key to cut UK offshore emissions: NSTA
London, 27 March (Argus) — The UK offshore oil and gas industry must make "decisive emissions reduction actions now and on an ongoing basis", with asset electrification and low carbon power central to making cuts, regulator the North Sea Transition Authority (NSTA) said today. "Where the NSTA considers electrification reasonable, but it has not been done, there should be no expectation that the NSTA will approve field development plans", the regulator said in a new emissions reduction plan. The NSTA set out "four clear contributing factors to decarbonising the industry" — including asset electrification, investment and efficiency and action on flaring and venting. It will also look at "inventory as a whole", ramping up scrutiny on assets with high emissions intensity. Relevant companies must produce emissions reduction action plans for offshore assets, the NSTA said. New developments with first oil or gas after the beginning of 2030 must be either fully electrified or run on "alternative low carbon power with near equivalent emission reductions", the NSTA said. New developments with first oil or gas before 2030 should be electrification-ready at minimum. If electrification is not reasonable, other power emissions reductions must be sought, the regulator said. The offshore industry must from 1 June provide "a documented method of the split of projected flaring and venting figures into categories", and must from 1 June 2025 have a plan and budget to "deliver continuous improvements in flaring and venting", it said. New developments — including tie-backs — must be planned on the basis of zero routine flaring and venting, which every asset must reach by 2030. Industry flaring almost halved between 2018-22, the NSTA said. The regulator has flagged a particular focus on methane emissions. The NSTA may require developers to agree to cease production of assets with high emissions intensity "with reference to societal carbon values", it said. Societal carbon values are calculated by the UK government to reflect the marginal cost to society of additional CO2 emissions. It will discuss end dates for production for assets with greenhouse gas (GHG) emissions intensity 50pc over the average for the UK offshore, and which intend to produce oil or gas beyond 2030. This represents a slight watering down of the initial plan the NSTA consulted on last year. The North Sea Transition Deal, agreed in 2021, commits the UK offshore industry to reducing its production emissions of GHGs by 10pc by 2025, by 24pc by 2027 and by 50pc by 2030, from a 2018 baseline. Industry has itself committed to a 90pc reduction by 2040 and a net zero basin by 2050, the NSTA said. It "would welcome industry owning and delivering these reductions", it said, adding that its plan is focused on emissions cuts and "emissions offsetting will not be considered towards meeting the obligations." By Georgia Gratton Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
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