Cleco, SWEPCO to close Louisiana coal plant early
Cleco and US power producer American Electric Power (AEP) subsidiary Southwestern Electric Power (SWEPCO) will retire the Dolet Hills coal-fired power plant in Louisiana at the end of this year, five years ahead of schedule.
Cleco and SWEPCO expect to retire Dolet Hills on 31 December as part of their efforts to reduce costs. The 638MW plant was previously scheduled to close in 2026.
Since 2019, the facility has operated seasonally. This year the plant ended seasonal operations on 31 October and took its last coal delivery last month, Cleco said.
"The cost of coal used to operate our Dolet Hills plant in Mansfield has increased to the point that the unit is no longer competitive," Cleco's chief operations officer Robbie LaBorde said in September.
In 2020, Cleco also said that the low market price of power, coupled with the cost of lignite mined at the nearby Oxbow mine was contributing to the Dolet Hills plant being less competitive.
The plant will lay off 54 of its employees.
Cleco, which holds a 50pc stake in Dolet Hills, operates the facility. SWEPCO has 40pc ownership, while the remaining 10pc stake in the plant is held by the North Texas Electric Cooperative and the Oklahoma Municipal Power Authority.
In the first seven months of 2021, Dolet Hills received 293,462 short tons (266,224 metric tonnes) of coal from Dolet Hills Lignite company's Oxbow mine in Louisiana, according to US Energy Information Administration data.
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Japan's trading firms see metals prices cutting profits
Japan's trading firms see metals prices cutting profits
Tokyo, 2 May (Argus) — Major Japanese trading houses are expecting lower profits from their metals businesses during the April 2024-March 2025 fiscal year, mostly because of lower prices of commoditiessuch as iron ore and coking coal. Japanese trading house Mitsui forecast profits for its metal and natural resource business falling by 14pc on the year to ¥290bn ($1.87bn) during 2024-25, primarily because of lower iron ore prices. Mitsui plans to cut iron ore output by 0.3pc on the year to 60.9mn t at its mining projects where the company owns production rights or a production stake during 2024-25. This includes the joint venture project Robe River in Australia with Australian iron ore producer Rio Tinto. Japanese trading house Sojitz also expects profits from its metal and natural resource business to decline to ¥35bn, down by 20pc on the year, mostly because of a bearish coking coal market. The company said its overall coal business can cut production costs during 2024-25, partly because it plans larger-scale output at the Gregory Crinum coking coal mine in Australia, without disclosing further details. But Sojitz said it cannot generate higher profits because of lower coking coal prices. The trading house expects the average coking coal price to fall to $230/t during 2024-25, according to the company's chief financial officer Makoto Shibuya, down by $57/t from a year earlier. The company reiterated that the price is not necessarily their selling price. Sumitomo expects profits from its natural resource business would remain flat at ¥72bn on the year, mostly as its nickel production in Madagascar recovers from the output cuts in 2023 , with an aim to produce 19,000t of nickel during 2024-25, up by 9.8pc on the year. A rebound in nickel production could offset possible losses from coal and coking coal prices falling to $266/t and $133/t respectively in the ordinary market, down by $21 and $9, according to the trading house. Sumitomo plans to increase coking coal production by 9.1pc to 1.2mn t but reduce coal output by 4.8pc to 4mn t during 2024-25. By Yusuke Maekawa Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Australia issues offshore wind feasibility licences
Australia issues offshore wind feasibility licences
Sydney, 2 May (Argus) — The Australian federal government has issued the first feasibility licences for offshore wind projects in the country following a competitive process, for up to 12GW of capacity off the coast of Gippsland in the southern state of Victoria and a potential further 13GW in the next stage. Six projects have received approval to explore the feasibility of offshore wind farms in the Bass Strait off Gippsland's coast, which was the first offshore wind zone declared in Australia at the end of 2022. Successful applicants include Danish investment firm Copenhagen Infrastructure Partners (CIP), Danish utility Orsted, Australian utility AGL Energy, European utilities EDP Renewables and Engie and Japanese utility Jera. The government also intends to grant another six licences, subject to consultation with First Nations groups. The 12 projects could have a potential combined capacity of around 25GW, the government said ( see table ). Projects that prove feasible will be able to apply for commercial licences and move to the construction phase if they secure financing, with the most advanced wind farms expected to start generating power in the early 2030s. CIP secured site exclusivity to develop two projects with a combined 4.4GW through a newly launched platform company Southerly Ten. The projects comprise the 2.2GW Star of the South, which claims to be the most advanced offshore wind project in Australia , along with the early stage 2.2GW Kut-Wut Brataualung. Southerly Ten is also developing the Destiny Wind project in Australia's second declared offshore wind zone off the Hunter region in New South Wales. Orsted was given one licence for a 2.8GW project and might receive another one for a 2GW wind farm. It said it will proceed with site investigations, environmental assessments and supply chain development, with a view to bid in future auctions planned by the Victorian government, which are expected to start in late 2025. Victoria is targeting 2GW of offshore wind capacity by 2032 and 9GW by 2040. "Subject to the above steps and a final investment decision, the projects are expected to be completed in phases from the early 2030s, with the aim to maximise dual site synergies through shared resources and economies of scale," Orsted said. The 2.5GW Gippsland Skies offshore wind project, belongs to a consortium made of Irish renewables firm Mainstream Renewable Power with 35pc, UK-based firm Reventus Power 35pc, AGL Energy 20pc and Australian developer Direct Infrastructure 10pc. The first phase of the project is expected to be operational in 2032, according to the consortium. The list of six projects already granted feasibility licences also include High Sea Wind, a proposed 1.28GW wind farm developed by EDP Renewables' and Engie's 50:50 joint venture Ocean Winds, along with Blue Mackerel North, a 1GW development by Japanese utility Jera Nex's subsidiary Parkwind. Parkwind is also developing another offshore wind project in Australia, with Australian utility Alinta Energy, the 1GW Spinifex in the Southern Ocean off Victoria, which was declared Australia's third wind zone in March. The other projects that might receive licences are being developed by companies such as Spanish utility Iberdrola, Spanish developer Bluefloat Energy, Australian firm Macquarie's wind developer Corio Generation, German utility RWE and a joint venture between Australia's Origin Energy and UK-based developer RES Group. By Juan Weik Australian offshore wind projects with feasibility licences Developer Capacity Licence Orsted Offshore Australia 1 Orsted 2.8 Granted Gippsland Skies Consortium* 2.5 Granted Star of the South Southerly Ten 2.2 Offered Kut-Wut Brataualung Southerly Ten 2.2 Granted High Sea Wind Ocean Winds 1.3 Granted Blue Mackerel North Parkwind 1.0 Granted Aurora Green Iberdrola 3.0 Under consultation Great Eastern Offshore Wind Corio Generation 2.5 Under consultation Gippsland Dawn Bluefloat Energy 2.1 Under consultation Orsted Offshore Australia 2 Orsted 2.0 Under consultation Navigator North Origin Energy, RES 1.5 Under consultation Kent Offshore Wind RWE N/A Under consultation Source: federal government, companies *Mainstream Renewable Power, Reventus Power, AGL, Direct Infrastructure Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
US southbound barge demand falls off earlier than usual
US southbound barge demand falls off earlier than usual
Houston, 1 May (Argus) — Southbound barge rates in the US have fallen on unseasonably low demand because of increased competition in the international grain market. Rates for voyages down river have deteriorated to "unsustainable" levels, said American Commercial Barge Line. Southbound rates declined in April to an average tariff of 284pc across all rivers this April, according to the US Department of Agriculture (USDA), which is below breakeven levels for many barge carriers. Rates typically do not fall below a 300pc tariff until May or June. Southbound freight values for May are expected to hold steady or move lower, said sources this week. Southbound activity has increased recently because of the low rates, but not enough to push prices up. The US has already sold 84pc of its forecast corn exports and 89pc of forecast soybean exports with only five months left until the end of the corn and soybean marketing year, according to the USDA. US corn and soybean prices have come down since the beginning of the year in order to stay competitive with other origins. The USDA lowered its forecast for US soybean exports by 545,000t in its April report as soybeans from Brazil and Argentina were more competitively priced. US farmers are holding onto more of their harvest from last year because of low crop prices, curbing exports. Prompt CBOT corn futures averaged $435/bushel in April, down 34pc from April 2023. Weak southbound demand could last until fall when the US enters harvest season and exports ramp up southbound barge demand. Major agriculture-producing countries such as Argentina and Brazil are expected to export their grain harvest before the US. Brazil has finished planting corn on time . unlike last year. The US may face less competition from Brazil in the fall as a result. Carriers are tying up barges earlier than usual to avoid losses on southbound barge voyages. Carriers that have already parked their barges will take their time re-entering the market unless tariffs become profitable again. The carriers who remain on the river will gain more southbound market share and possibly more northbound spot interest. By Meghan Yoyotte and Eduardo Gonzalez Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
US gas industry pins hopes on AI power demand
US gas industry pins hopes on AI power demand
New York, 1 May (Argus) — US natural gas producers and pipelines have pivoted almost in unison this year to talking up what they see as one of the strongest bullish cases for gas this decade: surging electricity demand from yet-to-be-built data centers to power artificial intelligence software. EQT, the largest US gas producer by volume, in an investor presentation last week called growing data center demand the "cornerstone" to the "natural gas bull case." Combining its own research with data from the US Energy Information Administration, the gas giant forecast an increase in gas demand of 10 Bcf/d (283mn m3/d) by 2030 to generate electricity, mostly to run data centers. Its more aggressive data center build-out scenario envisions a whopping 18 Bcf/d increase in gas demand through 2030. Total US gas production is currently about 100 Bcf/d. Kinder Morgan, one of the largest US gas pipeline operators, this month forecast 20pc of US power being gobbled up by data centers in 2030, up from a 2.5pc share in 2022. Cobbling together projections from several consultancies and financial advisories, the company said the electricity needed to run artificial intelligence software alone will comprise 15pc of US power demand by 2030. If just 40pc of that demand is met by gas, that would represent an increase in gas demand of 7-10 Bcf/d, it said. This is roughly in line with the high end of US bank Tudor Pickering Holt's forecast for gas demand to power data centers through 2030 (1.3-8.5 Bcf/d) and well above Goldman Sachs' and consultancy Enverus' projections of 3.3 Bcf/d and 2 Bcf/d, respectively. New tech, old problems Separating the wide ranges of these projections is the highly speculative nature of forecasting demand years into the future for competing energy sources to power next-generation technology. But the major upside and downside risks, analysts say, concern the more humdrum challenges of permitting and building out energy infrastructure. Goldman Sachs expects 28GW, or 60pc, of the generation capacity needed to power new data centers through 2030 will come from natural gas — 9GW from combined cycle gas turbines and 19GW from gas peaker plants. But with an average lag of four years from the time a gas transmission project is announced to the time it enters service, to say nothing of the high probability of litigation being brought by environmentalists and landowners, construction and permitting timelines are "the most top of mind constraint for natural gas," the bank said. Indeed, litigation and opposition from state regulators have ultimately led developers to call off several interstate pipeline projects in the eastern US in recent years. The exception to the rule, Equitrans' 2 Bcf/d Mountain Valley Pipeline is moving forward only because congressional action allowed it to bypass federal permitting hurdles. This is a particular problem for the gas industry's hopes of exploiting the data center boom, as a large share of future data centers are slated to be built in the southeast US, far from the major US gas fields. New data centers representing 2 Bcf/d of gas demand in Georgia probably requires a new pipeline into the southeast, FactSet senior energy analyst Connor McLean said. Southeast premium A significant data-center buildout in the southeast without new pipelines could put upward pressure on regional gas prices, McLean said. This could exacerbate the effects of what has become perhaps the most prominent bullish case for US gas: a massive build-out of LNG export terminals along the US Gulf coast. With new export terminals pulling increasing volumes of gas south along the Transcontinental gas pipeline to super-chill and ship overseas in the coming years, the build-out in data centers will likely produce "an even bigger deficit in that southeast (gas) market," EQT chief financial officer Jeremy Knop told investors last week. "We think that market really, in time, becomes the most premium market in the country," he said. By Julian Hast Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
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