Australia considers emissions targets in power planning
Australian energy ministers are to decide next week on including environmental considerations such as greenhouse gas (GHG) emissions reduction targets into electricity network and generation planning.
This aims to accelerate the transition to a power system supplied by renewable energy sources and create the infrastructure to develop a green hydrogen sector. The meeting of Australian federal, state and territory energy ministers on 12 August in Canberra will debate and vote on including the environment into the National Electricity Objective (NEO), which is the framework that energy regulators approve power generation and transmission projects.
The absence of including emissions reduction and renewable energy targets has slowed the development of renewable energy projects. The inclusion of environmental objectives in the NEO should assist the Australia's government achieve its target of reducing GHG emissions by 43pc by 2030 from 2005 levels after passing its climate bill in the lower house of parliament on 4 August.
The proposal to include the environment in the NEO has been led by the Australian Capital Territory (ACT) minister for energy and emissions reduction Shane Rattenbury.
"At the energy ministers' meeting in September last year, I secured agreement for the ACT to lead work towards incorporating emissions reduction into the National Electricity Objective working in collaboration with the Queensland government," Rattenbury said.
"Reflecting emissions reduction goals in the NEO is important for ensuring emissions intensity of generation is considered and reducing emissions is prioritised.
"We need to act quickly if we are to have any chance of meeting Australia's net zero emissions by 2050 target, and this means rapidly reducing emissions from the energy sector. Reflecting the net zero emissions goal in the NEO will help to ensure an efficient and co-ordinated national approach to decarbonisation."
The Labor federal government, which was elected in May, has set a target of sourcing 82pc of electricity from renewable sources by 2030 in the National Electricity Market (NEM) that covers east Australia and accounts for more than 80pc of the country's power demand. Around a third of electricity in the NEM came from hydro, solar and wind sources in the past 12 months. Coal-fired power plants generate around 60pc of the NEM's electricity.
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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 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.
Larger EU H2 bank auction could still clear below €1/kg
Larger EU H2 bank auction could still clear below €1/kg
Hamburg, 1 May (Argus) — The EU will launch a second European hydrogen bank auction later this year, ramping up the budget from a pilot for which results were published on 30 April. A bigger budget will allow more projects to win subsidies, but developers might still have to bid at or below €1/kg to stand a chance of being successful. As a result of the pilot, the EU will subsidise seven renewable hydrogen projects in Spain, Portugal, Norway and Finland with a total €720mn ($768mn), to be disbursed as a fixed premium per kg produced over a 10-year period. The European Commission picked the projects that requested the least support and the auction cleared at €0.48/kg, far below the bid ceiling of €4.50/kg . A second auction later this year is slated to have a much larger budget of around €2.2bn. This could open the door for projects with less competitive bids, but developers may still have to bid for less than €1/kg, data released by the commission suggest. If another €2.2bn had been available to the "next best projects" in the pilot, bringing the total budget to nearly €3bn, the auction would have cleared at around €1/kg, the data indicate. Spanish projects would have been the main beneficiaries of the larger budget. But it would have also unlocked subsidies for projects that did not field any winners in the pilot, including Germany, France, Austria and the Netherlands. This suggests that projects in these countries might be able to get subsidies in the second auction. That said, some German projects that participated in the pilot are bound to get funds from a separate €350mn budget set aside by Berlin , meaning they could not take part in the next round. In any case, the second round could clear even far below €1/kg, if developers revise their bidding strategies now they have indications from the pilot on how low they might have to go. Such signposts were not available for the first round, other than from a Danish auction last year with similar parameters — which had indicated that winning bids in the hydrogen bank pilot were likely to stay well below €1/kg . The commission plans to tighten some of the eligibility criteria for the second round , which might prevent some projects from participating again. A draft document suggests winners of the second round would have to commission their plants within three years, down from five in the pilot. And developers would have to provide a completion guarantee equivalent to 10pc of the requested subsidies, up from 4pc. The second auction will also have a lower bid ceiling of €3.50/kg based on the draft, although this is highly unlikely to be tested by the successful submissions. Budget uncertainties While previous commission comments suggested a budget of around €2.2bn for the second round, the draft rules leave the exact funds open. The commission initially earmarked €800mn for the pilot and might top up the second round with the unused €80mn. It plans to set an unspecified slice of the budget aside exclusively for projects targeting offtake for maritime transport, adding a degree of complexity. Austria is planning to top up the second auction with €400mn , while others, such as Belgium , could follow suit. Moving the needle? While bids in the pilot auction came in well below the ceiling — and are bound to do so again in the second round — the funds will only be enough to support a fraction of the EU's 10mn t/yr renewable hydrogen production target by 2030. The pilot auction will subsidise 1.58mn t, or 158,000 t/yr, of production from the seven selected projects — assuming the support they secured will be enough to get them built as planned. If the next best projects from the pilot were to repeat their bids in a €2.2bn second round successfully, the round could support close to 300,000 t/yr. While this would lift subsidised output across both auctions to nearly 460,000 t/yr, it would still be less than 5pc of the 10mn t/yr target. Assuming developers that missed out in the first round shoot lower in the second and the volume-weighted average of successful bids is in line with the pilot's €0.45/kg, 480,000 t/yr could be subsidised. Together with the pilot, this would yield 640,000 t/yr, or just over 6pc of the EU's target, although extra funds from Germany, Austria and potentially others could lift this further. The EU hopes this initial operating support, combined with subsidies for capital expenses, infrastructure developments and demand-side initiatives, will be enough to kickstart the sector and other projects will follow even without hydrogen bank support. By Stefan Krumpelmann Renewable H2 projects selected in hydrogen bank pilot auction Project Coordinator Project location H2 output t/yr Electrolyser capacity MW Bid price €/kg Requested funding mn € eNRG Lahti Nordic Ren-Gas Finland 12,200 90 0.37 45.2 El Alamillo H2 Benbros Energy Spain 6,500 60 0.38 24.6 Grey2Green-II Petrogal Portugal 21,600 200 0.39 84.2 Hysencia Angus Spain 1,700 35 0.48 8.1 Skiga Skiga Norway 16,900 117 0.48 81.3 Catalina Renato PtX Spain 48,000 500 0.48 230.5 MP2X Madoqua Power2X Portugal 51,100 500 0.48 245.2 - European Commission Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Mitsui makes delayed exit from Paiton power project
Mitsui makes delayed exit from Paiton power project
Tokyo, 1 May (Argus) — Japanese trading house Mitsui completed on 30 April the ¥109bn ($690mn) sale of its stake in Indonesia's 2,045MW Paiton coal-fired power plant in east Java following multiple delays. Mitsui originally tried to complete its exit by the end of March 2022 . It said the procedures with Paiton's offtaker Indonesian state-owned power firm Persero took more time than expected without providing further details. Japanese thermal power producer Jera withdrew from Paiton by selling its 14pc share in 2021. Mitsui sold its 45.515pc share in Paiton Energy, as well as a 45.515pc stake in Netherlands-based subsidiary Minejesa Capital and a 65pc stake in Singapore-based IPM Asia that are related companies of the Paiton project. Mistui sold the stakes to RH International (RHIS), which is a Singapore-based subsidiary of Thai power producer Ratch, and Indonesian power company Medco Daya Abadi Lestari's subsidiary Medco Daya Energi Sentosa (MDES). Paiton Energy is now owned by RHIS, MDES and Qatar-based company Nebras Power. Mitsui did not disclose their ownership ratios. Paiton consists of the 615MW No.7, 615MW No.8 and the 815MW No.3 units, which sell electricity to Persero through an unspecified long-term contract. Mitsui now holds 9.6GW of power capacity assets globally, with 8pc being coal-fired projects. The exit from Paiton cut its coal-fired ratio by 8 percentage points, while raising its renewable ratio by 3 percentage points to 32pc. Growing global pressure against coal-fired power generation likely prompted Mitsui to exit Paiton. Energy ministers from G7 countries this week pledged to accelerate "efforts towards the phase-out of unabated coal power generation". By Nanami Oki Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
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