Australia to open 1.8GW renewables tender

Spanish Market: Electricity
25/08/26

The Australian government will open a new tender under its national renewable energy Capacity Investment Scheme (CIS) for 1.8GW of new developments in the state of Western Australia (WA), it said today.

Projects under this tender are to be built by 2030 and will feed into Australia's Wholesale Electricity Market (WEM), the smaller of two main power grids in the country.

This 11th CIS tender is likely the last for the WEM, provided all targets are met, national renewables services group and tender operator ASL said.

Registrations are open and bids can be entered over 27 August-22 October. Results are due in March 2027.

Specific generation types were not released in the government announcement on 25 August but will likely be laid out in tender guidelines on 27 August. As it stands, proponents can register to bid for a range of generation types including solar, wind and hydropower. Minimum nameplate capacity per project is 30MW.

Project proponents must for the first time join the government's new Developer Rating Scheme to participate in the latest CIS tender. The scheme assesses developers' credentials to boost confidence with local communities.

A minimum of 180MW is reserved for native First Nations groups. ASL encourages proponents to include 5pc or higher equity or revenue sharing arrangements with First Nations partners, although this is optional.

Projects must also join WA's Reserve Capacity Mechanism to help maintain reliable power supply.

The latest tender will place "a stronger emphasis" on the deliverability of projects, including their ability to attract financing, the government said.

CIS tenders this year have already backed 1.9GW of renewable generation and 482MW of storage in WA, the government said. Two other projects in the state totalling 250MW from earlier CIS rounds are being built, it added.

Australia wants to tender 40GW of renewable generation and dispatchable capacity under the CIS by 2026-27, to support its 82pc renewable electricity target for 2030.

Thus far CIS tenders 1 to 8 have awarded 22.7GW of clean generation and around 1.62GW/62.7GWh of energy storage. Tenders 9 and 10 are pending results. They will add another 5GW of generation and 4GW/16GWh of storage it fully awarded.

By Liang Lei

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24/08/26

Vietnam’s Da Nang targets 1GW renewables in 2026-30

Singapore, 24 August (Argus) — Da Nang city, home to Vietnam's first free trade zone, is aiming to develop over 1GW of renewable power capacity in 2026-30, comprising hydropower, solar, wind and biomass facilities. The target includes up to 373MW small hydropower, 300MW pumped-storage hydropower, 100MW utility-scale solar, 100MW rooftop solar, 100MW on- and near-shore wind, and 58MW biomass capacity, state utility EVN said on 21 August. Da Nang will also continue to implement waste-to-energy projects, EVN said. The city's first plant is scheduled to operate by 2026-27, the government said earlier this year. The city will prioritise renewables deployment in industrial areas with high power demand and promote direct power trading between power generators and large electricity consumers, EVN said. The city also aims to have 50pc each of government offices and households installing rooftop solar panels for self-consumption — in line with a national target set earlier this year. The Da Nang Free Trade Zone was established in June 2025, with space allocated for manufacturing, logistics and digital services. Vietnam is targeting up to 38GW of on- and near-shore wind capacity by 2030, alongside up to 73.4GW of solar and 34.7GW of hydropower in its latest power development plan. These figures are up from existing capacities of 6.2GW of wind, 19.3GW of solar and 24.7GW of hydropower in 2025, according to the International Renewable Energy Agency. Argus last assessed Vietnamese current-year wind and solar I-RECs at $0.32/MWh on 20 August. By Liang Lei Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

Brazil's GNA II halts power generation indefinitely

20/08/26

Brazil's GNA II halts power generation indefinitely

Sao Paulo, 20 August (Argus) — Brazilian power firm GNA halted power generation from the GNA II natural gas-fired power plant after a technical failure damaged the plant's operation on 10 August, it said on 19 August. The 1.7GW GNA II plant is located in Acu port in southeastern Rio de Janeiro state, and is fired by LNG. It is Brazil's largest operating thermoelectric plant. GNA is assessing the cause of the failure and has no timeframe for operations to return, it said. The company also notified national grid operator ONS about the issue and it has been taken into consideration in ONS' latest operational schedule. The LNG terminal, the regasification terminal and the GNA I plant close to GNA II were unharmed by the failure and are operating normally. There were no victims nor environmental damage, GNA said. By Maria Frazatto Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

Indonesia solar groups seek better land, permit rules

20/08/26

Indonesia solar groups seek better land, permit rules

Singapore, 20 August (Argus) — Indonesia's solar power developers are hoping for improved land acquisition and permitting rules to help boost project development as the country seeks to scale up photovoltaic generation in the coming years, delegates heard at the Indonesia Sustainable Energy Week conference on 19 August. Developers currently face different land approval processes across Indonesia, which is a significant issue since solar projects often require large land areas, said Mada Habsari, chairperson of the Indonesian Solar Energy Association (AESI). Land acquisition has been in the spotlight since Indonesian president Prabowo Subianto firmed up a 100GW national solar target last year, up from under 2GW currently. Vacant mining land in regions such as East Kalimantan and South Sumatra, could be used for solar facilities — on top of the more frequently discussed ground-mounted or reservoir floating models, said vice-president at state utility PLN, Ricky Faizal. The government has identified about 9,000 hectares of land to help advance an initial 30GW tranche of the national 100GW solar target, said deputy minister for energy and mineral resources Yuliot Tanjung on the sidelines of the conference. AESI believes PLN's process for selecting private developers for new solar projects could be further improved. There have been projects that have been awarded for construction based on lowest tariff bid, but subsequently fell through because land could not be acquired, said Refi Kunaefi, AESI's lead for the independent power producers taskforce. An alternative approach where PLN requests initial plans from developers first, and then provides up to a year to secure land tenure before negotiating the final tariff rates, could be more feasible, Refi said. Any changes to how state agencies engage private developers for renewable energy could be significant — the country's 10-year power development plan envisions the private sector to undertake over 70pc of new clean energy buildouts up to 2034. Rooftop backlog Demand for industrial and rooftop solar systems has grown quickly in the past two years, because of sustainability requirements multinational companies operating in Indonesia abide by, and more recently as a response to diesel shortages, said Emmanuel Jefferson Kuesar, chief executive of developer Sun Energy. But the company has had to delay clients because Indonesia's rooftop solar quarter has been fully subscribed, he said. Indonesia allocated about 485MW for grid-connected rooftop installations at the start of the year — 304MW of which were for projects already previously on waitlist. More broadly the latest 10-year power development plan envisions over 3GW of rooftop solar additions between 2025-2034, split into yearly quotas. Rooftop solar development for now will be guided by quotas, which are updated every six months to a year, said Ricky. The utility is seeking to improve power system flexibility, and modernise distribution networks, to support a greater input of renewable power, he said. Indonesia currently has over 120 solar facilities of under 1MW — the typical size of commercial rooftop installations — registered to issue I-RECs. Current-year Indonesian solar I-RECs were recently offered at under $3/MWh. Financing headwinds Project financing remains yet another roadblock, developers said, citing both institutional rules and recent headwinds. Indonesian officials have often discussed the 100GW solar goal as spurring rural electrification and reducing dependency on diesel generators. But distributed rural projects are harder to finance because of their smaller scale, Mada said. The AESI is working on aggregating rural projects to improve their financing prospects, and seeking blended financing opportunities, she said. Some renewables projects that were previously bankable have been negatively affected by Indonesia's weakening currency and rising lending rates in the past months. Some institutional investors also have blanket bans on sectors such as mining, which becomes a roadblock to building solar projects for mining firms, Kuesar said. But there are still opportunities with investors such as pension funds seeking long-term stable returns, since solar projects can sign power supply agreements of 20-25 years, he said. By Liang Lei Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

Asia power grid delay may incur billions in cost: Ember

20/08/26

Asia power grid delay may incur billions in cost: Ember

Singapore, 20 August (Argus) — Delays in the development of the Asean Power Grid (APG) could result in billions of dollars in economic losses for the region and alter energy transition pathways, according to a report by think-tank Ember. Members of the Association of Southeast Asian Nations (Asean) have announced their target to establish the Asean power grid by 2045 . Under an assumed completion date of 2035, each year that the project is delayed beyond this will add $2.6bn in economic losses, according to the report released today by Ember. A five-year delay for the APG would cost the region almost $14bn, as well as 55bn m³ of additional gas, and over 71mn t of CO2 emissions. Ember uses 2035 as the baseline year, based on Singapore's plan to import 6GW of power via interconnections by then, as well as regional ambitions such as a 2,000MW Malaysia-Singapore interconnection targeted to begin operating in 2030. Asean's power demand is set to continue rising because of industrial growth, data centres, electrification, and cooling demand. Electricity demand in southeast Asia is set to almost double to 2,000 TWh/yr in 2050 from 1,300 TWh/yr today, according to energy watchdog the International Energy Agency (IEA). Coal and gas generated over 73pc of the region's electricity demand in 2025, compared with 5pc from solar and wind, according to Ember. Asean's vulnerability because of its reliance on fossil fuel imports has become apparent especially because of the US-Iran war. Southeast Asia gets about a third of its oil and refined products from the Middle East, and the conflict has raised regional gas prices by as much as 60pc compared with pre-war levels, the report said. Some countries offer subsidies to help absorb some of these price shocks, but "for economies that depend on affordable power to support industry and attract investment, this exposure is a major risk to economic competitiveness," the report said. The region's energy import bill is projected to reach a record $160bn this year, and is set to increase further in the decades ahead, potentially rising to $400bn, or 5pc of its economy, by 2050 based on current policy settings, according to the IEA. A five-year delay in the establishment of the APG would also mean 7.2GW of solar power would not be developed in Asean in 2035. Singapore would have to install an additional 300MW of gas-fired capacity to meet demand in 2035 locking in fossil fuel infrastructure with economic lifetimes that can span 25 years, as well as take-or-pay contracts, and this could extend fuel imports. Countries with abundant renewables such as Indonesia, Laos, Cambodia and Myanmar could collectively lose $1.1bn in revenue for each year the APG is delayed because they would be unable to monetise renewable resources through power exports, according to the report. Recommendations The APG would link national power systems to enable the sharing of reserve capacity to offset local shortages, and enhance system security, reliability and market efficiency, including through reducing the need for conventional plants or battery storage, the report said. It would also enable renewable energy to be developed where resources are most cost-effective. For the APG to materialise, political discourse needs to shift away from just discussions to commitment that extends beyond electoral cycles, and this has to be supported by working-level co-ordination, the report said. The Lao PDR–Thailand–Malaysia–Singapore Power Integration Project (LTMS-PIP) demonstrates that such co-operation is possible. Secondly, cross-border projects need to be made bankable through harmonised and transparent tariff frameworks and regionally co-ordinated wheeling charges. Cost sharing should also be done fairly, whereby costs are allocated according to each party's perceived benefits. Regional financing mechanisms such as the Asean Power Grid Financing Initiative are also important in mobilising capital. Lastly, while bilateral projects are more pragmatic in the near term because they require less harmonisation of regulatory frameworks and implementation timelines, their governance and institutional frameworks from the outset should be built with a view to expand easily into multilateral power trade, Ember said. By Prethika Nair Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

US' Alcoa, Australia's Equus ink 10-year gas sales deal

14/08/26

US' Alcoa, Australia's Equus ink 10-year gas sales deal

Sydney, 14 August (Argus) — Australian gas developer Equus Energy has signed a binding 10-year gas sales agreement (GSA) with global aluminium producer Alcoa to supply gas from the planned Equus project offshore Western Australia to Alcoa. Equus will provide 50 TJ/d of gas to Alcoa, equivalent to 182PJ over the term of the deal, the company said on 14 August. Alcoa will use the supplies to power its expanding portfolio of Western Australia-based (WA) alumina refineries. In return, Alcoa will provide advance payment of $30mn to complete a front-end engineering design (Feed) study for the Equus project in Western Australia's North West Shelf region. The funding will cover project costs until it reaches a final investment decision (FID), Equus said. It did not specify a timeline for the FID. Equus, which was known as Western Gas until December 2025, completed a pre-Feed study for the Equus project in May, confirming project design of 50 TJ/d of domestic gas, 2mn t/yr of LNG for export markets, and 12,000 b/d of condensate production over a 15-year project life. The project will address a peak day gas supply shortfall in Western Australia and will represent 5pc of the Western Australian domestic gas market upon completion, Equus said. Annual peak day gas demand in Western Australia is set to increase from 2026 by 36pc to 558 TJ/d in 2035 with the winter season recording the highest demand levels, according to the Australian Energy Market Operator's (Aemo) 2025 Western Australian Gas Statement of Opportunities . This is despite an expected decline in overall annual gas consumption over the same period due to increased large-scale wind and solar generation, Aemo said. The deal with Alcoa will fully satisfy Equus' commitments under Western Australia's domestic gas reservation policy, the company said. The reservation policy mandates that Western Australia-based gas producers retain at least 15pc of production for sale in the domestic market over a project's life. Alcoa operates the 30.5mn t/yr bauxite mine and the 4.2mn t/yr Pinjarra and 2.85mn t/yr Wagerup alumina refineries in Western Australia. Alcoa bought most of Australian mining company South32's aluminium supply chain stakes in June, including the 37mn t/yr Worsley bauxite mine and 4.4mn t/yr Worsley alumina refinery in Western Asutralia. Alcoa signed a three-year gas sales agreement with Australian independent Woodside Energy for 31.1PJ in June, which will begin in 2027. The company also secured a 10-year gas sales agreement with LNG operator Chevron in December 2024 for 130PJ, starting from 2028. This has built on Alcoa's existing 10-year gas sales agreements with Chevron, ExxonMobil and Australian independent Warrego Energy for a total of 198PJ of gas to its alumina refineries in Western Australia, starting in 2024. By Daniel Gage-Brown Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

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