The technical requirements for these systems are significantly more complex than those for traditional telecommunications or even static offshore wind cables. In a tidal context, the cable must often remain dynamic, meaning it is suspended in the water column or subject to continuous movement. This necessitates the use of advanced armor layering and bend stiffeners that prevent structural failure over decades of service. As the industry moves toward utility scale deployment, the pressure to reduce levelized cost of energy (LCOE) is driving significant innovation in the materials and configurations used in subsea cable technology to minimize both capital expenditure and ongoing maintenance requirements. Beyond the immediate electrical benefits, the resilience of these cables directly impacts the insurance risk profile of a project, influencing the availability of capital for large scale marine energy developments.

Mechanical Resilience in Dynamic Marine Environments

One of the most significant hurdles in tidal energy grid integration is the mechanical fatigue experienced by cables in the splash zone and the water column. In areas where tidal flow is strong enough to be commercially viable, the forces exerted on subsea infrastructure are immense. Standard static cables are designed to be buried and remain motionless, but tidal systems frequently require dynamic sections that connect a floating or seabed mounted turbine to a static export line. These dynamic sections are subject to millions of cycles of bending and tension over their lifespans. Engineers are addressing this by integrating specialized subsea cable technology that features high tensile steel wire armoring and high density polyethylene (HDPE) outer sheathing to provide a balance between flexibility and protection.

The implementation of bend limiters and stiffeners at the points where the cable enters the turbine or a subsea junction box is essential for preventing localized stress concentrations. Without these components, the cable would quickly succumb to copper fatigue or insulation cracking, leading to catastrophic electrical failure. Additionally, the use of buoyancy modules allows cables to be configured in “lazy wave” or “S-wave” shapes, which decouple the movement of the turbine from the connection point on the seabed. This configuration ensures that the cable can accommodate the motion of the tides without being pulled taut or dragging against rocky substrates, thereby extending its service life significantly. The design process now incorporates advanced computational fluid dynamics (CFD) and finite element analysis (FEA) to simulate the precise stresses a cable will face in a specific tidal race, allowing for a highly customized armoring strategy that avoids over engineering while ensuring safety.

High Voltage Transmission and Power Loss Mitigation

As tidal arrays grow in size and move further from the shore, the efficiency of power transmission becomes a dominant factor in project economics. Transmitting power at low voltages over long distances leads to substantial resistive losses, which can undermine the total energy yield of a project. To combat this, modern subsea cable technology is shifting toward higher voltage ratings, moving from traditional 33 kV systems to 66 kV and even 132 kV for larger export lines. Higher voltages allow for the transmission of more power through smaller conductors, reducing the overall weight and cost of the cable while improving electrical efficiency. This shift requires the development of new dry mate and wet mate connectors that can handle the increased electrical stress without risking breakdown in the pressurized underwater environment.

Insulation materials play a vital role in maintaining the integrity of these high voltage links. Cross linked polyethylene (XLPE) has become the industry standard due to its excellent thermal and electrical properties. However, in the marine environment, the risk of water treeing, a form of electrical degradation caused by moisture ingress, is a constant concern. Advanced subsea cable technology now utilizes metallic barriers, such as lead sheaths or corrugated aluminum, to provide a hermetic seal against the surrounding seawater. These layers are critical for ensuring that the insulation remains dry and effective throughout the 25 to 30 year operational life of the tidal array, even under the high pressure conditions found at depth. Newer designs are also exploring the use of thermoplastic insulation materials that offer higher thermal stability and recyclability compared to traditional XLPE, potentially simplifying the decommissioning process at the end of the project’s life.

Installation and Maintenance Protocols for Tidal Arrays

The installation of subsea cables in high energy tidal sites is a high risk operation that requires specialized vessels and precise timing. The very currents that make a site attractive for power generation also make it difficult for ships to hold position during cable laying activities. Installation windows are often limited to slack water periods, which may only last for an hour or less. This operational constraint has led to the development of rapid deployment systems within subsea cable technology, such as quick connect dry mate and wet mate connectors. These components allow for the mechanical and electrical connection of turbines to be performed efficiently without the need for complex underwater splicing. Vessel deck layouts are also being optimized to carry longer continuous lengths of cable, reducing the number of subsea joints which are historically the weakest points in a transmission link.

Maintenance is another area where technological advances are reducing risks and costs. Remote operated vehicles (ROVs) equipped with specialized sensors are now used to conduct regular inspections of cable routes and connection points. These vehicles can detect signs of abrasion, cable exposure, or biofouling before they lead to failure. In many cases, the synchronization of tidal turbine outputs requires a sophisticated offshore electrical infrastructure that can handle fluctuating power loads before transmitting energy to the primary grid. By integrating monitoring systems directly into the cable structure, such as fiber optic strain and temperature sensors, operators can receive real time data on the health of the connection, enabling a proactive approach to asset management. This predictive capability allows for maintenance to be performed during planned outages rather than as an emergency response to a fault, significantly improving the overall project uptime.

Materials Innovation for Enhanced Subsea Connectivity

The selection of materials for the core components of subsea cables is undergoing a shift as manufacturers prioritize environmental sustainability alongside technical performance. The transition away from certain heavy metals and toward recyclable polymers is representative of the industry’s commitment to reducing its ecological footprint. Within the context of subsea cable technology, several key material innovations are currently being deployed to enhance performance:

• Advanced aluminum conductors which provide a lighter and more cost effective alternative to copper for certain long distance applications, reducing the weight of the dynamic section.
• Enhanced semi conductive layers that reduce electrical stress at the interface between the conductor and the insulation, preventing localized heating.
• Biofouling resistant outer coatings that prevent the accumulation of marine organisms which can increase the drag and weight of the cable in high flow areas.
• Smart sensors integrated into the armor layers to provide continuous monitoring of mechanical strain and thermal profiles through the entire cable length.
• Thermally stable insulation materials that can operate at higher temperatures, allowing for increased power throughput during peak tidal flows.
• Zinc coated steel wire armor which offers superior corrosion resistance compared to traditional galvanized options in highly oxygenated tidal environments.
• Aramid fiber reinforcement layers that provide high tensile strength with minimal weight, particularly useful for floating tidal platforms.

These material improvements are not merely incremental; they represent a fundamental change in how subsea cable technology is designed to interact with the marine environment. By utilizing lighter and more durable materials, developers can reduce the size of the vessels required for installation, which in turn lowers the overall carbon footprint and cost of the project. The move toward modularity in cable design also allows for individual components to be replaced or upgraded as new materials become available, ensuring that the infrastructure stays relevant throughout its long operational life.

Enhancing Grid Stability Through Advanced Cable Design

The ultimate goal of advancing subsea cable technology is to ensure that tidal energy can be integrated into the national grid with the same level of reliability as traditional thermal power plants. Grid operators require a steady and predictable flow of energy, and any interruption due to undersea cable failure can cause significant instability. To address this, developers are focusing on redundant cable configurations and ring main systems that allow power to be rerouted if a single cable section is damaged. This system level approach to connectivity ensures that the failure of one turbine or connection lead does not take the entire tidal array offline. By distributing the transmission risk, developers can ensure a more consistent revenue stream and a higher degree of grid security.

In addition to physical redundancy, the electrical characteristics of the cables are being optimized to manage reactive power and voltage fluctuations. As tidal energy is naturally intermittent, the cables must be capable of handling rapid changes in power flow without overheating or causing voltage drops. The integration of power electronics at both the subsea and onshore ends of the cable further enhances this stability, providing the necessary control to match the tidal output with grid demand. This includes the use of active power filtering to manage harmonics generated by the turbine’s power converters. As subsea cable technology continues to evolve, it will play an increasingly central role in the global transition to a low carbon energy future, providing the reliable links necessary to tap into the vast, predictable power of the oceans. The synergy between cable engineering and grid management will ultimately determine the success of tidal energy as a utility scale power source.

The investment in Egypt Renewables Holdings B.V. will give the EBRD a minority equity stake, while Scatec will remain the majority shareholder. The vehicle is intended to finance the acquisition, development and construction of renewable energy infrastructure in Egypt and the wider southern and eastern Mediterranean (SEMED) region.

EBRD Takes Minority Stake in Scatec Investment Vehicle

The equity commitment will provide long-term capital for the renewable energy portfolio, bringing together the EBRD as an institutional investor and Scatec as the majority commercial stakeholder. The vehicle’s initial focus is Egypt, where the planned capacity additions are intended to strengthen energy security and reduce dependence on imported fossil fuels.

The EBRD’s investment of up to USD 221 million is an equity commitment rather than a conventional loan. The Bank says the arrangement will support the development of renewable energy infrastructure through its role as a shareholder, while Scatec gains access to institutional capital to advance its regional growth plans.

The portfolio is planned to include 2.7 GW of solar capacity, 900 MW of wind capacity and 4.2 GWh of battery energy storage. The announcement does not provide a schedule for developing the capacity or identify the individual projects that will be financed through the vehicle.

Energy Security Drives Egypt Renewable Energy Investment

Harry Boyd-Carpenter, Managing Director of the EBRD’s Sustainable Infrastructure Group, said the investment would help address Egypt’s energy challenges.

“This equity investment marks an important step in strengthening Egypt’s energy security,” he said in the announcement. “By partnering with Scatec, the EBRD is providing long-term capital as a shareholder, helping to expand access to reliable renewable energy. This will help to address one of the country’s most pressing development challenges while reducing reliance on imported fossil fuels.”

The planned combination of solar and wind generation with battery energy storage forms the basis of the portfolio’s renewable energy and storage strategy. The EBRD identifies energy security and lower dependence on imported fossil fuels as the principal objectives of the investment.

Scatec Chief Executive Officer Terje Pilskog said Egypt had become one of the company’s most important markets.

“Egypt has become one of Scatec’s most important markets, and this platform reflects both the scale of what we are building there and the quality of the assets we have developed. Partnering with the EBRD brings institutional capital and a long-term commitment that will accelerate Scatec’s growth ambitions across the region.”

Projects Linked to Egypt’s Nexus Initiative

The renewable energy projects supported by the investment will be developed under the energy pillar of Egypt’s Nexus of Water, Food and Energy initiative. The initiative was launched at the COP27 climate conference in Sharm El Sheikh.

According to the EBRD, the energy pillar supports private-sector renewable energy capacity, electricity-network investment, skills development and a just energy transition. The new investment vehicle therefore forms part of a broader institutional framework for advancing Egypt’s energy priorities.

The portfolio’s initial targets include 2.7 GW of solar capacity, 900 MW of wind capacity and 4.2 GWh of battery storage. The EBRD has not disclosed how the equity commitment will be allocated across individual projects or when the planned capacity will be delivered.

EBRD Builds on Existing Partnership With Scatec

Scatec ASA is a Norway-based integrated power producer specialising in renewable energy solutions. Founded in 2007, the company has been listed on the Oslo Stock Exchange since 2014.

The EBRD describes Scatec as a long-standing partner in renewable energy and battery storage projects across the Bank’s countries of operation. The new investment vehicle extends that relationship through a direct equity stake, with Scatec retaining majority ownership.

The arrangement provides a structure for financing the acquisition, development and construction of renewable energy infrastructure in Egypt and the wider SEMED region. The Bank’s participation is intended to provide long-term shareholder capital for the portfolio.

Investment Expands EBRD’s Presence in Egypt

The equity commitment builds on the EBRD’s existing investment activity in Egypt. Since beginning operations in the country in 2012, the Bank has invested more than USD 17.9 billion across 238 projects, according to its figures.

The new vehicle is intended to support renewable energy infrastructure initially in Egypt, with the potential to facilitate projects elsewhere in the SEMED region. However, the EBRD’s announcement does not specify additional countries, individual projects or a timetable for expanding beyond the initial portfolio.

The planned 2.7 GW of solar capacity, 900 MW of wind capacity and 4.2 GWh of battery storage define the initial scope of the investment. With the EBRD as a minority shareholder and Scatec retaining majority ownership, Egypt Renewables Holdings B.V. will provide a structure for pursuing the planned renewable energy and storage development.

The EBRD has committed up to USD 221 million in equity, but the announcement does not disclose a detailed breakdown of the commitment or a completion schedule for the planned capacity additions.

The proposed project is planned for Sinop, in Turkey’s Black Sea region. AtkinsRéalis Chief Executive Officer Ian Edwards said in a LinkedIn post that the company would conduct a feasibility study to advance the potential construction of CANDU reactors at the site.

The development follows an agreement between Canada and Turkey to strengthen their strategic partnership, including cooperation in energy, defence, security, trade and investment. Carney said the Turkish government would make the final decision on the nuclear project, but he believes Canada’s prospects have improved.

AtkinsRéalis Explores CANDU Technology for Sinop

Turkey has held discussions with several countries about its planned second nuclear power plant, including Canada, South Korea, Russia, China and Japan. The proposed facility is planned for Sinop, where AtkinsRéalis is exploring the potential application of its CANDU reactor technology.

Speaking to reporters in Istanbul, Carney said there was active competition for the project and suggested a decision could be made before the end of 2026.

He highlighted Canada’s nuclear technology, partnerships with Turkish businesses and potential to develop elements of the supply chain as factors supporting its proposal.

“If you would have asked us a year ago how we would have pegged the chances, they would have been very low. Now there are good chances. There’s real competition, of course,” Carney said.

The feasibility study is an early step in assessing the potential project. The announcement does not confirm a construction contract, a final technology selection or a construction schedule for the proposed plant.

Canada and Turkey Strengthen Nuclear Energy Cooperation

The nuclear discussions form part of a broader effort by Canada and Turkey to expand economic and strategic cooperation. During Carney’s visit to Ankara, the two NATO allies upgraded their bilateral relationship to a strategic partnership, with energy identified as one of its principal areas of cooperation.

The agreement aims to create further opportunities for Canadian and Turkish businesses through expanded trade and investment. The countries also announced plans to increase collaboration across the energy sector, including civil nuclear energy, liquefied natural gas (LNG) and renewable energy.

For AtkinsRéalis, the potential Sinop project would provide an opportunity to explore the use of Canadian CANDU technology in Turkey’s nuclear power development programme. Carney also pointed to cooperation with Turkish companies in construction and the potential to establish supply-chain links as elements of Canada’s proposal.

Turkey’s government will ultimately determine which partner or technology is selected for the second nuclear power plant. The country has been considering proposals from several international participants, and the feasibility study does not guarantee that AtkinsRéalis will be selected.

Turkey’s Nuclear Programme Includes Multiple Planned Plants

Turkey is pursuing nuclear power development at several locations. Its first nuclear power station is under construction at Akkuyu, in the Mediterranean province of Mersin, by Russia’s state-owned nuclear energy company Rosatom.

The Akkuyu project is being developed under a USD 20 billion agreement signed in 2010. Rosatom said in October 2026 that it expected a nuclear start-up at the site by the end of the year.

Beyond Akkuyu, Turkey plans a second nuclear power plant at Sinop and a third in the northwestern region of Thrace. The potential involvement of AtkinsRéalis in Sinop remains under consideration as Turkey engages with international partners.

The selection of a technology provider and project partner will be a significant step in determining how the second plant proceeds. At present, the AtkinsRéalis feasibility study represents progress in evaluating the CANDU option, rather than confirmation that construction will go ahead with the Canadian company.

Feasibility Study Precedes a Final Project Decision

Carney said the Turkish government would make the final decision on the second nuclear power plant and noted that competition from other international suppliers remains strong. He nevertheless expressed greater confidence in Canada’s position following the strategic partnership agreement.

AtkinsRéalis has identified the Sinop site as the focus of its feasibility work for potential CANDU reactor construction. The study is intended to advance consideration of the technology, while the broader bilateral agreement creates a framework for further cooperation in civil nuclear energy and other sectors.

No final contract, investment amount or construction timetable for the Sinop plant was announced in the report. The next major milestone will be Turkey’s decision on the project and the technology and partners it chooses to pursue.

The green hydrogen technology project has passed the evaluation process and been selected to enter the grant agreement preparation stage. It involves a planned investment of up to EUR 70.7 million, including the EU funding, to industrialise the Končar Smart Power Interface (KSPI), a 2.5 MW platform designed to convert medium-voltage grid electricity into direct current (DC).

Končar Nexus Targets Electrolyser Power Conversion

The Končar Nexus project focuses on developing and industrialising technology that supports the electrical systems required for green hydrogen production. Electrolysers need stable, high-quality DC power, while conventional grid connection systems can rely on multiple components, interfaces and conversion stages.

Končar’s Smart Power Interface is designed to combine several functions within a compact, modular platform. The technology is intended primarily for electrolysers used in green hydrogen production, although it can also serve other industrial processes requiring direct current.

According to Končar, integrating traditionally separate components into a single solution is expected to reduce energy losses, simplify installation and improve the efficiency and flexibility of power systems.

The project addresses an infrastructure bottleneck in the decarbonisation of energy-intensive sectors, where efficient electricity conversion is important for industrial-scale hydrogen production and other DC-powered applications.

Modular 2.5 MW Platform Integrates Key Systems

The Končar Smart Power Module (KSPM) is a standardised 2.5 MW modular platform based on solid-state transformer technology. It integrates medium-voltage interfacing, protection, power conversion, galvanic isolation, auxiliary power supply, liquid cooling, and digital monitoring and control within a single containerised unit.

By consolidating these functions, the platform is designed to provide a more integrated approach to connecting medium-voltage electricity networks with equipment that requires direct current. Its initial intended application is green hydrogen electrolysis, but the technology’s design also allows use in other industrial processes that require DC power.

The green hydrogen technology project will industrialise the technology for production and testing, rather than focusing solely on engineering development. Its planned manufacturing capability is intended to support serial assembly and dispatch of KSPM units.

Two Zagreb-Area Sites to Support Development and Production

Končar Nexus is planned across two sites in the Zagreb area, with separate roles for engineering validation and manufacturing.

The Fallerovo site will host engineering and validation activities. Planned facilities include a validation laboratory, engineering offices and a new 110 kV substation. The substation is intended to enable full-scale system testing and industrial qualification.

The second location, in Sesvetski Kraljevec, is planned as a greenfield production site. It will be developed for serial assembly, testing and dispatch of KSPM units.

According to the project update, the production facility is designed for a maximum output of up to 200 units annually. This planned capacity would establish a dedicated manufacturing base for the modular power technology.

EUR 70.7 Million Investment Includes EU Innovation Fund Support

The Končar Nexus project involves planned capital expenditure of up to EUR 70.7 million, with EUR 39.3 million expected from the European Commission’s Innovation Fund. The grant has not yet reached the final agreement stage, as the project has been selected to proceed with grant agreement preparation.

Končar is targeting financial closing by 31st March 2029. The system is scheduled to enter operation on 1st January 2031, according to the project update.

The funding programme supports innovative technologies intended to contribute to decarbonisation while strengthening industrial competitiveness. For Končar Nexus, the focus is on industrialising power conversion equipment that can support green hydrogen production and other industrial applications requiring direct current.

EU Innovation Fund Selects 77 Projects

In the latest funding call described in the announcement, the European Commission selected 77 projects from 23 European countries, with total funding of EUR 3.4 billion.

Končar Nexus is among the selected projects, with its proposed investment centred on power conversion technology for electrolysers and other industrial processes. The project combines engineering and validation infrastructure with a planned production facility, aiming to move the modular platform towards industrial-scale manufacturing.

The planned facilities, production capacity and funding schedule outline the next stages of development. Končar is targeting financial closing in 2029 and system operation from 2031, subject to completion of the grant agreement process and project implementation.

Published on 22nd October 2026, the preliminary draft initiates the process of amending and updating the 2025 Site Development Plan. It builds on the current draft amendment to Germany’s Offshore Wind Energy Act (WindSeeG) and addresses future offshore wind development areas, coordination with grid connections and potential cross-border projects.

Alongside the draft plan, the BSH has released a draft scoping document for the Strategic Environmental Assessment, supported by maps and additional studies. Authorities and members of the public have until 3rd December 2026 to submit comments as part of the consultation process.

Germany Identifies 14 Areas for Offshore Wind Development

The preliminary draft proposes designating 14 areas for future offshore wind projects across several planning zones. According to the German Offshore Wind Energy Association (BWO), the proposed areas include four sites in zone N-14, eight in N-16, and two additional sites identified as N-6.9 and N-12.7.

The draft also identifies 13 further sites for potential future development. These additional areas are not expected to receive formal designation during the current planning process.

BWO has welcomed the proposed site sizes of approximately 1 GW each and the BSH’s plans to carry out centralised preliminary investigations of additional sites. The association believes these measures could broaden participation in offshore wind auctions, strengthen competition and reduce planning risks.

The preliminary draft also proposes an average adjusted power density of 7.3 MW/km² for new sites in zones 4 and 5. This is below the general upper limit of 8 MW/km² advocated by BWO.

Power density determines the installed generation capacity within a given offshore area. The association supports a lower density approach to help reduce wake effects between turbines and improve electricity generation.

Cross-Border Projects Could Support Offshore Wind Generation

International cooperation is another element of Germany’s updated offshore wind planning framework. The preliminary draft allows cross-border projects to contribute towards the country’s national capacity targets.

BWO has highlighted cooperation with Denmark as an opportunity to develop offshore wind projects connected across national borders. The association referred to a joint study with the German Association of Energy and Water Industries (BDEW), which examined the relationship between turbine density, cross-border connections and electricity generation.

According to the study, lower power densities in German waters, combined with connections to offshore wind farms in neighbouring countries, could increase electricity generation while reducing costs per kilowatt-hour.

The proposed approach places cross-border coordination alongside domestic site designation and grid planning as Germany works towards its offshore wind expansion target.

Industry Calls for Contracts for Difference in Future Auctions

While welcoming the long-term planning framework, BWO has stressed that Germany’s offshore wind ambitions will also depend on investment conditions and regulatory certainty. The association argues that the ongoing amendment to the Offshore Wind Energy Act should introduce mechanisms that improve project financing and support investment decisions.

BWO is calling for indexed, two-sided Contracts for Difference (CfDs) to be used in all future offshore wind auctions instead of a two-stage model.

Stefan Thimm, Managing Director of BWO, said the preliminary draft provides a long-term outlook for offshore wind development, while emphasising the need for political and regulatory conditions that enable planned sites to translate into investment.

Contracts for Difference can help reduce revenue uncertainty by linking payments to an agreed reference price. BWO’s proposal reflects its position that the future auction framework should provide greater predictability for offshore wind investments.

BWO Questions a Uniform Overbuilding Requirement

The association has also raised concerns about a proposed uniform requirement for offshore wind farms to install generation capacity 10% above their grid connection capacity.

Overbuilding allows a wind farm’s installed capacity to exceed the maximum power its grid connection can transmit. Although this can increase the use of grid infrastructure when generation is below the connection limit, it may also raise investment costs and lead to additional curtailment during periods of high wind generation.

A study by Frontier Economics, commissioned by BWO and BDEW, found that the economically optimal level of overbuilding ranges from 5% to 10%, depending on site-specific conditions.

On this basis, BWO supports setting individual requirements for each offshore wind site rather than applying a uniform percentage across all projects. The association argues that site-specific assessments would better reflect differences in project conditions and economics.

Grid Development Must Align With Offshore Wind Construction

Coordinating offshore wind construction with the availability of grid connections remains another planning priority. BWO has emphasised that the development sequence for projects scheduled to enter operation by 2038 should support a steady expansion aligned with grid infrastructure timelines.

The association has also welcomed the draft’s integrated approach to extending the operating life of existing offshore wind farms and planning the future reuse of their sites.

BWO is calling for grid connections to remain available until decommissioning activities have been completed. It also wants dismantling work and subsequent construction plans to be coordinated sufficiently in advance.

These issues form part of the wider challenge of aligning offshore wind development, electricity transmission and the management of existing infrastructure as Germany plans for additional capacity.

Consultation Will Inform the Updated Site Development Plan

BWO plans to review the preliminary draft’s detailed provisions with its member companies during the public consultation period before submitting its comments in early December.

The consultation provides an opportunity for stakeholders to respond to proposed offshore wind areas, environmental assessment requirements, grid coordination and other planning provisions before the updated plan is finalised.

Until the revised Site Development Plan is formally adopted, the 2025 plan, as most recently amended, will remain in force.

The preliminary draft sets out a pathway towards Germany’s target of 70 GW of offshore wind capacity by 2045. Its implementation will depend on the final planning framework, investment conditions, grid infrastructure development and coordination between national and cross-border projects.

The order marks Nordex’s entry into the New Zealand wind energy market. The agreement also includes a 30-year service contract, covering the turbines over an extended operating period.

The New Zealand wind farm is located in the eastern foothills of the Lammermoor Range in the Otago region. With average wind speeds exceeding 8 metres per second, the site offers conditions for wind power generation. Installation of the first turbine, mounted on a 90-metre tubular steel tower, is scheduled to begin in early 2028, with commissioning of the first unit planned for mid-2028.

Nordex Supplies 40 Wind Turbines for Puke Kapo Hau

The order comprises 40 Nordex N133/4.8 turbines, providing a total installed capacity of 192 MW. The project represents the company’s first supply agreement in New Zealand and establishes a commercial relationship with Mercury, a major electricity generation and retail company in the country.

The accompanying 30-year service agreement forms a key part of the deal. Nordex will provide long-term service support for the turbines, while the agreement is intended to support Mercury throughout the wind farm’s operating lifecycle.

The Puke Kapo Hau development adds to Mercury’s wind energy activities and gives Nordex an entry point into a new national market. The company plans to combine its turbine technology and project experience with local expertise as it prepares for project execution and subsequent operations.

Installation Planned to Begin in Early 2028

The Puke Kapo Hau wind farm is planned for the eastern foothills of the Lammermoor Range in Otago. The site has average wind speeds of more than 8 metres per second, according to the project announcement.

Installation of the first turbine on a 90-metre tubular steel tower is scheduled to start in early 2028. Commissioning of the first unit is planned for mid-2028. The announcement does not specify a full wind farm completion date or provide a detailed schedule for installing the remaining turbines.

The project will require coordination across turbine installation, crane services and final run activities. Nordex plans to work with local companies in these areas as it prepares to deliver the project.

Mercury Expands Its Wind Energy Development

Mercury Chief Executive Officer Stew Hamilton said the company was pleased to work with Nordex on its first New Zealand wind farm development.

“Mercury has delivered five of the six wind farms constructed in New Zealand over the past five years, demonstrating our ability to execute major renewable energy projects safely, on time and on budget. Puke Kapo Hau marks the next phase of our wind energy development, and we’re pleased to be partnering with Nordex to help deliver new generation for New Zealand. Nordex has had a significant presence in Australia for many years, and we’re happy to support a new wind technology supplier into the New Zealand market.”

Mercury has an established renewable electricity generation portfolio in New Zealand. The Puke Kapo Hau project marks the next stage of its wind development programme and introduces Nordex as a new wind turbine supplier in the country’s market.

Nordex Plans to Build Local Project Capabilities

For Nordex, the Mercury order provides an opportunity to establish its presence in New Zealand. The company has operated in Australia for many years and plans to develop its local capabilities in preparation for project delivery and ongoing service operations.

Alberto Perez, Managing Director Australia of the Nordex Group, said entering the market with Mercury as its first customer was an important step for the company.

“Entering the New Zealand market with Mercury as our first customer represents an important step for the Nordex Group. New Zealand has excellent wind resources and ambitious renewable energy opportunities, making it a very attractive market for us. We are particularly pleased that Mercury has placed its confidence in our technology and our team for this significant project. With the combination of the N133/4.8 and our long-term service offering, we look forward to supporting Mercury over the full lifecycle of the wind farm.”

Nordex’s current plans include working with local contractors on crane services, turbine installation activities and final run activities. This approach is intended to combine the company’s international turbine and project experience with local expertise.

Long-Term Service Agreement Supports Project Operations

The 30-year service agreement extends the relationship beyond the initial turbine order and covers a substantial part of the wind farm’s operating lifecycle. The agreement accompanies the supply of the 40 turbines and forms part of the overall arrangement between Mercury and Nordex.

The 192 MW Puke Kapo Hau project establishes Nordex’s first position in New Zealand’s wind energy market. With initial turbine installation scheduled for early 2028 and commissioning of the first unit planned for mid-2028, the project will progress through preparation, installation and operational stages in the coming years.

For Mercury, the order supports its next wind farm development. For Nordex, the agreement creates an entry point into New Zealand while its plans for local contractor involvement help prepare the company for project execution and long-term service delivery.

Announced on 21st October 2026, the financing for the Indiana solar project brings together Royal Bank of Canada (RBC), DNB Bank ASA, Mizuho Bank Ltd., National Westminster Bank PLC and Wells Fargo Securities LLC. Deriva Energy’s Capital Markets team arranged the transaction, which the company says builds on financing structures used across its portfolio.

The Sullivan County Power Project is expected to become the largest project Deriva Energy has built to date. The company said the financing will help advance construction towards completion and commercial operation.

Five Banks Support Solar Project Financing

The USD 540 million financing involves five banking institutions, with RBC serving as both Administrative Agent and Collateral Agent. Legal advisers included Skadden, acting as counsel to the borrower, and Milbank, representing the lenders.

The financing supports the continued development and construction of the 350 MW Indiana solar project. Deriva Energy said the transaction reflects collaboration among its internal teams, financing partners and external advisers.

Paul Tivnan, chief financial officer of Deriva Energy, said the company was pleased to close the financing for Sullivan County Power. He noted that the project’s quality and financing attributes attracted strong demand from relationship banks and resulted in competitive terms.

Tivnan added that the company looks forward to working with the lenders to bring the project to completion.

The participation of five banks provides the project with financing support as construction progresses. For large-scale renewable energy developments, project financing is an important component of advancing construction and preparing facilities for eventual commercial operation.

Sullivan County Project Marks Company Milestone

Once completed, Sullivan County Power will be the largest project Deriva Energy has built, according to the company. The 350 MW installation represents a significant milestone in its development and construction portfolio.

Thomas Hopkins, senior director and head of Capital Markets and Treasury at Deriva Energy, said the financing close followed months of collaboration involving the company, lenders and external advisers.

According to Hopkins, the transaction builds on financing structures previously used across Deriva Energy’s portfolio and establishes a framework that could be applied to projects in its development pipeline.

The company said the financing positions Sullivan County Power to continue through construction towards commercial operation. The source announcement does not provide a completion date or a specific date for the start of commercial operations.

Financing Supports Renewable Energy Development

The Sullivan County project forms part of Deriva Energy’s broader renewable energy portfolio. The company reports nearly 7 GW of operating assets across major U.S. power markets and describes its wider portfolio as including 7 GW of wind, solar and storage assets that are operating or under construction.

Deriva Energy also has a multi-gigawatt pipeline of late-stage projects in development. The company said the Sullivan County financing structure could provide a model for future transactions across that pipeline.

The project is backed by Brookfield, which owns Deriva Energy as a portfolio company. Deriva Energy is headquartered in Charlotte, North Carolina, and develops and operates renewable energy assets across the United States.

Indiana Solar Project Advances Through Construction

The closing of the USD 540 million financing marks a further step in the development of Sullivan County Power. With construction already underway, the funding is intended to support continued work on the 350 MW solar installation.

The transaction combines financing from five banks with Deriva Energy’s project development and capital markets teams. The company expects the project to become its largest completed development to date.

As construction progresses, Sullivan County Power will add to Deriva Energy’s renewable energy portfolio. The company has positioned the financing as part of its wider approach to funding projects and advancing its development pipeline.

These findings come at a critical juncture for India’s power sector. Rising electricity demand, growing renewable energy penetration, and the need to maintain grid stability are redefining the role of thermal power plants. In this context, resource efficiency is no longer only an environmental concern; it is a strategic lever for improving plant performance, containing operating costs, and strengthening energy security.

India’s electricity requirement is projected to grow by 29.7%, from 1,907,835 MU in 2026 27 to 2,473,776 MU in 2031-32, while peak demand is expected to increase by 32.2%, from 277 GW to 366 GW over the same period. Growth on this scale makes it essential to maximize the performance of existing generation assets while preparing the system for a much larger share of renewable energy.

Turning Performance Gaps into Savings

Resource efficiency starts with a clear view of how well a plant converts fuel and other inputs into electricity. In thermal generation, SNHR, APC, boiler efficiency, and water consumption have a direct bearing on both performance and generation cost.

The benchmarking report assessed coal-based plants in the 300 MW (units between 150 MW to 350 MW), 600 MW (units between 500 MW to 600 MW) and 660 MW (supercritical units) categories. The best performance recorded in each category is as follows:

• SNHR: 2,450 kcal/kWh (300 MW), 2,377 kcal/kWh (600 MW) and 2,232 kcal/kWh (660 MW).

• APC: 6.76% (300 MW), 5.11% (600 MW) and 4.45% (660 MW).

• Boiler efficiency: 87.25% (300 MW), 87.43% (600 MW) and 88% (660 MW).

• Sp. raw water consumption: 2.0 m³/MWh (300 MW), 1.9 m³/MWh (600 MW), 1.8 m³/MWh (660 MW).

The report finds that supercritical units outperform subcritical units across key performance parameters due to higher cycle efficiency, superior steam conditions, lower APC enabled by Turbine-Driven Boiler Feed Pumps (TDBFPs) and Natural Draft Cooling Towers (NDCTs), and advanced control systems that maintain critical parameters close to their design values.

Comparing a unit’s performance with similar plants helps identify improvement opportunities that can be achieved through better operation and maintenance, while recognizing limitations imposed by the plant’s design.

For instance, a 600 MW unit operating at a THR of 1,995 kcal/kWh, APC of 5.5%, boiler efficiency of 87%, and SNHR of 2,427 kcal/kWh would experience an increase in SNHR of approximately 12 kcal/kWh for every 0.5 percentage-point increase in APC, 14 kcal/kWh for every 0.5 percentage-point reduction in boiler efficiency, and 12 kcal/kWh for every 0.5% increase in turbine heat rate. Minimizing these deviations can significantly improve plant efficiency, reduce coal consumption, lower generation costs, and reduce associated CO₂ emissions.

The priority is to identify, in a systematic way, the gap between design parameters and actual operating performance, set measurable improvement targets and track progress through regular review.

Digitalisation and Continuous Monitoring

Sustained efficiency requires a shift from periodic assessments to continuous performance monitoring. Real-time tracking allows operators to spot deviations early, diagnose their causes and act before inefficiencies become costly.

The benchmarking report recommends online heat-rate monitoring, continuous condenser vacuum monitoring, and maintaining critical operating parameters close to design values. Even small deviations can have a significant impact on unit performance. For a 660 MW unit, a loss of just 0.025 kg/cm² in condenser vacuum can increase the unit heat rate by approximately 2%, making it one of the most critical parameters for sustaining efficiency.

Optimized soot-blowing schedules, evaluation of variable frequency drive (VFD) applications, improved auxiliary and compressor performance, and Energy Management Systems can further tighten operational control and enhance overall plant efficiency.

Emerging technologies add to these options. Artificial Intelligence (AI) and advanced analytics can uncover patterns across operating parameters that conventional monitoring may miss. Digital Twins enable simulation of operating scenarios, predictive maintenance can flag potential equipment failures before they cause unplanned outages, and Advanced Process Controls help maintain stable, consistent operation.

Technology, however, delivers results only when supported by sound operating discipline. Reliable instrumentation, accurate data, clear ownership and skilled personnel are essential to convert digital insight into measurable improvement. The aim should be a continuous loop of monitoring, diagnosis, intervention and verification.

Preparing Thermal Plants for a Renewable-Rich Grid

As India moves towards its renewable energy ambitions, thermal plants will increasingly need to complement variable solar and wind generation. This means operating flexibly, responding to shifting demand and absorbing fluctuations in renewable output without compromising reliability.

The report found flexibility-readiness levels ranging from 50.8% to 65.1% (average: 56.86%) for assessed subcritical plants and 48.5% to 69.0% (average: 60.31%) for assessed supercritical plants. The wide variation highlights the need for plant-specific interventions rather than a one-size-fits-all approach. Moreover, the larger spread within the supercritical fleet suggests that flexibility-readiness is influenced not only by technology but also by the effectiveness of flexibility measures and operational practices implemented at the plant level.

The report identifies several measures to enhance plant flexibility, including sliding-pressure operation, improved standard operating procedures (SOPs), extended metal-temperature monitoring, installation of Steam Coil Air Preheaters (SCAPH), fine-tuning of regulating and control systems, and advanced flame scanners. The assessment highlights that all top-performing supercritical plants operate in sliding-pressure mode, underscoring its importance in improving flexibility. It further emphasizes that SOPs should comprehensively address low-load operation and emergency handling to ensure safe and reliable flexible operation.

Operator training and skill development are also identified as among the most critical enablers of flexibility, given the increased operational complexity associated with flexible operation. The assessment indicates that, with implementation of these measures, subcritical units can also achieve flexibility levels comparable to those of supercritical units.

Flexibility must be pursued alongside efficiency and equipment reliability. More responsive operating regimes require appropriate monitoring, maintenance, and control strategies to manage equipment stress and ensure safe operation. As flexibility requirements and plant conditions vary widely, solutions should be tailored to the unit’s existing technology, level of automation, and vintage. Unit-level assessments can help prioritize interventions that deliver the greatest benefits while balancing technical needs against investment and operating costs.

For generators, the business case goes beyond fuel savings. Greater flexibility improves a plant’s ability to meet grid requirements, while better maintenance and operational control support reliability in a system with increasingly variable supply.

Extending Efficiency Beyond Fuel

Fuel is only one dimension of resource-efficient generation. Water use, ash utilization, emissions and material recovery also shape a plant’s environmental performance and operating expenditure.

Water management merits particular attention. Better condensate recovery, greater recycling and reuse, optimized cooling-tower cycles of concentration, and systematic water consumption monitoring can all reduce freshwater demand. The report also identifies Zero Liquid Discharge (ZLD) systems as an area for implementation across power plants, to be evaluated against plant-specific water balances, regulatory requirements, and lifecycle costs.

These measures are critical for compliance with the water-consumption norms notified by the MoEFCC dated 7 December 2015 (as amended in 2018), which prescribe a maximum specific water consumption of 3.5 m³/MWh for existing thermal power plants and 3.0 m³/MWh for new plants, along with requirements for zero liquid discharge.

Ash management can turn an operational burden into a productive resource. Long-term agreements with cement and brick manufacturers, stronger ash-transport infrastructure and value-added ash products can raise utilization, provided planning and logistics are reliable.

On emissions, the key levers are biomass co-firing, waste-heat recovery, optimisation of cycle heat rate and reduction of unburnt carbon. Building these into plant-level efficiency programmes allows generators to address resource use and environmental performance together rather than as separate goals.

The principle is simple: every tonne of fuel, every m³ of water and every material stream should be measured and managed with a clear understanding of its operational value, its cost and its potential for recovery or reuse.

Building Accountability Through Benchmarking

The impact of efficiency initiatives depends on how consistently they are implemented and measured. Benchmarking offers a structured basis for setting targets, comparing performance and replicating good practice across similar plants.

Performance indicators should be reviewed regularly, with accountability running from plant leadership to individual operating teams. Energy audits and equipment-level assessments can pinpoint specific interventions, and financial evaluation can rank projects by expected savings, implementation requirements and payback period.

Not every gap calls for major capital expenditure. Many improvements can come from better operating procedures, maintenance discipline, process adjustments and workforce capability. Others will need equipment upgrades or advanced control systems. A prioritized approach lets plants capture near-term gains while building a pipeline of longer-term investments.

New installations should build efficiency in at the design stage. The report highlights supercritical and ultra-supercritical technologies, alongside renewable energy, energy storage and carbon capture, utilization and storage (CCUS), as relevant elements of the evolving generation landscape. Each must be assessed for technical suitability, system requirements and lifecycle economics.

Making Efficiency Central to India’s Power Transition

India’s installed generation capacity stood at 552 GW as of 31 July 2026, with non-fossil sources accounting for 54.4% and fossil-fuel sources for 45.6%. As renewable capacity expands towards the national target of 500 GW by 2030, efficient and flexible thermal generation will remain important for grid stability and energy security.

Resource efficiency offers a practical way to reconcile these priorities. By cutting avoidable fuel consumption, utilizing biomass, operating near design parameters, improving auxiliary systems, strengthening water management, and using digital tools to optimise operations, power plants can improve cost competitiveness while reducing environmental impact. The benchmarking exercise demonstrates that significant gaps remain among comparable plants in key parameters such as heat rate, auxiliary power consumption, flexibility readiness, and water use, highlighting that much of the sector’s efficiency potential is already within reach through proven operational and technological measures.

The opportunity lies not only in adopting individual technologies but in embedding efficiency into everyday operating decisions. Continuous benchmarking, measurable targets, technology adoption, and clear accountability can turn performance improvement from an occasional exercise into a sustained management priority.

Ultimately, the most resource-efficient plant is one that reliably delivers electricity while using less fuel, water, and other inputs per unit generated. Achieving this will be essential for India to meet rising demand, manage the shift to cleaner energy, and keep operational excellence at the heart of a resilient and competitive power system.

The development of nuclear fuel manufacturing is intended to strengthen the domestic nuclear fuel supply chain, support the existing US reactor fleet and enable the wider deployment of advanced nuclear technologies. Westinghouse described the facility as the first fleet-scale nuclear fuel factory built in the United States in more than 50 years.

The investment also aligns with the US government’s efforts to restore domestic nuclear fuel capabilities and meet rising demand for reliable, low-carbon baseload electricity.

New Facility to Expand LEU+ Fuel Production

The new Columbia factory will manufacture LEU+ fuel, which uses uranium enriched to between 5% and 8%. This enrichment range is higher than that of conventional low-enriched uranium fuel used in many commercial reactors.

According to Westinghouse, LEU+ fuel could allow eligible nuclear power plants to extend operating cycles and pursue power uprates, subject to reactor-specific technical assessments and regulatory approvals. These capabilities could help operators increase electricity output, improve operating flexibility and reduce certain operating costs.

The company said the new facility builds on the first successful deployment of LEU+ fuel in the United States in 2025. Expanding production capacity is intended to move the technology toward broader commercial availability.

Westinghouse also expects the fuel to support the long-term operation of existing nuclear plants and the deployment of its AP1000 reactor technology internationally.

Investment Supports US Nuclear Energy Expansion

The project is aligned with the United States’ UPRISE program, which seeks to support increased nuclear generation from the existing reactor fleet. By expanding fuel manufacturing capacity, Westinghouse aims to help utilities access the fuel needed to support higher output from eligible facilities.

US officials have also emphasized the importance of establishing a secure domestic supply chain for nuclear fuel. The Department of Energy is investing in efforts to restore uranium enrichment capabilities for both low-enriched uranium and high-assay low-enriched uranium.

Assistant Secretary for Nuclear Energy Ted Garrish said, “A strong American nuclear industry starts with a secure, domestic supply of nuclear fuel.”

The new factory will provide additional manufacturing capacity to convert enriched uranium into fuel assemblies and other products used in nuclear reactors. Its development forms part of a broader effort to strengthen domestic nuclear infrastructure and support the next generation of nuclear technology.

South Carolina Facility to Support Jobs and Economic Growth

Westinghouse’s Columbia Fuel Fabrication Facility was built in 1968 and is one of the world’s largest nuclear fuel plants. It manufactures fuel pellets, rods, assemblies and components for Westinghouse facilities and customers worldwide.

The site currently employs more than 1,200 people in Lower Richland, South Carolina. The expansion is expected to create additional employment opportunities through construction, equipment installation, workforce development and long-term manufacturing operations.

An economic impact study commissioned by Westinghouse in partnership with researchers at the University of South Carolina’s Darla Moore School of Business estimates that the investment could generate US$4.9 billion in positive economic impact across South Carolina over the next decade. Of that amount, approximately US$3.8 billion is projected to benefit Richland County.

“South Carolina is already leading America’s nuclear renaissance, and our state has been producing the nuclear fuel that powers approximately 10% of the United States from Westinghouse’s fuel operations in Richland County,” said South Carolina Governor Henry McMaster. “We are grateful for Westinghouse’s continued leadership in South Carolina, and we look forward to it expanding its work in our state to create next-generation fuel products that will continue to support nuclear energy production well into the future.”

Congressman James E. Clyburn added, “This investment is a testament to our state’s skilled workforce and the important role we play in strengthening America’s clean energy. By expanding our domestic nuclear fuel production capabilities, we are creating economic opportunities, supporting good-paying jobs and positioning South Carolina as a leader in the nation’s energy sector.”.

Construction Underway Ahead of 2030 Operations

Construction of the new LEU+ fuel manufacturing building is underway, with Westinghouse targeting the start of operations in 2030. The company said support from the US Department of Energy’s tax credit program, state authorities and Richland County helped advance the investment.

Westinghouse has also stated that the project will incorporate environmental stewardship measures, including responsible site development and preservation of native landscapes that support wildlife habitats and local air and water resources.

Once operational, the facility is expected to increase US capacity to manufacture advanced nuclear fuel. The expansion will be an important step in Westinghouse’s plans to support existing reactors, enable potential increases in nuclear generation and supply fuel for future reactor deployments.

The green hydrogen project represents a further step in China’s efforts to scale up renewable hydrogen and low-carbon fuel production for industrial and international markets. According to CEEC, the expansion involves an investment of RMB 10.83 billion and builds on the operating experience of the industrial park’s first phase.

Second Phase Targets Higher Production and Lower Costs

The second phase is designed to improve production efficiency and reduce the cost of manufacturing green ammonia. CEEC expects unit production costs to fall by more than 10% compared with Phase 1, supported by optimized facility design, upgraded domestic equipment and digital industrial management systems.

The wider industrial park integrates renewable electricity generation with hydrogen production, ammonia synthesis and methanol manufacturing. Wind and solar power supply electricity for electrolysis, which separates water into hydrogen and oxygen. The hydrogen can then be used to produce ammonia and other chemical products.

This integrated approach links renewable power generation with industrial fuel production. It also offers a way to store and transport renewable energy in chemical form, potentially serving sectors where direct electrification remains difficult.

The broader development plan envisages 3,000 MW of renewable energy generation capacity and large-scale production of green hydrogen, ammonia and methanol. The second phase will expand the facility’s production capabilities as CEEC seeks to improve the economics of renewable fuels.

Phase 1 Provides the Operational Foundation

The first phase of the Songyuan Hydrogen Energy Industrial Park began operations in December 2025. It includes 800 MW of renewable energy capacity and was designed to produce 45,000 metric tons of green hydrogen and 200,000 metric tons of green ammonia annually, alongside green methanol production and hydrogen storage facilities.

The first phase established the initial production infrastructure for the larger industrial park. The second phase is intended to build on that foundation through increased capacity, equipment upgrades and improved operating efficiency.

China Power Engineering Consulting Group’s Northeast Institute served as the engineering, procurement and construction contractor for the original project, according to CEEC. Other suppliers involved in the wider development include Sungrow Hydrogen for hydrogen production systems, Goldwind for wind turbines and subsidiaries of CIMC Enric for hydrogen storage equipment.

The green hydrogen project received ISCC EU certification in December 2025, according to CEEC. Such certification can support participation in international renewable fuel markets by providing evidence related to sustainability and supply-chain requirements.

Green Ammonia Targets Shipping and Industrial Markets

Green ammonia is one potential output of the expanded facility, with applications in established chemical markets and emerging low-carbon fuel markets. In shipping, ammonia can potentially be used as a marine fuel or as a carrier for hydrogen, offering an alternative pathway for reducing emissions in hard-to-electrify sectors.

In October 2026, ammonia produced at the facility was reportedly used in a ship-to-ship green ammonia bunkering operation in Zhoushan, Zhejiang Province. The demonstration connected production with storage, transfer and maritime fuel application.

Green ammonia may also serve conventional industrial uses, including fertilizer manufacturing. Its environmental benefits depend on factors such as the electricity source, production methods, supply-chain emissions and end use. Safe handling will require specialized procedures, while broader maritime adoption depends on the availability of suitable vessels, engines and bunkering infrastructure.

Expanding production could help CEEC pursue emerging demand from shipping operators and industrial consumers seeking alternatives to fossil-derived fuels. However, the commercial outlook will depend on production costs, certification requirements, transport infrastructure and buyers’ willingness to pay for lower-carbon products.

Cost Competitiveness Remains Key to Expansion

The Songyuan project reflects China’s efforts to move renewable hydrogen technologies from early deployments toward large-scale industrial production. The country’s established wind and solar manufacturing sectors, chemical production infrastructure and domestic ammonia market provide a foundation for integrating renewable electricity with fuel manufacturing.

Larger production volumes may help spread capital costs across more output and improve equipment utilization. Nevertheless, the commercial viability of green ammonia will continue to depend on renewable electricity prices, electrolyzer performance, financing costs, infrastructure availability and long-term purchase agreements.

The second phase will therefore provide a significant test of whether improved technology, optimized facility design and increased output can make renewable ammonia more competitive with conventional ammonia produced using fossil fuels.

International trade could provide another growth opportunity, linking Chinese renewable fuel production with shipping and industrial demand in overseas markets. Access to those markets will depend on sustainability certification, fuel standards, logistics and commercial agreements.

With the first phase operating and construction of the second phase underway, the Qingqing No. 1 Songyuan Hydrogen Energy Industrial Park is moving toward expanded production of green hydrogen and renewable fuels. Its performance will help demonstrate whether integrated renewable power and chemical production can achieve the cost reductions required for broader commercial adoption.