What do dams and bathtubs have in common?

The obvious answer is that both hold water, but there’s something more, which keynote speaker Andrew Watson of BC Hydro referred to at the recent NZSOLD/ANCOLD conference. He described the risk profile of a dam over time as ‘the bathtub curve’.

The riskiest periods for a dam are during the early years of operation and in later years as the dam starts to age.

We talk a lot about managing the risks of older dams through an appropriate dam safety program. A dam portfolio risk assessment is a great way of ensuring effort is focused appropriately. If the risk profile of an aging dam reaches an unacceptable level, this can result in a dam upgrade project. Clearly, there are many well-established processes and tools to manage risks on the aging dam side of the bathtub curve, but how about for new dams?

Reducing risk during design

During the design phase of a dam, we investigate the foundations, develop geological models to represent the foundation and assign geotechnical properties to the elements in our model. We also investigate materials that will be used in the dam, undertake laboratory testing to achieve material properties, and may even undertake insitu trials. We then model the dam structure to determine how it performs for various load cases, including extreme flood and earthquake loading, ensuring it meets the required engineering standards. Although the design process has checks and balances, some uncertainties and risks may have escaped identification at this stage.

Reducing risk during construction

The next phase is constructing the dam in accordance with the design specifications. A quality control assurance program sets quality control measures to give confidence that the construction meets the design requirements. Although the quality assurance and quality control systems are in place, there is still a level of uncertainty, making it difficult to guarantee that all the materials placed meet the required specification. Additionally, the foundation and material conditions may not totally reflect the design characterisation, necessitating modifications during construction. Typically, the designer is engaged in these changes, but was sufficient supervisory expertise on site to recognise these differences and engage the designer?

Reducing risk during first filling

For a dam design engineer, the filling of a new dam is often an exciting time. It is the completion of a major project, but it is also known to be the highest risk stage of a dam’s life. Everything that has gone into the design and construction of the dam is going to be tested for the first time: the design assumptions and models, the actual material properties, the engineering calculations, the quality of construction, the quality assurance systems, etc.

How can risk be mitigated during this first filling and the early years of operation, when the dam is being tested? From our experience, these practical steps can help reduce the risk (click each step for more details):

This process for new dams should apply equally to main dams and smaller saddle dams. In larger reservoirs, water may not fill against a saddle dam for a year or two after the commencement of impoundment. In this case, the same principles should be applied to the saddle dam during the period when water is against it for the first time. These principles also apply when a dam is raised, because when water load is placed against the raised section, the raised dam is being tested for the first time.

By applying these steps through the heightened risk period during first filling and the first 5 years of operation, dam professionals can mitigate the risks associated with the early side of the bathtub curve, helping the dam get a good start in life.

ABOUT THE AUTHOR

Richard Herweynen is Entura’s Technical Director, Water. He has more than 3 decades of experience in dam and hydropower engineering, working throughout the Indo-Pacific region on both dam and hydropower projects. His experience covers all aspects including investigations, feasibility studies, detailed design, construction liaison, operation and maintenance, and risk assessment for both new and existing projects. Richard has been part of a number of expert review panels for major water projects. He participated in the ANCOLD working group for concrete gravity dams and was the Chairman of the ICOLD technical committee on engineering activities in the planning process for water resources projects. Richard has won many engineering excellence and innovation awards (including Engineers Australia’s Professional Engineer of the Year 2012 – Tasmanian Division), and has published more than 30 technical papers on dam engineering.

Poutès Dam – a model of sustainable dam redevelopment

Having been named as the Planning Institute of Australia’s Young Planner of the Year for 2023 and awarded a bursary, Entura’s Bunfu Yu travelled through Switzerland and France to study hydropower and energy innovation. Her tour to Poutès Dam in France made a powerful impression. Here she reflects on what Poutès Dam demonstrates about environmentally driven engineering design and how genuine engagement with stakeholders in a design process can lead to balanced outcomes …

The Poutès Dam, located on the upper Allier River, a tributary of the Loire River in central France, has become a landmark case study of how to reconcile renewable energy production with environmental restoration. It’s a project that benefitted from genuine engagement, environmental-led engineering design principles, and future-conscious leadership by its operator, Electricité de France (EDF).

The dam was built during World War II without the usual approval processes. It has long been an obstacle to migratory fish, such as Atlantic salmon from the Allier basin, blocking the return of spawners and the downstream migration of juveniles. It has also disrupted the natural sediment flow of the Allier.

From conflict to collaboration

In the 1980s, environmental organisations highlighted the impact of the dam as a cause of the drastic decline in the wild Atlantic salmon population in the Loire-Allier basin. A sustained mobilisation of environmental groups through the 1990s evolved into a lengthy anti-dam campaign. In the mid-2000s, when EDF applied to renew its operating concession, it attracted criticism and rejection from global environmental NGOs, including WWF.

After decades of debate involving local communities, environmental NGOs, the dam operator (EDF Hydro) and public authorities, a compromise was reached in the late 2000s by which the parties agreed on a commitment to sustainable hydropower. Rather than completely remove the dam, a large-scale reconfiguration project – dubbed the ‘New Poutès’ – was born.

In 2015, EDF achieved a 50-year renewal of its licence, conditional on stringent environmental performance requirements, particularly regarding fish migration and sediment transport. It marked a new life for the project: those who once stood on the site of the dam in protest were now collaboratively discussing the future of Poutès with the operator and public authorities.

The ‘New Poutès’ project

A substantial refurbishment of the dam was carried out over several years to 2021, with the renovated dam inaugurated in October 2022. The design carefully configured to improve salmon migration and achieve the desired environmental outcomes.

• The dam height was lowered from 18 m to 7 m to reduce the water head and the reservoir’s impact. The embankment is also shaped in such a way that, along with the reduced hydraulic drop, the fish have a shorter and smoother vertical barrier to overcome.
• The reservoir length was decreased from 3.5 km to under 500 m, restoring much of the river’s natural profile (including a natural river gradient that allows salmon to swim) and rebuilding downstream spawning habitat.
• Two large centrally located sluice gates were installed, which can be fully opened during fish migration seasons and for high-flow water releases, allowing sediments and aquatic fauna to circulate freely. This is considered the key innovation to rejuvenate the river’s ecological dynamics.
• Fish-pass structures (fishway and fish elevator) have been incorporated in the design, which operate every 2 minutes to ensure upstream and downstream migration is effective.
• While the turbine flow remains similar to before, generation is paused during key periods to prioritise fauna movement.

The fish ladder in action

Ecological and social benefits match technical success

The New Poutès redevelopment did more than update an old hydropower plant; it reconnected a fractured ecosystem, restoring sediment flow and providing effective fish migration routes. The New Poutès continues to supply about 85% of its original hydroelectric output.

Importantly, this project demonstrates the potential of ‘collective intelligence’; that is, collaboration among diverse stakeholders (government, operator, NGOs, local communities) to produce outcomes that are superior to those achieved through conflict or unilateral decisions.

Moreover, it challenges the notion that dams are immutable – a rigid infrastructure at odds with the environment. Instead, New Poutès embodies a modern, adaptive approach: engineering solutions that evolve over time, responding to environmental and social imperatives.

Lessons from Poutès

As many dam owners and operators consider the future of their aging dams and the need for sustainable management, New Poutès stands out as a model. It shows that:

• with thoughtful design and management, hydropower and biodiversity can coexist
• partial removal and targeted retrofitting of a dam can sometimes be a cost-effective and ecologically positive alternative to full demolition
• restored rivers can recover ecological functions like fish migration, sediment transport and dynamic flow regimes, contributing to broader goals of ecological resilience
• multi-stakeholder participatory processes combining NGOs, operators, authorities and communities can help reconcile competing interests and produce durable solutions.

For me, as a planning specialist, this last point resonated particularly powerfully. It’s exciting to see a project that has learned from the lessons of the past, engaged openly and genuinely with its community, and navigated a path toward greater long-term sustainability.

When environmental, social and heritage values are considered from the outset and integrated into dam design, upgrades and refurbishments, the outcomes are better for everyone. In the Poutès story, it took the loss of the operating licence to make a major leap. Proactive efforts to bring a better balance to the ledger of impacts verse benefits may help avoid such dramatic circumstances.

Having finished my study trip and returned to Tasmania, I’m excited to continue my involvement in Entura’s projects involving dam refurbishment, redevelopment and upgrades – including the new lease on life being planned for Hydro Tasmania’s Tarraleah hydropower station. This project is sure to find itself amongst global examples of leading practice, setting the standard for other owners of older hydropower assets.

Bunfu thanks EDF team members Benoit Houdant (Technical Director Engineering) and Sylvain Lecuna (project manager of the Poutes Dam project), and Roberto Epple (former President of the European Rivers Network) for the site tour. It was incredible to share a site tour with representatives of 2 parties that were once in opposition, but now share in the pride of Poutès.

Poutès Dam and surrounding topography

Close-up of Poutès Dam

ABOUT THE AUTHOR

Bunfu Yu is a dynamic young leader in renewable energy planning, approvals and business development. Bunfu was named the National Young Planner of the Year by the Planning Institute of Australia. This honour recognised not only her passion for planning and delivering renewable infrastructure but also her active contribution to the profession through mentoring, public engagement and knowledge sharing. She is currently a Senior Environmental Planner and a Business Development Manager at Entura.

How the BESS general arrangement drives safety, certainty, speed and value

Despite the deceptively simple appearance of plug-and-play modularity, there’s a lot of crucial detail involved in achieving an efficient, safe and resilient BESS layout.

The layout or ‘general arrangement’ design will cover the BESS equipment (DC battery units/enclosures, PCS/inverters, medium-voltage transformers, switchgear, control and communications systems), the balance of plant (fire water tanks, buildings, laydowns, cable trenches, noise barriers, etc.) and the BESS substation.

Experience across the global BESS market shows that the devil is in the detail. In the push to accelerate renewable integration, there’s a danger that design decisions could be rushed, with too many details inadequately thought through or resolved. With a well-considered layout, a project is likely to move more quickly through approvals, construction and commissioning. A poorly designed project arrangement can embed inefficiencies, risks, delays and constraints that may be difficult to remedy.

Many developers have discovered that the layout of a BESS is a lever for risk, cost, speed and safety – with major implications for permitting, fire risk, insurability, environmental performance, lifecycle operating costs, augmentation and decommissioning complexity and, increasingly, community acceptance.

The BESS GA supports every phase of development

The responsibility for developing the BESS general arrangement (GA) shifts across the life of a project, and each iteration responds to the client’s evolving drivers, constraints and uncertainties. Early in development, the GA is typically prepared by the developer – or a consultant working under tight budgets – to support site selection, feasibility assessments and initial commercial decisions, often when project viability is not yet assured. As the project progresses into tender preparation, consultants refine the GA to define clear technical boundaries, ensuring EPC bids are accurate, comparable and compliant with planning requirements, fire safety and electrical standards.

Once an EPC contractor is appointed, the GA evolves into a vendor-specific detailed design, incorporating real equipment footprints, civil interfaces, constructability constraints and emergency-response provisions. The consultant – now acting as Owner’s Engineer – continues to review and challenge the GA to maintain design intent, ensure compliance and safeguard the developer’s interests throughout delivery.

Across all phases, a capable consultant adds value by anticipating the requirements of the utility and regulators, maintaining continuity through uncertainty, and designing with an appreciation of the developer’s realities – limited budgets, required studies, iterative decision cycles, and the constant question of whether the project will ultimately proceed – to ensure the final layout is safe, compliant and truly buildable.

Here we explore why GA decisions matter so much, and the key considerations shaping best-practice BESS arrangement today.

Navigating easements in BESS design

A workable GA begins with an accurate appreciation of the site’s constraints. Easements and land-use limits are not peripheral issues: they define the true buildable envelope and shape the BESS solution. Treat easements as primary design parameters rather than later checks.

Early identification and mapping of utility and service easements, gas pipelines, and other buried assets helps avoid design rework and ensures that access obligations and no-build zones are incorporated into the layout from day one, thereby reducing the risk of project delays. Hydrology deserves equal weight. Natural drainage paths and any stormwater easements identified through hydrological studies can restrict equipment placement, influence grading, and affect the location of roads and trenches. Flood mapping, too, should inform early decisions about elevating sensitive equipment or siting infrastructure on less exposed ground.

In many Australian settings, bushfire clearance requirements can dictate a reduced density and more generous separation between battery enclosures and vegetation. Where environmental or conservation easements exist, they may remove sizeable portions of land from consideration and require careful alignment with approval strategies.

Gather all easement, hydrology, flood and environmental information as early as possible, integrate it into spatial modelling, and shape the first iteration of the GA around these constraints. This will avoid the pitfall of attempting to impose an idealised arrangement on land that can’t support it and will create a stronger pathway to feasibility.

Addressing fire risk and emergency response

Given the nature of modern lithium battery technologies, fire risk must be front of mind. The spatial relationships between containers and the provision of firebreaks and passive barriers influence not only the likelihood of thermal events, but also whether a fire will spread beyond a single enclosure. Industry standards and guidelines as well as local fire codes provide structured approaches for managing separation distances, ventilation and fire-mitigation measures. The frameworks are increasingly referenced by regulators and insurers to verify that system layouts limit multi-unit fire spread.

Fire authorities in Australia now often expect evidence of large-scale fire testing which goes one step further by assuming the entire container is alight and evaluating whether the layout could allow fire to spread to adjacent units. Importantly, compliance is not limited to holding a certificate: the installed system must be constructed and configured in the same manner as the tested system, typically in accordance with the OEM’s certified design, internal spacing, materials and fire-mitigation features. Any deviation may invalidate the test assumptions and compromise fire-propagation performance.

Importantly, BESS technologies and safety standards continue to mature, with new insights regularly emerging from operational experience, incident investigations and evolving test methodologies. As a result, GAs must be developed with adaptability in mind, recognising that future updates to best practice or regulatory expectations may influence separation requirements, access provisions or fire-mitigation design.

Asset protection zones (APZs) are defined through a bushfire study. Requirements can vary even across a single site, reflecting changes in vegetation density or type, but recent projects have needed at least 10 m of separation on all sides.

The GA should support effective emergency response by providing clear access routes, equipment isolation points and adequate separation for firefighting operations – ensuring that the layout not only minimises the likelihood of fire spread but also enables authorities to intervene safely and efficiently. It’s crucial that the firefighting response is supported by engineered containment so that runoff remains within controlled zones. Grading, bunding and drainage design are therefore integral components of the overall GA, rather than secondary civil features.

Hybrid sites demand particular care, as the original renewable facility may not have been designed with BESS-specific hazards in mind. Shared roads, substations, cable routes and drainage systems must be adapted so that the BESS retains its own safety envelope.

Designing for construction, operation, maintenance and evolution

Construction is a real test for the GA. If adequate allowance isn’t made in the GA for heavy vehicle movements, crane access, delivery sequencing and temporary staging, projects are likely to run into significant costs and delays.

The size of the construction compound, laydown area and temporary storage will depend on the project scale, the number of trucks and size of workforce engaged, and the delivery and installation schedule. Critically, the expected size and reach of cranes, as well as the dimensions and handling requirements of major components such as transformers, need to be identified early in development so that access routes, turning circles, lifting zones and hardstand areas can be properly incorporated into the layout from the outset.

While a number of critical considerations should be defined during the concept design phase, it is inevitable that certain elements – such as final medium-voltage cable routing, auxiliary systems, drainage and other balance-of-plant details – will only be resolved as the design matures. To mitigate the risk of future spatial constraints leading to reduced capacity or alterations that could adversely affect the business case or grid-connection obligations, the initial GA should be intentionally developed with flexibility to accommodate later design requirements without compromising the ultimate capability of the facility.

Over the operational life of the BESS, the GA will continue to influence efficiency and cost. Reliable access for technicians, sufficient working clearances around major equipment and logical circulation routes are fundamental to safe and effective maintenance. Designs that overlook these requirements may appear economical on day one but can impose persistent operational inefficiencies over decades.

Energy storage assets built today must remain adaptable to tomorrow’s operating environment. As batteries degrade, room will be needed for augmentation or expansion – through reserved space, scalable electrical infrastructure and clear routing for future cabling. The increase in land area or civil cost is likely to be outweighed by the long-term benefit of being able to let the BESS evolve without major disruption.

No project is an island

BESS projects, like any other major infrastructure developments, will be subject to significant public scrutiny on issues such as fire risk, noise exposure, visual impacts, traffic movements and ecological impacts. Landowners, communities, stakeholders and regulators will want to know what impacts can be expected and how these will be managed. Many of these factors can be moderated to some extent by strategic placement and screening.

A clear and well-engineered GA needs to capture these considerations. It will demonstrate to regulators, stakeholders and the local community that project risks and impacts have been appropriately investigated, understood and managed – which will help build social and environment licence. A thoughtful GA is one of the most effective ways to build confidence in a project.

Make your GA a strategic advantage

As we’ve explored, the BESS GA is not just a technical document. It’s a set of strategic decisions where safety, social and environmental licence, operability, optionality and commercial performance intersect. Civil, electrical, mechanical, control, environmental and safety factors all influence – and are influenced by – the site arrangement, which makes it essential to bring an array of different perspectives and disciplines together early to avoid unforeseen flow-on implications and clashes among disciplines. At Entura, we integrate these streams to fully stress-test our designs and advice from all angles.

Now is the time to treat your BESS’s GA as one of the clearest opportunities to manage risk and materially improve your project outcomes.

To talk with us about your BESS project, contact Patrick Pease (Business Development Manager – Power & Renewables) or Donald Vaughan (Technical Director Power).

ABOUT THE AUTHORS

Senior Renewable Energy and BESS Engineer Dr Rahmat Khezri has vast professional and technical experience with batteries. He has worked in the renewable energy and battery industry in project delivery from design, business case and feasibility analysis to operation and construction. Rahmat has managed several utility-scale BESS projects during his time with Entura, overseeing successful delivery while ensuring compliance with industry standards, optimising performance and managing key stakeholder relationships. Before joining Entura, he worked on projects supported by Sustainability Victoria for technical design and business case development of ‘second-life BESS’ using retired batteries of electric vehicles. In 2023–25, he was recognised by Stanford University as being in the top 2% of scientists worldwide for 3 consecutive years.

Dr Chris Blanksby is a Principal Engineer who uses his expertise in solar and battery technologies to provide strong leadership in delivering a range of services to the industry. Chris is Entura’s lead battery specialist and has been technical lead on several key projects in the Australian battery industry over the past years. Chris leads multidisciplinary teams in feasibility, design and construction supervision for utility-scale solar, battery, and hybrid integration projects. Projects Chris has led include Owner’s Engineer and independent engineer, feasibility studies, construction supervision, tariff reform and power purchase agreements, resource and energy yield analysis, project technical specification and principal’s project requirements, technical due diligence, model and control system development and network integration.

Dam decommissioning: old dams, new opportunities

While many dams have very long lives, and could in theory operate for centuries, some dams reach a point at which decommissioning becomes a realistic final phase of the dam life cycle.

Decommissioning is not something that happens very often, given the significant value of dams and their functions, which are often multiple. Maintaining and upgrading dams, rather than decommissioning, can sometimes also be a more sustainable solution if this extracts more economic, social and environmental value to offset the initial impacts that the dam may have caused when originally constructed.

However, decommissioning may be the best option if the dam is no longer needed to deliver its original purpose, if it is no longer providing commercial or societal benefits, or if it is considered too costly to continue maintaining the dam or to undertake the necessary upgrades to stay compliant with contemporary regulations and standards.

How is a decision to decommission made?

The decision to decommission a dam is usually based on a comprehensive risk assessment. Risk assessments play a critical role in managing dams throughout their life cycle. They primarily focus on ensuring safety and minimising risks associated with dam operation, failure and decommissioning.

Risk assessments estimate risks, identify hazards and failure modes, evaluate the tolerability of the risk, compare potential risk reduction measures if needed, and establish a risk reduction strategy.

If the risk is not tolerable, risk reduction measures will be recommended, and a risk reduction strategy will be established to reduce the risk. The risk reduction measures will generally involve upgrade works. When the option to undertake dam upgrade works is considered, the option to decommission the dam is often also included. The dam owner can then undertake a cost–benefit analysis to determine the most viable option, understand the level of risk reduction achieved, and consider less tangible aspects such as community concerns.

What’s involved in decommissioning a dam?

Decommissioning a dam requires considerable planning to minimise environmental impacts and reduce the chance of leaving any residual hazards in the long term. A thorough assessment of the site conditions and downstream environment is a crucial first step towards identifying the appropriate decommissioning actions.

The location of the dam and the details of the dam works will determine the planning requirements, which often include:

• engineering design – taking breach width and batters into account to remove the possibility of retaining water, and assessing the impact on flooding downstream (as dams frequently provide flood mitigation even when this is not their primary function)
• sediment and erosion control planning – as sediment release can cause significant water quality issues and harm to habitats downstream. It is important to note that the reservoir area will initially be unvegetated and will not have any topsoil that can be used to support vegetation growth to control erosion. Additionally, sediments will typically have been deposited in the dam reservoir and are generally very easily remobilised, so this needs special attention from the designers
• flora, fauna and cultural heritage studies – as decommissioning can dramatically alter ecosystems both upstream and downstream, and heritage features can often be highlighted improving the amenity of the new asset. Ecological studies such as flora and fauna assessments are important to identify any threatened species that need to be considered in the decommissioning plans, such as through exclusion zones or timing the works to minimise impacts (e.g. conducting work outside of breeding seasons)
• fluvial geomorphology assessment – which identifies how rivers interact with their landscapes and how they change over time. It is important to understand this given that the decommissioned dam will have water flowing through it rather than retaining water, changing the balance of erosion and sedimentation processes
• dam safety emergency plan for decommissioning works – to protect communities from flooding during the decommissioning works
• regulatory approvals – a dam decommissioning permit will be needed, which will include managing any specific regulatory requirements such as issuing a notice of intent prior to commencing works and providing work-as-executed reports and drawings at the completion of the works to confirm all conditions have been successfully met.
• Depending on the use and location of the dam, it is recommended to consult with a range of stakeholders, including the local community and council, during the planning process to ensure that their perspectives and concerns are considered early. If the dam is located near to residences, public spaces or other civic amenities, extensive consultation is likely to be needed due to the potential nuisance from the works (e.g. noise, dust and additional traffic in the local area). A masterplan can be developed through this process of consultation, outlining potential options for remediating and repurposing the area based on the community’s priorities, such as creating potential new community assets such as wetlands, parks or sporting facilities.

The work involved in decommissioning a dam will depend on the type of dam and the surrounding environment but commonly involves:

• re-routing inflow away from the reservoir or past the dam
• removing all or part of the dam wall
• modifying or removing the outlet works
• lowering the spillway crest level or removing the spillway control gates or stop-boards
• treating retained liquid prior to discharging it in a safe condition
• stockpiling and stabilising accumulated sediments from within the reservoir
• removing or encapsulating impounded material, such as trees and vegetation
• revegetating the reservoir area and rehabilitating the site to perform its new purpose.

Doing it safely

Decommissioning a dam is a very complex matter involving many stakeholders and often taking some time to reach its conclusion, so it is prudent for dam owners to embark early on some interim measures to rapidly reduce any identified dam safety risks. The simplest and most cost-effective risk reduction measure is usually to lower the level of the reservoir.

The next stage is identifying the planning requirements and works involved with decommissioning and developing a decommissioning plan. The engineering design, included in the decommissioning plan, will consider the necessary environmental assessments and ensure adherence to appropriate guidelines.

Common considerations when developing the engineering design include:

• hydrological and hydraulic assessment of conditions before and after decommissioning
• the necessary breach width and batters to make the site safe
• safely discharging or removing retained water and material
• the volume of any attenuated water remaining after decommissioning
• gradient of the land if the reservoir is being completely drained
• erosion and sediment control during and after decommissioning
• managing inflows and floods during the decommissioning
• careful consideration of the final land use after decommissioning including the ecological restoration and community uses.

Achieving success

For decommissioning to be considered successful, it’s crucial that the decommissioning plan and engineering design take account of the priorities that emerge from stakeholder consultation. Many communities become attached to a dam as part of their local landscape, especially if the dam is very old. They may wish for some of the dam’s heritage to be retained or acknowledged in some way, such as retaining and integrating parts of the abutment into the future form or land use where it is safe to do so, or echoing the past by incorporating smaller water features into the resulting site.

Another major consideration for successful decommissioning is controlling erosion and sediment. Reservoirs typically have a low point that can function as a temporary sediment basin once the water level is substantially lowered. Rainfall and inflows can be channelled with small bunds and hessian silt rolls to the sediment basin. Turbid water can then settle or be treated, if necessary, before being pumped out. After decommissioning, erosion and sediment can be managed by revegetating exposed areas with native plants, creating habitat features such as wetlands or log jams, and managing and monitoring wildlife to ensure their adaptation to the changing environment. Simple solutions can be implemented to achieve positive – or at least neutral – outcomes for biodiversity.

Right process, right people

Decommissioning dams takes a wide range of skills to deliver a successful outcome – from hydrology and hydraulics, environmental and heritage assessments, through to detailed construction planning and a vision for the repurposed land. With the right people and process, decommissioning can reduce safety risks to the community, protect the environment during the works, and ultimately create new, sustainable assets enhancing the amenity of the area for the benefit of communities now and long into the future.

Entura has been involved in a number of dam decommissioning projects including Waratah Dam and Tolosa Dam. To talk with Entura’s specialists about a dam decommissioning project, contact Richard Herweynen or Phillip Ellerton.

ABOUT THE AUTHOR

Joey Scicluna is a civil engineer, who began his career managing commercial and subdivision projects. Since joining Entura’s dams and geotechnical team in 2022, he has undertaken a wide range of dam safety surveillance inspections and reporting, dam safety modelling and analysis and risk assessments. Joey has been the lead author for a number of intermediate and comprehensive dam safety reviews, and has developed design concepts and conducted feasibility studies for existing and new dams projects. Joey enjoys problem solving and working with stakeholders to achieve the best outcome for every project.

Risk is the word – reflections on the NZSOLD/ANCOLD 2025 conference

From 19 to 21 November 2025, industry experts from consultants to asset owners gathered in Ōtautahi Christchurch, New Zealand, to exchange insights, challenge thinking and strengthen connections ‘across the ditch’ and beyond. Here Entura’s Sammy Gibbs reflects on the conference …

If I had dollar for every time I heard the word ‘risk’ across the two-day event, I might have been able to fund next year’s conference myself!

Why was this the case? As noted in many of the presentations and papers, the dam industry is facing the combined challenges of aging dam infrastructure, changing design standards, climate change impacts, community expectations and resource/cost constraints. As a result, the industry is shifting more towards risk-informed decision-making/frameworks, compared to traditional standards-based approaches,to manage and design dam infrastructure.

No dam is 100% safe and all risks can never be designed out entirely, but a sophisticated understanding of their risk can inform our decisions and actions so that we can target key issues cost-effectively and ensure resilience in our dams and water infrastructure.

Risks in asset ownership

In his opening address, Andrew Watson, Director of Dam Safety & Generation Asset Planning at BC Hydro in Canada, provided valuable insights into how BC Hydro uses a risk-informed framework to manage its dams. He discussed the use of a ‘vulnerability index’ to understand the significance of identified physical deficiencies in the dam portfolio. The higher the index, the greater the likelihood that the deficiency would result in poor performance. This index allows BC Hydro’s dam safety team to understand the overall risk profile and prioritise future works. It left us contemplating how the ANCOLD 2022 Risk Assessment Guidelines and ALARP process may be enhanced by integrating components of this approach. This could be a useful way of measuring how far the dam is from meeting ‘best practice’ and hence enhance the justification for further risk reduction or accepting the position as ALARP.  

Later in the conference, Andrew Watson was joined by Peter Mulvihill, Lelio Mejia and Barton Maher to discuss legacy risk and how to manage it. Legacy risk is relevant for many asset owners (nationally and internationally) as our sector faces the complexities of inheriting aging facilities, acquired from past organisations/owners. A key challenge with these legacy structures is the transfer of knowledge to new asset owners. Important records such as monitoring data, design and construction information are often lost (or were never developed), making it difficult to understand and quantify the current risk position of the structure. These aging facilities are also unlikely to meet current design standards or withstand climate change impacts. Risk-informed decision making and phased approaches become critical in such instances, as does asking the question ‘Does it matter?’ when it comes to unknowns. Like tying surveillance programs to key failure modes, unknowns should also be associated with credible failure modes.

It was noted that for some of these structures the most appropriate solution is decommissioning, as the risk imposed by the structure (and the cost to mitigate it) may outweigh the economic benefit of the asset itself. In such instances, this decision can provide social and environmental benefits and are worth investigating.

Risk in surveillance monitoring

The conference reaffirmed the critical role of risk-based surveillance monitoring and the importance of understanding how dam instrumentation relates to key failure modes and/or performance. The most effective tool to support this is an event decision tree.

Entura’s Diego Real reiterated the importance of understanding key failure modes when implementing instrumentation upgrades. His paper presented a staged approach for the upgrades, providing clients with a cost-effective, practical solution that assists in managing dam safety risks.

Although there was discussion about various ways in which surveillance programs can be optimised, our industry is aligned in recognising the criticality of undertaking routine inspections as the first line of defence when it comes to identifying potential failure indicators.

Risk mitigation solutions

Several presenters shared examples of bespoke solutions responding to dam risks – including Entura’s Jaretha Lombaard, who highlighted how a Swedish berm was used to mitigate risks associated with piping failures at an earth and rockfill embankment dam in Tasmania.

Other risk mitigation solutions presented included non-physical works such as improvements in surveillance and monitoring. In one example, alarm systems in rivers are being used effectively to warn and evacuate the public in a swimming pool downstream in the event of a flood. Instead of relying solely on costly capital-intensive physical upgrades, the most effective strategy for reducing societal risks may lie in enhancing the speed and reliability of early warning systems.

Sharing knowledge to tackle similar problems

NZSOLD/ANCOLD 2025 was an excellent opportunity to see how specialists are tackling the complex challenges facing the dams industry. Walking away, my mind was full of phrases involving the word ‘risk’, but I felt reassured that we are all facing similar problems and by sharing our knowledge and innovations we’re continually improving our ability to design, monitor and maintain dams.

This conference will be a tough act to follow, but I look forward to the 2026 ANCOLD conference to be held in Lutruwita/ Tasmania (where I live and Entura originated).

ABOUT THE AUTHOR

Sammy Gibbs is a civil engineer with 7 years of consulting experience and joined Entura’s Dams and Geotech Team in May 2021. Sammy has a diverse background in dam and water engineering and works on a range of projects including consequence category assessments, hydrology studies, hydraulic design, risk assessments and dam design projects.

Reflections from MYCOLD 2025: Innovation, resilient dams and the evolving role of hydropower

Earlier this month, I had the privilege of joining colleagues from across Malaysia and the region at the 3^rd International Conference on Dam Safety Management and Engineering (ICDSME2025), organised by the Malaysia Commission on Large Dams (MYCOLD), held in Kuching, Sarawak. There’s a particular energy that comes with a MYCOLD conference – part reunion, part technical deep-dive, part regional conversation about water, resilience and community safety.

I returned energised and inspired – not only by the technical excellence on display, but also by the sense of shared purpose across our industry and the tangible people-to-people exchanges and collaborations. With energy systems transforming rapidly, climate change accelerating and dam safety expectations strengthening, it has never been more important for dam and hydropower professionals to share openly and learn from one another. ICDSME2025 offered that in abundance.

Here are just a few reflections on some of what I heard …

Reimagining hydropower in changing markets and climates

In the ‘Advancing sustainable hydropower’ session, I shared perspectives from Tasmania’s long hydropower journey and Entura’s experience supporting the state’s major renewable energy initiatives.

My message was clear: the feasibility of pumped hydro or of reimagining conventional hydropower isn’t simply a technical question of ‘can we build it?’ but ‘what is the long-term value it creates?’ Smart choices depend on a holistic understanding of context – i.e. the markets, energy mix, climate, environmental impacts and benefits, and community perspectives and impacts. Pumped hydro is never ‘impact-free’, and it is not inherently more sustainable than conventional hydropower. What matters is how we think about the future of the energy transition, understanding what role pumped hydro can play in that context, how well we select sites, how carefully we consider environmental and social impacts, and how thoughtfully we design (and extend) assets for long-term economic and social value.

With wind and solar dominating new energy investment in Australia, hydropower’s baseload role can shift to respond to evolving market dynamics. Hydropower’s deep storage, flexibility and system stability are becoming increasingly important. We’re seeing these opportunities in Tasmania, where both conventional hydropower and pumped hydro could – with more interconnection to the mainland – help balance a renewables-rich National Electricity Market while returning extra revenue to Tasmania and increasing the reliability of supply across Australia’s south-east.

Climate change adds further complexity to feasibility considerations. Changing rainfall patterns, more variable inflows and more frequent extremes – as well as with the increasingly variable generation mix and how energy sources interact – all influence when hydropower can generate or store.

Ultimately, I believe there are not only opportunities with extending operating life, refurbishing or redeveloping dam assets; there are also obligations upon us as an industry to do our best for the sustainability of these assets. We need to focus constantly on how to optimise outcomes from the base impacts of hydropower or dam developments and seek ways to reduce impacts into the future. We also need to think about how to deliver great outcomes and value that extends across a long asset life, beyond the limited commercial timeframes considered in final investment decisions.

Technology, people and the future of dam safety

I had the honour of chairing a keynote session featuring Yang Berbahagia Prof. Datin Ir. Dr. Lariyah binti Mohd Sidek and Dr Martin Wieland.

Dr Wieland’s insights into the seismic performance of dams reminded us that strong engineering fundamentals remain as crucial as ever, even as digital tools advance. Prof. Lariyah explored how digital platforms, artificial intelligence and risk-based frameworks are shaping the next generation of dam safety practice. She emphasised the importance of the human layer: building institutional readiness, strengthening safety culture, fostering stakeholder trust, and ensuring effective engagement with communities.

Together, their perspectives reinforced that the future of dam safety will depend on both technological innovation and human-centred capability and how effectively these dimensions interact. That’s something Entura is focused on as we continue to bring deep expertise and experience, while exploring and testing the possibilities of new technology to support design and analysis.

Learning from incidents to strengthen global knowledge

Another highlight for me was chairing a session on dam surveillance, monitoring and evaluation. Seven presentations, while different in context and purpose, in combination emphasised the power of data and the importance of learning from experience.

A standout paper examined the 2022 landslide incident at Kenyir Dam, an event that occurred quite soon after Entura’s dam safety inspector training program used the dam as a site visit capstone. Despite extreme rainfall and slope instability, and some damage to appurtenant structures and spillway, instrumentation data confirmed that the dam behaved as designed. What was also clear was that, largely, the instrumentation in place and the data that was able to be collected was a positive demonstration of the importance of robust dam design and monitoring systems.

Another paper explored machine-learning approaches to forecasting short-term reservoir levels at Batang Ai Hydroelectric Project – a scheme with which Entura has long been associated. The results were impressive and point to a future where AI-supported forecasting strengthens real-time operations, especially under increasing climate variability.

These are exactly the kinds of insights our industry must continue to share openly and widely. We can never ‘design out’ all risk, but we can reduce it through good data and continual reflection and learning from real-world events.

Strengthening long-term capability in Malaysia

ICDSME2025 also highlighted the importance of building capability – something I am passionate about. It was encouraging to see Malaysia’s Certified Dam Safety Inspector program, developed with input from Entura’s training arm ECEWI, growing into a sustained and locally led pathway, launched during the conference. Strengthening dam safety ultimately depends on skilled people and strong institutions, making investment in training an investment in long-term sustainability of dam safety governance – and ultimately greater national resilience. We hope to continue to work with MYCOLD to determine how our specialised expertise can further enhance capability uplift beyond surveillance, extending to dam safety risk decision making and dam safety engineering.

A shared commitment to the future

Conferences like ICDSME2025 are timely reminders of our collective responsibility and the shared purpose we need to bring to the challenges ahead. We’re all navigating the same landscape, and when we come together – sharing data, stories and lessons – we accelerate progress for everyone.

I am grateful to MYCOLD for the invitation to contribute and for the generous knowledge-sharing throughout the event. I left Sarawak optimistic: the connection, commitment and collaboration across our sector have never been stronger as we work toward our common goal: safer, more sustainable dams and hydropower systems that support resilient futures.

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Can you trust advanced tools without qualified professionals behind them?

To make confident decisions about renewable energy assets – from building a wind farm to monitoring dam performance or optimising asset management – owners and operators need precision data they can trust.

As the renewable energy sector becomes increasingly digitised, the quality of measurements matters more than ever. Digital twins, predictive analytics, AI-driven performance tools and remote operations all depend on reliable, precise and traceable data.

Good data provides visibility. It lets owners and operators detect faults or safety issues early, optimise performance, and protect reliability and revenue. For example, accurate turbine alignment during installation or refurbishment could save hundreds of thousands of dollars in downtime and maintenance.

However, data only provides value if it has the right level of accuracy for the job intended. If the data isn’t up to scratch, the decisions won’t be either.

Keeping pace with technology is a steep learning curve

Surveying has always been the backbone of infrastructure development, land management and industrial precision. From the early days of using theodolites and chains to today’s cutting-edge technologies like laser scanning, UAV photogrammetry and LiDAR, the discipline has evolved dramatically. Yet, one constant remains: the need for appropriately qualified and experienced professionals.

Surveying is far more than measuring distances – and achieving precision requires more than sophisticated instruments. It requires a deep understanding of geodesy, data integrity, error propagation and spatial analysis. Traditional instruments such as theodolites and total stations demand mastery of angular measurement and trigonometric principles. GNSS-based methods introduce complexities like satellite geometry, atmospheric corrections and datum transformations. As technology advances, the learning curve steepens: laser scanners and UAVs generate massive point clouds, while LiDAR systems demand expertise in filtering, classification and 3D modelling.

Surveying principles now extend beyond land and construction into industrial metrology, where precision is measured in microns rather than millimetres. In the renewable energy sector, the applications are vast, from assessing hydropower turbine blade wear and integrity of concrete structures to verifying the verticality of wind turbines and ensuring accurate positioning of new hydraulic equipment. Here, advanced techniques like laser trackers and terrestrial laser scanning dominate, and the margin for error is extremely small.

Precision gives confidence that the data feeding an asset’s digital models is accurate, consistent and aligned with recognised standards. When survey instruments, operational sensors and digital monitoring systems all work within a strong metrological framework, asset owners can be confident that their decisions are based on fact, not noise.

The human behind the technology

However sophisticated today’s measurement tools and technologies may be, their outputs are only as trustworthy as the professionals behind them.

Without properly qualified and experienced operators, advanced tools can become liabilities rather than assets. Misinterpretation of data or incorrect calibration can lead to costly errors in construction, infrastructure alignment or asset management.

Using the wrong technique or sensor for the use case and conditions, neglecting appropriate calibration, and a lack of adequate redundancy can lead to major issues and costly mistakes.

Specialised, qualified professionals will think through these issues early, ensuring that accuracy and tolerance requirements are clearly defined from the start and that data integrity is maintained throughout with robust quality control and assurance procedures.

Human insight provides the environmental and engineering context and assurance that automated systems alone cannot deliver. Surveying and metrology professionals can determine whether readings are valid and offsets are accounted for – and will be able to distinguish genuine change from measurement anomalies.

Ultimately, it is professional judgement that transforms accurate data into actionable insights and confident decisions.

Accuracy drives advantage

Today’s surveying advances are transforming how decisions are made. Spatial data is no longer just a technical input; when validated and interpreted by qualified professionals, it becomes a valuable source of real strategic insight and advantage. When the data is right from the start, every subsequent step becomes more certain and the outcomes have the best chance of being more efficient and sustainable. Such clarity can be the difference between success throughout an asset’s lifecycle and expensive lessons learned.

As technologies advance, so does the need for qualified professionals who understand both the science of measurement and the realities of complex, dynamic infrastructure. By ensuring accuracy, compliance with standards and efficient workflows, the qualified surveyor safeguards projects from financial and reputational risks – enabling the reliability, safety and commercial confidence that every asset owner depends on.

If you’d like to talk to us about the potential of advanced surveying and metrology on your project, contact Phillip Ellerton or a member of our Spatial & Data Services Team.

Unlocking repowering for Australia’s older wind farms

Europe and the US are already upgrading older wind farms with powerful new turbines. Repowering could potentially offer significant opportunities in Australia’s energy transition, but there are barriers. Australia risks falling behind unless action is taken now to make repowering easier, faster and more attractive for investors. Dr Andrew Wright, Bunfu Yu and Donald Vaughan explore the opportunities for intervention …

To accelerate the clean energy transition, repowering old wind farms should be a serious consideration. Many of Australia’s earliest wind farms are reaching the middle or end of their design lives. These projects were pioneering at the time, but today’s turbines are taller, more efficient and capable of generating far more electricity from the same site – which is likely to have some of Australia’s strongest and most consistent wind.

Repowering could potentially offer a faster, cheaper and less disruptive way to boost renewable generation than building entirely new projects. Yet, despite the clear potential, repowering is still rare in Australia.

The pending closure of Pacific Blue’s Codrington Wind Farm in Victoria announced in February 2025 is an interesting case study, demonstrating potential barriers. Pacific Blue has concluded that a project with new wind turbines at Codrington is not financially viable once the existing turbines reach the end of their useful life. Consisting of 14 x 1.3 MW wind turbines and completed in June 2001, Codrington is one of the earliest wind farms completed in Australia. The site no doubt has a great wind resource, but its small size and the limited capacity of the 66 kV grid connection do not suit modern wind turbines, which are typically at least 4 times the size and capacity.  

Codrington is the largest old wind farm to announce its decommissioning in Australia. But other large early projects of similar age are also facing decisions about repowering or decommissioning.

This raises a question: are government and regulatory authorities properly prepared for an influx of ‘new old’ projects?

There is an expectation that larger wind farms will repower with new wind turbines, using and perhaps augmenting existing grid connections, under new development permits. But this concept is yet to be tested and proven in Australia.

How should governments and regulatory authorities in Australia deal with the planning approval aspects of repowering wind farms? Presently, they are considered like any other new development – but other countries have shown that repowering can be unlocked with practical mechanisms to incentivise developers, streamline planning and ease grid connection hurdles.

Incentivising repowering

Repowering requires significant capital investment – so a targeted financial incentive could make a meaningful difference in getting the project to stack up.

In Europe, there is a growing view that governments are not doing enough to drive forward the repowering of older wind farms that might otherwise carry on operating with inefficient use of land and resources. Local communities are typically comfortable living in the vicinity of wind farms that have been operating for a long period, so there is a strong argument that governments should develop specific policies to encourage repowering of old sites that already have community acceptance.

Germany led the way in direct policy intervention with a ‘repowering bonus’ included in 2009 in its Renewable Energy Sources Act, rewarding wind farm owners with a EUR 0.5 cent/kWh feed-in tariff bonus for replacing older wind turbines with modern, higher-capacity machines. This policy delivered more energy from fewer turbines while reducing land-use impacts. Repowering has subsequently become a significant contributor to Germany’s wind energy growth, with 1.1 GW of new wind capacity in 2023 coming from repowering.

In the USA, the Production Tax Credit (PTC) is now phasing out. This is an example of a policy that encouraged repowering as an unintended consequence. Enacted in 1992, it provided businesses with a tax credit per MWh of electricity generation for the first 10 years of a wind farm’s life. This created an incentive to generate as much output as possible for 10 years, and then build a new project to renew the tax credit. Given that 10 years is too short a lifetime for a well-engineered and well-run wind farm, this is not an ideal example of incentivising repowering.

Australia has no equivalent incentive for repowering. Early wind farms like Challicum Hills in Victoria, Starfish Hill in South Australia, and Tasmania’s Woolnorth wind farms are now approaching the end of their operating lives. Direct financial incentives or market mechanisms rewarding greater efficiency, reliability and grid services provided by repowered assets could make the difference between decommissioning these assets or repowering with new wind turbines to deliver decades more renewable energy.

Navigating approvals

In most cases, repowering will require additional planning and environmental approvals. This depends on the scale of the changes: are the turbines taller? are there new civil works? is the layout shifting? what new accesses or grid connection corridors might be required? The success of repowering depends on navigating approvals with the same care and thoroughness as for new projects.

Policy positions and guidelines have evolved over the last 2 decades, and there are now more stringent guidelines dictating the matters for consideration during approvals. Additional threatened or endangered species may also have been listed over the years.

Community engagement is a critical part of repowering and should not be overlooked. Even where communities have co-existed with a wind farm for decades, taller turbines or different layouts could raise new concerns about landscape impacts or amenity. Early dialogue and transparent benefit-sharing will help build trust and engagement in the project.

Clear planning, targeted environmental studies, and early engagement with regulators and communities can help projects capture the benefits of modern technology while minimising risks of delay.

A dedicated fast-track pathway for repowering would help these projects progress. Such a pathway could recognise prior approvals, with updates only where impacts materially change (e.g. taller turbine heights, new technology, and the cumulative effects of other developments), or where environmental values have changed. This doesn’t mean bypassing safeguards or consultation, but it does mean matching the level of scrutiny to the level of risk.

Easing grid connection challenges

Connecting a repowered project to the grid inevitably involves meeting stricter requirements than the original project, which will take time and add cost. Yet there is a strong argument that repowered projects should have some special considerations, given the differences between a greenfield development plugging into an existing network, and a replacement of an existing project with newer technology.

Proponents are faced with three paths: a new connection to the current rules, a grandfathered connection under the previous rules, or a hybrid approach. All of these have benefits and drawbacks. The best path will depend on the like-for-likeness of the repowering in terms of size, turbine technology and the amount of reused equipment (transformers and other electrical balance of plant).

Another consideration is whether the non-scheduled status of early wind farms can be preserved through this process. It is likely that significant changes to power or energy output may trigger a change. As a minimum, model accuracy requirements will apply to a new connection – which may lead to more detailed testing than the plant had previously been subjected to.

Options to help alleviate these challenges could include tailored connection pathways that recognise existing infrastructure, de-coupling from grid queue management for repowering projects, and clear technical standards so developers know what to expect.

As well as accelerating repowering, this could help make better use of grid assets, reducing pressure for new transmission.

What now for repowering?

Jurisdictions in Europe and the USA demonstrate that repowering works when governments set the right conditions. Early Australian projects such as Codrington, Starfish Hill, Challicum Hills and Woolnorth wind farms show that the time to decide is already here.

Given the challenges to achieve timely and cost-effective repowering in Australia, should we leave the low-hanging fruit of legacy sites dormant for now, and keep deploying capital on scale-efficient large sites in the short term?

Prioritising efficient large sites makes sense for urgent growth, but there are ways to pursue both greenfield and repowering – and the advantages of repowering remain. The early wind farms were built in some of the windiest, most accessible locations in Australia. Leaving these sites dormant would waste high-quality wind assets where there may already be community goodwill and existing grid assets.

Now is the time to consider whether particular site design approaches could make a site more easily repowerable in future – such as the way reticulation is installed, different approaches to foundations, scalable switchrooms and yard layouts. Is there a niche for wind turbine OEMs to offer lower power variants of new designs to better suit the scale of repower sites? Creativity and innovation will be needed – because the transition is too big and too urgent for us to leave repowering in the ‘too hard’ basket.

By pursuing both new developments and repowering simultaneously, Australia could capture immediate growth from large-scale projects while also making efficient use of our best wind resources and existing assets, maintaining community benefits and regional employment, and avoiding a wave of retired or stranded capacity.

If you are considering your wind farm’s future options and opportunities, please contact Andrew Wright or Patrick Pease.

ABOUT THE AUTHORS

Dr Andrew Wright is Entura’s Senior Principal, Renewables and Energy Storage. He has more than 20 years of experience in the renewable energy sector spanning resource assessment, site identification, equipment selection (wind and solar), development of technical documentation and contractual agreements, operational assessments and Owner’s/Lender’s Engineer services. Andrew has worked closely with Entura’s key clients and wind farm operators on operational projects, including analysing wind turbine performance data to identify reasons for wind farm underperformance and for estimates of long-term energy output. He has an in-depth understanding of the energy industry in Australia, while his international consulting experience includes New Zealand, China, India, Bhutan, Sri Lanka, the Philippines and Micronesia.

Bunfu Yu is a dynamic young leader in renewable energy planning, approvals, and business development. Bunfu played a pivotal role in Entura’s Environment and Planning Team’s success in achieving the Planning Institute of Australia’s National Award for Stakeholder Engagement in 2024. In 2023, Bunfu was named the National Young Planner of the Year by the Planning Institute of Australia. This honour recognised not only her passion for the planning and delivery of renewable infrastructure but also her active contribution to the profession through mentoring, public engagement, and knowledge sharing. She is currently a Senior Environmental Planner and a Business Development Manager at Entura.

Donald Vaughan has over 20 years’ experience providing advice on regulatory and technical requirements for generators, substations and transmission systems. He has worked for all areas of the electrical industry, including generators, equipment suppliers, customers, NSPs and market operators. Donald specialises in the performance of power systems. His experience in generating units, governors and excitation systems provides a helpful perspective on how the physical electrical network behaves.

From feasibility to operations: how technical due diligence can empower renewable energy investment

Confident investment in renewable energy projects is the key to accelerating the clean energy transition. Yet every renewable energy project carries some uncertainties at every stage, from early feasibility to long-term operations.

For all involved – developers and contractors, investors and lenders, stakeholders and communities – trust in a project’s viability and success will grow when there is a strong framework in place to thoroughly assess and quantify the project’s technical and financial assumptions, risks and unknowns.

Robust technical due diligence needs to span all the stages of the project’s development, though its focus will change as the project evolves.

Here we examine how sound technical due diligence, applied throughout the lifecycle of a renewable energy project, can provide a strong foundation for sustainable delivery and greater confidence of a bankable investment.

Due diligence is an ongoing process

Technical due diligence of renewable energy projects (including wind, solar or hydropower) isn’t a one-off activity. It evolves as a project advances.

The aim in the early stage is to verify the design assumptions and to determine if a concept can evolve into a viable investment.

During execution (construction), the emphasis shifts to project monitoring and adaptive risk management, ensuring that construction progress aligns with budgeted milestones.

Once operational, the focus is on assessing the project’s outputs (energy generation, efficiency, etc.) and maintenance practices while also ensuring contractual integrity, which is critical for refinancing or acquisition decisions.

Together, these different phases of due diligence form a continuum of technical supervision which ultimately helps to support the long-term success of the project.

Pre-construction phase

Pre-construction due diligence is a multidisciplinary process that assesses site conditions, verifies design feasibility, and validates operational feasibility. This leads to more realistic financial projections, which in turn enable objective and systematic investment decisions.

Key elements of pre-construction due diligence typically include review or assessment of the following:

Execution phase (construction)

Once a project secures financing and enters the construction phase, the technical due diligence focus moves to active oversight of whether the project is being delivered safely, efficiently and to the required standard. The consultant helps the project achieve timely outcomes during construction and commissioning. The key elements of technical supervision during construction include the following:

These assessments help to identify deviations from plans, enhance transparency and reinforce investor confidence.

Operational phase (existing assets)

For businesses considering investing in or acquiring operational assets, due diligence helps to assess how the asset is performing, verify the asset’s physical condition, and identify improvements that can sustain value into the future. This is essential for establishing accurate valuations and identifying hidden risks. A competent technical consultant can offer tailored services that combine desktop reviews with on-site inspections to inform the investment decision.

Key components of due diligence of existing assets include the following:

This stage of due diligence is especially relevant in a secondary market, where investors are seeking to invest in brownfield assets to diversify their portfolios. The goal is to ensure that the asset’s operational reality matches its financial promise.

Building confidence from concept to operation

Entura has seen firsthand how due diligence strengthens projects at every stage. We’ve fulfilled many technical due diligence and advisory roles in different contexts – and sometimes multiple roles on a single project.

For continuity, a single consultancy can take on a range of responsibilities across the different phases of a project: whether that’s technical feasibility assessment, technical due diligence, Owner’s or Lender’s Engineer roles, or Independent Technical Advisor. These roles are different in focus, timing and perspective, but they’re ultimately all about building confidence in the viability and success of the project.

One example is the Kidston Pumped Storage Project (K2-Hydro), for which Entura initially prepared the technical feasibility assessment considering factors that influence the project’s technical and commercial viability, and then played an advisory role leading to financial close. During the construction phase, our role shifted to that of Owner’s Engineer, helping to ensure the project’s designs meet current practice and that construction is implemented in accordance with the designs and specifications.

In the pre-construction stage, Entura has completed technical due diligence of many hydropower and other renewable energy projects. For example, we’ve recently taken on this role for several hydropower projects planned for development in India, ranging from a 32 MW hydropower project right through to an 1800 MW pumped storage project. These assessments included hydrological studies, power potential studies and reviews of project layout, plant design and electro-mechanical works, power evacuation arrangements, power purchase agreements, technical risks, costs and construction schedule, and more.

We’ve also conducted due diligence for many solar, wind and hybrid renewable energy projects. For example, Entura was engaged as the technical due diligence consultant for the 112 MW Granville Harbour Wind Farm to support the client’s financial closure. We provided technical services including energy estimates, review of permits and grid connection, development of technical specifications, review of the project design, and checks of environmental compliance– all necessary for successful financial closure.

We continued our involvement into the construction stage as Owner’s Engineer, providing construction support, overseeing the civil and geotechnical components of construction, and conducting regular site inspections to ensure the works were undertaken in accordance with the relevant industry and safety standards.

Translating technical findings into financial indicators

Technical due diligence at every stage of a project’s lifecycle requires a level of rigour that goes beyond a simple compliance requirement. It is fundamental to long-term asset performance, stakeholder trust and the validity of financial assumptions and projections. Consultants involved through the feasibility, construction and operational phases can contribute meaningfully to the project development.

Although financial modelling lies outside a technical consultant’s scope, their work forms the backbone for credible financial analysis and investment decisions that are integral to the overall business case development. Each finding from the technical process can be used to support further financial due diligence to inform investment, lending or acquisition decisions.

By structuring the technical findings around the following four financial pillars, technical due diligence becomes a bridge between the on-the-ground realities of the project and its ultimate financial viability.

What does this mean for stakeholders?

Sound technical due diligence can cater to the financial expectations of different stakeholders making it a key instrument for strategic decision support.

• Long-term investors (developers or buyers) prioritise clarity on returns, dividend sustainability, and resilience of the asset into the future. Their confidence hinges on realistic operation plans, reliable energy forecasts, and durable O&M strategies derived from feasibility assessments and construction-phase monitoring.
• Debt providers focus on debt-service coverage ratios (DSCR) which indicate the capacity of the project to generate sufficient revenue to repay loans. Lenders will want reassurance about budget contingencies, capability of contractors and robustness of project schedules – all of which are assessed in detail during the due diligence.
• Insurers require information about structural failure modes, the risks of operational outage, and force-majeure conditions. These can be informed by detailed technical analyses and condition assessments from operational audits.

When applied consistently throughout the course of a project, from feasibility to operations, technical due diligence helps all stakeholders measure project risks, avoid unexpected costs, and evaluate potential and actual performance. This is the bedrock for confident financial decisions – and ultimately, for driving the energy transition forward at the scale and pace our environment and communities urgently need.

ABOUT THE AUTHOR

Sagar Shiwakoti is a civil engineer with master’s degree in water resources engineering and close to a decade of experience in flood studies (hydrological and hydraulic assessment) and hydraulic design for hydropower projects. Prior to joining Entura in 2022, he worked with the Nepal Electricity Authority and Hydroelectricity Investment and Development Company, where he gained extensive experience in technical due diligence for hydropower projects. Sagar was also a lecturer in civil engineering for a number of years at Tribhuvan University, Kathmandu.

New technologies give deeper insight to protect the shallows

Water is a precious resource for communities and industries – and for the health of river ecosystems. Balancing these needs around dams can be very complex. In this article, Dr Will Elvey and Dr Colin Terry explore how advanced technologies and methods can help dam owners/operators better understand shallow downstream areas to support aquatic biodiversity …

Dams are crucial for many communities, providing water security, energy and economic growth – but they also change the natural flow of rivers and streams.

To preserve downstream ecosystems and species, ‘environmental flows’ (e-flows) began to be implemented in hydropower operations from the 1970s and the concept became more sophisticated and more formalised as the decades rolled on. In Australia, e-flow assessments are now typically required by state or Commonwealth regulators for new dam projects or major operational changes.

These assessments are complex and challenging both for new developments and for retrofitting existing schemes. As the concept of e-flows continues to evolve, methods of modelling and assessing these flows must evolve too.

Getting a deeper understanding of what’s downstream

Scientific understanding of the ecological requirements of freshwater species and the physical processes that shape their habitats has advanced significantly since e-flow studies began. Many aquatic species exhibit preferences, or even strict dependencies, on specific velocities and depths. To accommodate those preferences or dependencies, it’s vital to better understand how habitat availability and quality respond to different e-flow regimes (i.e. the timing of discharge and the diversity of velocity and depth across the channel).

There are many approaches for simulating habitat changes under varying flow conditions, but all rely on hydraulic models. E-flow assessments are often constrained by the capabilities of the hydraulic models used, and simpler models are generally inadequate for addressing complex ecological questions. Attempts to use simple models to inform more detailed ecological metrics, such as habitat preference curves for individual species, often fail to deliver the intended environmental outcomes.

Using simple models can lead to adopting basic flow rules, where benefits are difficult to quantify beyond broad estimates (e.g. maintaining wetted channel widths or meeting minimum depth thresholds). The inherent limitations of simplistic hydraulic modelling can also make it difficult to justify proposed environmental water releases to regulatory agencies and water resource managers.

Simple models suit simple questions only

Early environmental flow studies commonly used one-dimensional (1D) hydraulic models, which assume uniform water properties across the channel and throughout the water column, varying only along the main flow direction. But in reality, the shape of a watercourse and its hydraulic properties are too variable to be able to be simulated well by 1D models.

Shallow water zones in rocky riverbeds – which are often highly ecologically diverse and are vulnerable in droughts or insufficient flows – are particularly hydraulically complex.

1D models are still used and do provide useful general information such as wetted cross-sectional area, average velocity, and minimum and maximum depths. However, they lack detail about vertical and lateral flow dynamics and can’t simulate water movement around complex in-channel structures like rock substrates or little waterfalls.

This means that 1D models are best suited to answering relatively simple questions – for example, how different discharge changes the wetted area, or what the maximum and minimum depths and velocities are for a cross-section.

1D models, when configured with sufficient cross-sections through complex areas of riverbed, can more effectively address questions such as whether minimum depths allow fish to pass through shallow reaches during low flows, or whether velocities are sufficient to support macroinvertebrates that thrive in faster flowing areas, such as stoneflies, mayflies, caddisflies, elmid beetles and some dragonfly species.

Estimating water velocity is crucial for understanding how physical habitat is maintained through the mobilisation of bed particles, from the fine silts to the largest rocks.

The accumulation of fine sediments on surfaces, and within the spaces between and beneath rocks, can degrade habitat quality for many aquatic species. Simulations of water velocity and associated shear stress can help determine whether flows are sufficient to transport fine sediments away from riffle habitats.

At the other end of the spectrum, annual peak flows of sufficient magnitude to mobilise larger substrate classes (from gravels to boulders) play a key role in maintaining healthy river systems. However, the low spatial resolution and limited physics of 1D models means they can only contribute to general estimates of bed mobilisation.

New technologies reveal more detail – informing better e-flows

Emerging field observation methods and computer modelling approaches that are more sophisticated and detailed can better guide environmental releases, particularly where the riverbed slope and substrate vary. These environments require a deeper understanding of the dynamics of shallow flow to support ecologically meaningful outcomes.

In the past, field measurement was limited to point surveys at cross-sections, and computers only had the capacity for modelling 1D versions. Now, with accurate airborne drone surveys using photogrammetry and LiDAR, scientists can better describe the physical geometry of a watercourse.

Advanced computer hardware and 3D modelling software are enabling a more accurate – and more rapid – understanding of water behaviour. It is now possible to create a plausible 3D time-varying version of the water flow, with detail that enables aquatic scientists to provide better advice on appropriate environmental flows. Fewer limitations generally leads to more cost-effective insights and, in turn, better management of environmental values.

Modern methods in practice

This example demonstrates the power of evolved methods and new technologies.

A 600 m stretch of a river that is approximately 20 m wide, with a rocky bed, was surveyed by drone, capturing 1,260 images which were used to create a highly detailed 3D version of the river’s geometry. Then, using 2D and 3D hydraulic software, different flows in the test area were simulated, ranging from a trickle to larger floods. The critical flows for healthy aquatic life are the diverse shallow flows in areas large enough to allow an abundance of diverse life.

Figure 1 gives a typical view of the river. Figure 2 shows samples of the geometry captured and processed. Figure 3 shows output from the 3D hydraulic modelling software.

Figure 1. River at low-flow gauging (0.0077 m³/s) site looking upstream and downstream

Figure 2.  a) Aerial image, b) DTM, c) 2D grid, for the same area of river

Figure 3. Water surface with scaled velocity vectors, looking upstream for 3 m³/s (3D model)

ABOUT THE AUTHORS

Dr Will Elvey is a Senior Environmental Scientist with Entura specialising in aquatic invertebrates, freshwater fish, freshwater habitats and ecohydrology. Will has nearly three decades of experience as a consultant in Tasmania and the United Kingdom. He has been involved in a wide range of projects that include assessing impacts of stressors on aquatic ecosystems.

Dr Colin Terry is Entura’s Senior Principal, Water (Hydraulics/Hydrology). Colin has over three decades of engineering experience, most with a water focus. He has expertise in water modelling, design and planning of dams, hydropower and water infrastructure, including 3D CFD analysis of hydropower intakes, rivers and dam spillways. Colin has worked at senior technical levels of small and large organisations across Australia and New Zealand.

How hydropower history and innovation can continue to power progress

Having been named as the Planning Institute of Australia’s Young Planner of the Year for 2024 and awarded a bursary, Entura’s Bunfu Yu travelled through Switzerland and France to study hydropower and energy innovation. Her reflections from the study tour highlight how history-rich hydropower assets can continue to evolve and add value in a changing world …

Switzerland’s Ritom hydropower project – which is in the late stages of a major redevelopment and anticipated to be operational later in 2025 – is a technical marvel of the past and the present. It is also a lesson in how energy infrastructure can evolve while still respecting its historical roots.

The original Ritom power station was commissioned in 1920 as part of a traditional hydropower scheme using water from Lake Ritom to generate electricity. It holds a special place in Swiss energy history as the first plant to supply electricity to the Gotthard railway, which is a vital north–south transit corridor through the Alps. This early integration of hydropower with transport infrastructure helped shape the modern Swiss energy landscape.

However, after more than a century of faithful service, Ritom’s aging infrastructure and the region’s changing energy needs prompted a major rethink.

Modernising with purpose

Ritom is undergoing a major transformation to meet 21^st century demands. The redevelopment project involves replacing the historic hydropower plant with modern facilities and converting it from a conventional hydropower scheme to include a pumped hydropower component. By using two existing lakes (Lake Ritom and Lago di Cadagno) as the upper and lower reservoirs, energy can be stored by pumping water uphill during periods of low demand and releasing it to generate electricity when demand peaks. This is critical for maintaining reliability and stability in today’s dynamic grid. The lakes are also popular with walkers, and this recreational value will continue alongside the repurposed scheme.

The revamped facility will increase capacity to 120 MW, improving energy resilience for both the local Ticino region and the Swiss Federal Railways. The upgrade enhances energy security and does so with a strong emphasis on environmental and community values.

Balancing environment, engineering and community

Like all major infrastructure projects, Ritom has complexities. A key concern is managing downstream water flow to protect river ecosystems. To address this, the project incorporates a demodulation basin – an engineered feature that moderates flow variations, preserving the ecological health of the river below.

Minimising disruption for the local community during construction has also been a priority. This has taken careful management, as the project is nestled between the alpine villages of Piotta and Piora. The project team constructed a dedicated cableway to move heavy materials – such as massive steel penstocks – away from narrow local roads. This solution reduced construction traffic and helped preserve the peace and safety of surrounding communities.

Ritom is an inspiring example of how infrastructure can evolve when regulators, engineers and communities work together. Innovative thinking coupled with flexibility in permitting has enabled tailored solutions that are practical and environmentally sound – an approach that is replicable worldwide.

Technical excellence delivering long-term social value

Ritom reminds us that great infrastructure is more than engineering and functionality – it can inspire and be enjoyed.

Each year, the region celebrates the connection between nature, people and infrastructure through the ‘Stairways to Heaven’ race – a brutal yet iconic event that ascends 4,261 steps alongside the original penstocks of the Ritom scheme. With an average 89% incline over 1.2 km, it is Europe’s steepest race, attracting elite athletes as well as daring locals. The climb is physically punishing, but those who reach the summit are rewarded with breathtaking panoramic views of the Swiss Alps and the glistening Ritom reservoir.

This race is more than a sporting challenge. It is a symbol of how infrastructure can become deeply woven into the identity of a community, engendering enduring pride and delivering long-term social value well beyond its technical purpose.

The Ritom project is a powerful reminder that the future of energy lies in more than technology alone, but in how we carefully and intentionally navigate the intersections and synergies of history, environment and communities.

Planning for progress

Redeveloping or repurposing long-standing hydropower assets demands more than engineering expertise – it requires sensitivity to contemporary expectations. Since many of these projects were first built, the regulatory environment has shifted dramatically, with much greater emphasis on biodiversity protection (terrestrial and aquatic), climate resilience, the voices of local communities, and the cultural and heritage values of the Country on which these projects have been developed. The best projects don’t treat these as hurdles, but as opportunities to build broader value into the asset’s future.

Making good decisions at the earliest stages of refurbishment, repurposing or redevelopment is critical. To ensure lasting benefits, projects will need clear strategies grounded in sound technical evidence and shaped by a strong understanding of regulatory requirements and community expectations. Long-term success is more likely when projects are not only viewed through the technical lens of extending asset life, but are reimagined with community and environment at their core. Hydropower projects such as these can be catalysts for long-term energy security, greater ecological stewardship, strengthened social outcomes, and even become a source of community pride and inspiration.

In Australia, Entura is working with Hydro Tasmania to apply these principles through our work on the redevelopment of the Tarraleah hydropower scheme, parts of which are more than 80 years old. The redevelopment aims to increase capacity and flexibility so that Tarraleah can better serve the needs of the changing energy market – and future generations. It’s a project that echoes Ritom’s lesson: that heritage and innovation can coexist to create modern, sustainable infrastructure with value that endures for generations. By striking the right balance, hydropower can continue to do what it has always done best – power progress – while also meeting the needs and values of communities and environments today and long into the future.

Bunfu (above left) thanks Lombardi Engineering Switzerland for organising a comprehensive on-site tour of the Ritom hydropower project.

ABOUT THE AUTHOR

Bunfu Yu is a dynamic young leader in renewable energy planning, approvals, and business development. Bunfu played a pivotal role in Entura’s Environment and Planning Team’s success in achieving the Planning Institute of Australia’s National Award for Stakeholder Engagement in 2024. In 2023, Bunfu was named the National Young Planner of the Year by the Planning Institute of Australia. This honour recognised not only her passion for the planning and delivery of renewable infrastructure but also her active contribution to the profession through mentoring, public engagement, and knowledge sharing. She is currently a Senior Environmental Planner and a Business Development Manager at Entura, having joined the business as a Graduate Planner in 2018.

What to consider when you’re thinking about a synchronous condenser

Depending on when and where you want to connect your new solar farm or wind farm, the network service provider or your consultant may tell you that you’ll need a synchronous condenser. That may not be good news, because these machines don’t come cheap and they usually don’t provide a direct revenue stream. What should you do next?

Do you understand why you need a synchronous condenser?

The first step is to understand why you need the synchronous condenser. The inverters at the heart of most solar farms and most modern wind turbines need a strong electricity grid to push their energy into. If the network is not strong, the inverter is likely to fail to switch at the required times, swing against the power system like a pendulum, and distort the waveform, causing harmonics. The synchronous condenser overcomes this, strengthening the power system in the local area by forcing the network voltage into a near-perfect sine wave of the required size. 

The rules have changed!

The burden for providing system strength in Australia’s National Electricity Market has shifted significantly. Previously, new generators bore the primary responsibility under a ‘do no harm’ principle.

As of December 2022, ‘transmission network service providers’ (TNSPs) became ‘system strength service providers’ (SSSPs) and are now responsible for proactively providing a baseline of system strength across their networks.

Furthermore, new connecting parties now face new access standards and ‘system strength mitigation requirements’. This framework offers generators two clear choices to address their system strength impact: (1) pay a system strength charge, which is a fee reflecting the cost for the SSSP to provide the necessary system strength, or (2) self-remediate by installing their own solutions, such as synchronous condensers or grid‑forming inverters, to mitigate their impact.

At Entura, our experience so far indicates that many generators are actively exploring the self‑remediation option, prioritising operating cost over capex for their project.

Self-remediation may mean using synchronous condensers. However, there are also other solutions to system strength, which we’ll discuss below.

Is it possible to predict the need for a synchronous condenser earlier?

There are ways that you can predict at the project pre-feasibility stage that a synchronous condenser might be needed, before the network service provider becomes involved. Take a look at other renewable energy installations that have been constructed recently in the same region; if they needed a synchronous condenser, you almost certainly will too.

Consider where the installation is in the grid. If the answer to any of the following questions is yes, you will likely need a synchronous condenser: Is your installation remote from all traditional generating stations? Has a large traditional generator shut down in the area recently? Are other generators in the area routinely constrained due to network stability challenges?

Simple calculations can be completed based on information that most network service providers publish on their websites, including network constraints and fault levels. These calculations aren’t always definitive, but they will offer significant insight.

What do you need to specify?

It is best to specify the exact function that the synchronous condenser must achieve. Typically, this means specifying the fault current contribution that is required from the machine and leaving it up to the manufacturer to decide the optimal machine design including the headline MVA rating. Once these headline values have been determined, consider the following questions, each of which has a substantial cost impact:

• How much reactive power do you need the synchronous condenser to absorb? Typically these machines can only absorb approximately half of their headline rating, so don’t ask for too much unless you have deep pockets.
• Do you really need inertia that is greater than the manufacturer’s standard? Synchronous condensers are known for having inertia, but asking for inertia that is greater than the manufacturer’s standard will result in substantial additional cost and usually results in no additional revenue stream.
• The synchronous condenser is being installed to provide system strength, so do you really want it to be able to supply reactive power indefinitely? Perhaps 60 seconds would be enough.
• What are the impacts of planned or unplanned outages of the synchronous condenser?  Do these impacts warrant increased redundancy or spares retention?  We’ll talk about this in more detail below.

Are some cost savings not worth making?

For a synchronous condenser project, there are some measures that, on the surface, might appear to be potential cost-saving considerations. Can you omit the transformer tap changer? Could the cooling equipment be downsized or even omitted? Can you connect to the station 33 kV busbar? Detailed analysis is needed to answer these questions definitively. In our experience, however, the answers to each question have been emphatically no.

If you need the synchronous condenser to operate close to its rated reactive power absorption limit, you’ll need a transformer tap changer. Similarly, if the machine connects to a 33 kV busbar, fault levels will become unreasonable and an even larger machine will be required.

What’s the best contracting model?

Your choice of contracting model will depend on your appetite for risk and the sensitivity of your schedule. A typical solar or wind farm project is very schedule-sensitive, which suits an all-inclusive turnkey project delivery including everything from civil foundations, fencing and drainage through to integration with the farm’s control system. But this delivery mode comes at a price, and there are few Tier-1 equipment suppliers prepared to take on this model. The lowest-cost suppliers will be likely to want to put your machine onto a ship, point it in your general direction, and send you the invoice.

Whatever your contracting model, one of the largest risks to projects is the adequacy of the power system models. You need to be confident that the original equipment manufacturer (OEM) understands the market operator’s model requirements and has the skills to comply with them.

Can the machine offer economic benefits?

Two possible revenue streams could potentially flow from installing a synchronous condenser. By sizing the synchronous condenser to provide the reactive power required from a solar farm by the electricity rules, it is possible to operate the solar inverters and the main transformer at a higher power factor. This has the potential to increase the power output and consequently the revenue from the farm by up to 7%. A proponent could also install an oversized synchronous condenser and sell the spare system-strengthening capacity to another renewable farm in the same region. In the future, inertia and system-strength markets may evolve in ways that provide direct revenue streams for the synchronous condenser.

Redundancy considerations: Is one syncon enough?

Most new generators initially opt for a single, larger synchronous condenser to minimise upfront capital expenditure and ongoing operational expenditure. However, this decision inherently introduces a significant operational risk: the potential for severe output constraint if that sole synchronous condenser becomes unavailable. While synchronous condensers are generally highly reliable, mechanical and electrical failures can occur, and the lead times for repairs or replacement components can be substantial, leading to prolonged outages.

For asset owners considering the future divestment of their renewable energy project, this redundancy factor becomes a critical due diligence item for potential purchasers. A single point of failure for system strength support will be scrutinised. A prospective buyer will likely conduct a far more pessimistic assessment of the probability and duration of generation curtailment due to a synchronous condenser being unavailable, compared with the assessment of the original developer. This increased risk perception can directly and negatively impact the valuation and sale price of the entire energy park.

Is there an alternative?

The inverters at the heart of most solar farms and most modern wind turbines are changing. Until approximately 2023, they exclusively used a technology called ‘grid-following inverters’, but a newer ‘grid-forming inverter’ is breaking into the market. These inverters are more expensive at the moment, but that’s changing rapidly. The newer inverters are much less sensitive to system strength and can typically be operated with the base level of system strength that the TNSP is required to provide. Applications are now emerging in which changing the inverter eliminates the need for a synchronous condenser.

Putting it all together

The most cost-effective projects are often those that link multiple technologies – such as a wind farm with modern wind turbines, static VAr compensators and more than one synchronous condenser. These technologies were not designed to work well together, but with carefully coordinated controls they have done so in practice, providing the required system strength, voltage control and inertia for a successful minimum-cost project.

If you would like to find out more about how Entura can help you overcome electrical challenges for your renewable energy projects, please contact  David Wilkey  or Patrick Pease.

ABOUT THE AUTHOR

David Wilkey is Entura’s Principal Consultant, Secondary Electrical Engineering. He has more than 25 years of consulting experience in electrical engineering across Australia and New Zealand, focusing on the delivery of advisory on secondary systems and power systems engineering. David’s expertise spans all areas of electrical engineering with a particular focus on electrical protection, power system studies and rotating electrical machines.

MORE THOUGHT LEADERSHIP ARTICLES

Renewables in remote mines – a litmus test for the wider renewables transition

Entura’s Greg Koppens has recently returned from the Energy and Mines Summit in Perth, where he led the ‘Think Tank’: a collaborative session addressing the challenge of powering process steam requirements from renewables-generated electricity. Here he shares his observations on the rise of renewables in the mining industry …

Australia’s mining industry is beginning the peak phase of its energy revolution. However, I find it unfortunate that this exciting fact is invisible to regular people. It is happening in remote areas on mining leases, inaccessible to the public. Each project alone is not sensational enough for media attention, but added together these projects are nothing short of a technology revolution. For remote mining sites to have a solar farm is now standard practice. In many cases this is backed up by battery storage and a handful of mines have onsite wind turbines.

The past: fossil-fuel driven mines

Australia is world-renowned for our mining industries, with mines of virtually every resource throughout our country. Up until about ten years ago, nearly all of Australia’s mines ran completely on diesel or gas. In most cases diesel was trucked in, or gas was brought in via pipeline. Most of these mines have energy expenses in the tens of millions of dollars per year. A small change in the oil price can drastically impact the mine’s bottom line.

If there’s one doubtless fact about mining, it’s that miners are practical people. They are problem solvers, and they know what works. With the boom-and-bust nature of resource markets and shareholder responsibilities, finances must be well managed.

The present: hybrid renewables power generation

At the Energy and Mines Summit, there was no discussion about whether it’s a good idea to consider renewables in the mix of power generation – it was simply a given. This is an industry in ‘early maturity’: it is no longer pioneers running a trial. Several systems are in the order of 100 MW capacity. Renewables are a tested and proven business decision. Everyone has crunched the numbers on their sites and, while each project has unique site-specific requirements, the conclusions are unanimous. The frontier is now getting access to skilled people, there is community engagement for siting of large assets and mutual benefits, and the industry is exploring emerging technologies such as electric fleet.

We now have all the technology needed to harness the power of the wind and the sun in an 80/20 mix with fossil fuels. Or a 50/50 mix when the system has solar power alone. And this is what is being implemented in practice all over Australia. We can do it in a way that achieves targets for price, reliability, service life, operability, maintainability and environmental impact. This greatly reduces the costs and risks of intermediate services such as refining and transportation as well as exposure to the global oil price. Mining companies are taking control of their energy supply by either owning the energy and storage assets or building well-defined low-risk partnerships.

The big project: transitioning the Pilbara to renewables

At the conference there was some focus on the Pilbara, which is a huge and complicated energy consumer, consuming 16 TWh (16 million MWh) of electricity per year, mostly coming from gas.

On the surface, it seems to be very low hanging fruit to quickly construct a few solar and wind assets to shift this picture. However, in the interests of the best long-term outcomes, the area needs planning, consultation and coordination. The Western Australian Government has developed a plan for ensuring that common-use infrastructure is used where possible, rather than risking having multiple redundant assets owned by different corporations. Aboriginal and community participation is recognised as crucial for the appropriate siting of wind, solar and transmission equipment.

The near future: electric fleet

Approximately half of a typical mine’s energy needs can be met by onsite electricity generation. The other half currently requires diesel fuel to run a fleet of light vehicles, monstrous ‘haul’ dump trucks such as the 250 tonne CAT 793, and every piece of mobile machinery in between. These mobile machines are the next target for reducing costs, carbon emissions and labour. Several trial projects are happening. For underground mines, where diesel has previously been used, huge ventilation fans will need far less power when there are no exhaust fumes to expel.

Machine manufacturers are developing a wide array of specialised battery electric products. In some applications, there is battery swap technology, as in modern power tools. In other applications, a fixed battery plugs in to recharge, like in an electric car. There are also trolley systems, akin to a tram or train. The best system for each job depends on the application.

Transitioning to a fully electric fleet will significantly increase a site’s electricity needs, with the biggest chargers running at 6 MW at full power. We are expecting to see sites’ electrical grids upgraded soon to integrate this high-power charging.

What is Entura doing?

At Entura, in addition to electrical generation and distribution design, we have specialised capabilities in control systems and power system studies for mining projects. Our microgrid control system (MCS) uses standard and reliable industrial Allen Bradley hardware to monitor and control the power station assets. We have a field-proven core algorithm for maintaining a priority of reliable power supply including backup/reserve supply, while making the greatest use of wind and solar where available. We’ve proven this process in our existing installations in the field and we lead the industry in methodology, practicality and voltage/frequency management.

We’ve seen the real benefits these systems bring to our clients and communities, both at mining sites and in other remote locations. Entura has a long history of design, formation and operation of microgrids throughout Australia (such as King Island, Flinders Island, Rottnest Island, and at mining sites such as the Agnew gold mine) and in the Pacific region (including the Cook Islands, the Federated States of Micronesia, Tonga, and the Solomon Islands, to name just a few).

Contact us if you’re interested in unlocking the full potential of microgrids for your operation or community, or if you’re interested in ways to increase your use of renewable energy.

[Image immediately above] Entura’s Patrick Pease, Greg Koppens and Mark Richardson at the 2025 Energy and Mines Summit

[Top of article] Greg Koppens (centre) onsite at Jabiru Power Station, Northern Territory

ABOUT THE AUTHOR

Greg Koppens is Entura’s Principal Control Engineer Hybrid Renewable Systems and previously led Entura’s secondary electrical engineering team. Greg’s experience spans power, oil and gas, and mining, including onsite roles. With over two decades of detailed design experience, Greg facilitates collaboration between engineering disciplines and other stakeholders to solve complex problems. He regularly shares his extensive expertise with the mining sector to advance their decarbonisation goals. Find out more about Greg in our podcast series here.

New technologies are important tools, but they need to be used properly

Entura’s Technical Director (Water), Richard Herweynen, recently attended the 2025 ICOLD Congress in Chengdu, China, themed ‘Common Challenges, Shared Future, Better Dams’. Here he shares his observations on the state of play in the international dams industry – and the opportunities emerging with artificial intelligence and automation.

My first ICOLD Congress was in Beijing, China in 2000. I was presenting some finite element analysis work that I had done on Gordon Dam, a 140m-high concrete arch dam in Tasmania. The analysis was being used to help predict and explain some cracks that had formed at the base of the downstream face of the concrete shell, roughly normal to the foundation, during first filling. In the 1980s, an attempt had been made to model the crack using finite element modelling, but with little success due to the coarseness of the mesh. However, by the late 1990s, computing power had increased and finite element programs had improved, providing the capability to construct more detailed finite element models, which were able to predict and explain the cracking that had occurred.

Dr Sergio Giudici, the designer of Gordon Dam, was my mentor on this finite element analysis, and he reinforced these principles:

1. It is important to verify the input data to make sure the model represents, as well as possible, the actual dam parameters.
2. Results should be validated using alternative techniques to give the engineer confidence in the results that the model is producing (i.e. structural hand calculations still have a place).
3. Complexity should be built into these models only gradually, so that the engineer can see the impact of changes and determine whether they are reasonable.

These same principles are true for many complex engineering models and when setting up calculation spreadsheets or similar.

Now, 25 years on, I have had the privilege of attending the 2025 ICOLD Congress in Chengdu, China. At this Congress, there was much talk about the importance of dams in society for water security, the growing role dams and reservoirs play in providing resilience to climate change and the energy transition, the importance of balancing economic benefits and environmental needs, and – in all of this – the importance of ensuring that our dams are safe for communities downstream.

We have discussed many of these themes before – and they remain highly important; however, one thing I took away from ICOLD 2025 in particular was how China is embracing technology and advancing a ‘Smart Dam’ initiative.

New technologies and smarter dams

One could say that our industry has always been building smart dams, but China’s ‘Smart Dam’ concept is about using the full power of current technologies to construct, monitor and operate dams in smarter ways, and to use technologies to predict and adapt to changing conditions.

The CHINCOLD Workshop on Digital and Intelligent Technologies for Dam Construction, Operation and Maintenance, which occurred during ICOLD 2025, gave a glimpse of what may be possible.

Many projects utilise 3-dimensional digital models and building information modelling (BIM). However, the concept of having a digital twin of the dam, replicating every aspect of the physical dam in a digital form, opens the door to many possibilities, especially in light of the advent of artificial intelligence (AI).

Artificial intelligence and machine learning

Many organisations and nations have been cautious about AI, but China is increasingly adopting it to improve construction practices in dam engineering, improve monitoring and surveillance of dams, and to help adapt to extreme events as they occur.

Machine learning (ML), an element of AI, enables computers to learn from data without being explicitly programmed. ML algorithms analyse data, identify patterns, and make predictions or decisions, improving their performance over time and with more data. There are no doubt many engineering applications where ML could be used to help improve predictive modelling or optimisation, and to make these more efficient. However, the same principles that were important when we were beginning to embrace larger, more refined finite element models with the advent of faster computing remain true here:

1. We must verify the input data that machine learning is utilising to ensure we don’t get ‘garbage in equals garbage out’.
2. Results need to be validated. AI needs to be trained correctly, and we need experts involved at this stage to ensure that the outputs from AI are correct.
3. Complexity, or the full power of technology, should be added incrementally, to provide progressive confidence in the outcomes.

Engineering is the application of science, and therefore it is critical for every engineer to understand the fundamental principles and how to apply them. The complex computer programs used for a lot of engineering modelling can become ‘black boxes’, and practitioners risk diluting or losing their understanding of the fundamental principles behind the models, and hence their ability to validate the results.

Automation brings a step change in efficiency and accuracy

At the ICOLD Congress in 2000, I co-authored a paper for the international symposium on concrete-faced rockfill dams (CFRD) entitled ‘Hydro Tasmania experience in concrete-faced rockfill dams – past, present and future’. There is no doubt that Hydro Tasmania has a strong history in CFRD, with Cethana Dam playing an important role in the development of the modern, high CFRD.

In 2000, however, the future in CFRD that we envisaged did not include unmanned construction equipment with automatic quality control feedback loops. At the 2025 CHINCOLD Workshop on Digital and Intelligent Technologies for Dam Construction, Operation and Maintenance, a presentation was given by Wang Jiajun from Tianjin University on intelligent unmanned roller systems to compact rockfill dams. Unmanned rolling compaction (URC) systems involve three core technology modules: (1) intelligent perception, (2) autonomous planning and decision making, and (3) intelligent control.  These systems use automated driving technology to control the rolling process on earth and rockfill dams, improving productivity and quality. They can accurately control compaction parameters such as passes, speed, vibration and lift thickness. URC systems also enable continuous monitoring and real-time feedback for quality control, reducing human error and improving overall project performance. This automated technology was used on the 295m-high, 1.57km-long Lianghekou hydropower dam in China, with a total fill volume of 43 million m³.

The changing face of dam engineering

With AI and automation, the scope for embracing new technology in dam engineering is growing fast. It is clear that there are significant benefits that could be realised for dam design, construction, operation, dam safety and emergency response – and there’s a role for these advanced technologies at all of the stages of the life cycle of a dam. A degree of caution is appropriate and necessary, but caution should not be a reason to refuse to engage with the new technologies available to our industry.

However, with more sophisticated models – such as digital twins – being created of our dams, it is important to ensure we maintain the guiding engineering principles of verifying input data, validating models for correctness, and building complexity gradually. By doing this, we can provide the necessary assurance and confidence in our increasingly sophisticated and evolving tools.

ABOUT THE AUTHOR

Richard Herweynen is Entura’s Technical Director – Water. He has more than three decades of experience in dam and hydropower engineering, working throughout the Indo-Pacific region on both dam and hydropower projects. His experience covers all aspects including investigations, feasibility studies, detailed design, construction liaison, operation and maintenance and risk assessment for both new and existing projects. Richard has been part of a number of recent expert review panels for major water projects. He participated in the ANCOLD working group for concrete gravity dams and was the Chairman of the ICOLD technical committee on engineering activities in the planning process for water resources projects. Richard has won many engineering excellence and innovation awards (including Engineers Australia’s Professional Engineer of the Year 2012 – Tasmanian Division), and has published more than 30 technical papers on dam engineering.

When the lights go out

Major power outage events, like the one that affected Spain and Portugal this April, can be enormously disruptive and even deadly. Here Entura’s Technical Director Power, Donald Vaughan, considers the complex factors at play and their implications for grids everywhere ...

The recent power outage on the Iberian Peninsula provides a serious opportunity for reflection. Many articles have been published that try to explore the seconds and milliseconds after 12:32 PM on 28 April 2025 while only having access to the grainy frequency plots and approximate timelines that have been released (to date). This is not one of those articles. Nor is it an article that will lay blame on a particular technology or energy source. Instead, I will expand on the physics at play in this instance and reflect on whether current network security practices are adequately catering for changes to the power grid.

The physics

The power system is governed by the laws of physics, as is normal in the physical world. Quite a few of these laws tend to gang up on us during a power system event[1].

(i) conservation of energy
(ii) Ohm’s law
(iii) Newton’s laws of motion
and, of course,
(iv) Murphy’s law.

We’ll talk about the first three now and the last one later.

We learn very early that energy can neither be created nor destroyed (law i, above). This is at the heart of a power system event. The power system supplies loads by supporting voltage across the network that supplies millions of parallel loads. Each of these loads converts electrical energy into another form of energy based on the voltage it sees and its internal characteristics. This will continue as long as the voltage profile is maintained (law ii). So, demands take energy out of the power system regardless of what generation events occur. 

We know that the main trouble in the recent Iberian event started when a large amount of generation stopped in southern Spain. This led to an imbalance between generation and demand in that region. That imbalance is immediately addressed through the inertial action of synchronous generation across Europe (law iii). 

If interconnection were perfect, the burden of this inertial response would be shared perfectly across Europe and we probably wouldn’t be talking about this event quite as much as we are. Yet interconnection is rarely perfect (law ii). The frequency in Spain started to move away from frequency to the east and the AC interconnection to the east opened (which avoided the disturbance that stems from loss of synchronism). This should have been some help to the falling frequency in Spain given the eastward flows at the time. Under-frequency load shedding (UFLS) occurred around this time and should also have helped. It seems that the voltage disturbance that then occurred as a result of all these trips was the last straw.

Network security practices

It would be a gross over-simplification of network security practices to say that the power system should not lose customer load for the loss of one generation or network element (N-1 redundancy). The event on 28 April is way beyond that. Typically, for larger events, the grid should fail safely. We’ll look at that definition of ‘safely’ later. For now though, we can see that the grid did, in fact, try to fail gracefully:

• The AC interconnectors opened to avoid damaging loss of synchronism. 
• The under-frequency load shedding operated to try to preserve supply to some customers and keep the grid up, so as to reduce the duration of the interruption.
• Other generating unit controls acted to either increase output or trip to avoid damage.

We see in the Iberian Peninsula outage, as we did in the major South Australian blackout in 2016, lots of independent protection operations slowly but surely weakening the grid to the extent that it is no longer viable. Each of these protection operations undergoes scrutiny after an event of this nature, and will likely lead to some changes in Spain and France as was the case in South Australia.

The 28 April event appears to be quite slow in comparison to some other network blackout events. Even so, the event lasted less than 20 seconds and had 2–3 stages within it. One of the bases of design of the AC network is that it can generally operate with minimal, fast coordination even under large events. Control relies on observation, computation and action. So, to manage an event, a control system must measure what it needs to reliably determine what control actions it must make, and then take those control actions (assuming it can control all the elements it might need to control) in time for them to have an effect. If we think about a need to deftly control the response of individual units (or control systems) in an unusual way in a short period of time, then we can quickly conclude that this may not be possible.

If we can’t manage these events in real time, we have three courses of action:

(i) Physical plant

We could design networks, network supports, and network and generator protection and control systems to be more robust in the face of large power system events, thus decreasing the likelihood of unnecessary cascading protection operation.

This would include better interconnection, more dynamic reactive support (separate from generating units and demand), system-level protection schemes, and a review of generating unit protection settings to ensure generator capability rather than network requirements setting operating limits

(ii) Dispatch rules

We could change dispatch to provide greater margin for real and reactive power control as determined by the security risk and the cost to mitigate it. 

We could continue the traditional N-X approach to system supports or we could use a stochastic approach to determining system support requirements (weighting the probability of an event occurring against its impact). Either way, we’d have to pay an ‘insurance’ premium at each dispatch interval to make large-scale system outages less possible.

(iii) Restart planning and capability

We could make recovering from major blackout events easier and faster.

We think about these events in terms of how often they occur (which is what the first two course of action cover) and how long they last. System operators typically have generic plans for system restart that rely on starting synchronous plant and re-energising transmission systems and eventually customer demand. This can be made easier with interconnection. It can also be made easier with good visibility of voltages and voltage profiles across regions (and the tools to control them). Often, for big events like in South Australia in 2016, the network is left somewhat stricken from equipment damage. System restart efforts are often hampered in this scenario because plans need to be improvised to adapt. This depends on the skill, knowledge and experience of the operators. Some jurisdictions have simulated such events as part of training operators. 

The fourth law

We know that ‘anything that can go wrong will go wrong’. Seemingly simple things can undermine the best laid plans and the best intentions. We often can’t plan for these things specifically, although HAZOPS, root-cause analyses, scenario simulations and reviews can help us understand where the problems may lie and give us a chance to close loop-holes before they become SNAFUs.

Major power outage events are serious. They often lead to loss of life or injury, and the recent Iberian Peninsula event was no exception. They also always have an economic impact, which is not always fairly distributed. As an industry we need to improve how we manage them. We also need to get better at talking about technical issues in a political environment. If there’s a risk of blackouts, we have a duty to not only mitigate that risk within the current rules but also advocate for rule changes if that mitigation is inadequate. To be most productive, this conversation should happen in a techno-economic environment. The automatic debate after power system events often focuses on the role of renewables, commercial interests and the like, which may sometimes be entertaining but inevitably affects the techno-economic outcomes in a negative way for everyone.

ABOUT THE AUTHOR

Donald Vaughan has over 20 years’ experience providing advice on regulatory and technical requirements for generators, substations and transmission systems. He has worked for all areas of the electrical industry, including generators, equipment suppliers, customers, NSPs and market operators. Donald specialises in the performance of power systems. His experience in generating units, governors and excitation systems provides a helpful perspective on how the physical electrical network behaves.

Image: Basil James on Unsplash

READ MORE THOUGHT LEADERSHIP

[1] There are more laws, but these are the main and most accessible.

Decommissioning battery energy storage systems: It’s never too early to plan for retirement

All good things come to an end – even big battery energy storage systems (BESS). In Australia, the end of life for BESS may feel very distant, since we’re really only in the infancy of the booming BESS industry; however, the life expectancy of these big batteries is nothing like the design life of other renewable energy and storage technologies. With BESS currently only lasting for around 10 to 15 years of operation, developers and owners of BESS installations need to be thinking and planning now for what decommissioning will involve and what it will cost. In fact, planning for decommissioning is best done right from the start – long before the project is constructed.

Here, one of Entura’s BESS specialists, Dr Rahmat Khezri, answers some burning questions about the end stages of a BESS project.

• When does the life of a BESS project come to an end?

The need to decommission a BESS project could arise either from the conclusion of a contract or power purchase agreement – though this is unlikely – or from the expiration of the battery’s operational lifespan. This could be when the battery capacity has degraded to a point where it is no longer financially viable to operate in the market or when the battery’s internal chemistry has reached a point where it is unsafe to continue operating.

For nickel-manganese-cobalt (NMC) batteries, which held a significant share of batteries before lithium-iron-phosphate (LFP) batteries entered the market, this could be after 3,000 to 7,000 cycles at 80% depth of discharge (DoD) or around 10 to 15 years. For LFP batteries, which are gradually dominating the battery market for BESS, it’s around 4,000 to 10,000 cycles or 15 to 20 years. However, several factors can either reduce or extend the battery lifespan. Higher DoD shortens battery life, and frequent high-power cycling (e.g. for frequency control ancillary services, FCAS) can accelerate degradation. Avoiding prolonged high or low state-of-charge management (SoC) reduces degradation. Temperature is also an issue – so proper cooling and heating systems can support greater longevity.

• Is decommissioning the only option?

Full decommissioning of aging BESS assets is not always necessary at battery end of life, as some key components – such as inverters, transformers and balance of plant (PoP) – often retain residual service life. There may be opportunities for repowering or augmentation instead, which will require a much lower level of decommissioning activities. Repowering replaces old batteries with newer or upgraded technology to restore or enhance performance. Augmentation generally aims to increase capacity or power output by expanding the system with additional capacity, for example by adding extra battery racks to an existing setup.

• What does a full BESS decommissioning program involve?

A typical full BESS decommissioning program includes the following activities:

• developing the decommissioning plan including a risk assessment
• de-energising the BESS
• removing power conversion systems (inverter/transformer stations)
• removing integrated battery storage units (site dismantling and packaging may be required)
• shipping the packed battery storage units to recycling facilities
• removing electrical cables and conduits
• removing substation equipment
• shipping the power conversion systems and cables to recyclers of electronic waste
• transporting non-recyclable material removed from the site to disposal facilities
• restoring the site.

• How long could BESS decommissioning take?

Once a BESS project stops operating, the decommissioning process can begin (usually within 12 months) and can take around 6 to 9 months. Of course, this will depend on the scale of the BESS project, which will determine the amount of battery units and electrical infrastructure that will need to be removed from the site. If site restoration is required, this could extend the timeframe.

• What might BESS decommissioning cost?

Decommissioning costs are made up of labour, equipment, transport, materials, and recycling or disposal. These costs can be categorised across the stages of the project: removing the BESS facilities, restoring the site, packaging and transport, and the cost of recycling or disposal. If it is possible to achieve some value from salvage, this can be offset against the decommissioning costs. Currently the total recycling fee for high-powered batteries is around $10–15 per kg. Assuming approximately 6 kg for 1 kWh, the recycling cost would be $60–90 per kWh.

• Talking about recycling, what are the options for decommissioning BESS sustainably?

In Australia, we’re still in the early days of developing a lithium battery recycling industry – but we are seeing increasing recognition by owners, developers, regulators and the community of the need for the renewable energy industry to strengthen the circular economy and minimise landfill. Battery modules are recyclable – but salvage and reuse are likely to remain very dynamic and the future market for used lithium-ion modules remains uncertain. We recommend that every BESS developer/owner should aim to maximise recycling and develop as sustainable a waste management plan as possible. It is worth noting that recycling and reuse of inverters, transformers and BoP components are well established and available.

• What regulatory requirements are there in Australia for BESS decommissioning, and how do you envisage this changing?

In Australia, BESS projects must comply with relevant environmental regulations, which vary by state but generally align with the environmental protection guidelines set by each state’s Environment Protection Authority (EPA). At the federal level, the Product Stewardship Act 2011 promotes the responsible management of products at the end of their life cycle, including batteries. Decommissioned components from BESS projects, particularly lithium-ion batteries, are typically classified as prescribed industrial waste (PIW), requiring handling by licensed transporters and disposal at approved facilities.

At this stage the permitting process to build a BESS facility does not require a formal plan for decommissioning and disposal – but it is probably only a matter of time until we see more stringent requirements as part of the development application process. Despite a detailed plan not yet being required, it is definitely worthwhile doing, not least because the costs of decommissioning should be factored into the business case from the outset.

• What lessons have been learned from international examples of BESS decommissioning?

There haven’t been many examples of BESS decommissioning in our region yet, but the example of decommissioning the Tehachapi Energy Storage Project (TSP) project in South California in 2022 is an instructive real-life case study. This 8 MW / 32 MWh lithium-ion battery project was one of world’s first and largest BESS when it was commissioned in 2014. It had a footprint of 585 m^2, with 604 battery racks and two 40-foot PCS containers. The decommissioning was completed in just over 4 months from the generation of the purchase order to the finish.

A key takeaway from this case study is the significant impact that logistical and site-specific constraints can have on project outcomes. Although the PCS containers were initially expected to be removed within a single day, unforeseen space limitations and permitting restrictions ruled out the use of cranes. As a result, the containers had to be dismantled and cut into sections on-site. This increased the schedule by 17% and the cost by 20%. The lesson here is clear: success lies in the details, particularly when it comes to transport and access logistics. Thorough, site-specific planning is essential to avoid unexpected delays and budget overruns.

• What should Australian BESS developers and owners be doing now about decommissioning?

Ideally, every player in the BESS industry in Australia should be thinking ahead, however far off BESS decommissioning, repowering or augmentation may seem right now. It is never too early to start investigating the potential options, costs, timing, emissions, challenges and solutions – and developing a plan that can continue to evolve as the industry matures. A robust decommissioning plan will also be a valuable input into the technical due diligence process for sale/purchase. Ultimately, solid, early planning is the key to minimising risk and maximising value – and achieving a more efficient, more cost-effective and more sustainable outcome for any BESS project.

At Entura, we’ve been involved with BESS since the very start of the sector in Australia, and we’re always learning from our experiences here and around the world. We’re actively developing our analyses of decommissioning costs, transport, timing and circularity opportunities so that we can support your BESS project holistically, from cradle to grave.

Regardless of the stage of your BESS project, Entura can help. Contact Patrick Pease to find out how.

About the author

Senior Renewable Energy and BESS Engineer Dr Rahmat Khezri has vast professional and technical experience with batteries. He has worked in the renewable energy and battery industry in project delivery from BESS design, business case and feasibility analysis to operation and construction. Rahmat has managed several utility-scale BESS projects during his time with Entura, overseeing successful delivery while ensuring compliance with industry standards, optimising performance, and managing key stakeholder relationships. Before joining Entura, he worked on projects supported by Sustainability Victoria for technical design and business case development of ‘second-life BESS’ using retired batteries of electric vehicles. In 2023 and 2024, he was recognised by Stanford University as being in the top 2% of scientists worldwide for two consecutive years.

Planning for the future – the challenges of dam inspection and maintenance

No dam is ‘maintenance free’. Without appropriate maintenance and refurbishment at the right times, a dam may not be able to fulfil its function safely for the full length of its design life (which could be more than a century).

This presents many challenges for asset owners. To keep the dam operating as the designer intended – and get the most out of the original investment over the long term – owners will need to develop and implement a suitable operations and maintenance manual aligned with the asset management plan and reflecting a ‘whole of life’ strategy. These plans will need to consider the unique characteristics of each dam and cover all the relevant issues. And there are many!

Dams consist of a number of different elements. There are the main civil engineering components including the wall that holds back the water and the spillway – but there could also be mechanical elements (pipework, valves and gates) and electrical elements (power supply to lights, valves, gate motors and control systems). Each of these elements will have its own operational and maintenance requirements and different lifecycle duration. Ideally, all this detail needs to be captured in the operation and maintenance manual (as recommended by ANCOLD guidelines) and in an asset management plan.

Civil components

The civil components of dams have the longest life span, typically more than 100 years if well constructed and maintained. Common maintenance items that need to be regularly addressed include:

• Vegetation management

Trees and bushes will readily grow in earthfill and rockfill embankments. Regular control (e.g. annually) is necessary to ensure that roots don’t grow through the fill and initiate leaks through the embankment. Mowing the grass on the downstream face of the earthfill embankment and downstream contact is necessary so that the condition of the face can be observed. Even concrete gravity and concrete arch dams will require vegetation control along the downstream face contact with the foundation so that the dam can be easily viewed in routine inspections.

• Surface water drainage

Dam construction typically affects natural drainage lines, which is why surface water drains are a common feature around and on dams – such as along the groins (where the dam wall intersects with natural ground), along berms in embankment dams, along benches, at the top of cuttings, and along access tracks. Drains will need regular inspection for both erosion and blockage due to sediment or vegetation.

• Foundation drain cleaning

Concrete gravity dams and concrete arch dams typically have drains drilled into the rock foundations to relieve uplift pressures and help maintain stability of the wall. Over time, silt or iron-rich slime can build up as a byproduct of bacterial growth in the drains, reducing effectiveness. These drains typically require 5-yearly high-pressure flushing. Cleaning will also be needed for drains underneath spillways founded on rock and cut slopes in rock.

• Protection of the dam safety monitoring system

Protecting the dam safety monitoring system requires a range of regular activities. These include cleaning and clearing vee-notch seepage monitoring weirs, checking survey monitoring pillars and targets, and checking the calibration of level monitoring and indication devices, such as reservoir-level sensors, piezometers, tiltmeters and inclinometers. Regular functional testing will also need to be carried out on the alarming and tripping devices that form the primary protection elements of the dam, including spillway gates and scour valves.

• Clearing of trash racks

Outlet works usually have trash racks to stop debris entering the pipework and causing blockages. It’s important to check that the build-up of debris is tolerable and that any hydraulic losses won’t affect operations. Assessing and removing the debris isn’t easy, as the trash racks are often accessible only by remotely operated vehicles (ROVs) or by divers. Before the inspection, the outlet will typically need to be closed and isolated.

Inspection-driven longer term maintenance will also be required for particular elements of the dam, ideally addressing repair items promptly to minimise damage and the cost of future repairs if left untreated. For example, concrete repairs may be needed to address erosion in stilling basins and spillway chutes, or spalling of concrete due to reinforcement corrosion or freeze/thaw damage.

While regular inspections should be undertaken to detect slow deterioration, special inspections following major events – such as floods or earthquakes – should also be part of the operations and maintenance plan. Given that the key areas for inspection are often difficult to access safely, use of UAVs (e.g. to inspect a spillway crest and chute) or ROVs (e.g. to undertake underwater inspections or scanning of stilling basins, plunge pools or riverbed scour) should be considered.

When special inspections identify the need for repairs, the time is right to consider whether the dam’s design or surveillance could be improved to increase resilience for a similar event in future. For example, a higher strength concrete overlay may treat erosion of a spillway chute and increase its resistance to future erosion.

Mechanical components

Mechanical items such as steel or cast-iron pipework can also often last up to 100 years if adequately protected from corrosion. Concrete and cement mortar are very effective for this purpose as the alkaline environment provided by the cement paste provides a very low corrosion environment. Key to the effectiveness of this protection is ensuring that the cement remains in intimate contact with the steel or iron. This will require regular inspections and timely repairs. Where concrete protection is not practical, paint systems can be very effective for up to about 20 years. A suitable inspection regime will be needed so that any areas where the paint has deteriorated can be detected and patched.

Mechanical items such as valves and gates typically have an effective life of around 50 years; however, they need to be exercised regularly to keep them able to work on demand. This is not an issue of the parts wearing out from use; rather, it’s the risk of them seizing due to lack of use. Regular lubrication of bearings, gearboxes and trunnions needs to be included as part of the maintenance of these items. This is particularly important in scour valves and spillway gates that may have a very low frequency of use during normal operations but are there for use in emergencies. The wire ropes commonly used to hoist spillway gates open will need even more frequent replacement, at approximately every 20 years.

Electrical components

Electric motors are commonly used to drive the winches hoisting spillway gates or driving the shafts to open valves. Associated with the motors will be switchboards and power supply systems, typically including grid power supply and backup diesel generators. The typical life of these components is around 25 years. As with the mechanical components, lack of operation can lead to premature failure, so a regular regime of exercise is necessary to ensure maximum reliability and life.

The programable logic controllers (PLC) that are used to automate operations, allow remote operations and generate alarms will have a typical life of only 10–12 years due to changes in programming languages and rapid evolution of the hardware. 

Getting the most out of life

As we’ve seen, regular maintenance is fundamental for keeping all the components of a dam operating as intended and maximising their lifespan – whether that’s 10 years or 100. This maintenance, including the exercising of the mechanical and electrical components, needs to be clearly documented in the operations and maintenance manual and recorded in an asset management system. The asset management plan must allow for regular maintenance and also budget appropriately for replacement or refurbishment when any component of the dam is due for retirement.

At Entura, we believe in getting the most out of every piece of infrastructure because that’s good for our clients, communities and the planet. With a solid regime of inspection and maintenance, all the parts of your dam will be on the strongest path to a long, reliable and sustainable life.

If you’d like to talk with us about inspecting and maintaining your dam/s, contact Phil Ellerton, Paul Southcott, or Richard Herweynen.

About the author

Paul Southcott is Entura’s Senior Principal – Dams and Headworks. Paul has an outstanding depth of knowledge and skill developed over more than 3 decades in the fields of civil and dam engineering. He is a highly respected dams specialist and was recognised as Tasmania’s Professional Engineer of the Year in Engineers Australia’s 2021 Engineering Excellence Awards. Paul has contributed to many major dam and hydropower projects in Australia and abroad, including Tasmania’s ‘Battery of the Nation’, the Tarraleah hydropower scheme, Snowy Hydro, and numerous programs of work for water utilities including SeqWater, Sun Water and SAWater. His expertise is a crucial part of Entura’s ongoing support for upgrade and safety works for Hydro Tasmania’s and TasWater’s extensive dams portfolios. Paul is passionate about furthering the engineering profession through knowledge sharing, and has supported many young and emerging engineers through training and mentoring.

What have we learnt about renewable microgrids and remote area power systems?

With the evolution of modern inverter and renewable energy technologies, it’s become possible to build microgrids with very high renewable penetration. These renewable solutions are revolutionising electricity sustainability, reliability and access in many far-flung locations – such as Pacific islands, remote locations around Australia, and on mining sites.  

High renewable penetration allows operators of off-grid microgrids to extract maximum value from their installed solar, wind or other renewable generation while minimising the use of fossil fuels, such as diesel. It’s a win-win for the financial bottom line and emissions-reduction goals. If the microgrid connects with a broader power system, the benefits of reducing reliance on externally sourced energy are significant too.   

Establishing a relatively simple microgrid with modest fuel-saving targets doesn’t have to be particularly complex. It’s within the reach of current technology and practice to be able to optimise microgrids to all but eliminate the use of fossil fuel (with the related advantages of eliminating fuel handling, shipping, etc.). However, careful thought must be given to the distinct nature of the microgrid: its customers, energy sources and storage options. 

To make a microgrid successful, some technical challenges will need to be managed. Resolving these challenges in a cost-effective way becomes more difficult as the renewable energy balance approaches 100% – but they’re not insurmountable. Let’s explore. 

Challenge 1: Ensuring quality of supply and an acceptable customer experience 

The small size of microgrids and the fact that they are usually dedicated to a single ‘customer’ makes engineering a microgrid a sensitive task. While larger grids can operate with tight voltage and frequency tolerances and multiple levels of redundancy, microgrids often cannot. This inevitably means negotiating acceptable system standards for islanded operation that are within the tolerance of customers’ equipment and expectations. Microgrids powered by fossil fuels typically have more difficulty maintaining tight frequency and voltage tolerances than renewables-based microgrids. 

Understanding customer and stakeholder expectations relating to reliability and robustness (energy availability and the ability to ride-through faults) is key to the establishment of a successful microgrid. Where the microgrid exists with no possibility of interconnection to another power network (i.e. in an ‘island’), there is more flexibility and less operational complexity. Discerning acceptable standards and practices is still not easy but it can be a more productive discussion than when the microgrid must comply with less tailored standards due to interconnection. 

When the microgrid is interconnected, many of the technical requirements for the microgrid will be specified and/or mandated by the network service provider, electricity code requirements, and some operational requirements for electrical safety. If additional communication and inter-tripping with network equipment remote to the microgrid are required, these can add further complexity. 

Challenge 2: Managing different modes of operation requiring different controls 

In the previous section, we discussed how complicated it is to determine system standards. A great deal of care is also needed when contemplating which standards and controls are most appropriate to the microgrid’s specific characteristics. This is where cookie-cutter solutions could under-deliver and a more insightful approach is required. 

A microgrid must manage the voltage, frequency and quality of supply while it is islanded as well as during periods of interconnection. Islands can remain satisfactory for longer if there are energy sources, storage and load controls within the island. Each of these elements comes at a cost and, depending on the frequency and duration of islanded operation, must have a value outside of the islanded scenario. 

Our experience with microgrids is that semi-autonomous operation of each of the power sources using standard power system control approaches (solar, BESS and other power sources on voltage and frequency droop control) leads to the simplest and most secure response to transients (load or generation trips, network or network faults). Slower controls can be put in place to balance generation and rates of battery charge or discharge. If the battery power rating is large enough relative to the largest disturbance, it can manage most frequency disturbances within acceptable limits. If the battery energy capacity is large enough, it can always maintain a state of charge that allows fast reaction to variations in customer demand or VRE. Alternatively, auxiliary plant such as switched resistors, synchronous condensers and customer-level load control can be used to minimise battery power, storage and other energy inputs.  

Operating microgrids in different modes requires careful engineering of the controls and equipment. The solutions and approaches described above have proven successful across multiple projects, but the key is to always be open to new solutions as new problems arise or new technologies emerge. 

Challenge 3: Understanding the marginal value of resistors, synchronous condensers and/or demand management 

Auxiliary equipment can help to extend the range and effectiveness of a microgrid to rely solely on renewable energy. The challenge is to understand the actual value of extension in this context. Where it has a direct bearing on fossil fuel use, the benefits are clear. Where it might cause an incremental improvement in the robustness of the islanded operation only, it’s important to consider whether any operational benefits or security benefits gained from the additional capital investment are valuable enough to justify the cost. 

If the robustness of islanded operation is to be increased by managing customer demand, customer storage and/or embedded generation (e.g. rooftop solar), the value of the extended island longevity should be weighed against the perceived cost (direct or indirect) to the customer. This requires careful consideration of the diversity within the community, their openness to energy management, and the relationship between true costs and benefits. 

Microgrids that maximise local use of renewable resources represent a relatively cost-effective option for lowering carbon emissions and/or reducing energy costs. Isolated communities, remote industrial sites, unreliably connected rural communities and others could benefit greatly from considering microgrid opportunities.  

Entura has a long history of design, formation and operation of microgrids throughout Australia (such as King Island, Flinders Island, Rottnest Island, and at mining sites such as the Agnew gold mine) and in the Pacific region (including the Cook Islands, the Federated States of Micronesia, Tonga, and the Solomon Islands, to name just a few). We’ve seen the real benefits these systems bring to our clients and communities.  

Contact us if you’re interested in unlocking the full potential of microgrids for your operation or community, or if you’re interested in ways to increase your use of renewable energy.  

ABOUT THE AUTHORS

Donald Vaughan has over 20 years’ experience providing advice on regulatory and technical requirements for generators, substations and transmission systems. He has worked for all areas of the electrical industry, including generators, equipment suppliers, customers, NSPs and market operators. Donald specialises in the performance of power systems. His experience in generating units, governors and excitation systems provides a helpful perspective on how the physical electrical network behaves.

Greg Koppens is Entura’s Principal Control Engineer Hybrid Renewable Systems and has led Entura’s secondary electrical engineering team. Greg’s experience spans power, oil and gas, and mining, including onsite roles. With over a decade of detailed design experience, Greg facilitates collaboration between engineering disciplines and other stakeholders to solve complex problems. He regularly shares his extensive expertise with the mining sector to advance their decarbonisation goals. Find out more about Greg in our podcast series here.

We built this synchronicity … but what now?

The alternating current (AC) transmission age started in 1891 through collaboration and perseverance. This transmission method has transformed the world, led us to the brink (or over the brink) of a climate disaster, and provides the backbone for a future founded on abundant renewable resources (in Australia, at least). Collaboration and perseverance are now required to ensure the continued utility of the grid.

Synchronous machines have always been the driving force in the grid. These elegantly simple electrical machines sit in powerhouses around the globe using their century-old technology (nearly 150 years, in fact) to convert mechanical energy into electrical energy to power the computer that I’m using to type this.

There’s a romance to these machines. It’s more than nostalgia. They spin, as the name suggests, in synchronism. If one of them falters, all the rest pick up the slack. The only connection they need is the power lines. This robustness is central to the way our electricity grids have operated for over 130 years – but the influence of synchronous machines is slowly being eroded.

The most obvious erosion of the influence of synchronous machines is their displacement by inverter-based renewable (IBR) technologies as solar, wind and battery energy storage (BESS) installations proliferate. A less obvious erosion of their influence is the diminishing understanding and appreciation of synchronous technology within the industry. This lack of understanding by engineers, planners and regulators of the fundamental building blocks of the electricity grid is starting to show. 

This might sound like the curmudgeonly ranting of yesterday’s engineer as technology passes them by. Maybe it is … but, rather than dwell on negatives, let’s look at what synchronous machines bring to the power system.

• System strength

The fundamental difference between synchronous machines and IBR is thermal inertia. Typical synchronous machine design can sustain high levels of over-current for a relatively long time (seconds) compared to IBR units (milliseconds). This difference allows synchronous machines to provide a strong ‘natural’ response to voltage variations in the power system without threat of overload and damage. Transmission protection systems – and therefore grid security and safety – rely on this characteristic.

There are alternatives. Overload capacity can be built into inverters, but this is expensive. Dedicated inverter-based devices such as static synchronous compensators (STATCOMs) can be used to provide fault response.

• Inertia

Synchronous machines spin. Their spinning bits (rotors) have mass, so they have mechanical inertia. This mechanical inertia doesn’t require a control system to provide an inertial response. The inertial response from a synchronous machine is a known, predictable quantity, regardless of voltage.

IBRs can provide synthetic inertia and, when voltage is healthy, can out-perform synchronous units. When voltage is not nominal, the same current limitations that affect the IBRs’ ability to deliver fault level can also restrict the effectiveness of synthetic inertia delivery.

• Robustness

The previous two characteristics – system strength and inertia – show the support that synchronous machines can provide to the power system during disturbances. The synchronous machine can deliver these supports across a wide range of power system disturbances to voltage and frequency.

IBRs typically rely on fast controls to manage their response to system disturbances. Under some extreme conditions these controls may not be fast enough or well enough tuned to manage. While tuning is important to synchronous machine performance, often it has a second-order effect or adds robustness over and above the natural response.

Displaced but not superseded

Understanding the inherent dynamics of synchronous machines gives power system engineers a better appreciation of these machines’ contribution to power system stability. Regulators should be mindful of the reduced risk (and mostly advantages) to system security that synchronous machines offer relative to IBRs. This is despite the uncontrollable nature of synchronous machines. That is, physics dictates the stabilising effects from synchronous machines whereas control algorithms determine whether an IBR can stabilise or destabilise. Controller model accuracy is therefore more important for IBRs than it is for synchronous machines where transient stability or electro-mechanical transient time frames are considered.

Better understanding of synchronous machines should lead to more appropriate rules relating to dynamic response to system events. Overly specific requirements for fault ride-through, power recovery post-fault, and maintenance of real and reactive power during voltage disturbances may all lead to needless protracted negotiations over access standards. This slows down the progress of the energy transition, frustrates otherwise helpful development, and diverts resources towards trivial considerations rather than focusing on issues of greater importance.

Synchronous machines will play a role in the energy grid of the future. Our industry needs to maintain expertise and regulatory frameworks that allow this technology to continue providing the grid with vital stabilisation and robustness.

ABOUT THE AUTHOR

Donald has over 20 years’ experience providing advice on regulatory and technical requirements for generators, substations and transmission systems. He has worked for all areas of the electrical industry, including generators, equipment suppliers, customers, NSPs and market operators. Donald specialises in the performance of power systems. His experience in generating units, governors and excitation systems provides a helpful perspective on how the physical electrical network behaves.

‘Dams for People, Water, Environment and Development’ – some reflections from ICOLD 2024

Entura’s Amanda Ashworth (Managing Director) and Richard Herweynen (Technical Director, Water) recently attended the International Commission on Large Dams (ICOLD) 2024 Annual Meeting and International Symposium, held in New Delhi. Amanda presented on building dam safety capability, skills and competencies, while Richard presented on Hydro Tasmania’s risk-based, systems approach to dam safety management, and the importance of pumped hydro in Australia’s energy transition. 

Here they share some reflections on ICOLD 2024 …

Richard Herweynen – on the value of storage, ‘right dams’, and stewardship

At ICOLD 2024 we were reminded again that water storages will be critical for the world’s ability to deal with climate change and meet the growing global population’s needs for food and water. We can expect greater climate variability and therefore more variability in river flows, which means that more storage will be needed to ensure a high level of reliability of water supply. Without more water storages to buffer climate impacts, heavily water-dependent sectors like agriculture will be impacted.

To slow the rate of climate change, we must decarbonise our economies – but without significant energy storage, it will be difficult to transition from thermal power to variable renewable energy (wind and solar). Pablo Valverde, representing the International Hydropower Association (IHA), said at the conference that ‘storage is the hidden crisis within the crisis’. There was a lot of discussion at ICOLD 2024 about pumped hydro energy storage as a promising part of the solution. It is also important, however, to remember that conventional hydropower, with significant water storage, can be repurposed operationally to provide a firming role too. Water storage is the biggest ‘battery’ of the world and will be a critical element in the energy transition.

With the title of the ICOLD Symposium being ‘Dams for People, Water, Environment and Development’, I reflected again on the need for ‘right dams’ rather than ‘no dams’. ‘Right dams’ are those that achieve a balance among people, water, environment and development. In the opening address, we were reminded of the links between ‘ecology’ and ‘economy’ – which are not only connected by their linguistic roots but also by the dependence of any successful economy on the natural environment. It is our ethical responsibility to manage the environment with care.

When planning and designing water storages, we must recognise that a river provides ecological services and that affected people should be engaged and involved in achieving the right balance. If appropriate project sites are selected and designs strive to mitigate impacts, it is possible for a dam project’s positive contribution to be greater than its environmental impact, as was showcased in number of projects presented at the ICOLD gathering. Finding the balance is our challenge as dam engineers.

The president of ICOLD, Michel Lino, reminded delegates that the safety of dams has always been ICOLD’s focus, and that there is more to be done to improve dam safety around the world. At one session, Piotr Sliwinski discussed the Topola Dam in Poland, which failed during recent floods due to overtopping of the emergency spillway. Sharing and learning together from such experiences is an important benefit of participating in the ICOLD community.

Alejandro Pujol from Argentina, who chaired one of the ‘Dam Safety Management and Engineering’ sessions, reflected that in ICOLD’s early years the focus was on better ways to design and construct new dams, but the spotlight has now shifted to the long-term health of existing dams. It is critical that dams remain safe throughout the challenges that nature delivers, from floods to earthquakes. In reality, dams usually continue to operate long beyond their 80–100 year design life if they are structurally safe, as evidenced in the examples of long-lived dams presented by Martin Wieland from Switzerland. He suggested that the lifespan of well-designed, well-constructed, well-maintained and well-operated dams can even exceed 200 years. As dam engineers, no matter the part we play in the life of a dam, we have a responsibility to do it well.

From my conversations with a number of dam engineers representing the ICOLD Young Professional Forum (YPF), and seeing the progress of this body within the ICOLD community, I believe that the dam industry is in good hands – although, of course, there is always more to be done. I was pleased to see an Australian, Brandon Pearce, voted onto the ICOLD YPF Board.

Another YPF member, Sam Tudor from the UK, reminded us in his address of the importance of knowledge transfer, the moral obligation we all have especially to the downstream communities of our dams, and our stewardship role. He was referencing his experience of looking after dams that are more than 120 years old – all built long before he was born. Many of our colleagues across Entura and Hydro Tasmania feel this same sense of responsibility and pride when we work on Hydro Tasmania’s assets, which were built over more than a century and have been fundamental to shaping our state’s economy and delivering the quality of life we now enjoy. It is up to all of us to carry the positive legacy of these assets forward with care and custodianship, for the benefit of future generations.

Amanda Ashworth – on costs and benefits, dam safety, and an inclusive workforce

Like Richard, I found much food for thought at ICOLD 2024. For me, it reinforced the need to accelerate hydropower globally, particularly in places where the total resource is as yet underdeveloped. To do so, we will need regulatory frameworks that support success – such as by monetising storage and recognising it as an official use – and administrative reforms that ease the challenges of achieving planning approvals, grid connection agreements and financing for long-duration storage. We must encourage research and development to move our sector forward: from multi-energy hybrids to advanced construction materials and innovations to improve rehabilitation.

In particular, I’ve been reflecting on how our sector could extend our thinking and discourse about the impacts and benefits equation beyond the broad answer that dams are good for the net zero transition. How can we enact and communicate the many other potential local environmental and social benefits and long-term value from dams?

Much of the world’s existing critical infrastructure came at a significant financial expense as well as social and environmental costs – so it is our obligation to pay back that investment by maximising every dam’s effective life. When we invest in extending the lifespan of dam infrastructure through effective asset management and maintenance, and when we maximise generation or the value of storage in the market, we increase the ‘return on investment’ against the financial, social and environmental impacts incurred in the past.

Of course, the global dams community must continue to prioritise dam safety and work towards a ‘safety culture’. I was pleased to hear Debashree Mukherjee, Secretary of the Ministry of Jal Shakti, celebrate the progress on finalising regulations across states to enact India’s Federal Dam Safety Act and establishing two centres of excellence to lift capacity across the nation. Dam safety depends on well-trained people with the right skills and competencies to comply with evolving standards, apply new technologies, and respond effectively to changing operational circumstances and demands. 

I also enjoyed hearing from ICOLD’s gender and diversity committee on its progress, including updates from around 14 nations on their efforts to build a more inclusive renewable energy and dams workforce. This is front of mind for us, as we step up Entura’s own focus and actions on gender equity throughout our business this year.

The challenges facing our dams community – and our planet – are enormous, but there is certainly much to be excited about, and we look forward to continuing these important conversations over the next year.

From Richard, Amanda and Entura’s team, many thanks to the Indian National Committee on Large Dams (INCOLD) for organising and hosting this year’s ICOLD event, supporting our sector to build international professional networks, and facilitating the sharing of experiences and knowledge across the globe – all of which are so important for growing the ‘ICOLD family’ and supporting a safer, more resilient and more sustainable water and energy future.