Life cycle of a dam – Phase 1: Inception – Setting a dam project up for success

By Jaretha Lombaard

A dam’s life cycle moves through inception, design and construction through to operation and maintenance, and potentially to upgrades, decommissioning or repurposing. In this first article in our forthcoming ‘Life cycle of a dam’ series, Senior Civil Engineer Jaretha Lombaard shares her insights into the important first stage in a dam’s life, and how a strong inception stage has shaped a new pumped hydro project proposal.

Infrastructure’s ability to successfully serve communities for generations depends heavily on good beginnings. To me, a ‘good beginning’ for dam-specific projects looks like this:

Know your ‘why’

The first step in any infrastructure project is usually to clearly define needs, objectives and key benefits. In the case of water and energy infrastructure, the need may be residential, industrial or environmental water supply, irrigation, flood mitigation, river regulation, energy generation and storage, or a combination. Once the need is clear, we should explore the best way to meet the need – rather than assume that a dam is necessarily the right answer. If the ‘why’ is unclear, momentum can build around a technical solution before the real objective has been tested. When the ‘why’ is clear, every subsequent decision has a stronger basis.

Start broad

If the right answer is a dam, we now need to probe deeper – from the ‘why’ to the ‘where’, ‘how’ or ‘what’. This is the time to brainstorm a range of high-level options and then investigate whether they’re technically feasible, practical and capable of meeting the project’s objectives. How much water, energy storage or flood mitigation is required? How often must water or energy be available? Should we be considering a smaller or larger storage, an off-stream storage or a multipurpose project? Where could the dam be located? What type of dam could suit the available sites? Can the project be safely constructed? What are the main environmental and social constraints, and the possible risks?

Align multidisciplinary expertise

Engineers should work alongside geologists, hydrologists, environmental scientists, ecologists, heritage and social specialists and dam safety practitioners from the earliest stages so that potential impacts can be identified early and addressed right from the start. The planning and concept stages have the greatest influence on a project’s long-term outcomes. This is when decisions about site selection, dam type, reservoir level, spillway configuration, operational rules and mitigation measures are still open to improvement. Once the project moves into later phases, changes become more constrained and often more costly to implement.

Engage stakeholders early

Stakeholder alignment should always begin early to confirm the need, identify constraints and priorities, reveal local knowledge and alternative ideas, and test whether options are likely to be acceptable. Some stakeholders may seem less prominent at first but could become highly influential if their needs or concerns are missed. Once stakeholders are aligned, it’s important to ensure transparency and ongoing communication to build and maintain trust.

Gather the right level of information at the right stage

Options need to be developed to a comparable level. Too little information makes meaningful comparison difficult. Too much detail wastes effort on options that may not proceed. The focus should be on the factors most likely to determine the preferred option, such as technical feasibility, environmental and social impacts, constructability and approvals risks. Effort should be spent where and when it will make the biggest difference to the outcome. This means focusing on the key knowledge gaps and risks that will drive the technical feasibility, cost, delivery timelines, and stakeholder acceptability.

Carefully size and stage investigations

Geology and geotechnical characteristics are key inputs for early decision-making around technical feasibility and cost of a dam project, but the timing and scale of investigations need to match the maturity of the project. A staged investigation program may begin with desktop geological and topographical reviews, engineering geology site walkovers, and non-destructive, low-impact methods such as geophysical surveys and geological mapping. As the options narrow, more intrusive investigations such as test pitting and drilling can be targeted where they will provide the most value. Drilling too early can create its own problems. If too many options are still under consideration or general site conditions area not yet well understood, investigations may need to cover a very large footprint, which means more cost and more disturbance. A staged approach helps balance decision-making needs, investigation costs, and risks by progressively refining the understanding of site conditions as the project matures.

Use a consistent, defensible method to compare options

A structured, risk-based multi-criteria analysis can help compare options more transparently by keeping material risks visible. High risks should not disappear within averaged or low weighted scores. Decision-makers need to see the trade-offs clearly, especially where environmental, social, technical and financial considerations point in different directions. The strongest options are usually those that perform consistently across multiple criteria. They may still have uncertainties, but those uncertainties are understood, recorded and can be effectively managed.

Keep good records

Dam projects often span many years, during which project teams, stakeholders and decision-makers, as well as regulations, can change. A well-maintained record of decision-making is essential. It provides transparency and rationale around why options were excluded, preferred pathways selected and constraints addressed, including the risks, uncertainties and opportunities that influenced those decisions. It also reduces the likelihood of revisiting issues that have already been assessed.

Involve independent reviewers early

An independent reviewer or review panel can be one of the most valuable contributors during project inception and development. The individual or panel should have the right balance of technical expertise, be able to communicate well in a collaborative manner, understand their scope of work and be well briefed. An early and ongoing engagement enables reviewers to develop a strong understanding of the project’s original ‘why’s, ‘what’s and ‘how’s, enabling them to provide informed advice and constructive challenge throughout project development.

Don’t try to do everything at once

Not every detail needs to be resolved to 100% when comparing potential options or even once the preferred option has been established. That resolution and optimisation can happen in the ‘detailed design’ phase, which we’ll talk about in our next article. However, by the end of the preliminary design or ‘reference design’, the preferred option should be workable, costable and suitable for approvals and investment decisions, with the key aspects robust enough for the project to move forward with confidence.

INCEPTION PRINCIPLES IN PRACTICE: THE PROPOSED CETHANA PUMPED HYDRO PROJECT

The proposed Cethana pumped hydro project in Tasmania is a large energy storage project with a generating capacity of 750 MW and a storage capacity of 20 hours. It proposes using the existing Lake Cethana as the lower storage and building a new upper storage, underground power station, and underground tunnels connecting the storages. If approved, it will be the first pumped hydro project in Tasmania.

The inception phase of the project demonstrates how the principles discussed in this article have been applied in practice.

Entura contributed to the prefeasibility and feasibility studies that identified 14 possible pumped hydro sites in Tasmania and narrowed these to the three most promising, and then to Lake Cethana as the preferred option for final feasibility. The options were assessed against technical, environmental, social and economic factors using multicriteria analysis. The Lake Cethana option was selected as the preferred project option because it offered deep storage capacity, greater cost certainty, less potential environmental and social impacts, and more flexibility in sizing and capacity.

By the time I became involved, the upper storage site had already been selected, but there were still aspects to resolve. My focus was on revising the layout and embankment material zoning of the upper storage so it could best fit the available space, reduce the environmental impacts, balance cut and fill volumes, reduce spoil, preserve the required storage volume and hydraulic head, and maintain efficient flow to the intake.

An understanding of the geology and geotechnical conditions was central to refining the layout and internal embankment zoning. Some areas included highly compressible soils which directly informed the quantity of material to be excavated and spoiled, the construction phasing required to limit post-construction settlement to acceptable amounts, and ultimately construction cost estimates.

The outcome was a reference design for the upper storage that supported the overall project cost estimate, based on available information, and provided a clearer understanding of the key considerations for the next stages of design.

The team did not need to solve everything at this stage of the design, but it did need confidence that the main concept would work. For example, the project needed a technically sound and workable approach to lining the storage, maintaining the liner, monitoring performance and detecting potential leakage. Although some opportunities for improvement were carried forward to the future stages of the design process, the fundamentals needed to be strongly in place at this stage.

This is the purpose of inception: It should move a project from a broad need to a robust and defensible preferred option. At its core, inception is about progressively reducing uncertainty, allowing decisions to be made with increasing confidence while keeping options open long enough to identify the best path forward. When done well, it provides owners, stakeholders and reviewers with confidence that the project is worth taking forward.

In our next article in this series, Principal Civil Engineer Tim Griggs will share his insights into the second stage in a dam’s life and how a rigorous development phase led to the successful completion of Meander Dam.

To see the full picture of the life cycle of a dam – all in one place – check out this article.

ABOUT THE AUTHOR

Jaretha Lombaard is a senior dams engineer with more than 12 years of diverse experience across southern Africa and Australia. Her expertise includes dam design, tender and construction support, dam safety assessments and inspections, with a strong focus on safe, sustainable infrastructure. Since joining Entura, she has contributed to major projects including as design manager for major dam upgrades. She is highly regarded for her commitment to technical excellence, leadership, proactive problem solving and collaborative delivery. Passionate about best practice, continuous improvement and professional growth, she actively supports mentoring, knowledge sharing and training.

Making more of your monitoring

Monitoring dams is a key aspect of dam safety, but what do we mean by monitoring, why is it necessary, and how can dam owners make the most of their monitoring investment? Senior Principal Paul Southcott shares his insights …

Dam safety is a system that responsible dam owners put in place to protect the community, environment and infrastructure. Monitoring is an important element of this system. By monitoring we mean using instrumentation to help assess the condition of the dam and detect early signs of deterioration so that action can be taken to address the issue.

Here are some principles for getting the best value from your investment in dam instrumentation:

Monitoring across the dam lifecycle

Exactly which instruments need to be considered will depend on both the stage of the dam’s life the type of the dam. For example, at the concept stage, rainfall and stream gauges in the catchment will provide key data on the hydrology including flood estimation and yield. Similarly, during construction of an embankment dam, settlement cells may be used to measure the deformation of fill as the dam is built. There may even come a time in the dam’s lifecycle when certain instruments no longer provide relevant data to the dam owner. This article focuses on the operation stage of the dam, but the same principles apply regardless of the stage of the dam lifecycle.

Measuring the right things in the right places

Instrumentation is fundamentally about measuring a parameter associated with dams – such as seepage, pressure or movement – that tells us if the dam is behaving as the designer intended or if some investigation and/or intervention is required. To decide what instruments to install and where to locate them, the key thing is to measure the parameters linked to the potential failure modes (PFM) of the dam. This reveals when early intervention is needed to prevent failure or to trigger emergency actions through the Dam Safety Emergency Plan (DSEP).

To understand the PFMs of a dam, we must first undertake a risk assessment that considers all the potential ways that the dam can fail. The next step is to consider which parameters could be measured to give warning of that particular failure mode. For example, if the failure mode was flood overtopping leading to erosion and breach of an embankment dam, then measuring rainfall and reservoir level would be appropriate. Rainfall would warn that a flood is coming; reservoir level measurements would reveal how close the dam is to being overtopped. Both forms of instrumentation would be useful: rainfall as a lead indicator that conditions are changing and reservoir level as an indicator of current conditions and whether actions need to be taken (e.g. opening spillway gates or starting emergency evacuations).

Other PFMs would require different types of instruments to detect incipient failures. For example, piping or internal erosion is often a key failure mode of earthfill and earth and rockfill dams. The best instrument to detect this failure mode is a seepage monitoring weir, often using a v-notch weir. This instrument captures and measures the seepage rate by measuring the water level behind the weir, which can then be converted to an equivalent flow. The trend in the readings over time will indicate whether seepage is stable or is showing an increasing trend that may indicate an emerging piping failure. Location of the weir is critical: it needs to be located so that it captures all the seepage from the dam (or part of the dam) but is not so far downstream that there is a significant catchment highly influenced by rainfall runoff.

Installation and commissioning

To make sense of instrument data, we need to know exactly where the instrument is installed and what it is installed in, and be confident that we have the right calibration certificates. This is why a detailed quality assurance process needs to be in place for installing and commissioning instruments.

Consider the installation of a vibrating wire piezometer in the rock foundation of a concrete gravity dam to measure the uplift pressures under the dam. Installing the piezometer will require drilling a hole into the rock, lowering the piezometer down the hole, surrounding it with a backfill material and sealing it into the hole, running the cable to a data logger and programming the data logger. Each step could affect the instrument’s ability to provide meaningful data for review and analysis:

Drilling the hole: Soil and rock foundations are typically heterogeneous (not uniform), so the instrument’s location will affect its readings (a piezometer installed in solid rock will not record anything, whereas installation in closely jointed rock may record close to reservoir pressure). Geotechnical logging of the hole is recommended so that the instrument can be installed where it will capture the most relevant information and to assist in interpreting the data.
Installing the instrument: The level of the instrument must be recorded correctly because it is critical to both the calculation of the foundation pressure and the associated interpretation of the data. Similarly, before installation, the instrument needs to be correctly identified by recording its serial number (and associate calibration certificate), and its function must be checked with a zero reading obtained.
Sealing the instrument in the hole: Sealing the hole prevents it becoming a drain (i.e. providing pressure relief), but will also prevent removal of the instrument in the future, which is why a quality assurance process should first confirm that the instrument is functioning appropriately.
Running the cables: Cables must be correctly identified to ensure the instrument is correctly identified at the data logger. This is particularly important when many instruments are being installed at the same time.
Programming the data logger: It is easy to incorrectly program the data logger to convert the raw data (a frequency measurement in vibrating wire instruments) to either a pressure or head value. The raw data should be recorded and saved in the long-term database so that it can be checked and validated by manual instrument readings.

Checking the data

Getting data is not enough; the data needs to be good. Instruments can tell us a lot about how a dam is performing, but all instruments fail eventually and their calibration needs to be checked regularly. Ideally, this should be done using an independent instrument that can be read manually. For example, many different instruments can measure the water level in a reservoir. It is very easy to check they are providing good data by having gauge boards in the reservoir set to the same datum that can be read by operators during routine inspections and then cross-checked against the data received from the electronic instruments and data loggers. If there is an anomaly between readings, the cause of the data error needs to be tracked down and fixed.

Data storage

Data loggers have limited data storage capacity and typically overwrite old data if the data is not downloaded frequently enough. A secure database is needed to ensure that the full record of monitoring data is available for the life of the structure. Retaining the full record allows long-term trends to be identified and investigated.

Review and interpretation

Collecting and storing monitoring data is only the beginning. To make it a useful dam safety tool, the information needs to be regularly reviewed and interpreted. This will typically involve generating timeseries plots of the parameters against environmental data (e.g. rainfall and temperature) and loading data (e.g. reservoir level). The purpose of monitoring is to check that the dam is not exhibiting signs that may be an early indicator of a potential failure mode.

For example, seepage monitoring data from an embankment dam is a key way of monitoring for initiation of a piping or internal erosion failure mode. Seepage is influenced by both reservoir level (as this influences the seepage rate through the embankment and foundation) and rainfall (adding to the flow through the monitoring weir from rainfall runoff). Interpretation of the plots is not simple. A step change or a gradual change over years may indicate an emerging safety issue and should be investigated further. Sometimes the scatter in the data is hard to resolve, but a scatter plot of one variable against another (e.g. plotting seepage against reservoir level) can help untangle the key influences and relationships between parameters.

Monitoring data can also highlight potential safety issues when compared against the design assumptions and expectations. A common example is comparing the actual foundation pore pressures below a concrete dam against the assumed uplift pressures used in the stability analysis. This would confirm that the dam stability is (or is not) meeting the accepted factors of safety envisaged by the designer.

Regular review of the monitoring data by a dam safety engineer familiar with the dam is essential, and can be aided by alerts and alarms. Setting alert and alarm levels needs to consider both design expectations and historical precedent for the instrument. When an alert or alarm is triggered, automated messages should be sent to the dam safety team for review and interpretation.

In summary …

As we’ve discussed here, making the most of dam safety monitoring requires a carefully considered and comprehensive process, in which:

instruments are targeted to detect key failure modes
instruments are carefully installed and the process is well documented
data produced by the instruments is checked and validated
data is securely stored as a permanent record of the dam performance
data is regularly reviewed and interpreted by experienced dams engineers.

Technology alone doesn’t keep dams safe, but when paired with sound engineering judgement, effective dam safety monitoring provides a strong foundation for safer, more resilient and more sustainable dams that can serve communities for generations.

ABOUT THE AUTHOR

Paul Southcott (Senior Principal – Dams and Headworks) is Convenor of ANCOLD’s ‘Guidelines for Dam Instrumentation and Monitoring Systems Working Group’. He has nearly four decades of experience in civil and dam engineering, with an exceptional depth of technical knowledge and extensive industry experience. Paul’s expertise is a crucial part of Entura’s ongoing support for dam upgrade and safety works for our clients’ extensive dam portfolios. He has contributed to many major dam and hydropower projects throughout Australia and the Indo-Pacific region, including for Hydro Tasmania, TasWater, Snowy Hydro and numerous councils and water utilities including SeqWater, Sun Water and SAWater. Paul was named Tasmania’s Professional Engineer of the Year in Engineers Australia’s 2021 Engineering Excellence Awards.

Navigating the shifting landscape of energy storage

Developers of renewable energy and storage projects are facing some big dilemmas: what type and size/duration of energy storage to invest in, and how to futureproof investments in a changing market.

Long‑duration energy storage (LDES), formally defined as energy storage with more than 8 hours of capacity, is an integral part of the Australian Energy Market Operator’s Integrated System Plan (AEMO’s ISP) and an inevitable part of our future electricity system.

From a theoretical standpoint, LDES has always existed – it’s just that historically the storage came from organic matter over aeons in the form of fossil fuels, or from rainfall captured for hydropower.

What has changed is that LDES is now really about the need to store grid electricity itself due to the increase in wind and solar generation. That shift is driving the rapid ramp‑up of pumped hydro energy storage (PHES) and battery energy storage systems (BESS), and forcing developers to reassess what ‘long term’ really means in a rapidly evolving market.

The line blurs between short and long duration

To date, energy storage investment cases in the National Electricity Market (NEM) have largely fallen into two camps. On one side has been short‑duration lithium‑ion BESS, typically in the 2‑ to 4‑hour range. On the other has been long‑duration pumped hydro energy storage (PHES), generally offering 8 to 24 hours of storage, with Snowy 2.0’s 6‑day capacity being the obvious exception.

That distinction is now starting to blur.

Eight‑hour lithium‑ion BESS projects are increasingly creeping into what would traditionally be considered the LDES range. At the same time, other technologies including flow batteries, air-iron batteries and others are either maturing or beginning to align with emerging niche market opportunities.

A changing equation

One reason non‑lithium battery technologies have matured slower is their significantly lower round‑trip efficiency. This has long been a consideration for PHES as well. However, the near‑daily occurrence of zero or negative pricing across parts of the NEM changes that equation fundamentally. In a market increasingly characterised by excess generation (particularly solar), efficiency advantages begin to fade and may even conceptually become a disadvantage. That is, the more electricity it takes to charge your relatively inefficient LDES during negative price events, the more revenue you might make.

Moderate over‑installation of solar PV, and to a lesser extent wind, can be a cost‑effective mitigation against very long‑term storage requirements on weekly, monthly and even seasonal timescales. Over‑installation also helps reduce short‑term variability through higher DC‑to‑AC ratios. Even setting aside the extraordinary growth of domestic solar, it seems increasingly likely there will be an abundance of excess solar generation most days for the foreseeable future. From that perspective, bulk (potentially low‑efficiency) long‑duration storage begins to make much more sense.

If round‑trip efficiency is no longer a defining constraint, and the LDES business case is starting to stack up even for lithium‑ion BESS, there emerges a strong driver for ramp‑up of other technologies that offer significantly lower mature costs.

Combining technologies to manage risk and value

One logical response to this shifting landscape is to stop thinking about storage projects as single‑technology assets. Conceptually, new developments may instead consider combined plants behind a shared connection.

A project might pair a fast‑responding 100 MW 4‑hour lithium‑ion BESS with very long‑duration, low‑cost storage such as a 4 MW 100-hour iron‑air battery, allowing the asset to take advantage of excess solar generation, meet deep storage needs cheaply, while still delivering rapid response and low degradation.

Even simpler approaches, such as planning for the later addition of LDES behind the connection of a more typical BESS, may be sufficient to preserve optionality while markets continue to evolve.

What matters is recognising that storage requirements will not stand still, and that portfolios blending duration, technology and commercial exposure are likely to be more resilient than single‑solution investments.

The rise of residential storage

A subtle but increasingly important entrant to the LDES market is home energy storage. The federal government’s Cheaper Home Batteries Program (CHBP) has been associated with a huge growth in household batteries, along with a noticeable increase in the typical size of installations. Advertisements for 50 kWh home batteries at remarkably low prices have become commonplace (though the market is adjusting to the revised structure of the CHBP, with discounts reduced on larger systems). Less obvious is that inverter sizes often remain in the 5–7 kW range, effectively turning many of these systems into long‑duration storage assets.

It could be argued that the growth of home storage, when utilised through aggregators and virtual power plants, may offset the need for utility‑scale LDES. However, history suggests otherwise. Rather than reducing the requirement for larger‑scale storage, distributed energy resources have tended to accelerate confidence in renewable‑dominated systems and hasten the decline of fossil fuel generation. At the very least, they reduce any need to prolong fossil fuel assets in the face of growing electric vehicle uptake and expanding data‑centre loads.

What should developers be doing now?

For developers, the task now is to navigate an increasingly complex landscape of options. The challenge is not a lack of technologies, but understanding their technical and techno‑commercial performance across different roles and timeframes to enable negotiation of aligned offtake agreements and inputs to financial modelling. This is where experience across generation, storage and power systems becomes critical.

We help developers sort through this complexity – testing assumptions, exploring combinations of technologies and durations, and aligning storage strategies with the realities of the future power system. In doing so, we help clients move beyond narrow definitions of storage and towards portfolios designed for longevity, flexibility and value in an increasingly dynamic market.

ABOUT THE AUTHOR

Dr Chris Blanksby 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.

Wind farm life extension: managing uncertainty, not just fatigue

Australia’s wind fleet is entering a new phase. A growing share of assets are moving beyond the challenges of optimising output into the tough question of whether continued operation stacks up technically, commercially and reputationally.

For many owners, this question is no longer just about engineering. Life-extension decisions are influenced by merchant exposure, transmission constraints, OEM supportability, insurer scrutiny and capital demands. The challenge is often less about whether a turbine can continue operating, and more about whether a decision to continue operating can instil confidence in boards, financiers, insurers, regulators and communities.

No single calculation or inspection campaign can keep a life-extension program on course. The answer is a broader evidence program that takes a broad view of operational and commercial options.

Evidence, not optimism

Most owners don’t need glossy reports that say everything’s fine. They need to be able to explain what risks exist, what evidence supports continued operation, what uncertainty remains, and what controls are in place.

Technical specification IEC TS 61400-28 leans heavily into this mindset, and Wind Energy Ireland’s lifetime extension guidance reinforces it alongside DNVGL-ST-0262.

This evidence-based decision-making is where life extension starts to overlap with broader asset-management thinking. In many ways, it shows how the wind sector is maturing. Australia’s first wind farms were often managed with a delivery mindset: get the asset built, maximise output and manage warranty risk. As fleets age, life extension becomes more about a structured approach to managing asset condition over time: balancing integrity, operating flexibility, capital timing and portfolio value under uncertainty.

Hydropower and other mature infrastructure sectors have been dealing with these kinds of issues for many years, and the same principles apply. This also aligns with ISO 55000 thinking: the aim is not just to estimate remaining life, but to support repeatable, risk-informed decisions that balance performance, cost, risk and uncertainty over time.

If you can’t explain the evidence chain, you don’t really have an extension strategy.

Three disciplines, one defensible decision

Across the standards and industry guidance, three disciplines appear repeatedly: analysis, inspection and risk framing. The challenge isn’t choosing between them but integrating them into a coherent decision framework.

1. Analysis: identify where uncertainty matters

Analytical assessment remains foundational. Historical loading, wind conditions, operational data and design assumptions are used to estimate accumulated fatigue and identify limiting components or operating conditions. Good analysis helps determine which turbines likely retain meaningful fatigue reserve, which assets may be constrained by poor evidence rather than poor condition, which turbine types have known fleet-wide weak points, and which assumptions materially influence decisions.

The framework of DNVGL-ST-0262 is particularly useful because it recognises that not every project has the same evidence base or requires the same analytical depth. At portfolio scale, this matters. The objective is rarely to prove that every turbine can operate equally long. More often, it is to identify where selective mitigation, derating, targeted replacement, enhanced monitoring or staggered retirement delivers the best overall outcome.

2. Inspection: confirm reality and validate assumptions

Analysis tells you what might be possible. Inspection tells you what is real. The most effective inspection programs are designed to answer specific questions, such as whether predicted fatigue behaviour is credible for this turbine and site, whether there are known fleet issues emerging in safety-critical load paths, whether operating assumptions are still valid in practice, and whether damage has occurred where consequences are high.

Wind Energy Ireland’s guidance is particularly practical in how it frames inspections and supporting information, including the records and operational history required to support a life-extension assessment.

3. Risk framing: define what is acceptable

Risk framing converts engineering evidence into operational decision-making. IEC TS 61400-28 is explicit that the objective is not just an assessment result, but continued structural integrity and demonstrable risk minimisation, particularly where injury or collateral damage could occur.

For many Australian owners, the key objective is preserving optionality. They may be bridging to transmission upgrades or constraint relief, sequencing repowering across a portfolio, exploring hybridisation with storage, navigating exposure to volatile market conditions or finding ways to align with landholder, community and planning strategies.

In this context, life extension becomes part of strategic asset transition planning rather than a standalone structural certification exercise.

The inspection escalation trap

Many life-extension programs begin to lose discipline at the inspection stage. Once targeted inspections and non-destructive testing (NDT) commence, it’s tempting to keep expanding the scope in pursuit of greater certainty, even when additional information no longer changes decisions. The resulting program may feel rigorous but stops being proportionate or cost-effective.

A practical ‘stop rule’ is that each escalation should pass two tests: decision relevance (i.e. will the additional investigation change decisions regarding operation, mitigation, inspection intervals, monitoring, repair or replacement?) and consequence relevance. (i.e.does the failure mode credibly relate to safety, major asset loss or meaningful third-party impact?). If a proposed investigation does not change a decision or reduce a meaningful consequence, it risks becoming gold-plating.

Unknown provenance is an assurance problem

A growing challenge in Australia is whether to refurbish existing turbines with known operating history, or replace them with refurbished machines sourced elsewhere with less transparent evidence. The standards do not answer this question directly, but the underlying logic is clear: the quality of evidence matters.

Operational records, maintenance history, modifications, inspection findings and known incidents form part of the evidence base that underpins a defensible extension assessment. If an incoming refurbished turbine cannot carry an evidence pack comparable to the existing fleet, owners should expect more conservative life assumptions, increased inspection scope, additional monitoring requirements, different contractual risk allocation and greater insurer or lender scrutiny

Gradual aging or sudden reliability cliff?

Owners often ask whether turbines simply decline gradually after design life or whether reliability eventually deteriorates rapidly.

Some late-life effects are gradual: the rising O&M burden, declining availability, challenges in getting spare parts and OEM support, increasing frequency of maintenance intervention, etc.

Other risks can be more abrupt: fatigue crack initiation and propagation, failures in critical load paths, latent defects emerging under cumulative loading, issues associated with known fleet-wide weaknesses, and so on.

Gradual commercial deterioration and sudden structural risk are managed differently. The former can often be addressed economically. The latter requires targeted inspection, monitoring and clear operational controls.

Avoiding gold-plating while still meeting ‘state of the art’

A common concern for owners is that applying modern standards to older assets will require upgrading every turbine to contemporary design expectations. The issue of proportionality applies here, as it did to the inspection scope. The goal is not to modernise every aspect of an aging asset. It’s to demonstrate that remaining risks are understood, controlled and acceptably managed, with evidence that stands up to scrutiny.

IEC TS 61400-28’s emphasis on evidence for third-party reliance is particularly relevant here. Owners increasingly need to demonstrate not only that an engineering team is comfortable with continued operation, but that the decision-making process itself is robust and defensible. It’s about demonstrating adequacy, not chasing theoretical completeness.

Why governance and third-party credibility matter

Life-extension decisions increasingly need to withstand scrutiny beyond the engineering team. Boards, insurers, lenders and regulators are becoming more active participants in late-life asset decisions, particularly where aging fleets, reduced OEM support or major repowering deferrals are involved.

This makes governance and credible evidence increasingly important. In practice, late-life decisions are often judged as much on process integrity as engineering outcome, including what was assessed, what evidence was used, how uncertainty was treated, what controls were implemented and what assumptions remain critical.

A practical evidence roadmap for Australian owners

A scalable approach typically includes these actions:

Build the evidence base early: Retain and organise operational data, maintenance records, inspection findings, modifications, major component history and known fleet issues. Evidence quality becomes increasingly valuable as assets age.
Use analysis to target effort: Select an assessment pathway aligned to evidence quality and decision criticality, and use it to identify where uncertainty actually affects outcomes.
Run disciplined inspections: Use layered inspection strategies that escalate only where findings justify further investigation.
Convert findings into operational controls: Define inspection intervals, monitoring requirements, operating restrictions, repair triggers and replacement thresholds based on identified risks and confidence levels.
Communicate risk in decision-maker language: Translate engineering findings into structured risk and assurance language that boards, insurers and financiers can evaluate consistently.

Closing thoughts

Life extension isn’t about squeezing the last possible year from a turbine at any cost. It’s about preserving choices: continue operating, derate, refurbish, monitor, partially repower, hybridise with storage, or retire – with each choice supported by a defensible evidence position and a clearly understood risk profile.

Owners tend to achieve the best outcomes when life extension is treated as an ongoing program of assurance and strategic transition management rather than a one-off engineering report. That means analysis and inspections designed to answer specific decisions, governance robust enough to withstand external scrutiny, and investment focused on reducing the uncertainties that really matter. This approach helps avoid gold-plating while keeping safety firmly at the centre of decision-making.

For owners considering life extension – or simply wanting to preserve future options – one of the most valuable first steps is an evidence and decision-readiness review. Explore what evidence already exists. If there are gaps, will they materially affect decisions? Which failure modes are most limiting, and where should inspection effort be focused? Which uncertainties are actually worth reducing?

The earlier these questions are addressed, the more strategic options you’re likely to retain and the less time and money you’ll spend where it won’t change the outcome.

ABOUT THE AUTHOR

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 and the Philippines.

Three principles for planning better dams

Dams are critical infrastructure in a world shaped by climate uncertainty, growing populations and rising pressure on water, food and energy systems. Storage is central to water security, climate resilience and the renewable energy transition. But the focus cannot simply be on building more infrastructure. The challenge is to identify and develop the right dams in the right places, with the right planning to manage impacts and produce long-lasting value.

This theme resonated strongly at the recent ICOLD conference in Guadalajara, Mexico. Throughout discussions on water planning, environmental impacts and sustainability, one point stood out: the quality of a dam project is largely shaped long before detailed design gets underway. By the time a project is technically mature (i.e. the arrangement has been fixed), some of the most important opportunities to improve outcomes have already passed.

In practice, 3 planning principles matter most.

1. Start with the river basin, not the individual project

The best dam planning begins at basin scale. Before comparing individual sites or refining layouts, it is essential to understand the wider river system, competing water demands, environmental constraints and social context. A Strategic Environmental Assessment (SEA) helps provide that broader view by evaluating environmental, social and economic effects early in the planning process, when there is still flexibility to shape decisions.

This matters because some parts of a basin are more suitable for development than others. Some areas carry high environmental or social value and should be avoided. Others may present lower overall risk and therefore provide a more sustainable pathway for development. Basin-scale planning helps identify this early. It also supports better application of the hierarchy for mitigating impacts – from most to least preferred: avoid (best!), minimise, rectify, reduce, offset (only as a last resort).

For project proponents, this kind of early strategic assessment can increase sustainability while also reducing conflict, supporting more robust approvals pathways and giving decision-makers greater confidence that the project is in the right place.

2. Choose projects using a broad decision lens

Once lower-risk opportunities have been identified, the challenge becomes deciding which project should move forward. This decision shouldn’t be based on economics alone. The most successful projects are usually those selected through a structured multicriteria assessment that considers technical feasibility, financial performance, environmental risk, social impact, safety and long-term resilience together.

A funnel provides a useful analogy. There may be many possible project options at first. Through an iterative process of evaluation and comparison, the range narrows until only the strongest candidate remains. The value of this process depends on whether the criteria reflect the full picture of project success.

The Hydropower Sustainability Alliance’s HydroSelect tool supports this kind of early-stage thinking. It considers 12 sustainability factors such as societal contribution, water quality, sedimentation, dam safety, downstream flows, biodiversity, cultural heritage, resettlement and livelihood impacts, and climate change. Although developed for hydropower, the tool is relevant to all dams: the best project is not necessarily the cheapest or fastest to develop; it’s the one that stands up best when all risks and benefits are weighed up.

This kind of screening is particularly valuable for identifying red flags before they become too difficult to resolve.

3. Recognise that impact is greatest in the early phases

The planning and concept stages have the greatest influence on a project’s long-term outcomes. This is when decisions about site selection, dam type, reservoir level, spillway configuration, operational rules and mitigation measures are still open to improvement. Once the project moves into later phases, changes become more constrained and often more costly to implement.

Multidisciplinary planning is very important for better outcomes. Engineers should work alongside environmental scientists, ecologists, social specialists, geologists, sediment experts, hydrologists and dam safety practitioners from the conceptual stages of the overall general arrangement. A collaborative approach allows potential impacts to be identified early and addressed right from the start.

The benefits of multidisciplinary planning can flow into successful multipurpose projects, where a dam can deliver even greater value beyond its primary purpose. A better understanding of habitat and land use in the reservoir as well as downstream will enable better decisions about final reservoir level, operating regimes and spillway arrangements to manage floods safety. Early knowledge of sediment behaviour and downstream needs will shape flushing provisions and operational rules. Better understanding of environmental flow requirements and fish migration will improve outlet works and the design of successful fish passages. The earlier and broader the understanding, the better the ultimate decisions.

Dam safety must, of course, be prioritised at this stage. Decisions about dam type should be based on a deep understanding of the hazards the dam may be exposed to during its life and by considering all the potential failure mechanisms and the societal risks. While appropriate surveillance (both visual inspections and instrumentation monitoring) remains essential throughout operations, the foundations of a safe dam are laid during planning and concept development.

Better planning yields better outcomes

Large dams can be controversial, particularly when their environmental and social impacts have not been well understood or well managed. This is why good planning matters so much. If we start with basin-scale thinking, compare options using a broad range of criteria, and make the most of the early project phases with multidisciplinary expertise, we have a far better chance of delivering infrastructure that is safe, defensible and genuinely valuable over the long term. It’s a pathway to achieving the right dams, in the right places, with the right outcomes.

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.

Making defensible dam engineering decisions in an ever-changing world

New technology, evolving climate science, aging infrastructure and workforce turnover are reshaping what it takes to design, assess and manage dams responsibly.

In this article, two of Entura’s dam professionals outline key considerations that today’s dam engineers should keep firmly in mind when making dam engineering decisions.

1 Keeping pace with changing technology for dam engineering and monitoring

Dam engineers now have access to far greater computing power and analytics than ever before, which means we can estimate extreme flood behaviour, seismic loads and complex structural responses in unprecedented detail.

But, as the saying goes, with great power comes great responsibility. Highly sophisticated models can create a false sense of certainty, but models are only as good as their inputs and assumptions. It’s up to us as dams engineers to use sound engineering judgement to interrogate model reliability, to identify uncertainty and to understand the limitations of the modelling in decision-making.

Advances in monitoring and surveillance have been equally rapid and sophisticated, with remote sensing and automated, near-real-time data acquisition allowing earlier and more precise detection of potential issues. The challenge, though, is managing an immense flow of data to filter and interpret.

Artificial intelligence (AI) could be a game changer for efficiently collating and interpreting data, helping detect trends and anomalies. However, using AI as a decision-making tool has limitations and its outputs could be misleading. There’s also a risk that overreliance on AI could erode our opportunity to independently exercise and apply professional engineering judgement.

Against a backdrop of advancing technology, dam engineers must still bring a holistic understanding of a dam’s underlying design philosophy, the performance of structures under various load conditions, and the impacts of construction practices on dam behaviour.

2 Deepening the understanding of failure modes and risks

Risk-based dam safety practices are now firmly embedded in Australian and international dam safety guidance. Failure modes analysis and risk assessment form the foundation of prioritised risk-based dam safety surveillance programs and dam design.

Assessing failure modes demands a multidisciplinary perspective and collaboration. Geological and foundation conditions, climate conditions and the implications of construction sequences and historical modification could result in vulnerabilities that are not apparent in routine inspections.

Tools such as LifeSim and TotalRisk quantify social, economic and environmental risks – which can help inform, justify and clearly communicate decision-making about the timing and scope of risk mitigation works.

3 Considering the impacts of climate change

For dam engineers, consideration of environmental factors is nothing new. However, the potential for significant changes in climate, and the consequences of these changes and associated uncertainty, are increasingly important and complex concerns.

Updated climate projections and hydrological guidance, including the most recent update to Australian Rainfall and Runoff (Ball et al. 2019), have altered design flood estimates in many regions. In some cases, this has reduced flood capacity margins and prompted reassessment of spillway adequacy and flood tolerability for both near-term and long-term climate scenarios.

In addition to increased rainfall expectations, we also need to consider the impacts on dams during prolonged periods of low rainfall, such as drying and cracking of the clay core material in embankment dams.

Today’s dam engineers need to consider a wider range of plausible future scenarios and engage explicitly with uncertainty across the asset’s remaining life.

4 Working towards sustainability

Sustainability is an increasing focus for dam owners and regulators. Dam upgrade and remediation projects need to consider expectations around reducing carbon emissions, lowering the environmental footprint, and improving the process and outcomes for local communities.

For dam engineers, this means thinking beyond traditional approaches and being prepared to challenge long-held assumptions. Can the construction and carbon footprint be reduced? Can existing materials be reused onsite to reduce haulage and waste? Are there options to improve safety outcomes? How can works be designed to improve, rather than degrade, local biodiversity or downstream environments?

To answer these questions, we need to engage as early as possible with industry best practices, and collaborate with environmental specialists, experts in carbon accounting, peak standards bodies and stakeholders. We should also learn from projects that are demonstrating innovation and successful outcomes.

5 Navigating competing priorities

Scrutiny by the community, stakeholders and dam safety regulators with respect to the safety and sustainability of dams and upgrade works continues to increase, but at the same time many dam owners face constrained budgets and competing priorities across their infrastructure portfolio, which may mean staging dam upgrades.

Many large dams are now more than 50 years old and may be inadequately monitored or in need of remediation works. However, the limited budgets of public and private sector dam owners can constrain their ability to fund comprehensive surveillance programs and dam safety remediation works.

Dam engineers, therefore, have a complex advisory role. Our recommendations need to be risk‑informed, prioritised, staged where appropriate, and defensible in technical, economic and societal terms. Clear communication of residual risk, uncertainty and long‑term implications is critical.

As in any infrastructure project, meaningful engagement with communities and stakeholders can improve the process and the outcomes. Explaining clearly why certain works are prioritised, how risks are being managed, and what communities can expect during upgrade construction grows trust and can help defuse conflict. This may not sound like the role of the engineer but it is our inputs, translated into plain language, that will help create accessible, honest narratives that help stakeholders and communities understand what’s happening and why.

6 Futureproofing the workforce

Ultimately, safe and sustainable dams depend as much on skilled and experienced people as on technology. But a global skills gap is emerging as experienced dam engineers retire, taking with them invaluable institutional knowledge of older assets, construction practices and surveillance practices and priorities. This is certainly the case in Australia, given that new dam construction has declined steeply over the last few decades, reducing opportunities for first-hand experience.

Preserving design knowledge, construction understanding and institutional memory is important, and it won’t happen by accident. Investing in mentoring and knowledge transfer will be key to ensuring that younger and emerging dam engineers learn as much as possible from experienced senior engineers before they retire. Tailored training from experienced engineers and providers can also help bridge context gaps. Where local experience is limited, there may be opportunities to draw on international expertise or related industries.

We encourage all dams engineers to get involved in industry initiatives led by organisations such as ANCOLD and Engineers Australia, including emerging professional networks and mentoring programs, so that together we can grow capability across our sector.

ABOUT THE AUTHORS

Jaretha Lombaard joined Entura as a Senior Dams Engineer in January 2024. She has a range of experience in dam and water resource engineering in Southern Africa and Australia. She is experienced in numerous aspects of dam engineering, including dam design, tender and construction support, dam safety assessments and inspections. She has also been involved in developing dam safety emergency management plans, operations and maintenance manuals, and is actively involved in facilitating dam safety training through the Entura Clean Energy and Water Institute (ECEWI). Jaretha has taken lead roles on various projects, including as the design manager for the Bradys Dam upgrade and Meadowbank Dam upgrade projects.

Sally Fracalossi is also a Senior Dams Engineer. She joined Entura’s Dams and Geotech team in 2020, following 5 years in a multinational private consultancy where she gained a broad civil engineering and project management experience. Sally is experienced in numerous aspects of dam engineering, including dam design, dam safety assessments and inspections, risk assessment and construction support. She has also been involved in developing dam safety emergency management plans, operations and maintenance manuals, and is actively involved in facilitating dam safety training through the Entura Clean Energy and Water Institute (ECEWI). Sally was project manager for TasWater’s dam safety surveillance program which encompassed over 50 referable dams in the north and south of the state during 2020–22.

Becoming better: tackling the major challenges facing the Australian wind sector

The Wind Operations and Maintenance Australia 2026 conference, held recently in Melbourne, reflected a confident industry. The Australian wind sector has matured. Technology has improved. Knowledge is deeper. Projects are bigger. There is a strong belief that engineering problems are solvable. Yet confidence, while important, is not the same as resilience.

In his 2023 song Never Been Better, Australian singer/songwriter Ben Abraham explores the uneasy space between resilience and denial – the quiet insistence that everything is fine, even as complexity and vulnerability simmer beneath the surface. The Australian wind sector often sounds like it has never been better. And in many respects, that confidence is justified.

But beneath it lies a more nuanced truth. Operational risk is rising in complexity, contractual frameworks are under strain, and the economics of wind are not improving as visibly as they need to. The question for owners is not whether the industry is ‘better’ – but whether it is stronger.

Active ownership: the end of passive wind

One of the clearest themes at the conference was this: owners must actively manage their wind assets.

The era of ‘set and forget’ – handing long-term O&M to OEMs and stepping back – is over. Modern wind farms are too complex, too data-rich and too commercially exposed.

Active ownership means:

demanding structured access to operational data
ensuring documentation is complete, portable and contractually enforceable
retaining strategic decision-making capability.

Data and documentation are not administrative details; they are strategic assets. If an owner needs to change O&M providers, incomplete data can become an existential risk.

Contracts must explicitly define data ownership, format and accessibility, handover requirements, and ongoing documentation standards.

Insurers, too, are increasingly data-hungry. Risk pricing now depends on transparency – condition monitoring trends, blade histories, lightning strike records, gearbox temperatures. Owners who control and understand their data are likely to access more tailored and potentially cheaper coverage.

In the song, there’s tension between image and reality. In wind O&M, the equivalent tension is between contracted performance and actual asset health. Owners must look beneath the surface.

Contracts: precision without paralysis

There was extensive discussion about getting contracts right – particularly at the handovers from development to construction to operations.

Key themes included:

clear, rigorous defect definitions
step-in rights for owners (e.g. procuring a gearbox faster than the O&M provider)
termination rights
careful allocation of scope to whoever is best placed to deliver it.

OEMs are increasingly focusing their scope on maintaining wind turbine generators, which is where their expertise lies. That is sensible. Contracts should allocate responsibility to the party best positioned to manage the risk.

But this raises a deeper tension:

Can contracts be both rigorous and concise, perhaps as the lyrics of the song posit – ‘two different things can both be true at the same time’?

Legalese frustrates engineers and operators. Yet ambiguity in defect language or scope boundaries can create expensive disputes. The answer may not be shorter contracts, but clearer ones.

If the industry has matured, then our contractual frameworks should mature too.

Fleet size and the limits of self-perform

Only owners with very large fleets can realistically internalise full O&M capability. In the United States, this is achievable. The economics are harder in Australia, where fleets are smaller and geographically dispersed.

It’s expensive to build internal processes, inventory systems, technical depth, safety frameworks and 24/7 operational support. Most Australian owners will remain reliant on third parties.

That makes governance capability even more critical. Owners must be intelligent buyers of O&M – not merely customers.

Blades: the growing anxiety

If there is a component that generates consistent concern nowadays, it is blades. To name just a few of the worries, think about lightning damage, manufacturing defects, blade root bearing issues, and structural integrity as turbines scale in size.

Blade monitoring technology has advanced rapidly. Aerial drones for external inspection are now standard. Internal blade inspections are becoming mainstream. Condition monitoring systems (CMS), once debated, now appear broadly accepted for new turbines.

Leading-edge erosion remains an issue, but discussion has matured: the structural implications may be more significant than the production losses, which are often less severe than feared.

As turbines grow, so do consequences. Bigger rotors mean higher loads, more complex failure modes and more expensive interventions. The industry sounds confident … but confidence must be backed by data and structural understanding.

Harking back to the song’s refrain “And the more I learn, the less I know”, the wind industry faces a similar paradox with turbine blades.

As blade lengths have grown, the theoretical sophistication of design, modelling and materials science has increased. Yet the practical ability to apply rigorous quality assurance has, in some respects, diminished. The sheer physical scale of modern blades makes full inspection more complex and less forgiving. Manufacturing tolerances become harder to control. Logistics, handling and curing processes carry greater consequences.

Layered on top of this are compressed production schedules driven by global demand and competitive pressure. When volume and velocity increase, quality assurance systems are strained – not necessarily by intent, but by physics and time.

In other words, as we have learned more about blades, we have also discovered how much harder they are to build flawlessly at scale.

Underground cables: the invisible risk

Repeatedly, practitioners stressed the importance of quality oversight during construction, especially at underground cable joints.

These are invisible assets. When they fail, remediation is slow and costly. The lesson is simple: invest in the right people on the ground during construction. Operational excellence begins years before commercial operation date.

This ties back to contracts and handover. Development teams must think like operators. Construction quality must anticipate 25-year asset lives.

Noise and compliance: a moving target

Noise remains both contentious and technically challenging. It’s hard to isolate turbine noise from background noise. Another noise complexity is understanding the interactions between wind farms and BESS installations.

These are not static risks. Regulatory expectations – like 5-year compliance measurements – continue to evolve.

Again, the industry says it has matured. But maturity means anticipating future scrutiny – not reacting to it.

The small things matter

One practical observation was that wind farms need more toilets for operators working remotely from O&M buildings.

That might seem like a small thing, but operational design must reflect human realities. As fleets expand and layouts become more dispersed, infrastructure for field technicians must keep pace. Productivity and safety are not abstract concepts – they depend on practical, on-site conditions.

Sometimes maturity can be measured in amenities.

Knowledge sharing … or the illusion of it?

There was optimism that engineering problems are able to be solved and that knowledge sharing is strong. But is it?

The same issues – blade defects, cable failures, contract disputes – continue to circulate. Commercial sensitivities and reputational concerns still inhibit transparent lessons learned.

If the industry is truly ‘better’, it should be demonstrably learning faster.

The missing conversation: LCOE

Reducing levelised cost of energy (LCOE) was an implicit but not always explicit theme of the conference. As befitting an operations and maintenance conference, much of the focus was on reducing long-term costs, even at the expense of high initial costs.

Australia is on an unstoppable path toward renewable energy, yet relatively few wind farms have progressed recently. Connection challenges, financing conditions, cost inflation and supply chain constraints all contribute.

But operational excellence is also an LCOE lever:

reducing unplanned blade repairs
improving defect management
ensuring robust cable installation
designing contracts that minimise disputes
leveraging data to optimise maintenance.

These are not just risk controls. They are cost controls.

If the industry wants to move beyond confidence into competitiveness, LCOE discipline must return to the centre of the conversation.

‘Never been better’ or ‘becoming better’?

The refrain from Ben Abraham’s song is not triumphalist; it is layered. It carries strength, but also fragility.

The Australian wind industry is more experienced, more technically capable and more sophisticated than it was a decade ago. That is undeniable. But maturity is not the same as invulnerability.

Active ownership. Data control. Contract clarity. Blade vigilance. Construction quality. Real knowledge sharing. Human-centred operational design. LCOE focus. These are the fundamentals our industry must keep tackling, if 5 years from now it is really going to be ‘better than ever’.

Continue the Conversation

If you’re interested in hearing more about the evolution of the Australian wind sector and the lessons learned from over two decades in the field, you can listen to the insights Andrew shares on the Entura Behind the Scenes podcast. In this episode, Andrew shares his journey from aircraft aerodynamics to pioneering some of Australia’s earliest renewable projects.

You can also explore more of Andrew’s insights through some of his previous articles:

ABOUT THE AUTHOR

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):

1) Ensure good technical governance through design and construction

2) Set up quality assurance and quality control systems

3) Continue a design presence on site

4) Use a risk framework to determine a dam’s readiness to impound

5) Have a dam safety system in place before impoundment

6) Maintain a heightened level of monitoring and surveillance

7) Be prepared in case of an unlikely dam safety emergency

8) Keep a close eye on the dam in its first years of operation and during new peaks

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

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.

FIND OUT MORE ABOUT AMANDA

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

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:

– environmental approval status and consent conditions

– geological and geotechnical studies

– hydrology and hydraulic components (hydropower)

– mechanical and electrical equipment

– power evacuation and grid connection

– constructability and logistics

– unit rates and project costs

– pre-construction risk assessment

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:

– ongoing design reviews

– initial review of the execution plan

– construction quality monitoring

– construction progress monitoring

– updated risk assessments

– assurance of adherence to standards

– identification of opportunities for continuous improvement

– milestone reporting

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:

– review of condition of plant and equipment

– performance review

– review of O&M

– hydrological assessment (hydropower)

– risk identification

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.

Capital and operational expenditure

Energy production and revenue estimates

Financing arrangements

Financial appraisal parameters

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)

Find out more about the evolution of the e-flow concept and assessments

Unregulated rivers naturally experience highly variable flows, including seasonal and interannual fluctuations and occasional short-duration floods. However, the introduction of onstream storages can significantly alter these patterns by reducing annual peak flows, creating unnaturally high baseflows from hydropower discharges, or partially or fully drying out channels when water is diverted and tributary inflows are low.

Scientists began to recognise the ecological consequences of dams and advocated for minimum flow releases reduce negative impacts on downstream biodiversity and support aquatic species, especially fish.

These environmental flows (or ‘e-flows’) began to be implemented in hydropower operations during the 1970s, particularly in the United States and Scandinavian countries. These early efforts focused on preserving individual species through ‘minimum flows’, which later evolved into broader ‘instream flow’ concepts with a more holistic ecological emphasis.

By the 1990s, the concept of environmental flows expanded to encompass comprehensive flow regimes designed to support entire ecosystems and the communities that depend on them. This shift led to the development of more sophisticated assessment methods and the integration of environmental flows into dam operation strategies.

Globally, the World Bank Group and the International Finance Corporation (IFC) began formalising environmental flow guidance in the mid-2000s which culminated in the Good Practice Handbook for Environmental Flows in Hydropower Projects (2018), which outlines frameworks for integrating e-flows into hydropower planning.

In Australia, formal implementation of e-flows began in the early 2000s, with the Snowy River Scheme as a notable example. However, many instream storages in Australia began with no environmental flow requirements and continue to operate in this way other than for very basic requirements for downstream landowner/industry usage rights.

Today, e-flow assessments are typically required by state or Commonwealth regulators for new dam projects or major operational changes.

Find out more about river habitats and the importance of shallows for aquatic biodiversity

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.