Breathing new life into Australia’s aging wind farms

The wind industry, well-established in Europe for decades, took baby steps onto Australian soil in the late 1980s and 1990s. By the early 2000s, Australia’s new wind industry was ready to take off. Given that wind farms usually have a design life of anywhere between 15 and 30 years, our earliest wind farms are now reaching retirement age. The industry therefore faces a new set of challenges. Can these older wind farms continue to serve their important role in Australia’s clean energy transition or are they at their end of life?

So far, few wind farms in Australia have been decommissioned, dismantled and removed from the land. With many of our older wind farms sited to capture the best wind resources, there’s every reason to try to continue using these sites to harness wind energy.

One option is to squeeze more years out of the wind farm through effective maintenance and supportive analysis to ensure it is safe to do so while accepting that there may be increasingly frequent outages and increased maintenance costs to keep the wind turbines in service. However, although operation beyond the nominal life of a wind turbine is theoretically feasible, old wind turbines can’t keep spinning forever and will need to be stopped at some stage.

Other options for aging wind farms are refurbishment of some parts of the turbines, or full ‘repowering’ with completely new machines. This could also include a full redesign to accommodate larger turbines or to incorporate solar or battery energy storage systems.

An example of rejuvenation

Small grids may be some of the first to need to consider what to do about old wind farms. As an example, Hydro Tasmania’s Huxley Hill Wind Farm on King Island has three 250 kW wind turbines that were installed in 1998, and two 850 kW wind turbines that were installed in 2003.

For Huxley Hill Wind Farm, the King Island electricity load has not changed much over time, and offsetting diesel using renewable energy continues to make perfect sense.

For this site, the owner opted for a like-for-like replacement of nacelles (generator, gearbox, yaw system) of the Nordex 3 x N29 250 kW and potentially for the 2 x Vestas V52 850 kW wind turbines. This decision was partly about the good economics and sustainability of reusing existing infrastructure, and also because wind turbines of this size continue to suit the project so well.

When the wind farm was constructed 20+ years ago, the installed wind turbines were considered modern, large wind turbines. These days, the same suppliers do not offer anything less than 2 MW in capacity, with rotor diameters greater than 110 m. The lack of availability of what are now considered smaller wind turbines (say 1 MW) poses challenges for some small projects. At the scale of less than 1 MW, there are now few proven wind turbine options. At an even smaller scale (<100 kW), solar PV now dominates.

When any existing infrastructure is to be retained to support life extension of old wind turbines, such as at Huxley Hill, it’s crucial to confirm that it is still suitable and safe. This can include various techniques and activities, including:

  • physical inspection by technicians and engineers
  • excavation of the foundation backfill cover to reveal the tower-foundation joint and inspect corrosion and remediation
  • surveying the tower and blade condition using drones
  • surveying the tower verticality
  • surveying the thickness of tower sections
  • ultrasonic testing of bolts
  • eddy current testing of welds to detect any flaws
  • reviewing data from the turbines to refresh understanding of the actual wind regime, reassess fatigue loads and estimate remaining life.

Another important consideration when rejuvenating older wind farms is to consider the potential for adding solar or battery energy storage. With solar now more viable than when Huxley Hill Wind Farm was conceived, a 1.5 MW solar farm has been added to augment the wind generation.

Starting over with full repowering

Because the Australian wind industry is still relatively young, there is not yet an established practice or precedents for full repowering. However, in Europe, hundreds of wind farms have been repowered, often massively increasing output by using fewer but much larger modern turbines.

Repowering at around 25 years seems the most likely timeframe for most Australian wind farms – but few have yet reached this age. Ultimately, market factors will determine when repowering provides the best financial return.

Even though we’re still just on the brink of Australia’s repowering journey, it’s never too early to start considering the complexities and implications and assessing all options.

Repowering won’t be simple or quick. The development process for repowering NEM-connected wind farms is likely to be just as challenging as developing a new wind farm on a greenfield site.

The concept of ‘repowering’ involves a range of options for replacing old wind turbines and associated footings and electrical balance of plant with new, but it’s unlikely that much of the existing infrastructure and balance of plant will be able to retained if larger, modern turbines are selected. The layout of the wind farm is also likely to need revision to accommodate longer blades.

Planning approvals need to start just as early, as should the process of renegotiating with hosts, neighbours and communities. People may be concerned about the impacts of much taller turbines and the logistical issues of getting them to the site, as well as arrangements for the dismantling, removal and disposal of the superseded technology and infrastructure.

Repowering with bigger and more powerful turbines is also likely to involve re-permitting and negotiating a new grid connection agreement – neither of which are certain, given the cumulative impacts that may have emerged over time and any changes to rules and regulations since the wind farm was first developed.

By planning early for repowering, developers can get ahead on these issues as well as on condition assessment of the assets, decommissioning plans for old turbines, new studies that might be needed (such as bird monitoring), and new wind measurements for taller, modern wind turbines, perhaps using modern wind measurement technology such as lidar.

While some repowered wind farms will very likely incorporate new battery energy storage systems (BESS), they are less likely to deploy large-scale solar as a default, given that many of the best original wind sites in Australia are coastal or hilly, particular those in the south of the country. Nevertheless, the potential for co-located renewable generation, storage and loads is worth exploring. 

Don’t wait for trouble – start planning now

We suggest that wind farm owners take action now to deepen their understanding of the condition and present value of their assets, and explore the full range of short-term and long-term options available through a feasibility and options study. After all, in such a dynamic market and technology landscape, and with the potential for aging assets to deteriorate or fail, decisions about end of life may need to be made earlier than expected.

About the author

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 engineering services. Andrew has worked closely with Entura’s key clients and wind farm operators on operational projects, including analysing wind turbine performance data to identify reasons for wind farm underperformance and for estimates of long-term energy output. He has an in-depth understanding of the energy industry in Australia, while his international consulting experience includes New Zealand, China, India, Bhutan, Sri Lanka, the Philippines and Micronesia.


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. 

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, and 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.

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 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.

Is there an alternative?

The inverters at the heart of most solar farms and most modern wind turbines are changing. Until recently, they have 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 likely to change rapidly. The newer inverters are much less sensitive to system strength. It is likely that applications will soon emerge in which changing the inverter will eliminate the need for a synchronous condenser. We predict that this could occur for small installations first and evolve over time to include larger renewable farms.

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 wind farms or solar farms, please contact  David Wilkey on +61 3 6828 9749 or Patrick Pease.

About the author

David Wilkey is Entura’s Principal Consultant, Secondary Electrical Engineering. He has more than 20 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.


Is there still a role for small wind turbines in hybrid systems?

Many governments, industries and businesses worldwide are pursuing greater sustainability, reliability and affordability of their electricity sources, and transitioning away from fossil fuels.
In remote or isolated locations such as Pacific islands or remote desert mining operations and communities, hybrid renewable energy systems offer an effective option for meeting these energy goals.

Flinders Island Hybrid Energy Hub.

King Island Renewable Energy Integration Project

Commonly, hybrid systems include a mix of solar PV, wind turbines, battery energy storage systems (BESS) and other enabling technologies. The inclusion of wind and solar generation in the mix is far more than an investment to earn money for the owner. These sustainable sources of energy reduce the traditional heavy reliance on fossil fuel, with its associated costs, insecurity of supply, and high emissions.

Why wind?

With the plummeting costs of solar PV and its ease of installation, is there still a role for wind turbines in the design of a hybrid system? Our answer is yes; however, there are a number of factors to consider when choosing the best configuration for your location and needs. It’s a combination of available solar and wind resource, the degree to which the load matches these resources across a full day, and the level of renewable energy targeted. In essence, the sun is out only during the day, but the wind is likely to be available across the full day.

So, why not solar and batteries? This combination can be fine for smaller percentages of renewable energy, but it is still the case that for the non-sun hours it is cheaper to directly source renewables from wind energy than it is to store solar energy in a battery and to retrieve it later in the day.

Right site, right size

For developers of large commercial wind farms, the first consideration and top priority has usually been finding a site with an excellent wind resource and good grid connection, as this is what will drive profitability. However, for micro-grid projects, wind turbine siting is largely dictated by the location of the project. There may be a small degree of siting flexibility at the local level (e.g. an adjacent hilltop, or the preferred side of an island), but generally the wind turbine has to fit in within the given conditions.

For larger remote hybrid systems that power mining operations, large wind turbines may be feasible, given the high level of electricity demand as well as the availability of the relevant infrastructure to enable delivery of large components. The recent Agnew Hybrid Renewable Power Station, with 5 x 3.6 MW wind turbines, is an example.

However, for sites with lower electricity demand or difficult access, the delivery and integration of a wind turbine greater than 1 MW can become exponentially more difficult and costly, and doesn’t necessarily convey extra value.

Bigger isn’t always better

For a commercial wind farm operating on a large grid, an extra 1% in power output often translates directly to energy generated, and revenue, at little cost to the project. In contrast, for a wind turbine connected to a micro-grid, an extra 1% in power generation often translates to a great proportion of energy ‘spilled’ (energy not generated because the grid can’t accept any more). Therefore, as a general rule, the sensitivity to variation of financial metrics such as Investment Rate of Return for a wind turbine on a micro-grid is much less than for a grid-connected wind farm.

Furthermore, from the perspective of system operations and redundancy, having many smaller machines is typically preferable to having only one or two large machines, particularly in more remote locations with greater time involved in repairs. If one of only two or three larger turbines is out, this represents a higher percentage of increased fuel use and operational cost compared to an outage of one of many smaller turbines.

A small problem

So far, so good. But now we run into a challenge. There simply aren’t many small wind turbines now available. Wind turbines have been constantly increasing in size. This is because wind turbine manufacturers target the large grid-connected wind farm market, in which larger wind turbines push down the cost of wind energy. Larger rotors and blades and greater height make mega-turbines much more effective than smaller turbines at harvesting power from sites with low wind speeds, allowing greater opportunities for wind farm sites.

This is fine for larger hybrid systems at outback mines where there are large spaces, good infrastructure and access to install 150 m diameter rotors on 120 m tall towers. However, it’s not so helpful for small Pacific island nations and remote communities, with relatively low wind speeds, lower electrical loads and under-developed infrastructure.

The lack of availability of smaller wind turbines poses challenges for some small projects. At the scale of less than 1 MW, there are now few proven wind turbine options. At an even smaller scale (<100 kW), solar PV now dominates.

For some, second-hand wind turbines that have been refurbished might be attractive. However, remote sites require a high level of reliability, so this option will not suit all operators.

At a minimum we suggest early engagement with potential suppliers. And in some cases early procurement may even need to be considered to lock in supply.

Repowering an old system 

It’s a similar situation for existing small grids with wind turbines that are nearing the end of their design lives.

The typical nominal design life of a wind turbine is 20 years. Although operation beyond the nominal life of a wind turbine is feasible, old wind turbines will at some stage need to be replaced, either with new wind turbines or by alternative forms of energy generation.

The term ‘repowering’ captures a range of options for replacing old wind turbines and associated footings and electrical balance of plant with new. Because the wind industry is relatively young, there is not yet a clear established practice for repowering. However, in our view, the most likely options are:

  1. Extend the life of existing assets until the costs of maintenance make this uneconomical. In practice, this may be well beyond the original 20-year life, and further repowering decisions can be delayed.
  2. When Option 1 becomes untenable, completely replace wind turbines and footings, and electrical balance of plant. Because of the continuing increase in the size of wind turbines over the past 20 years, reuse of existing balance of plant is unlikely.

Small grids may be some of the first to need to ‘repower’ old wind sites. As an example, Hydro Tasmania’s King Island Power Station has three 250 kW wind turbines that were installed in 1998, and two 850 kW wind turbines that were installed in 2003. For that site, it is likely to be feasible to consolidate the generation using several large modern wind turbines. However, in other long-standing smaller hybrid systems, the challenge of finding replacement sub-1MW wind turbines will be all too real.

For any redevelopment there will be a range of considerations, including permitting, existing power station equipment, and the rapidly decreasing costs of battery energy storage systems. We suggest that owners should at least develop a good understanding of the condition and the present value of their assets, and what options might be available (e.g. through a feasibility and options study). After all, the unexpected does happen, and the failure of a major component such as a gearbox may require decisions to be made about end of life, earlier than expected.

If you would like to discuss how Entura can help you with your hybrid or wind project, develop an asset management strategy or support you with due diligence services for proposed or operational projects, contact Patrick Pease or Silke Schwartz on +61 407 886 872. 

About the author

Andrew Wright is a Specialist Renewable Energy Engineer at Entura. He has more than 15 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 engineering services. Andrew has worked closely with Entura’s key clients and wind farm operators on operational projects, including analysing wind turbine performance data to identify reasons for wind farm underperformance and for estimates of long-term energy output. He has an in-depth understanding of the energy industry in Australia, while his international consulting experience includes New Zealand, China, India, Bhutan, Sri Lanka, the Philippines and Micronesia.


Turbines on Flinders Island.

Flinders Island Energy Hub

Keeping international projects moving, even when we’re grounded

With no set date for when life will return to usual after COVID-19, nor any guarantee of whether life will ever return to what we previously knew as ‘usual’ at all, there are very few areas in the consulting life in which we can simply say ‘we’ll wait until this is all over’. Life, and projects, must go on.

Although we can’t avoid the disruption and uncertainty that the coronavirus has unleashed, we can increase our resilience and agility. We can also embrace opportunities to innovate and to create new ways (or reinvigorate old ways) to achieve our goals.

Here, Entura’s Environment and Planning team continue to apply their proactive approach to keeping projects alive in the current circumstances, and explain how they are continuing their activities on two international projects despite the travel restrictions that are making it impossible to visit the project sites.


Old ways for new times – Engaging communities in Tonga

For many countries across the globe, the immediate challenge is building resilience to fight through the pandemic. However, for some small island nations that have managed to stay out of the virus’s path so far, such as Tonga and the Federated States of Micronesia, the concept of resilience has a broader context.

Climate resilience is a core objective, as these nations are feeling the increasing impacts of rising sea levels and more frequent and intense weather events. In this context, robust power infrastructure that is suited to extreme weather is one component of greater resilience, as is transitioning from diesel dependence to higher levels of renewables, which builds greater security of energy supply at a lower longer term financial and environmental cost. More access to stable, reliable and clean electricity is also critical for the health, wellbeing and education of local communities, and is the foundation for economic development. Entura has been fortunate to be involved in some meaningful resilience-building projects in the Pacific, supporting many of our neighbouring nations to implement sustainable energy solutions.

However, with a current project in Tonga, coronavirus has thrown our travel plans into disarray. The challenge we’re facing now is how to continue the planning, engagement and environmental activities required by such a project when we can’t physically get there, can’t hold town hall meetings and can’t host information sessions with locals.

While the pandemic is forcing many practitioners to extend and expand their use of digital forms of engagement (such as websites, Facebook, Twitter, ‘Bang the Table’ or moderated ZOOM-based focus groups), some projects are located in communities that do not enjoy easily available or reliable internet or telephone access. In these cases, such as our project in Tonga, we need to think differently about ways to facilitate engagement from a distance.

For the Tongan project, we’re heading back to basics: the tried and tested solution of providing information on paper. Working with the local project management unit, along with our client, we are designing and implementing a newsletter to be printed in the local language and distributed to regulators and communities. It will provide snapshots of the project, latest updates on scheduling, and will even feature some interviews to provide greater coverage of ongoing community engagement.

As the construction company for the project is, like us, unable to travel internationally at the moment, construction is yet to take place. Nevertheless, we are continuing to facilitate all aspects of the project remotely, such as lining up approvals with regulators, and guiding engagement on the ground. With the help of our Tongan counterparts, we can still keep information and updates flowing despite the physical limitations on our involvement ‘in the flesh’.

Buying time and building partnerships in South-East Asia

Just as COVID-19 started closing borders and halting international travel, our team was reaching the culmination of many weeks planning an impact assessment for a large infrastructure project in South-East Asia. Our discipline experts were about to book their tickets and embark on the journey to site to survey environmental and social impacts. However, we placed the site surveys on hold indefinitely to comply with travel restrictions, ensure the safety of our people and contractors, and not risk spreading the virus in remote communities.

This abrupt shift in our plans afforded us the chance to take a breath, reflect on the project and its broader risks, and then develop an alternative plan to keep progressing aspects of the work that could be done remotely. We are now proactively undertaking desktop approval studies and initial public consultation from our desks. We’re ‘buying time’ now to save time later.

When travel restrictions lift and it is once again safe to physically attend the site, we will be ahead of where we would have been pre-COVID-19. We will better understand potential issues and have a more thorough insight into the local and community context. We’ll have already carefully planned our field studies with more targeted approaches. We’ll be better prepared for stakeholder questions that may arise, and will have already considered ways in which the project might manage challenges and risks going forward.

But there’s something more that we’re seeing emerge in this COVID-19 period. We’re finding that the shared need to adapt to trying times and the mutual desire to find workable solutions is strengthening our relationships with our clients, building even greater trust and collaboration, and it is leading to ‘partnership’ relationships that transcend the more common transactional paradigm of client–consultant. We are working closely together to openly discuss issues and options, and to determine how best to manage emerging challenges to benefit the project.

Would this have happened without COVID-19? Perhaps – but under the usual pressure of timelines, expectations, standardised processes and the drive for efficiency, there isn’t often the same flexibility or space to build different qualities and layers in our relationships or to consider potential issues quite so broadly or creatively.

Will the project benefit from the changes made necessary by COVID-19? Probably – despite the difficulties caused by the limitations on travel, it can only be positive to have had the chance to take the time to more thoroughly and holistically consider all the issues and risks before we proceed to field studies and stakeholder engagement.

Will timelines change significantly because of COVID-19? Not necessarily – we will inevitably lose some months by not being able to go into the field, but we will have ‘bought’ some time by compiling a good portion of the project documentation prior to the field studies, so that the time required in subsequent stages is lessened.

Wherever in the Indo-Pacific region our international projects are located, our clients can be confident that we’re seeking all the ways we can – new or old – to keep making progress in these uncertain and complicated times … and to come through them stronger together.

If you would like to discuss how Entura can help you with your environmental or planning project, please contact us.


Don’t let COVID-19 stop your project

A vital part of the success of all projects, whether they are new or operational, is maintaining progress towards milestones and retaining currency in the social and regulatory realms. How can we achieve this during a global pandemic?


With the COVID-19 crisis affecting people and businesses across the globe, employers and employees alike are racing to find normalcy. Fortunately for Entura, we’ve already been working and collaborating virtually for many years across country and state borders, with dispersed office, client and project locations. So, even though our teams are working from home, it is still business as (mostly) usual, in unusual times!

Although COVID-19 hasn’t thrown us completely, travel restrictions have pushed us to think differently about many of our projects and methods. This is the time to explore proactive ways to ensure projects do not come to a grinding halt or fall off a community’s or regulator’s radar.

Keeping environmental and planning projects moving forward

Entura’s environment and planning team works frequently in the field – lakes, forests, roadsides, development sites and many more – so COVID-19 travel restriction have taken a hit at our ability to undertake survey and monitoring programs or to conduct site visits, but it hasn’t led to tools down.

We may miss out on our chance to hit the frosty outdoors this autumn and winter, but there are still many ways that we can and will continue to make progress and deliver value. It’s about thinking creatively about how we can be proactive. And that means finding measures and activities for the short and medium term that will keep the project moving towards the longer term project milestones and goals (without the anticipated longer term extending into the much further horizon!)

For example, there are proactive things we can do to prepare us better for when we can once again visit the site. We have access to a wide range of data and can undertake thorough desktop investigations early in the project. We will then be able to step on site well prepared and looking to fill knowledge gaps or to verify what should be there. That puts us in a better position to be alert to anything unexpected we might find when we’re physically on site in future. Unusual discoveries and observations will be more pronounced. Such approaches can help shorten project timelines post-COVID-19 compared with the inevitable blowouts that would be caused by downing tools completely.

Policy and regulatory reforms are also still happening across the country – some as a result of COVID-19, others associated with larger reform programs to update antiquated legislation. Our discipline experts continue to engage with the regulators and relevant government agencies and authorities to ensure we understand the nuances of these changes and how they may influence the scope of existing and future projects and programs of work.

More proactive, less reactive

The restrictions caused by COVID-19 have highlighted the need to be proactive so that we can be better positioned for the longer term. It’s natural for a consulting paradigm to tend towards the reactive and process-driven, but this is the time to shift such tendencies.

With a future-focus and forward thinking, we can all seek out proactive solutions to keep projects and processes running as smoothly as possible, to meet any milestones that are still feasible, and to do everything that is reasonably possible in the present circumstances that will minimise delays once the pandemic has eased.

This needs to be a shared process. If as consultants and clients we put our heads together, we can develop shared understandings of the opportunities, risks and issues affecting all parts of the project and all the players involved. With team work and good communication, together we’ll find the most innovative and workable solutions, and together we will survive and thrive.

Beyond the immediate

The circumstances of the pandemic are also an opportunity to think beyond the immediate projects on our desks. This is a great time for our clients to review their projects and environmental and social management practices, to be better positioned for the post-COVID-19 future. This could include being more informed about potential risks or thinking through changes that you could make to your management practices to better address ongoing or emerging issues.

In our next article, we will highlight some of the projects we are currently working on, and how we have adapted them in light of COVID-19. We will also dig down into some of the key regulatory reforms happening across the country, and what implications they may have on projects during the COVID-19 period and beyond.

At Entura, we will continue to respond to government measures as they surface, and we will continue to be here to assist all our clients to better understand the opportunities, risks and issues associated with keeping your project alive during COVID-19.

A message from our team to yours

And to finish on a light note – Entura’s environment and planning team has nimbly settled into their new branch offices, from urban Melbournian set-ups to peri-urban workplaces at the foothills of the majestic kunanyi/Mount Wellington in Tasmania. From our team to you or yours, here are a few handy tips which we have found to help with this transition to working from home:

  • Stay connected – drop your colleague or manager a line and ask how they are going, and where possible (bandwidth permitting), turn on the video during your virtual meetings.
  • Schedule regular team catch-ups, and why not end the week with an optional virtual gathering to kickstart some weekend banter?
  • Don’t be embarrassed if your pets or children make an appearance – it helps lighten the mood and may provide the laugh that someone really needed.
  • Get some fresh air before you start work – imitate that commute to work by going for a walk or cycle.

If you would like to discuss how Entura can help you with your environmental or planning project, please contact us.

Pictured, clockwise from top left:

  • Senior Social and Stakeholder Consultant, Dr John Cook
  • Land Use Planner, Bunfu Yu
  • Senior Aquatic Scientist, Dr Malcolm McCausland (and friends)
  • Team Leader Environment and Planning, Raymond Brereton
  • Senior Environmental Planner, Cameron Amos
  • Senior Planning and Environmental Consultant, Scott Rowell (about to head out for a ride)
  • Environmental Consultant, Rachael Wheeler


Engineering – by humans, for humans

When engineers think about the future, do we get so engrossed in the complex technical problems that we don’t attend enough to the human angle?


Engineers have a reputation, whether rightly or wrongly, for being poor communicators, working obsessively and in isolation, and focusing on the immediate goal rather than its impacts on communities. Often, clichés have a basis in truth. If we are going to shift perceptions, we need to start by thinking about the way we work and the leadership we show to the next generation of engineers.

There’s no way we can predict the major developments, challenges or solutions of the next five or six generations of engineering careers. What we should focus on is what we can do right now to lead change in our profession and our communities – and I think the keys are communication, collaboration and community.


I recently listened to a podcast in which two energy market experts talked with a power system engineer. They discussed all sorts of technical matters relating to frequency and voltage control. I love those topics, but this conversation was limited and uninspiring because the participants simply didn’t have a common language or understanding.

We need to learn to communicate in ways that a variety of people can understand. That will mean better conversations with the people who can help our work have greater impact, and it will help our communities to appreciate the importance of our work in their lives.

It’s too easy for us as a profession to sit at our desks or stand under our hard hats and luxuriate in how clever we are, and then bemoan how so many people have no idea what we do and don’t value our work.

When things that involve engineers go wrong, a flurry of opinions erupts. Failures such as the blackout in South Australia, or the cladding issues at the Grenfell Towers, or issues with airlines or bridges or dams all lead to our communities questioning and debating engineering practice. Engineers tend to try to stay out of this rough and tumble for fear of being misrepresented. Yet maybe it’s better that we do engage where we can, since being misrepresented on a small issue is better than allowing a groundswell of misguided public opinion due to a lack of understanding of engineering principles. 

We need to try to better explain our work and find simple ways to convey the complexities of the decisions that we make. 


The world is far more complex now than it was a century ago – but it is impossible to imagine what level and pace of change future generations will experience. If we want to transform our world or help build a better future, we can’t do it by ourselves. 

Engineering no longer operates in isolation, if it ever did. We must collaborate across the engineering team and across other professional disciplines to achieve truly effective development for our communities. Sometimes we may need to focus a little less on technical delivery as a primary outcome, and increase our recognition of the value gained by engaging successfully with the communities on whom the project relies for success.

Collaboration makes our work more effective, and exposes us to a wider range of inputs and values that we can incorporate into our designs and processes. Engineering can be a leader but it can also be a facilitator for better outcomes when we draw on, listen to and learn from the other experts involved in other aspects of our projects.


Engineering work almost always benefits more people than merely the one who pays the bill. Much of my work is in connecting wind farms and solar farms to the grid. Mostly my work is paid for by the owner of the farm, and while it delivers direct benefits to the owner through return on investment, it also affects everyone connected to the nearby network. It affects the network service provider and market operator, it pays salaries, and it supplies the clean energy that helps the country reduce emissions and meet its international targets. In other words, my work, which may seem intangible, has tangible effects in the real world.

If we agree that our labours produce real impacts, we need to take better care to fully consider the wider consequences of our work, which often has the potential to cause ‘collateral damage’. We can’t build a road or a wind farm without changing the landscape. When we build a machine, it uses energy and may emit pollutants; and it reduces reliance on manual labour, which may put someone out of a job. There may be a risk to lives, livelihoods or the environment if something goes wrong.

Do we always make decisions about these matters with the community front of mind, or do we place our clients on the higher pedestal? This is a tricky area and I’m not espousing a puritanical approach. However, if we knew in 1919 what we know now about lead poisoning, acid rain, greenhouse gases, scarcity and general sustainability principles, what different choices could have been made?

In a time of automation, we need to think about benefits and risks and how they affect our communities. On one occasion early in my career, I designed a controller to turn on and off a couple of compressors at a power station. I wrote some code to balance the run hours. A few months after the new system was commissioned, I asked one of the operators how the system was going, in terms of the run hours management, and he said ‘you’ve done me out of a job’. I hope he was joking. The task he’d been doing wasn’t particularly important, but there was value in having a person who was in tune with the equipment to take care of it, and there was also value in giving that person dignity through work.

My point is that we must keep our communities foremost in our minds as we go about our work. It’s not just about what we produce. It is the way we work and the people we choose to work with and for. Our influence on the development of the next generation of engineers perhaps has more impact on communities than our actual work outputs.

Through communication, collaboration and community, engineering can be both ‘more human’ and ‘for humans’.

About the author

Donald Vaughan is Entura’s Technical Director, Power. He has more than 25 years of experience providing advice on regulatory and technical requirements for generators, substations and transmission systems. Donald specialises in the performance of power systems. His experience with generating units, governors and excitation systems provides a helpful perspective on how the physical electrical network behaves and how it can support the transition to a high renewables environment.


Asset management trends for profitable wind farms

How can a wind farm realise its full lifetime potential in an increasingly cost-sensitive market?


Until now, improving the wind industry’s profitability equation has been driven by increasing the size and efficiency of wind turbines, resulting in more energy produced for every dollar of capital expenditure. However, there’s only so far we can go with this approach.

To keep driving costs down and maintaining your wind farm performance, we now need to turn our focus to another aspect of the equation: a wind farm’s significant ongoing operational and maintenance (O&M) costs, which are set to increase as wind assets age. Achieving maximum yield at minimum risk and cost across a wind farm’s full operational life is a major asset management challenge, and much is yet to be learned.

In 2018, at the Wind O&M EU conference in Germany, I observed some international trends and perspectives on O&M that can offer useful insights for the wind industry in Australia. Although some aspects of the topic generated a deal of consensus, other areas are far less certain with many questions and possibilities yet to be fully explored.

Learn from other industries

Across the wind industry, there’s strong agreement that commercial returns for wind farms are not as high or as easy to obtain as they once were, and that reducing O&M costs on wind farms is critical when profit margins are being squeezed.

This may seem obvious, but the fact that we still need to articulate this point demonstrates that the wind industry has a significantly less sophisticated O&M approach than more mature industries such as oil, gas, other energy and heavy industries, and the IT and telecommunications sectors.

The wind sector should, and no doubt will, look to these more mature industries in the coming years for innovations that can be applied successfully to streamline our O&M and asset management strategies.

Plan for a longer life

Another implication of the relative youth of commercial wind farm development is that the industry has little practical experience with ageing wind farms – yet wind farms are set to get even older. Where it was previously the norm for a wind farm’s business case to be based on a 20–25 year life, it is becoming increasingly common for business case scenarios and asset management strategies to consider lifetimes up to and potentially beyond 30 years.

We need to be developing thorough and sophisticated asset management strategies that fully embrace the later stages of a wind farm’s life – not only the earlier stages in which O&M may have been conducted under contract with risks managed very effectively.

When we think about ageing wind farms, we weigh up the choices of continuing operations, decommissioning, or repowering with new turbines. From our understanding, it seems that wind farm repowering is only happening in locations with very friendly tariffs (such as a few areas in Germany), or where the existing project is fundamentally unsound from a technical and commercial perspective.


In Australia, full repowering with new wind turbines is not currently a commercially attractive proposition, and may not be widely considered for at least another decade. So, a wind farm’s extension of life will need to be achieved through effective O&M and refurbishment. I observed that some wind turbine owners and suppliers are beginning to think in more sophisticated ways about whole-of-life asset management strategies that maximise project value for the longer term, but it is still early days across the sector.

I also noted a range of diverging opinions about whether it is preferable for an owner to manage O&M through long-term comprehensive O&M contracts or whether risk is better mitigated by owners taking on the management of O&M themselves. Approaches vary depending on portfolio size, experience, capability and the general philosophy of the business. Clearly, this is not an area in which one solution will work for all.

Share information to build knowledge

Given the relative newness of the large-scale wind industry, and the need to squeeze every last drop from existing infrastructure, there is much to be gained from learning from and with each other.

Many industry players at the conference expressed a desire to see increased cooperation and sharing of information between different owners, operators and manufacturers.

The industry as a whole will benefit if SCADA system data is the property of the wind farm owner and shared more openly across the industry. Greater openness and availability of data will allow better benchmarking across turbine models scattered across the globe, enabling operators to better predict future costs and performance and incorporate reliability-centred maintenance.

Better benchmarking may offer insights into the extent of the performance improvements that could be gained on existing projects by adopting some available upgrade options. Many service providers are offering control system upgrades, aerodynamic improvements, yaw alignment systems, and advanced condition monitoring systems for increased availability – yet the industry is still learning how to translate this dizzying variety of rapidly developing technologies and options into a robust business case.

It can be difficult for owners to justify expenditure when the gains are uncertain, difficult to measure, and sometimes accompanied by drawbacks that are hard to quantify directly. For example, do you take increased generation at the risk of a reduced lifetime or increased maintenance costs?

If performance improvements of wind projects were more easily measured, we could more realistically quantify their impact on profit.

From these trends, observations and uncertainties, it’s clear that in any wind farm project – whether developing a new project or changing ownership of an existing project – we need to look very carefully at ongoing O&M costs, particularly as the increasing costs of end-of-life loom large. Thorough due diligence and realistic assumptions in this area will be vital for developing viable business cases across an increasing range of possible lifespans.

If you would like to find out more about how Entura can help you optimise your wind farm, develop an asset management strategy, or support you with due diligence services for proposed or operational projects, contact Patrick Pease or Silke Schwartz on +61 407 886 872.

About the author

Andrew Wright is a Senior Renewable Energy Engineer at Entura. He has more than 15 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 engineering services. Andrew has worked closely with Entura’s key clients and wind farm operators on operational projects, including analysing wind turbine performance data to identify reasons for wind farm underperformance and for estimates of long-term energy output. He has an in-depth understanding of the energy industry in Australia, while his international consulting experience includes New Zealand, China, India, Bhutan, Sri Lanka, the Philippines and Micronesia.


Congestion and losses: more than a blocked nose for new renewable generation

Anyone who’s ever had a cold understands the discomfort of blocked airways. Congestion challenges, albeit slightly different ones, also face developers of new renewable energy generation.


The nature of powerflows around the grid is changing rapidly with a lot of new generation being built on the edges or middle of the transmission system. This is increasingly being recognised as a problem, but quantifying the impact can be tricky.

Developers are asking: “What other generation will or can be built in the area? Will there or can there be collocated storage? When may these things be built? Will other projects in the area have a similar generation pattern to my plant?” And these questions are becoming harder to answer with the wave of renewables development.

Answering these questions

There’s no real substitute for analysis and an understanding of the degree of certainty required.

A simple example of adding generation in north-east New South Wales illustrates the point. Naturally, developers think first about competition: “Will added generation displace existing generation in NSW or generation on the interconnector? What is the most conservative assumption? What is the balance of probabilities?

Even this simple example leads to many assumptions and choices, so proponents and owners need to understand how certain they need to be – and therefore how thorough the investigation of congestion needs to be.

What other questions are there?

Traditionally, congestion has been considered a problem of network thermal capacity. The nature of renewable energy generation adds other factors into this mix, such as: “Will fault levels remain high enough to support short-circuit ratios? Will critical clearance times be maintained to allow the full thermal capacity to be used? Will imbalance of generation development on parallel paths reduce pre-contingency loading limits?”

These sorts of questions require complex analysis, adding further uncertainty and additional dimensions to the results.

There’s talk of additional network provision being required to support changes to the flows in the transmission system. Such changes will no doubt be helpful, but questions of when, how much and who pays must be asked. 

We can see that calculation of congestion has real impact on expected revenues – but with so little certainty, it is hard to determine how critical any impacts may be on the overall business case.

What about losses?

The other effect of large generation on transmission flows is greater network losses. The marginal loss factor (MLF) regime that accounts for losses in the National Electricity Market (NEM) relies on many of the assumptions of congestion analysis, with similar levels of uncertainty of the input increasing the uncertainty of the output.

MLF has always appeared punitive for new renewable generation distant from the load centre, since long transmission distances (often over low-capacity lines) lead to inefficient power delivery.

The MLF regime is supposed to incentivise development of efficient and timely generation and demand. The drivers for renewable generation are less about actual demand and more about displacement, so the MLF inhibits the building of new generation in favour of the status quo.  A simplistic analysis, however, shows that, on average, new renewables see slightly higher MLFs than the established generation and new thermal assets.

There could be a number of explanations for this but it shows that the density of generation has remained low enough thus far. Increased build and in-fill will ultimately lead to MLFs becoming a bigger and bigger factor for new and existing plant.

Other congestion issues

There’s another form of congestion looming or already starting to impede the rapid deployment of solar and wind technology: a lack of capacity of network service providers (NSPs) and other regulators to deal with the influx of applications for new connections.

Add to this the increasingly technical analysis required to demonstrate compliance of these connections with the rules and a real bottleneck is created.

Blow your nose

The truth is, the only answer to any congestion issue is to remove the blockage .

In terms of network congestion, in the short-term, we need to continue to think about the likely requirement for renewable developments (with storage) to meet the challenges of the energy trilemma – replacing coal-fired generation following retirements with reliable, affordable and more sustainable generation.

And we will need to better understand the value of transmission re-enforcement to support a changing generation fleet.

It may also force a return to the Hub or Scale Efficient Network Extension (SENE) type of thinking that gives a clear signal to proponents to ‘build here’, as we can now see in New South Wales.

Network re-enforcement may also improve MLFs, slightly. However, if MLFs are low across the board in a region, the pool price will adjust to reflect this over time. In the short term, local or regional storage may be cost-effective in raising MLFs to investment-tolerable levels.

In terms of resource issues, training and applying more skilled resources to this sector must be a focus for NSPs and regulators.

Our approach as consultants is to not always recommend more analysis but, alternatively, the right and the most efficient form of analysis.

The challenge for NSPs and regulators is to act more commercially and embrace an engineering approach to analysis, tolerating some uncertainty – just as proponents do.

We always feel better once the fog of congestion lifts. Sometimes we try to fight through it, but it’s often better to take deliberate action to treat it and to avoid complications, just as when you are suffering the symptoms of a cold.

If you would like to find out more about how Entura can help you navigate network challenges, please contact Donald Vaughan on +61 3 6245 4279.

About the author

Donald Vaughan is Entura’s Technical Director, Power. He has more than 25 years of experience providing advice on regulatory and technical requirements for generators, substations and transmission systems. Donald specialises in the performance of power systems. His experience with generating units, governors and excitation systems provides a helpful perspective on how the physical electrical network behaves and how it can support the transition to a high renewables environment.


Tackling renewable energy integration: five lessons from Sri Lanka

Ambitious renewables targets, movements away from thermal generation, increasing demand for electricity … it’s boom time for renewables around the world. Yet the global energy transformation brings some challenges, particularly for network stability and security.


Sri Lanka offers an interesting case study in the complexities of quickly integrating a large proportion of renewables and how some of the hurdles may be overcome. The lessons we can learn from the Sri Lankan experience are applicable worldwide.

In 2016 the government of Sri Lanka set a very ambitious renewable penetration target, with 100% of power generation to come from renewable sources by 2050. Coal and oil generation, currently accounting for around 50% of all generation, will cease by 2045. If this isn’t challenge enough, add in the projection of maximum demand rising above 7000 MW (from a current daily maximum of 2500 MW) by 2040.

Between September 2015 and March 2016, three nation-wide blackouts threatened to significantly undermine Sri Lankan industry and foreign investment prospects. The challenge for the Ceylon Electricity Board (CEB, which runs Sri Lanka’s power system) now is to achieve the country’s power transformation while still ensuring network security and reliable electricity. Any future unexpected system outage would be likely to erode public confidence in renewable development, regardless of whether the outage relates to renewables or not.

What can we learn from the Sri Lankan experience of the 2015/16 blackouts and Sri Lanka’s current challenges in its journey to a renewable energy future?

1 – Focus on accurate modelling of the power system

The first lesson to be taken from the 2015/16 blackouts is the need to focus on power system modelling. The first blackout occurred after a trip of the largest generating plant under light load. The next was due to a trip of a major transmission line when two parallel circuits were taken offline for maintenance. Neither of these events were envisaged through system model simulations. If a utility’s simulation tools won’t predict such events, planning engineers will struggle to anticipate or guarantee system security under system contingencies. 

For system planning and operations, CEB has developed a power system model consisting of major hydropower, oil, coal and wind plants. However, no model accuracy requirements are specified in the national grid code, which leads to the use of generic models with unknown modelling accuracy. Prior to Sri Lanka’s 2015 blackouts, limited tests were conducted to tune the models to accurately represent behaviour. During 2017, CEB embarked on a project to test the model validation for at least some of the major hydro units. These tests need to extend to all major power plants so that engineers can trust the actual performance of every major generator in the system.

2 – Determine a clear, single responsibility for the system model

The second lesson from Sri Lanka’s system modelling is the need for a single owner of the system model files, with responsibility to maintain the model and ensure its accuracy. If different departments of a utility have different system models, results of an event analysis may vary.

Ideally, the entire power system should be modelled accurately and the model controlled by a single team. This is vital for maintaining integrity of the system studies conducted by various parties.

3 – Consider minimum generation

When making decisions about the size of power plants, it is quite common for the focus to be on maximum generation. However, to minimise any unwanted constraints, it is really important to consider the lowest level of generation at which the plant can operate. 

Three coal plants in Sri Lanka each have capacity of 300 MW with minimum generation of 180 MW. During periods of low demand, all three coal plants need to remain at their minimum of 540 MW (3 x 180 MW) even if other generation is available in the system. 

4 – Ensure the network code looks to the future

When determining the grid code, it is essential to keep an eye on the development of non-conventional renewables. The grid code needs to be able to manage power quality issues in the future while minimising unnecessary costs to developers. In other words, it must have enough regulatory power to impose required technical targets, yet be flexible enough to minimise unnecessary mandatory capital expenses.

5 – Set up an ancillary service market

Sri Lanka does not currently have an ancillary service market, so the fall-back position is mandatory interruption to the system load under certain contingencies. This will not be acceptable in the longer term and customers will demand higher reliability. A way of categorising system support, especially frequency control ancillary services, will enable CEB to maintain system reliability as well as understand the quantities and price to deliver the required reliability.

Some tightening of Sri Lanka’s current technical and connection policies and practices will be needed as the country embarks on drastic change in its generation mix in pursuit of its renewables target. Yet the lessons we’ve explored in this article are readily applicable to any network keen to accelerate substantial integration of renewables, especially solar PV and wind, for a successful energy transformation and a future of reliable and sustainable power.

If you would like to find out more about how Entura can help you overcome network challenges when integrating renewables, please contact Ranjith Perera on +61 3 6245 4272, Shekhar Prince on +61 412 402 110 or Patrick Pease.

About the author

Ranjith Perera is a Specialist Power Systems Engineer at Entura.  He has over 22 years of experience in Australia and South-East Asia, working on customer and generation connections and broader power system analysis.  Ranjith has provided power system advice on a wide range of network augmentations, network planning and system stability in Australia and internationally. These studies included option analysis in transmission planning, constraint analysis, determination of reactive support (dynamic or static) in system stability / TOV and detail load modelling in voltage stability. Ranjith also developed voltage recovery guidelines to TNSP based on regulatory requirement and customer equipment tolerances.


Dispatchable renewables: a contradiction in terms?

As Australia replaces retiring coal generation with renewables, can we achieve an energy future that is affordable and sustainable as well as reliable?


The role of renewable energy in achieving affordability and sustainability is clear. As coal-fired power stations approach retirement in Australia, renewable generation from wind and solar PV appear to be the most cost-effective options for new energy generation. Wind and solar power now offer the lowest cost of energy, have low ongoing operational costs, and emit the least greenhouse gases across their lifecycle – and therefore hold the greatest potential for rapid decarbonisation of the energy sector.

But what about achieving the third element in what has been termed the ‘energy trilemma’: reliability?

Replacing coal-fired power stations with wind and solar PV is not a like-for-like swap in terms of availability of power when it is needed by consumers. Coal-fired power stations produce firm baseload power, but generation from renewable resources varies due to the availability of the natural resource. Wind and solar PV power vary according to the weather and the time of day, and even if we consider new hydropower opportunities, most of these are small ‘run-of-river’ systems, the output of which varies with rainfall and the inflows to rivers.

Yes, these renewables certainly produce energy, but is the power produced when it is needed?

The variability in power from renewables makes matching supply and demand a challenge. This challenge increases as more renewables enter the market. With moderate amounts of renewables, it is still possible to maintain system reliability through clever solutions – in particular, targeted grid support designed through careful planning and study of generation profiles, and supported by solid communications, control, power systems studies and forecasting. However, there is a limit to such approaches, and ultimately Australia will need ‘dispatchable renewables’ in the energy mix to achieve all the elements of the energy trilemma – in other words, renewable generation that is available whenever consumers require it. The time to start planning for this transition is now.


For generation to be dispatchable it needs to be available at the request of power grid operators or the plant owner according to the needs of the market. Dispatchable generators can be turned on or off, or can adjust their power output according to market need. If a generator is dispatchable it can be used to match load, meet peak demands, or fill the gap if another generator suddenly goes offline. Dispatchable generation is very valuable to the market because it can be used to match the profile of energy demand.

Effectively, baseload fossil fuel generation can be replaced by the combination of variable renewables, dispatchable renewables, smart high-voltage network support and planning to ensure sufficient transmission capacity, and change in use of existing hydropower.

How can we make variable renewables ‘dispatchable’?

The concept of dispatchable renewables seems almost contradictory: how can something generated from an inherently variable resource be dispatchable? There are two parts to this: the first is to look at how well different wind and solar PV sites naturally work together to firm supply (i.e. how likely it is that dips in one source are filled by peaks in another). Once this is understood, we need to consider how much storage is required to manage residual variability. Storage is critical here as it provides flexibility to store excess or low-value energy for times when it is really in demand.

When patterns of renewable generation are highly correlated (in other words, the timing of generation is very similar), more storage is required. For example, if the east coast of Australia develops a very high proportion of solar PV generation capacity, then all of these will be generating within about two hours of each other during the day (because of similar sunrise and sunset times across this region), and not at night. To fully utilise this energy, much of it would need to be made ‘dispatchable’ by adding substantial storage for the night-time hours, or we would need to firm the supply using another generation source, such as a gas turbine. But with a suitable proportion of wind in the mix (and stronger interconnectors to solar generation from other regions), the same dispatchability can be achieved with a more moderate amount of storage. This example demonstrates the importance of achieving a mix of renewable generators to meet the goal of dispatchability. 


Various studies of generation in the NEM over time have demonstrated that wind and solar generation are not highly correlated. These studies have shown that even with low to moderate correlation, when considered over a large geographical area, a combination of such generators reduces variability and increases reliability of supply. Understanding this effect enables appropriate sizing of storage to create a dispatchable renewable portfolio with maximum value. There will always be some times when multiple generators produce near maximums, as well as some times when both wind and solar produce near minimums; these occasions are not common, but could have significant consequences. This is a risk that needs to be managed by the system.

The amount of firm capacity can be increased by over-installing generation, and curtailing its output when there is too much generation. However, there are still those infrequent periods when multiple generators are at their minimum and parts of the grid need extra support. Having this support available during these rare occasions will be critical to managing risk and maintaining reliable supply.

This indicates that the mixture of different renewables won’t take us all the way to the goal of achieving ‘dispatchable renewables’; storage remains a critical ingredient.

What’s the future for energy storage?

The media is awash with reports of new energy storage options. It is important to recognise, though, that different types of storage solutions vary widely in their ability to discharge power over different time frames. Therefore one type of storage will not necessarily deliver the same solution as another type of storage. Understanding this is critical to the concept of dispatchable renewables.


The power and duration of the storage are the two key variables in determining the most suitable solution. Low-power, short-term storage is currently more cost-effective using batteries, but longer periods and larger power requirements are likely to rely on bigger storage options, such as pumped hydro energy storage and traditional hydropower.

With individual wind and solar plants pushing 1 GW, pumped hydro and modified traditional hydropower solutions need to be considered. Smoothing out the daily variability in renewables can be achieved effectively through pumped hydro, but multi-day storage to supplement periods of extreme events of both low wind and low solar will require traditional hydropower with very large reservoirs.

In the long run, short-term storage will not be sufficient alone to achieve the aim of ‘dispatchable renewables’. Achieving full dispatchability of combined wind and solar PV power will depend on utilising pumped hydro storage and existing hydropower storages to their full potential.

When will we need dispatchable renewables?

The question of when we’ll need dispatchable renewables is complex. It’s driven by a combination of commercial, regulatory and technical considerations as well as changing customer behaviour (all of which are in motion).

The short answer is now.

There are already isolated opportunities in which dispatchable renewables offer distinct advantages, and where the business case may stack up. With increasing wind and solar PV developments in the network without dispatchable capability, such opportunities will only expand. However, the lead time required to include large-scale storage in these ‘dispatchable renewables’ projects means that planning must begin well in advance.    

If you would like to discuss how Entura can help you explore potential opportunities for dispatchable renewables, please contact Phillip Ellerton on +61 439 010 172, Richard Herweynen on +61 3 6245 4130 or Chris Blanksby on +61 408 536 625.

About the authors

Richard Herweynen is Entura’s Technical Director, Water. Richard has three decades of experience in dam and hydropower engineering, and has worked throughout the Indo-Pacific region on both dam and hydropower projects, covering all aspects including investigations, feasibility studies, detailed design, construction liaison, operation and maintenance and risk assessment for both new and existing projects. Richard has been part of a number of recent expert review panels for major water projects. He participated in the ANCOLD working group for concrete gravity dams and is 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.

Dr Chris Blanksby is a Specialist Renewable Energy Engineer at Entura, and Entura’s lead solar energy specialist. He has undertaken and published research on the solar resource in Australia, and has led several due diligence and owner’s engineer projects for wind, solar and microgrid projects in Australia, the Pacific and Asia.  


Six steps to reduce risks when investing in renewable energy projects

Big investments require confidence – however, caution in unlocking funds is perfectly reasonable. A thorough due diligence is the key to building investment confidence by identifying and quantifying the project’s risks, costs and benefits. 


Due diligence is a broad term, and consists of technical, legal and commercial considerations. In practice, it means developing a full understanding of the proposed project, discovering any risks that could prevent its success, and capitalising on the project’s strengths. Not all risks will be ‘show stoppers’, but identifying any potential risks, judging the likelihood and impact of those risks, and identifying mitigations will enable greater confidence that the project is a viable investment.

Whatever the renewable energy project – a solar farm, wind farm, hydro scheme, hybrid solution, pumped hydro energy storage facility or other emerging option – technical due diligence considerations need to explore total energy yield, project uncertainties, technology choices, social and environmental implications, contractual terms, the business case and also non-financial goals.


For any project, a critical requirement of lenders is a bankable energy yield assessment. Renewable resources such as sunlight and wind generate power with a variable output that can be forecast, but is not necessarily available on demand. This leads to daily, quarterly and annual variations in generation and to uncertainties in revenue that need to be factored in. Despite this variable yield, renewable projects do not incur the risks of variable fuel costs which affect other energy projects.

To avoid lower-than-expected revenue generation, the project needs to be able to export power into the electricity grid without constraint. This makes the grid connection arrangements and understanding the risks associated with the eventual operational regime critical to the success or failure of a project.


Project lenders require confidence in the capability and reliability of the proposed technology for the project. For wind farms and hydropower projects using equipment from a supplier with a long operational history or large install base, this is less likely to pose hurdles than for emerging renewable energy options such as hybrid systems using batteries.

A project developer would be well advised to obtain relevant documentation from suppliers, such as a solar panel’s assessments results from recognised testing institutes. Absence of information is likely to result in conservative assumptions for financing purposes, so efforts to extract and justify all parameters is typically well worthwhile.


Renewable energy projects operate within communities. There will be a range of attitudes towards any project and many stakeholder relationships to manage. The relationship established with the project’s community can make a substantial difference to the success of the project.

A major risk to social acceptance of the project and development approvals is environmental impacts. Best-practice identification, mitigation and management of the environmental implications of the project is critical to the long-term success of a project and to corporate reputation.

4 – TAKE CARE WITH Contracts

Renewable energy projects require a large upfront capital expenditure. Depending on the investor’s risk appetite, exposure to risk can be managed through the contractual arrangements with the developer, equipment suppliers and the construction contractor.

Land-owner agreements; connection applications; engineering, procurement and construction contracts; supply and installation contracts; and operations and maintenance contracts of various forms will be required to develop, construct and operate the project. While a legal adviser will need to comb through these, many technical aspects can vary significantly in their favourability to a purchaser or investor. Identifying and quantifying these items will need input from a technical advisor.

Investments that are otherwise sound can suffer due to delays in construction, which can have significant impacts on expenditure and revenue profiles, and the terms of any debt provision. The investor can mitigate some risk through delay damages in EPC contracts, however, the adverse impacts of projects delays are rarely fully mitigated by contractual arrangements.   

For operations and maintenance, comprehensive long-term agreements offered by the original equipment manufacturer are an effective method of transferring risk associated with plant reliability onto the supplier or EPC contractor. However, the certainty afforded will come with a cost premium, and it is critical to appreciate that a comprehensive operations and maintenance agreement does not guarantee energy output.


Renewable energy projects are often supported by government policies that recognise the environmental benefits of clean energy generation. It is essential to understand both the commercial market for the energy and the policy environment in order to negotiate power purchase agreements or to manage merchant risk if the energy is being sold on the spot market.

It is also vital to understand the relevant regulatory frameworks – planning, environmental, electricity grid, corporate governance, taxation, financial, employment, or occupational health and safety. All these factors need to be considered when assessing the cost of the project and the risks associated with the investment.

Another potential risk – or opportunity – is change in the market, both short term and longer term. Consider how foreseeable or unforeseeable market movements (such as changes in industrial loads, or shifting levels or patterns of demand) may affect performance and viability of the project over its life.


The ultimate motivations and goals of the investor will influence the assessment of risk. The project may not simply be all about financial return, but also a desire to limit carbon exposure or to increase corporate social responsibility. Understanding the goals of the project will provide a clearer perspective for the due diligence investigation.

Whatever the motivations of the investor, the financial realities of the business case will be critical. Technical viability and environmental benefits won’t be enough to get projects over the line if they can’t demonstrate their long-term financial soundness and ability to weather the competitive pressures of the market.

Businesses are likely to gain substantial benefits from making structured and systematic efforts to foresee and quantify risks across the spectrum of commercial, technical, social and environmental issues. The more detailed a due diligence process is, the more accurately risks can be quantified, and the less likely it is that potential risks will be overlooked. A thorough due diligence will take time and expertise, but it is a critical investment in the success and resilience of every renewable energy development.

To discuss how Entura can assist you with practical, expert technical due diligence services for proposed or operational projects in Australia and the Asia-Pacific region, please contact Patrick Pease, Silke Schwartz on +61 407 886 872 or Shekhar Prince on +61 412 402 110.

About the author

Daniel Bennett is a renewable engineer at Entura. He has near a decade of experience investigating feasibility and due diligence energy yield assessments for renewable projects in Australia and around the world. He has worked on various wind farm projects in Australia, China, India, Sri Lanka and South Africa. Daniel has also worked directly for developers and suppliers.


Maximising the benefits of GIS for better business decisions

‘Location, location, location!’ It’s a familiar catch-phrase in the real estate industry, but it’s just as relevant in the power and water sector. Wherever there’s location-related data, a geographic information system will guide better business decisions.


Mobile devices and apps are increasingly using location-based data collected via satellites, drones, LIDAR and other rapidly developing sensing and data capture technologies. With these advances, we are able to find relevant information more quickly and draw on that information to make informed decisions. We’re seeing this proliferate in everyday life through apps that help us navigate, find services and products, and make decisions ranging from the trivial to the profound.

Developers and managers of power and water infrastructure projects who embrace GIS (geographic information systems) stand to gain benefits on an even greater scale. Gathering high-quality spatial information and analysing it to guide business decisions will certainly improve productivity and the bottom line.

Better decisions are the necessary foundation for increased revenue, lower costs, greater efficiency and productivity, and reduced risks. So, if the technology is available and there’s so much to gain, why isn’t GIS being as widely used in the power and water sector as it could be? What may be holding businesses back from fully embracing this powerful and dynamic technology?

Do we really need to use GIS for this project?

All power and water projects involve location – from finding an optimum site for your project, to analysing combinations of spatial data to make the best management decisions or to predict events. Whenever you ask a ‘where?’ question, GIS can help. Where is the asset best located? Where are the constraints or hazards? Where are the reports of previous work done in this area? Where are the customers or opportunities?

In other words, rather than asking whether GIS is needed on a project, consider making GIS a default for every project. The real question should be “how can we maximise the benefits of using spatial data and GIS on this project?” GIS can offer business benefits far beyond the most commonly understood use: making a map.

Data capture in the field can now be streamlined – gone are the days of capturing field data with pen and paper. Users can now collect data on mobile devices, sync to databases while in the field, share data, and generate their own maps, queries and reports. Embracing these advances will save time and enable faster and better decisions.

As well as providing valuable business insights, spatial analysis and location intelligence can greatly improve communication and knowledge sharing – within project teams, with the broader business, and with the community and stakeholders – via tools such as web maps and apps, visual analysis and 3D modelling.

One of the most important applications is the simultaneous analysis of different spatial datasets to provide the best solutions or choices between alternative options, locations, objects and so on. This process is better known as multi-criteria analysis (MCA) and it can be used for many applications.

For example, MCA can be used to find the optimum site for your project taking into account a range of values such as local geology, threatened species, resource availability, land use and terrain, planning restrictions, communities and demographics. Using MCA, you can establish areas of best fit for your project based on thematic overviews of areas of constraint, cost of construction, access and transportation routes.


Risks such as bushfire, weeds, threatened species, pollution sources, landslides and erosion can also be more easily and fully understood, supporting your ongoing site management of such issues.

GIS also links with document management, asset management, business intelligence and enterprise resource planning (ERP) systems. It can act as a portal, creating a central point of easy access, pulling together information and making it available on one of the simplest forms to interpret – a map.

Of course GIS is not the answer to everything, and it is not a standalone platform. However, there’s much it can offer across many different business activities, working together with other business systems.

What about the costs?

The return on investment of using GIS should be positive if it is used appropriately. For site selection of power and water projects, using GIS is a no-brainer. For example, using GIS to find the best site for a wind farm – locating the best winds, minimal constraints, good proximity to existing infrastructure and appropriate land use – will obviously result in vastly greater returns than siting the wind farm in an inferior location.


Some examples may be less immediately apparent, but equally valuable – for example, using GIS to increase efficiencies in everyday workflows. If your workers are taking an extra half hour every time they need to find previous work completed in an area, this time can add up quickly. Or perhaps they can’t find previous information, so work is re-done unnecessarily. These costs will keep adding up. Instead you could use a GIS web map to locate all your previous reports and projects, so that a simple click on a map finds the files and saves hours (if not days) of time.

Do we need specialist software or skillsets?

With most things, you do need specialised skillsets and software to get good results, and of course bad data in equals bad data out. Users of GIS do need to understand and assess the spatial data needs in each application.

You could undertake some GIS work yourself using free or open-source software. However, be aware of the risks of using data or tools that aren’t fit for purpose. Just because you know how to use Microsoft Word, doesn’t mean you could write a detailed report outside your area of expertise!

We have seen cases where coarse-resolution data has been used to infer finer project details and costs, resulting in poor decisions. We have also seen inexperienced operators make invalid assumptions. To get the best results, you need to be sure that you’re using the technology wisely.

If you are engaging a power, water or environmental consultant on a project, they are likely to have access to GIS capability; however, GIS is still often underutilised. When deciding who to engage on your project, ask your consultant how they will maximise the benefits of GIS to produce better outcomes for your project.

To discuss how Entura can help you harness the potential of GIS to improve your power and water project decisions and outcomes, contact Stephen Thomas on +61 3 6245 4511, Patrick Pease or  Phillip Ellerton on +61 439 010 172.

About the authors

Stephen Thomas is Team Leader and Senior Technical Officer with Entura, specialising in geographic information systems, 3D visualisation and CAD software. Steve has over twenty-six years of technical experience and specialises in environmental assessments and approvals for engineering surveys and property. He has created 3D models and animations of proposed developments including wind farms, urban landscapes and city frameworks. Steve’s work on the Hobart Waterfront 3D model won an international award in geospatial modelling.


Can big data and artificial intelligence transform the wind sector?

Big data and advances in artificial intelligence hold extraordinary potential for transforming the energy sector. But is change in the wind sector likely to be transformational, or can we expect only incremental performance improvement?


For utility-scale wind farms, the benefits of big data technologies may not be on the scale of the transformations occurring in distributed generation, energy storage and demand management – but there is no doubt that there is potential for incremental improvements in the efficiency and cost of wind turbines, improved energy forecasting, and better fault prediction and detection – and that means opportunities for competitive advantage.

Big data, machine learning and AI

Big data is the result of having more data sources and more storage. We are now flooded with data of all types and we have the ability to store it, but the key challenge is making that data useful so that it can create value. Machine learning deals with computer models that apply algorithms allowing them to learn from experience, modify their internal rules and make better predictions. When you put the two concepts together, big data enables machine learning to act like an artificial intelligence (AI), creating systems that mimic cognitive functions such as learning or problem-solving.

Underpinning all this are computer models, which translate input data into outputs or predictions. For a wind farm, input data can include wind speed, turbine output, climatic conditions, error messages and condition monitoring data. The outputs might be improved turbine siting, predicted component failure, or predicted wind farm generation one hour in the future. Let’s have a look at some examples.

How can big data and AI help wind developers and operators now?

Plenty of research is underway into how big data and AI can optimise wind generation. Increased yield, more accurate forecasting, and more effective operations and maintenance are just some of the possibilities.

Increased yield

Greater yield means more generation and more power into the grid. The improvements in yield can come from improving the estimated power curve, and tailoring the operation of each turbine to suit the conditions.

A number of turbine manufacturers are developing and offering individual turbine tuning. This involves analysing the historical weather conditions and resultant production, and setting up specific control settings for different conditions. A more complex approach could allow a system to autonomously vary the turbine settings during the operation of the wind farm and learn the effect of those adjustments on production, retaining them for future use.

The verdict: Incremental yield improvements in the order of 1–5%.

More accurate forecasting

To balance energy supply and demand in the grid, as well as to maximise returns on the spot market, it’s critical to have accurate forecasts of a wind farm’s production.

Weather forecasting is a very popular area for researchers, and it seems that the entire range of machine learning algorithms has been applied in attempts to demonstrate superiority. Generally, in each case studied, researchers are able to show that machine learning methods improve upon the accuracy of classical prediction models. However, models and assessments all depend on the site, and no clear recommendation of one model can be made across the board. The best-performing approaches incorporate multiple numerical weather prediction forecasts, combined with live site data for wind, power and atmospheric conditions, and commonly use neural network methods. 

The verdict: Incremental improvements in forecast accuracy, as meteorological agencies continue to incorporate machine learning components into weather models.

More effective operations and maintenance

More effective operations and maintenance (O&M) plans can significantly reduce a wind farm’s ongoing costs and increase its output and operational life. Because O&M are major expenses with all industrial machinery, there’s a lot of work being done in predictive maintenance and fault detection.

One opportunity is using SCADA data to detect faults. The approach is to train a model during normal operating conditions to predict a measurement, for example, bearing temperatures. Then input the current operating conditions and flag where the observations don’t match the prediction. This can allow abnormal behaviour to be picked up early, before a major component fails. 

Wear and tear on each turbine’s individual components can be tracked using the specific conditions to which the turbine on site has been subjected. Components that need replacement or can be safely left in service can be identified by collecting the full operating history of individual turbines, and using a representative computer model of the turbine. This can provide savings based on extending conservative estimates of serviceable life, and allowing better scheduling of maintenance through earlier signalling of the need for component replacement.

The verdict: Gradual lowering of costs of O&M and lost yield, as parts can be replaced prior to catastrophic failure.

Where are we going?

There’s no doubt that the future will see widespread take-up of machine learning services, and even more data. The ‘internet of things’, or the idea that everything will be network-enabled, will mean that big data will get even bigger. With that come data storage issues, but also potential for even more fine-grained analysis, if the right tools can be developed.

We are likely to see more tech companies offering to apply data analysis and machine learning services. However, it is also likely that data analytics will be built into systems and supplied as standard, particularly for equipment such as gearboxes or entire wind turbines. 

But the biggest related change we see is the impact on the competitiveness of businesses, their services and products in our industry. For example, the last ten years has seen significant consolidation of wind turbine suppliers. In the United States three wind turbine suppliers accounted for 78% of new capacity in 2016 (according to the US Energy Information Agency). Substantial benefits can be offered by those wind turbine suppliers that are able to analyse the data pulled from a critical mass of installed wind turbines and their hard-won operating experience in a range of locations and conditions.

Being part of a large interconnected worldwide network of wind turbines is proving to be an attractive proposition for wind farm owners. The consequences include a trend towards longer and more comprehensive O&M agreements with the original equipment manufacturers, and a reduction in the perceived risk in providing finance to wind farm projects – just two of many trends that are contributing to a truly transformational change in the energy generation sector.

The verdict: Continuing gradual technical improvement, and significant commercial opportunities for suppliers leveraging data from large install bases.


The improvements from applications of machine learning are fascinating for the technically inclined, and are already improving the performance of wind farms worldwide. However, we don’t consider them transformational when compared with the major changes the application of AI will have in other industries such as transportation (e.g. self-driving cars).

Big data, machine learning and artificial intelligence offer current and future benefits for wind farm developers, manufacturers, owners and electricity market operators and traders, and it’s worth considering the applications, while understanding the limitations.

If you would like to find out more about how Entura can help you use data and machine learning to optimise your wind farm, contact Patrick Pease or Silke Schwartz on +61 407 886 872.

About the author

Daniel Bennett is a renewable engineer at Entura. He has near a decade of experience investigating feasibility and due diligence energy yield assessments for renewable projects in Australia and around the world. With a background in mechanical engineering and computer science, and an interest in poking around in data to see what falls out, he assists clients seeking to understand the value in their projects.


Protecting your embedded generator from islanding without breaking the bank

If you are planning to generate some of your own electricity, such as through a few wind turbines or a small solar farm, you’ll need to know about islanding.


Adding new embedded generation such as wind or solar into the power grid can produce some challenges, but these challenges can be overcome. One such concern is the potential for network faults to cause islanding – in other words, when an embedded generator keeps supplying power to a grid when the grid power falls or fails, forming an island.

Understanding the cost implications of anti-islanding protection will help you negotiate with your network service provider, and may help you save money on a fit-for-purpose solution.

Network service providers (NSPs) are particularly sensitive to the risk of islanding. Although the probability of an island developing is low, the potential for islanding causes NSPs concerns about safety, about delivery of poor-quality electricity, and about the chance of damage to their equipment.

However, the high costs of some anti-islanding measures could cripple your embedded generation project, so you need to be aware of your options.

How can islanding be detected?

To protect against islanding, many NSPs will install high-speed communications circuits between your new plant and their substation or control centre. This works well: the NSP determines that an island may be forming and sends a trip signal to your generator. However, the communications circuit is expensive and, typically, the cost will come out of your pocket. The extra expense might spell the end for your power project, regardless of its size.

In the future, the gold standard in anti-islanding protection is likely to be based on synchrophasors, so that the phase angle of various parts of the grid can be compared and a tripping decision can be made without involving the NSP control centre. This method will still require high-speed communications circuits.

It is common for proponents to consider ‘passive’ anti-islanding protection based on measurements made at the generator. The usual measurements made to detect islanding are over/under voltage, over/under frequency, rate of change of frequency, and vector shift. The NSP is likely to ask what will happen if the island load matches the island generation. In a purely academic sense, if the load matches the generation then none of these elements will detect the island. But is this concern warranted in practice?

The bigger risk you will face, particularly in off-grid networks, is that the rate of change of frequency or the vector shift will trip your generator unnecessarily. It is very difficult to set vector shift protection sensitively enough that it will detect an island but not malfunction during a network fault.

What’s the best option?

If you are connecting an inverter-based system (e.g. a solar farm or a type 4 wind turbine) make sure that it has ‘active’ anti-islanding protection and that the inverter documentation discloses the method being used. In Australia, simply specifying compliance with the standard AS 4777 is sufficient.

Specialist advice on how the active anti-islanding protection operates will help you and your NSP determine whether you can avoid the need for high-speed communications and use a lower cost communications circuit such as 3G.

If you are connecting an induction generator, you might think that it is not possible to supply an islanded load. It is not impossible, just unlikely. Your NSP may not accept unlikely, when you could install a high-speed communication circuit and eliminate the risk at no additional expense to them.

Although an induction generator can sometimes supply an islanded load, it is almost impossible for it to do that at nominal voltage and frequency. Passive protections can be applied and are likely to work reliably. The rate of change of frequency protection is particularly useful in this case because, unlike vector shift, it is not susceptible to network faults as long as you select a relay with the right algorithm.

If you are connecting a synchronous machine, you’re providing valued inertia, but you may have the largest anti-islanding challenge. The synchronous generator can supply an island indefinitely and often without going far outside the nominal system voltage and frequency.

In this situation, there are three alternatives:

  • You could attempt to convince your NSP that the power you provide to any island will be of the highest quality and that there is no need to panic if an island is created for a short time. The NSP will likely ask you to fund the installation of one or more new voltage transformers in their network.
  • You could accept that high-speed communications really are required to safely incorporate your new generator into the network, and shoulder the expense.
  • You could apply vector shift protection to your generator and accept that there will be occasional instances in which your machine will trip off and need to be restarted following a network fault.

Anti-islanding protection is complex, and it adds an extra hurdle in the process of embedding small generators in our networks, but this challenge can be resolved satisfactorily. By being better aware of your options, you’ll be much more likely to achieve a safe and cost-effective solution that meets your needs as well as the requirements of your NSP.

If you would like to find out more about how Entura can help you overcome islanding and other electrical challenges, please contact  David Wilkey on +61 3 6828 9749 or Patrick Pease.

About the author

David Wilkey is Entura’s Principal Consultant, Secondary Electrical Engineering. He has more than 20 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.


Connecting renewables in a changing grid

As the network continues to incorporate increasing levels of inverter-based asynchronous generation such as wind and solar, connection standards in the weakening grid are tighter than ever before.


Successful grid connection is a key factor in the ability of generating plant to operate effectively and reliably , and it does not need to be a roadblock to the roll-out of new renewable generation. But connecting new solar and wind generation into a weakening transmission system can involve challenging grid connection requirements, particularly at periods of low demand.

Network faults can cause potential imbalances between network segments, and these imbalances may be exacerbated by fault ride-through (FRT) algorithms.

We have written previously that it may not be easy to understand the worst case from a system fault perspective. So we need to consider a wide range of system scenarios in combination with a broad spectrum of contingency events. 

A number of factors are at play here, but we will focus particularly on the effect of FRT algorithms on the transient stability of the network.

When considering the connection, we tend to focus first on the stability at the connection point. This can lead to reducing the aggressiveness of the FRT algorithm to ensure FRT re-strikes are not caused by the power ramping back too quickly.

But this is where the seeds of the problem are sown. The weak voltage support at the point of connection leads us to withhold power longer during FRT to give voltage controls (remote or local) a chance to work immediately after fault clearance. In a stronger grid (even if we’re on a weak connection) this power deficit is not significant, but it can be crippling in a weak grid.


A fault forms two islands (momentarily). These two islands will invariably be unbalanced internally. That is, there will be a surplus of generation in one island and a surplus of load in the other. One island will then speed up and the other will slow down. If our inverter-based generator is in the island that is slowing down, then the withdrawal of energy by FRT makes the energy deficit in that island worse.

When the fault clears, the two islands need to re-establish synchronism. If the two islands have diverged then they may not be able to snap back to synchronism. This may lead to system separation and possible load shedding or worse.

What can be done when this occurs?

If a new connection runs into this problem as part of the connection studies, it may be able to get around it by tweaking the FRT controls. Setting these to return to normal control as fast as possible and to minimise the depth of power withdrawal during FRT will weaken the effect. Installing synchronous condensors may be another way to improve Short Circuit Ratio (SCR) at the connection point. This should allow more aggressive return from FRT.

On a network level, stronger interconnection and meshing should reduce the locations where faults can actually form the islands we’ve described here. This solution is possibly expensive, but network capability is currently the missing link in our Rules.

This is the problem we face as we move closer to the edge of the technical envelope. The capability of the network is not and has never been defined by the transmission elements alone. We’ve had generating units that have provided voltage and frequency stability. Now, those generating units are being displaced by wind and solar sources that do not provide the same levels of grid support.

This is where the interpretation of the Rules is going to be a threat to further renewable penetration. When assessing a new connection we routinely look for dispatch scenarios that will test the limits of grid strength. If the new connection can’t meet an appropriate standard of performance, we determine that it is this new connection that is at fault. Sometimes this is true, but sometimes it’s just that connections that came before have soaked up the available system strength.

On one level, this is an appropriate response. The new connection should not be allowed to connect if it can’t meet an acceptable negotiated level below the automatic access standard. On the other hand, it seems that the network resource is not being equitably shared. That is, people ahead in the queue have been given more than what we now understand to be a fair share. 

We’re not suggesting a reallocation of those shares. That’s impractical. Nor are we suggesting that earlier connection agreements were ill-advised. We, as an industry, just know more now about how valuable and scarce network strength can be. 

How will this affect future connections?

Ultimately we need a reasonable approach to negotiated access standards. Perhaps there’s a need for an adjustment to minimum access standards too. It is not practical or fair to expect that that burden be shouldered by new connections alone. Nor is it practical or fair to renegotiate the connection standards of existing plants. If we are to continue to add non-synchronous generation, we will need alternative sources of grid strength. 

If you would like to find out more about how Entura can help you overcome grid connection challenges when developing your solar farm, please contact Donald Vaughan on +61 3 6245 4279 or Ranjith Perera on +61 3 6245 4272.

About the authors

Donald Vaughan is Entura’s Technical Director, Power. He has more than 25 years of experience providing advice on regulatory and technical requirements for generators, substations and transmission systems. Donald specialises in the performance of power systems. His experience with generating units, governors and excitation systems provides a helpful perspective on how the physical electrical network behaves and how it can support the transition to a high renewables environment.

Ranjith Perera is a Specialist Power Systems Engineer at Entura. He has over 22 years of experience in Australia and South-East Asia, working on customer and generation connections and broader power system analysis.  Ranjith has provided power system advice on a wide range of network augmentations, network planning and system stability in Australia and internationally. These studies included option analysis in transmission planning, constraint analysis, determination of reactive support (dynamic or static) in system stability / TOV and detail load modelling in voltage stability. Ranjith also developed voltage recovery guidelines to TNSP based on regulatory requirement and customer equipment tolerances.


Planning a renewable energy journey in the Pacific

Like many stories of island journeys, the pursuit of high levels of renewable energy in the Pacific involves good planning and skilled navigation to stay safe and on course, and holds the promise of rich rewards.

Planning a renewable energy journey in the Pacific-680x350

Throughout the Pacific, island communities are embracing ambitious renewable energy targets , many as high as 100% renewables over the next decade or two. This isn’t surprising, given that these islands are already experiencing significant impacts of climate change, and recognise the environmental benefits of reducing or replacing carbon-intensive diesel power generation.

There are also sound economic benefits to reducing reliance on expensive diesel fuel, which remains the single largest expense to generate power in these remote locations.

The answer to meeting targets, while also reducing carbon emissions and costs, lies in power systems that use only renewable energy. However, transitioning to higher levels of renewable energy in power systems requires confidence that the renewables can provide the energy security, self-sufficiency and system stability required by these remote communities.

Renewable energy technologies may pose some challenges for reliability and quality of power supply, but remedies can be found in enabling technologies. In an isolated power system, matching the renewable technologies with the right enabling technologies at the right moment needs detailed planning.

Every journey needs a map

As each island community’s renewable energy journey is different, careful strategic planning is needed to choose the right solution, to integrate it in the right way, and to be able to scale it up effectively to meet increasing renewable targets and electricity demands.


Click image to view infographic.

Entura has been helping a number of Pacific island communities embark on their renewable energy journeys. Through this experience, we’ve developed a map of the key stages of the journey:

Stage 1: Planning – In this stage, we explore the status of the current power generation assets, determine what needs to be improved, understand the renewable resource, and investigate the cost of the renewable energy journey and options for funding it.

Stage 2: Introduction of renewables – In this stage, we begin by harvesting the ‘low-hanging fruit’ – introducing the renewables that we can without enablers or network upgrades, and without changing the control philosophy. At this stage, the renewables are perceived as mostly load offset, and could reach up to 15–20% of the island’s total energy demand. Few enabling technologies are necessary at this stage.

Stage 3: Expansion of renewables and introduction of enablers – As we progress beyond 15 to 20% renewable penetration, we need to stop, review and adjust course if necessary. To progress towards 35% renewable energy contribution to the power system demand, we need to adjust the system’s operating philosophy to integrate large-scale renewables, and introduce the appropriate enabling technologies.

Stage 4: Expansion of renewables and enablers – This stage marks the largest change in how an island power system is operated. As we move beyond 50% renewables, again we should stop, review and adjust course where needed. At this stage, power systems become very complex to operate and maintain as high renewable penetration can only be achieved through a delicate balance of multiple new enabling technologies working in perfect sync. The island community could find itself investing more in enabling technologies than in renewable energy at this stage, but this could result in a higher renewable energy contribution. It is also crucial at this point to consider changes to energy delivery, relationships with customers and to the utility’s procedures, and to building its personnel capabilities.

Stage 5: Approaching 100% renewables – As most of the major changes to the power system are introduced in the earlier stages, Stage 5 is about finishing off the journey. The ‘last renewable mile’ is usually the most expensive one, so this last stage is all about identifying enabling technologies and techniques that can bridge the gap between 70–80% and 100% renewable contribution, without significant increases in the cost of electricity.

Yap’s journey to 25% renewables


Entura has helped several island communities plan and begin their renewable journeys. One example is the island of Yap in the North Pacific.

We’ve been working with the Yap State Public Service Corporation to reduce Yap’s heavy reliance on imported diesel for power generation, and to enable the island to rely as much as possible on indigenous, renewable resources through an integrated high-penetration renewable energy remote area power system (RAPS).

After decades of operating on diesel fuel only, the system will soon reach 25% renewable energy contribution. Once completed, the project aims to enable Yap to experience up to 70% instantaneous renewable penetration when conditions allow, and to deliver an annual fuel saving of up to US$500 000.

Back in 2014, Entura helped the Yap community plan their renewable journey by embarking on Stage 1. Since then, Entura has helped the Yap utility to reach Stage 2 by integrating small amounts of solar and by building its capability to install and maintain solar arrays.

The Yap renewable energy development project is now entering Stage 3, in which a new breed of high-renewable-supporting diesel generators are being installed, major works are being carried out to install three 275 kW cyclone-proof wind turbines, an island-wide solar-controlling communications network for 500 kW distributed solar PV is being rolled out, and a centralised control system is being installed.

Once these activities are completed, the Yap power system will be firmly in Stage 3, and ready for future stages in Yap’s renewable journey.

On course for 100% renewables in the Cook Islands

The Cook Islands is a group of 15 small islands in the South Pacific, to the north-east of New Zealand. Entura is helping the Cook Islands on its journey to reduce reliance on diesel fuel and achieve greater energy security, self-sufficiency and sustainability through developing renewable power systems on six islands. The country’s goal is to generate electricity from renewable energy sources on all islands by 2020.

The islands of Mauke, Mitiaro, Mangaia and Atiu have small average loads of around 100kW each. After careful planning, upgrades to the distribution grid and programs to train and build local capacity, these islands will quickly reach Stage 5 of their journeys, operating at almost 100% renewable energy using solar PV and batteries, with diesel providing backup during longer periods of renewable energy resource deficiency.


A fifth island, Aitutaki, is currently at Stage 1, finalising the planning of its renewable journey. It will rapidly jump to Stage 3 as 1 MW of solar PV, a 0.5 MW power battery, new diesel generator and centralised control system start working together to deliver a power system with a renewable contribution of up to 25%.

Rarotonga is the largest, main island in the Cook Islands and operates a complex power system requiring meticulous strategic planning. This power system is already at Stage 2, with a renewable contribution surpassing 10% due to the contribution of residential and commercial solar. Entura is helping the Rarotongan utility to move towards Stage 3 by introducing an additional 1 MW of solar PV and enabling technologies such as energy storage, which will help the system absorb even more renewable energy.

The journey continues

It is often said that the end of one journey is the beginning of another. After a community has reached 100% renewable energy, it needs to continue its journey to maintain that status through proper operation, maintenance and asset management, to secure the system for years to come. This long-term asset management challenge involves attention to both physical and human assets, including capacity building, training and skills development for individuals and organisations.

Entura is bringing practical maintenance know-how to island communities such as Yap and the Cook Islands. And, through the Entura clean energy and water institute, we are helping to boost the skills of technicians and managers. By doing so, Entura is offering island communities a guiding hand from the start of the renewable journey right through to its destination, and beyond.

If you would like to discuss how Entura can support your renewable energy journey, please contact Silke Schwartz on +61 407 886 872 or Shekhar Prince on +61 412 402 110.

A version of this article has been previously published by


How can we manage a network with more renewables?

Can our network and market frameworks support two to three times more renewables in Australia in the next 10 to 15 years without radical or innovative actions?

How can we manage a network with more renewables-680x350.

Once upon a time, we had an electricity system that was dominated by large users and large producers, and everyone else just tagged along.  It needed very few points of control.  Demand was easy to predict, as was the availability and cost of generation.

This is increasingly not the case.

The predictability and consistency on which the market and the network relied are being eroded by changes in how we produce and consume electricity.  The efficiency benefits of the market are being undermined and it seems unable to find a ‘new normal’ that works.  At the same time, the technical robustness of the electricity supply is being undermined through the reducing share of dispatch of synchronous generation.

These effects are only beginning to emerge in the wider National Electricity Market (NEM).  We are suffering from increasing uncontrollability, unpredictability and variability.


As wind and solar PV replace synchronous generation in the NEM, system inertia and fault levels will steadily decline, along with the availability of frequency-control ancillary services (FCAS, or ‘spinning reserve’).  More self-dispatched generation also limits the market operator’s ability to efficiently manage transmission constraints.


We can use statistical models to predict demand pretty accurately unless we factor in customer storage.  Installation of uncontrolled storage adds a degree of uncertainty to the demand.  The current pre-dispatch followed by real-time dispatch methodology may not be capable of dealing effectively and efficiently with this uncertainty.  Furthermore, the factors determining take-up of new technologies are difficult to predict.  This uncertainty makes it more difficult for network planners to forecast and hence maintain capacity in the network.


Increasingly, generation dispatch patterns (and load patterns in some regions) depend on non-market variables like sun and wind (and rain).  This variability can lead to a wide range of valid system dispatches, which in turn may require a wide variety of network supports, such as reactive power support from SVCs and the like.  Interconnector capacity requirements vary depending on dispersion or concentration of generation relative to demand.

How might a low-synchronous-generation network be managed?

In many ways Tasmania provides a glimpse of the future in terms of how a low-synchronous-generation network may be managed.  Since Tasmania has been connected to Victoria, generators, major customers and the network service provider, with support from Entura, have collaborated to extend and enhance the Tasmanian power system’s ability to cope with what is already in excess of 70% non-synchronous generation under high wind and high import on the interconnector.  While the interconnector can provide some frequency support, this support is capped within the capacity of the link.

The solution in Tasmania is to reduce demand for frequency control, increase capacity to supply frequency control and actively manage fault level and inertia.  This has required detailed understanding of the power system dynamics within the Tasmanian power grid as well as innovative engineering to understand and adapt hydro generators to extend their capability or flexibility. The solutions range from tweaking the control systems of individual generating units to establishing and coordinating system-wide protection schemes and constraint equations.

This experience shows that understanding the fundamental characteristics of a power system and its likely operating modes, and a common purpose and resolve to enhance its operation, can lead to an expanded technical envelope in which the electricity market can seek a cost-effective outcome.  It has required collaboration across the sector including equipment manufacturers, owners of windfarms, hydropower stations, interconnectors and large customers.

Can this experience be replicated elsewhere? 

Different power systems may demand a different set of solutions, but the fundamentals remain the same.  A functioning AC power system needs inertia, fault level, frequency and voltage control as well as energy sources to function to an acceptable standard.  Each power system will have its own sweet spot for providing these requirements.  Inverter-based generators (solar, wind and batteries) can provide inertia-like responses for instance and so may reduce reliance on synchronous machines for that requirement.

A bigger question is: will the market takes us there or will it lead us down a blind alley of misguided self-interest?  We are already seeing some murmurings of market reform that may ultimately lead us to the right long-term solution, but I’m not sure that we can always rely on market-led transitions, especially where the transition has not been envisaged as part of market design.  This may be a misplaced leap of faith.

It’s clear that no single solution is going to sort this out in most cases.  It’s also clear that some level of collaboration will be required to make the transition work smoothly.  The planner must also consider technological change and customer expectations; else we run the risk of over-capitalising on solutions only for them to become redundant and ‘stranded’.

Ultimately, we know the challenges are not insurmountable but we also know that the solution is likely to be arrived at through care and deliberation rather than market meanderings.

If you would like to find out more about how Entura can help you adapt successfully to the rapidly changing market for electricity generation and energy services, contact Donald Vaughan on +61 3 6245 4279 or Wayne Tucker.

About the author

Donald Vaughan is Entura’s Technical Director, Power. He has more than 25 years of experience providing advice on regulatory and technical requirements for generators, substations and transmission systems. Donald specialises in the performance of power systems. His experience with generating units, governors and excitation systems provides a helpful perspective on how the physical electrical network behaves and how it can support the transition to a high renewables environment.


Finding the right value in dynamic modelling of renewables

What value can you derive for renewable energy projects through developing accurate models? When is the effort and expense involved justified by potential benefits?

Renewable energy project developers are often confronted with seemingly large costs to develop accurate dynamic models of their projects. This can be due to regulation, or it may be because that level of accuracy, potentially in excess of the regulatory requirements, adds value to the project.  It may be that the modelling actually allows the project to remain viable in the face of connection issues.


On some levels it’s easy to say the regulations require accurate modelling.  However, for any renewable energy project there is a level of modelling that will be the right fit , and the regulations shouldn’t ask for more than that without good reason.  So let’s look at the relative value of accurate modelling in various contexts, and then later we can see if there’s a mismatch between that value and regulatory regimes.

The requirements for power system modelling of generating units vary from place to place, but as ‘traditional’ generation levels recede and power electronics and intermittency gain more than a foothold in the power system, accurate modelling will increase in importance and value.

The aims of these models cover three levels:

  • Level 1: Does my plant work?
  • Level 2: Does my plant interact appropriately with the nearby network?
  • Level 3: Does my plant interact appropriately with the power system as a whole?

Accurate modelling can add value at any of these levels, but the degree of effort required to release that value depends on the type of project, the type of network and the location in the network.

The issue impacts all renewable energy projects but let’s take a wind farm as an example and move it around the network to explore this.

Small wind farm in the distribution network

Let’s build a 10 MW wind farm and connect it close to a distribution substation on a 33 kV feeder.  At this size, most of the ‘does my plant work?’ question is answered by the off-the-shelf inverter controls, so little value is to be gained at that level.

However, the interaction of the plant with the network and nearby customers is critical.  The connection point is close to other customers and so the variability of the wind farm can impact the quality of the neighbours’ supply.

Accurate modelling here gives certainty that there’ll be no surprises at commissioning.  Imagine convincing a network service provider that your flicker indices are OK, only to have the neighbouring plant force you to redesign or curtail your operations after commissioning. That has real project impact and possibly brand impact too.

Larger wind farm in the sub-transmission network

What if we move our wind farm to the remote end of a 132 kV line and build it ten times bigger?  Now we don’t have any neighbours, although we could have some in the future.  We have a stability problem because of the long line, so we now need auxiliary plant (e.g. a capacitor bank) to help control voltage and hence maintain production.

We’ve got a plant that has to cater for an external requirement (level 2) but that then implies an internal control or coordination requirement (level 1).

In this scenario, our models’ accuracy helps with internal design and, as a results, saves commissioning time. It also helps optimise production by clearly communicating the control actions of our plant to the wider system model.  This allows the degree of stability improvement to be accurately characterised and so constraints are not arbitrarily applied. The business-case levels of production are preserved.

Large wind farm in the transmission network

If we move this large plant to a 500 kV connection point and triple its size, it’s almost akin to the scale of our 10 MW plant back on the 33 kV.  Now we’re less interested in voltage controls due to the high fault levels at the connection point.  It’s very difficult to see the influence of the wind farm’s controls on the surrounding network.  The only possible value now is related to system strength and fault-ride-through phenomena (level 3).

This now requires accurate modelling of a smaller subset of controls, but it’s interacting with the whole system.  In a strong system these issues are generally negligible.  In a weak network, they’re critical.  So, for this example, the value is derived from integrated design of the controls to ensure system compatibility (i.e. no constraints). The value stems from efficiency and effectiveness at levels 1 and 3.  The value is in gaining connection, preserving energy production and streamlining commissioning.

The following tables summarises these three examples.  It shows my opinion on the value of dynamic model accuracy to projects connected at various levels of the electricity grid.  Note there is never a complete lack of value in having accurate models .  Also note that this is relative value.


The cost of accurate modelling may not vary much across these three connection levels but the value it brings to a project does.  The table shows an estimation of the value that model accuracy brings relative to the connection point strength and what aspects of the project it helps support.

So if you’re considering a wind farm, or any generation project, don’t forget the value that accurate modelling may bring to that project, but be mindful that this value may be limited due to the nature of the system and locale that you’re connecting into.

The art is to find the ‘Goldilocks Zone’ between the regulatory requirements for model accuracy, production loss through avoidable constraints and modelling effort. Too much or too little attention to these issues leads to unrealised project value.  If we find the right balance, it’ll be just right.

If you would like to find out more about how Entura can help you adapt successfully to the rapidly changing market for electricity generation and energy services, contact Donald Vaughan on +61 3 6245 4279 or Silke Schwartz on +61 407 886 872.

This author originally presented on this topic at the Clean Energy Council Wind Industry Forum in March 2016.

About the author

Donald Vaughan is Entura’s Technical Director, Power. He has more than 25 years of experience providing advice on regulatory and technical requirements for generators, substations and transmission systems. Donald specialises in the performance of power systems. His experience with generating units, governors and excitation systems provides a helpful perspective on how the physical electrical network behaves and how it can support the transition to a high renewables environment.


Binary states: the rise of the switching controller

The security of an electricity network is threatened by the rise of sophisticated controls on modern generating equipment.  These controls lead to complex interactions with the electricity network and must be managed carefully to maintain reliable system security.

Transient stability power system modelling has almost always been the cosy domain of Laplace transforms and smooth, linear controls. The rise and abundance of power electronics in wind turbines and solar PV is changing this and adding a degree of discomfort.

These new controllers switch control modes based on internal and external variables, and as such introduce a new model phenomenon, the switch controller action.  A switched controller can be particularly difficult to model accurately as it invariably switches based on an imperfect measurement of a process quantity, coupled with a time delay.

The switch will operate if the process quantity remains out of tolerance for the delay period.  The imperfection in measurement can make it hard to accurately predict when or if a switching controller will operate.  This can lead to a ‘Schrödinger’s cat’ scenario:  the simulation continues past the switching point but we never know whether it should have switched or not, and if it had switched would the result be more or less valid? The simulation could just as correctly be in either state.  Argh!



One school of thought is that more accurate and less assumptive modelling practice (such as using electro-magnetic transient simulations) might reduce this problem.  However, it is highly unlikely that this form of modelling will deliver all the gains that its proponents expect.  Rather, some conditions are likely to still give rise to the switching uncertainty, even with a much higher modelling cost.

Confronted with this uncertainty, how can we ensure that the modelling provides a useful insight into the limits of system operation? We’ll look at three scenarios: generator integration, system model validation, and system planning.

Generator integration

For generator integration, we typically define a set of boundary conditions and extreme event scenarios and determine whether the new generator is able to be connected within the system technical standards.  This approach almost always ensures operation of the switching controllers that protect a generator from abnormal conditions, and there is no ambiguity of outcome.  All good, job done? Well, no!

What if a slightly less severe system event leads to a condition in which the switching controller doesn’t activate but really should have? That’s a problem. This uncertainty requires us to define a much more complex set of scenarios to assure ourselves that a generator will comply with the technical standards.


System model validation

To validate system models, we generally measure responses from generating units and the system, and this tells us how the system and the generating units have behaved. So far, so good.  Although, we don’t always know the severity of the instigating fault with any certainty, and this degree of freedom can open the dreaded window of switching controller uncertainty.  Again, two possibilities exist in the model space: switching or not.

We know which is right, but is it fair to assume that the model inaccuracy suggested by comparison is entirely due to the generator with the switching controller? Um, well, probably not, but sometimes, yes.  This is perhaps more difficult to resolve because it’s hard to unpick the sum of small inaccuracies in the system model from the clearly aberrant behaviour of the switching controller since the aberrant behaviour may be due to those summed inaccuracies.

System planning

The number of scenarios explored in system planning studies leads us to try to ignore the contributions of single generating units, or at least to assume accuracy in those contributions.  Limits to system dispatch are established based on breakpoints such as transient stability and damping ratios.  But how do we know we’re studying the correct, most onerous events?  Severe events will always lead to switching controllers operating. Less severe events lead to hit-and-miss operation and potentially less stable system operation at potentially lower flows, so they must become part of our planning simulation considerations.

The rise of the switching controller and the uncertainty that it brings is a worrying development , with no easy work-around.  Being aware of the conundrum should lead to accounting for it in some way.  When the problem first arises during connection studies, the results at this stage can inform validation tests to increase the certainty of the modelling of the switching controller.  Understanding the sensitivity of the controller to voltage and frequency variations and imbalance should provide an appreciation of the need for more advanced modelling, or not.

Switching controller uncertainty demands due consideration from network simulators lest the security of the power system is compromised and we all suffer.

If you would like to find out more about how Entura can help you adapt successfully to the rapidly changing market for electricity generation and energy services, contact Donald Vaughan on +61 3 6245 4279.

About the author

Donald Vaughan is Entura’s Technical Director, Power. He has more than 25 years of experience providing advice on regulatory and technical requirements for generators, substations and transmission systems. Donald specialises in the performance of power systems. His experience with generating units, governors and excitation systems provides a helpful perspective on how the physical electrical network behaves and how it can support the transition to a high renewables environment.


Eight principles for successful investment in renewable energy projects

When you are considering investing in a renewable energy project, a thorough due diligence investigation can identify the costs, benefits and risks, and lead to well-informed decisions.

In practical terms, this is about asking the right questions about the project, distinguishing when an issue is important and when it is not, and prioritising your efforts.

Why prioritise your efforts?  Because the unfortunate reality is that most due diligence investigations don’t result in an investment. As consultants, we are aware of this reality, but as part of a larger business that acquires, develops and owns renewable energy assets, we understand that effort and expenditure must produce results.

When we lead renewable energy due diligence investigations, we often start with a quick assessment to establish as soon as possible if there are any ‘show stoppers’. No matter how preliminary or comprehensive the assessment, these eight principles guide our considerations:


1 – Identify the motivation to invest

A thorough due diligence investigation will identify high-level issues such as sovereign risk, right down to detailed technical issues associated with the particular investment opportunity.

Your motivations as the investor will influence the assessment of these risks. It may not simply be all about financial return, but also a desire to limit carbon exposure or to increase corporate social responsibility. And if we understand your business, we can bring a clearer perspective to the assessment.

Traditionally, investors have relied on consultants to assess the technical issues in detail, but have preferred to assess high-level risks ‘in-house’. This approach is understandable, but it may not be making the most of your consultant’s knowledge. Most renewable energy consultants these days have been in the game a long time, and you will find them keen to provide a more holistic assessment of risk.

2 – Understand the business case

As with any investment decision, investors interested in renewable energy projects need to understand the level of investment of financial and human resources required for the project, and the likely returns for that investment – the business case.

Each project will have its own set of issues and risks to identify and potentially mitigate as part of a robust business case. Risks will affect the revenue stream, the cost of the project, and/or the social acceptability of the project.

An experienced due diligence provider can provide value by recognising the difference between issues that will materially affect the project business case and those that will not, or by identifying opportunities where others might only see risks.

3 – Understand the relevant markets, policies and regulatory frameworks

Renewable energy projects are often supported by government policies that recognise the environmental benefits of clean generation and support the revenue stream for the project. It is essential to understand both the commercial market for your energy and this policy environment.

You also need to understand the relevant regulatory frameworks – planning, environmental, electricity grid, corporate governance, taxation, financial, employment, or occupational health and safety. All these factors need to be considered when assessing the cost of the project and the risks associated with the investment.

4 – Understand the impacts of the variability of renewables

Renewable resources such as solar, wind or small run-of-river hydropower schemes generate power with a variable output that can be forecast, but is not necessarily available on demand. This feature of renewable energy can lead to quarterly or annual variations in generation and in revenue that are beyond the control of the owner.

However, renewable projects do not have variable fuel costs. So by weathering the short-term fluctuations of renewable generation through prudent technical and financial risk management, you can achieve greater long-term certainty in your business case than with non-renewable generation projects.

The variability also means that when the resource is available (for example, the sun is shining), you want your project to export energy to the electricity grid without constraint. Therefore, for renewable energy projects, the grid connection arrangements can mean the success or failure of your project.

5 – Minimise uncertainty of revenue

The variable nature of renewable generation can create short-term uncertainty in revenue; however, long-term certainty in revenue is generally a must-have for a renewable energy project looking to sell its power output.

In some markets, set tariffs may be offered from government bodies for renewable projects. In markets with a floating electricity price, long-term power purchase agreements are often sought with counterparties such as retailers or large-scale energy consumers.

There may not be much assistance a consultant can provide on this issue – except to remind you to read the fine print of any agreements and, if the project does not have a confirmed buyer for the power, make sure you know the risks!

In terms of what the project is technically capable of generating, an operational project has more certainty than a development site, and may be more attractive for some investors.

6 – Manage capital and operational expenditure

Renewable energy projects require a large upfront capital expenditure. Depending on your risk appetite as an investor, exposure to risk can be managed through the contractual arrangements with the developer, equipment suppliers and the construction contractor. Comprehensive long-term operations and maintenance agreements are often available, which reduce your risk, but at a cost.

One issue worthy of particular note is construction delays. Investments that are otherwise sound can suffer due to delays in construction, which can have significant impacts on the expenditure and revenue profiles, and the terms of any debt provision.

7 – Develop and maintain community relationships and acceptance

Renewable energy projects operate within communities. There will be a range of attitudes towards your project and relationships to manage, and it will be up to you to develop and maintain a healthy relationship with the community.

Your community may see your project as a major contributor to the local economy through direct employment and indirectly through contracting. The community may even expect you to play a leading role in supporting local community activities through sponsorship and other activities.

8 – Ensure right action and compliance

An opportunity to invest in a renewable energy project might occur at any stage of the project. Regardless, the nature of the due diligence is usually very similar – have the right actions have been undertaken, does the project comply with its commitments, and will it continue to comply into the future?

Because Entura is part of Hydro Tasmania, Australia’s largest renewable energy producer, we understand what it means to live with the full consequences of investment decisions and risks. So we approach due diligence for our clients in the same way we would if the investment opportunity was our own.

That means developing a full understanding of the proposed project, discovering any risks that could prevent its success, and finding the best ways to make the most of the project’s strengths and avoid any possible weaknesses.

If you are seeking to invest in renewable energy, Entura can assist you with practical, expert due diligence services for proposed or operational projects in the Asia-Pacific region. Please contact Patrick Pease or Silke Schwartz on +61 407 886 872.

About the author

Seth Langford is a specialist renewable energy engineer at Entura and has been working in the wind industry for more than ten years. Seth has been involved with major wind farm projects as a technical specialist and a team leader for feasibility studies and due diligence projects in India, China, Australia, Sri Lanka, South Africa and New Zealand. Seth has spent considerable time assessing greenfield and operational wind farms on behalf of developers wishing to acquire wind farm projects.