Green hydrogen: big buzz or good business?

Everyone in the energy industry is talking about green hydrogen, and the buzz just keeps on growing. 

green hydrogen 680x350

It’s been clearly demonstrated technically that with an adequate supply of water and renewable energy, green hydrogen can be produced through electrolysis for local use or for export – with no associated emissions. The role for green hydrogen is likely to increase in the global energy transition and the race to net-zero. There’s much to be excited about; particularly the potential to make valuable use of ‘excess’ wind and solar generation that would otherwise go to waste, particularly in off-grid systems.

A number of potential opportunities for green hydrogen are developing. The primary markets in Australia are large-scale export, particularly for the Japanese and South Korean markets, transport, and the mining and industrial sectors.

Of course, these are early days, and there will be many technical, economic and regulatory hurdles to overcome, just as there were at the outset of the journey into solar and wind generation and battery storage.

Is there a place for green hydrogen in the off-grid and mining sector? 

In Australia, the mining sector may be a fertile ground for green hydrogen, not only because there is potential for multiple end-uses both on-site and off-site, but also because some of the hurdles may be lower. For example, the cost of energy for remote mining is generally high, and is vulnerable to disruption of fuel supply or price shocks. This is already leading to significant interest in off-grid hybrid renewable energy systems coupled with battery storage. The nature of high-penetration hybrid renewable off-grid systems is such that there is an excess of renewable energy. Adding green hydrogen capacity into a stand-alone renewable energy system could offer yet another layer of added value by capturing the excess to produce hydrogen.

This stored hydrogen could then have potential to fuel the mining transport fleet, to support processing, or to create product for export. The recent announcement that Rio Tinto, with support from ARENA, will investigate the use of hydrogen instead of natural gas in alumina refineries is an example of this thinking. With increasing shareholder demands on green mining, it may also lower the business’s carbon footprint and improve the ‘green’ brand positioning for the mine’s minerals or ore.

Can the hype become reality? 

The primary hurdle for hydrogen to become viable is cost. But this is not a new challenge. The first projects in off-grid hybrid renewable systems needed funding support; the ARENA funding for projects such as King Island Renewable Energy Integration Project, Flinders Island Hybrid Energy Hub and Coober Pedy Hybrid Renewables Project was paramount for their viability. These projects were needed to demonstrate and, importantly, de-risk hybrid systems. With the confidence gained and with subsequent reductions in component prices, the mining sector is now forging ahead with a strong appetite for commercially viable hybrid renewable systems that need no extra funding support.

So, in a kind of history repeating, the first step towards making green hydrogen a reality on mining sites will be large-scale investment support or grant funding for demonstration projects. Just like in the period of hybrid system development, such projects are critical for building the industry confidence and knowledge necessary to escalate uptake. 

Policy settings will also be instrumental in driving change. Investors, markets and communities are demanding ever-improving sustainability credentials from the mining sector; however, in Australia, regulatory structures such as emissions caps or financial penalties have not kept pace with consumer and financier expectations.

As we learnt on our journey with renewable hybrid systems, a key challenge will be the technical expertise to appropriately integrate all the elements of a hybrid renewable energy and storage system coupled with green hydrogen capacity. Having solid individual technology components is only one aspect of a successful deployment; integration of these elements is critical for maximising the renewable energy contribution or hydrogen use and for meeting stringent reliability and security requirements of the system. We have always found this need for an integration focus, be it in remote desert outback systems we have been involved with such as the Agnew Mine Hybrid Renewable Project deploying our hybrid control system, or in nations in the Pacific Ocean, or more recently in designing hybrid systems for Antarctic conditions.

Are there any answers, or just more questions? 

No one has all the answers yet, but we must keep asking the right questions about the possibilities of including green hydrogen into the power system technology mix. It’s not only a matter of ‘how can we make the best use of excess renewables?’ We also need to carefully think through the many operational aspects, such as when is the right time to move to green hydrogen, how much is optimum, how would the introduction of green hydrogen affect the sizing of other system components, how would it affect the operation of other devices, how would the system dynamics be impacted, and just what is the right hydrogen technology to use at a given point.

These operational aspects aren’t so different from the questions we already consider on hybrid renewable projects, and they’re a crucial step towards achieving a technically viable and cost-effective arrangement. Equally important will be questions around access to water resources, environmental impacts and social licence, as well as other planning and regulatory requirements. Project proponents venturing into the green hydrogen frontier will need to grapple with a very wide array of issues beyond just the technology and cost – and should seek trusted advisors who have a sound understanding of the many considerations required for the success of any integrated renewable project.

Despite the uncertainties surrounding green hydrogen technologies and applications, new frontiers are exciting places – and we’re standing right on the threshold, with costs of green hydrogen technologies and processes expected to fall and become cost-competitive within a decade. If research and innovation proceeds through industry consortiums (such as the mining industry’s Green Hydrogen Consortium) and research bodies, if grant funding is made available to support early developments, and if early movers have the appetite to take some risks on large-scale projects (such as the HyEnergy Renewable Hydrogen Project and the Asian Renewable Energy Hub), we expect to see the available technologies mature, and to see green hydrogen move from being a good idea to something that could potentially make sound financial and environmental sense.

If you would like to discuss how Entura can support your journey towards green hydrogen or hybrid renewable systems (whether off-grid or on-grid, large scale or small), please contact Ray Massie on +61 408 571 057 or Dale Bryce on +61 409 984 447. 


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.


Can the power grid weather the weather?

Even a single day of load shedding makes people doubt the national grid’s robustness. How will the grid cope if we experience extreme weather conditions more often?


Things get hot in Australia. They can get smoky, or wet, or cold. Australia’s beauty is in its ruggedness, its unpredictability and its diversity of natural environments. It’s what Dorothea Mackellar captured so well in the famous Australian poem ‘My Country’ – a ‘sunburnt’ land of ‘flood and fire and famine’, with ‘droughts and flooding rains’.

As dramatic weather patterns become more intense and more frequent, the electricity grid must be robust, or at least be managed to adapt to short-term challenges.  

If we get the design standards right and if conditions fall within the expected extremes contemplated by the framers of the standard, then everything works. However, what happens when conditions are abnormal? In heatwaves, we see people hosing the rail network to stop expansion. We’ve seen hosing to cool distribution power transformers at peak times too. But there’s only so much water and so many hoses that we can deploy when the heat is on. It’s not a sustainable solution.  

Can we manage?

Yes … but we must manage actively. Business as usual will not be enough. Consumers will not tolerate lower levels of reliability based on the weather. So something has to change.

There are a few mutually supporting paths we could take, including (1) considering extreme temperature ratings and improving the reach and spread of weather monitoring and weather-dependent grid management; (2) adjusting standards to contemplate higher temperatures; and (3) reducing our reliance on high flows to deliver peak demand.

1.  Consider extreme temperature ratings

Incentives already exist for our network service providers (NSPs) to release hidden capacity in networks. The incentives remain a small percentage of the overall regulated income they receive. The contemplation and control of realistic ratings under unusual weather conditions could be made more attractive to our NSPs. The NSPs would then be more likely to make these opportunities for capacity benefits transparent to the regulator and the public.

Generators are now being required to stipulate capacity at higher temperatures, but this is not being applied universally across existing plant. As we saw in Victoria this summer, the market is very reactive to the unplanned withdrawal of power from large thermal units – as much, if not more, than it is to variations in wind and solar power. Thermal machines have shown themselves to be sensitive and not always robust in prolonged hot spells.

2.  Change the standards

If maximum temperatures continue to climb, our standards or ratings may need to be adjusted to suit. In a global market, we have to be careful about being too ‘special’ or we’ll end up paying for specifications that cost more than the benefits they deliver. A half-way position may be for generators to estimate their capacity in relation to temperature conditions and require tuning of these estimates over time. This would at least give us an idea of the temperature effects on production across the fleet. The results of this might then inform the need for changes to standards or at least build quality to relieve unmanageable reductions.

3.  Reduce reliance on high flows

We’ve seen the effect that emergency events such as storms and fire have on the grid. Storms are managed through localised declarations of special constraint sets. They’re also generally short-lived. As we saw with the Tasmanian bushfires this summer, smoke and fire can affect a transmission corridor for weeks at a time. Because intense storms and fires tend to be rare, the market can take some time to adapt. Some planning or scenario work by AEMO might help prepare the market and reduce the impact on supply.  

Reducing our reliance on high flows to regulate price or maintain supply may also be valuable. This suggests a need for storage/s at opposite ends of tie lines and interconnectors so that short periods of constrained flow can be compensated partially or fully by the far-end storage.

We may also need some flow-path diversity on critical corridors or on corridors that link dispatchable generation sources with loads.

There’s little doubt that Australia will experience more frequent and intense floods, fires and heatwaves. In our ‘sunburnt country’ we need to keep our eyes firmly on the future of our climate, and we must build resilience into our generators, grid and market systems.

If you would like to find out more about how Entura can help you navigate your challenges in the electricity market, 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.


Limber up for a more flexible electricity grid and market

Integrating renewables into grids and markets is a hot topic worldwide, with many challenges and approaches to explore.


In late June 2018, a series of meetings run by the International Energy Agency (IEA) in Yokohama, Japan, brought together a wide range of electricity industry regulators and participants to discuss the IEA’s current work in this arena. There was a lot of ground to cover. I shared the Tasmanian experience of managing frequency using inertia and governor tuning.

For me, three main takeaways from the discussions are that we need to improve Australia’s market arrangements, increase flexibility, and we should try to re-imagine the grid as an interaction.

Improving Australia’s market arrangements

Anyone who’s been watching the Australian electricity sector over the last few years will recognise that there’s room for improvement in our market arrangements.

The National Electricity Objective (NEO) aims to promote the long-term interests of electricity consumers through efficient investment in, and operation of, electricity services. These consumer interests include the price, quality, safety, reliability and security of supply of electricity. It also means ensuring the reliability, safety and security of the national electricity system. However, commercial and environmental drivers are beginning to affect the security of electricity, and in some instances affecting the price as well.

It’s hard to see why we’ve ended up where we are. What’s important is what we do next, and why.

Understanding and pursuing flexibility

All sources of generating plant have flexible and inflexible attributes. We have always worked around the limitations and taken advantage of the benefits. Now, with disruption, prosumers, micro-grids and all the other ‘scary’ status-quo-busters, we have much more freedom to achieve flexibility than we have had in the past. That is, generators, grids and customers can all provide flexibility and add to the overall value of the electricity market.

Designing new plant, retrofitting old plant and improving controls to increase flexibility must all form part of planning and regulation as we continue to decarbonise electricity production.

Imagining the grid as interaction, not assimilation

The philosophy of grid revolution to date has been assimilation. That is, where possible, new generators need to look and feel like traditional generators.

As system security margins decrease, this is becoming even more the case. It sets up a sometimes false dichotomy in terms of market share, political ideology, technical requirements and standards, and assessment of value. And this is unhelpful as we move towards an electricity sector with increasing proportions of renewables. One reason why Australia may have ended up where we are now may be that the NEO is silent on environmental impact.

When we think of the grid and the market as spaces for interaction rather than assimilation, these dichotomies break down and we’re more likely to achieve fruitful outcomes. Interactions are not just technical (electrons and Ohm’s law) or commercial (tariffs and hedges) but also human.

The electricity transformation will be able to occur faster and more successfully when the electricity industry embraces the power of the demand side, interacts in a more beneficial way with human-scale usage patterns and requirements, and thinks about the flexibility that exists or is required in demand, storage and production.

Finding a new approach

This all sounds marvellous, doesn’t it? It is the sort of regulatory utopia that could only come from a group of government officials sitting around a table a long way from home. But for me, it was refreshing. The thought that the market serves a higher ideal can only inspire. Certainly, the developing countries that presented at the meetings are firmly motivated by the immediate benefits and opportunities that reliable access to electricity will provide to their people. 

In some ways Australia, too, is a developing country in the electricity sector. In the status quo, the path to future sustainability is blocked by the threats of climate change and, in some respects, by resource scarcity (depending on your view of the horizon). We need to develop a new approach to electricity production and consumption just as developing countries do.

If we think of the market as a facilitator for humans to flourish, then we must be careful to design markets for this purpose. Is the Australian market hampered in this respect by the dominance of a limited number of large players? Is there sufficient direct participation of individuals in the market? Does the regulatory framework accurately and adequately reflect the needs of all market players? Does the market inherently promote and reward flexibility? 

Market power, democracy and flexibility

My feeling is that there’s work to do across each of these areas.

A former Australian trade minister once remarked that Australia would always be somewhat of an oligopoly. We will never have large-enough markets that won’t be dominated by a few players. In some sectors we’ve enshrined protections that almost guarantee it. The current market design has led the electricity sector down this path.

This is okay so long as the behaviour of these players remains able to be influenced by their customers through choice of provider and volume, but this isn’t always the case.

Allowing more players to provide greater diversity of energy and grid services will help to erode the power of the oligopoly and will also increase the flexibility of the grid and the market. Various system incidents in South Australia and the Northern Territory have highlighted the need for flexibility. If we understand flexibility properly, we will understand a way to meet the need for it.

Greater flexibility can mean different usage patterns, different contributions from a wider number of players and more give and take between the grid and the various generating technologies. Providing rewards for flexibility will encourage diverse contributions, slow the retirement of existing plant, and bring new players into the mix.

Markets, grids and power plants must be planned and will need to allow for greater flexibility to provide better outcomes for customers. It’s time for the electricity sector, its regulators and its customers to limber up.

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

This article was first published in RenewEconomy.

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.


Are batteries the best way to go?

Renewables are now the cheapest form of new energy generation, but to make variable renewables ‘dispatchable’, we need to add storage. Are batteries the best way to go?


Batteries have been around for more than a century, but now we’re wanting them at a much larger scale. This is driving rapid advances in battery technology, ramping up capability and pushing down costs.

With batteries having such huge potential, this is the time to build a better understanding of battery technologies and applications. Batteries are a key element in addressing the complexity of achieving ‘dispatchable renewables’ and providing the necessary and complex functions of load balancing and network support.

As we plan how to include batteries in our energy future, we need to temper the hype with a careful, informed and strategic approach.

Shifting the load, stabilising the grid

A good place to begin is by clarifying what batteries do. The two main functions are load shifting and grid stabilising. In this article, I will focus on lithium batteries as they are the market leading technology at present. Of course there are other technologies that will forge a place in the “battery mix”, both chemical and other storage.

Load-shifting batteries are designed to better match generation to daily load cycles – for instance, storing excess solar generated in the day so it can be used at night – so they normally operate on a daily cycle. This is the most widely understood application of a battery in the wider community, but they require large amounts of storage (typically 4 hours for solar) and are currently too expensive to be realistically applicable.

With every charge/discharge cycle, battery life reduces, and this comes at a cost that is beyond the average cost of energy (except in some off-grid and remote mini-grids). If the battery is used for shifting energy only at times when the electricity price is high, this low level of utilisation will push up the unit cost of generation.

As battery prices come down over time, these issues will become less important. As major coal plants retire over the next decade in Australia, demand for load shifting will increase , which will also contribute to greater viability of battery solutions. However, pumped hydro is another major player to watch in the load-shifting arena, and may be difficult to beat, especially as a long-term storage solution.

The other main function of batteries is in supporting the stability of the grid. Grid-stabilising batteries can increasingly provide a whole raft of support functions such as FCAS (frequency control ancillary services) and NSCAS (network support and control ancillary services). This is mainly driven by very rapidly improving capabilities of the power electronics and control of the power conversion system (PCS) – the AC-DC converter – but is also supported by high-power battery technologies that can provide substantial power capability to support the grid without requiring much storage.

This type of battery really punches above its weight, providing short-term energy that can support most of the localised issues that arise in parts of the grid. These batteries could provide the glue needed by an increasingly fragmented grid. Right now, though, the need for these batteries is not widespread. Grid stability may be the most useful function of a battery into the future, but it is not well understood in the broader community.

The state of play

There’s plenty of hype about batteries, but at the utility scale we are yet to see great uptake in terms of numbers. The exceptions are in unique locations – areas of constraint on the network or on generation, where batteries can offer some grid support. Many of these are in South Australia; some in the rest of the NEM.

Additionally, batteries are being included in project planning as mitigation against future storage costs, penalties or other obligations that may occur under future legislation, regulation or market arrangement.

In smaller grids, solar intermittency can cause issues for the ramp rate, which offers batteries an opportunity – but these cases can also be addressed by other measures such as forecasting, constraint and control, or possibly a smaller battery.

A foreseeable future

What about the future? Batteries don’t generate energy – so, like network costs, batteries will need to be minimised to form an efficient grid. We think that the exceptions will increase, but still remain exceptions and tweaks to keep the network functional.

All of the many published studies of high renewable energy systems indicate that future grids will depend on a dynamic interplay between different generation types, strongly supported by interconnection for geographical distribution and strengthening. Batteries will be included strategically where required to provide grid support functions, and often this will mean co-location with a renewable generator. We’re definitely not going to see every renewable generator producing output on demand like a gas plant.

Taking a long term view, the future retirement of coal generators will inevitably produce a need for longer term storage or load shifting. Pumped hydro is a major contender here: projects such as Snowy 2.0 in NSW or Tasmania’s ‘Battery of the Nation’ can fill part of the requirement, supported by other smaller but targeted projects. While pumped hydro is being developed in readiness for or in sync with forthcoming retirements of coal-fired power stations, the market is also starting to see the need for more roll out of utility-scale batteries.

In this context, it’s often said that batteries will never serve the function of pumped hydro, but we should challenge this assumption. Large-scale battery deployment is conceivable with DC coupling of batteries with a solar plant (avoiding duplication of inverters). And the learning curve for battery prices coupled with higher efficiency and flexibility could within 10 years make such a solution competitive with pumped hydro for up to 4 to 6 hour storage (the timeframe in which load shifting will become important by then). Time and economics will tell.

Going behind the meter

We would be remiss not to mention grid-connected behind-the-meter batteries for domestic and commercial customers in this discussion. Even though the choice to install is not easily rationalised (and perhaps fuelled by non-cost-reflective customer pricing), significant numbers of customers are going ahead. This can act as an evolving distributed storage resource.

While smart grids have been touted as the means to utilise this storage resource, there is also the likelihood of a more organic utilisation because of the fine granularity of this storage. Opportunities are already emerging for market aggregators to utilise blockchain technology and the internet to extract the best value from these batteries at any given time. This trend may defer some of the requirement for large-scale storage for a limited period.

It is still early days…

A certain amount of caution is warranted as we move to embrace rapidly evolving battery technologies. Batteries are highly proprietary, so their functional nature, capabilities and controls can vary widely and are rarely transparent, and there is not yet a functional standard for their specification or operation. This creates a degree of risk, and calls for experienced guidance in specification, procurement and testing in particular.  This situation is evolving, but agreement and standardisation take much longer than technology development.

That’s not to say we shouldn’t be excited. Batteries offer extraordinary potential for enabling higher proportions of renewable generation in our energy future . There’s just still work to be done to help industry fully understand the technology and its applications, so we can be confident of getting the best out of batteries in a network context.

If you would like to find out more about how Entura can help support you with storage options for dispatchable renewables, please contact Patrick Pease or Chris Blanksby on +61 408 536 625.

About the author

Dr Chris Blanksby is a Specialist Renewable Energy Engineer 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, including over 20 MW of battery projects.  


Rethinking the role of hydropower in Australia

Although hydropower is older than wind and solar generation and battery storage, its role in Australia and around the world has never been more important.


Hydropower is still by far the largest contributor to the world’s total generation of renewable energy. The fact that this old technology is still very much alive today shows that hydropower can stand the test of time and help us meet the challenges of the future.

As the proportions of solar and wind generation rapidly rise, and as we see a gradual retirement of existing thermal generation and reduced construction of new thermal generation, the role for hydropower – both in Australia and internationally – continues to broaden and build.

New opportunities for hydropower

There’s no need to see rapidly emerging and increasing new technologies as a threat to hydropower. This isn’t a winner-takes-all environment. Rather, new opportunities are emerging for hydropower as an enabler of integrated renewable developments by providing the storage needed to smooth the intermittency of weather-dependent renewables – creating ‘dispatchable’ renewable energy.

In the last couple of years, particularly since blackouts in South Australia in 2016 and nationwide rises in electricity costs, debate about energy affordability, sustainability and reliability has become both mainstream and continuous. The pressure has never been greater to find the cheapest, cleanest power that is available whenever and wherever it is needed.


It is well known that traditional hydro schemes can provide baseload power or peaking power, grid stability services, and availability to fill in the gaps when intermittent renewables aren’t generating. However, the recent resurgence in interest in pumped hydro offers something extra: the ability to use excess available generation from wind and solar to pump water uphill into storage so that it can be used for electricity generation later – and this is why it can be described as a ‘battery’.

But how does pumped hydro compare with ‘actual’ batteries? Will rapid improvements in battery technology displace pumped hydro as a preferred storage solution? Technology is advancing very quickly in batteries, but I’m convinced that there are still some major differentiators that create space for pumped hydro.

One advantage is that we have a greater understanding of pumped hydro’s lifecycle costs and sustainability, whereas there are still a number of uncertainties in this respect for newer technologies such as batteries.

Also, critically, while batteries may be a good solution for low-power, short-term storage, they are not yet capable of providing the frequency and voltage regulation required by a grid with a high proportion of intermittent renewables. Batteries also typically cannot supply the significant level of output over a longer duration that pumped hydro energy storage or traditional hydropower can make possible.

Pumped hydro and modified traditional hydropower solutions will be needed for smoothing daily variability as wind and solar plants expand in number and size. And it is really only traditional hydropower with large reservoirs that will be able to provide the multi-day storage needed in extreme events of both low wind and low solar.

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.

If the future of both traditional hydropower and pumped hydro is strong, why have no new pumped hydro projects been built in Australia in thirty years? What is needed to not only get it going in Australia, but also to make sure we get it right?

I believe that three crucial elements to realising hydropower’s future and ‘getting pumped hydro right’ will be identifying the most viable sites, developing a sound business case, and ensuring that we invest in the skills and capacity we’re going to urgently need in the future.

Identifying the most viable sites

A critical element for pumped hydro success is identifying a viable project – where the right site and the best design can come together into an optimal mix of capacity and cost. Entura has done a lot of work in this area, and we have developed a methodology to filter the many hundreds of potential pumped hydro sites across Australia down to the most ideal.


This methodology has enabled us to develop a real-world, relevant and practical pumped hydro atlas of Australia identifying project opportunities from many thousands of theoretical possibilities.

Our atlas has already been used to shortlist potential pumped hydro sites for the Battery of the Nation initiative in Tasmania, and it identifies many more promising sites and opportunities for developers in states such as South Australia, New South Wales and Queensland. And the nation has room for many more batteries.

Building a robust business case

We’ve often said that a project won’t get over the line on the base of technical viability and environmental benefits – in the current market, the dollar wins. So pumped hydro needs some level of predictability in its revenue streams. As the dynamics of arbitrage change, we need to explore a range of other revenue opportunities. And that’s a complex forecasting challenge.

Part of the solution may be price insurance and a value placed on providing network support services and firming. Another part is behind-the-meter generation and integration – such as in the Kidston project, in which pumped hydro is coupled with a large-scale solar farm, and potentially wind generation, to form a renewable energy hub.

Investing in capacity development

To me, a third critical component is investing in talent, skills and capacity. This is a global issue as much as an Australian one. To prepare our industry to adapt to change as well as to drive further change in the sector we will need to harness talent and upskill and transition workforces.

This is the kind of strategic whole-of-business workforce planning that we encourage our clients to adopt, and it will be crucial over coming years and decades.

I am excited about the future of both traditional hydropower and pumped hydro. I firmly believe that if we value hydropower as a key player in the future mix of technologies in our energy markets, we can solve the energy trilemma at home and around the world.

About the author

Tammy Chu is Entura’s Managing Director. She leads Entura’s business strategy, performance and services to clients, and is part of Hydro Tasmania’s Leadership Group. Tammy joined the business in 2000 and has held a range of positions at Entura, from Technical Professional to Project Manager, Business Development Manager and Water and Environment Group Manager.

As a civil engineer, Tammy specialised in the design and construction of mini-hydro and hydropower systems, project management, hydropower investigations, prefeasibility and feasibility studies, environmental assessments and approvals, resource investigations and resource water management.

Tammy is a member of the Board of the International Hydropower Association. She was the first female and now past president of the Tasmanian Division of Engineers Australia, and was an Engineers Australia National Congress representative.    

Tammy holds a Master of Business and Administration from Chifley Business School, is a Fellow of Engineers Australia, and a graduate of the Australian Institute of Company Directors.


Hybrid renewables deliver sustainable, reliable power for Rottnest Island

Whether on-grid or off-grid, hybrid renewable energy systems offer exciting potential for achieving a sustainable and reliable power supply.


The specific drivers for each hybrid renewable development and the particular configuration of technologies will vary depending on the circumstance – yet, the common factor is applying supportive technologies to maximise the use of renewable energy and stabilise the resulting power system.

In many off-grid projects, the main goal may be to displace diesel generation. Renewables offer a free and often abundant fuel source with low or no emissions, but the challenge is ensuring these weather-dependent resources are available when needed.

The relative impact of the variable nature of renewable energy is greatest in off-grid applications. As the proportion of renewable energy increases, so does the need to carefully manage the wider power system by incorporating technologies such as batteries, flywheels, diesel generators, feeders and auxiliary systems to enable, control, integrate and support the variable renewable energy sources without compromising the security or reliability of the power system.

The Rottnest Island Water and Renewable Energy Nexus (WREN) project offers an inspiring example of how innovative deployment of hybrid renewables can increase the power supply security and sustainability of an off-grid island and drive water desalination.

A roadmap to renewables

Rottnest Island is a nature reserve and major tourist attraction about 20 kilometres off the West Australian coast, near Fremantle. This island’s management authority, residents and visitors have long desired a more sustainable way to power its needs, not only for electricity but also for water, while protecting its precious and delicate environmental values.

Until the late 1970s, diesel generation was the only source of electricity on the island – an expensive and not environmentally friendly option. Early-development wind turbines began limiting diesel use, but it wasn’t until 2004 that a 600 kilowatt wind-diesel hybrid system was installed – generating about a third of Rottnest’s energy and saving about 400 000 litres of diesel each year. 

That was a start, but there was still a long way to go towards a more sustainable, reliable and affordable power system. The WREN project was conceptualised by Hydro Tasmania and Entura after working with the Rottnest Island Authority to develop a roadmap for increasing energy efficiency and renewable energy. The roadmap presents a staged plan to increase the renewable energy contribution with times of 100% renewable supply in the future.

Designing the WREN

The WREN project integrates solar, wind and diesel, supported by a dynamic resistor, which smooths fluctuations in the availability of the renewable energy sources. The wind, solar and diesel generators are regulated by a hybrid power system controller that coordinates and dispatches the generation and demand-side management. It also manages the enabling technologies automatically to ensure reliable power and maximum savings of diesel fuel. But that’s not all. What makes the project a ‘water and energy nexus’ is that it incorporates management of the intensive power demands of the island’s water desalination plant.

The desalination plant is automatically controlled from the power station to operate when the renewables are abundant, rather than ‘wasting’ any excess renewable energy (available during sunny or windy periods when renewable generation exceeds customer needs). In effect, storing surplus renewable energy as water acts like a ‘water battery’.


The WREN project uses any available surplus renewable energy not only to run the desalination plant, but also to provide useful ancillary services, resulting in a higher quality and more reliable power supply. High power quality is maintained by quickly and accurately balancing supply and demand. Surplus energy is converted into fast-acting reserve within the dynamic resistor through rapidly loading and unloading the resistor elements. This means that the system can achieve and maintain a higher level of renewable penetration over a wider range of conditions. 

The dynamic resistor greatly improves the security of the system by supporting the low-load diesel engines to operate at a minimum loading of only 5%, compared with 30% for standard high-speed diesel generators. It does this by absorbing rapid increases in renewable generation that would otherwise result in a reverse power trip of the generators.

With the increased sophistication of the Rottnest power system, the existing equipment controllers were unable to effectively integrate control information, as that information couldn’t be provided at the required resolution or speed. The hybrid controller was able to integrate directly with industry-standard diesel controllers and newly installed power meters to overcome these issues.

Powering a sustainable energy future

The WREN project’s combination of managing demand and providing ancillary services via the dynamic resistor and other enabling technologies creates a cost-effective way of reducing reliance on diesel fuel without needing to rely on capital-intensive battery systems. The project required coordination of protection and control for a reliable, firm power supply.

The result of integrating all these technologies and measures is that Rottnest Island is now almost 45% powered by renewables, and up to 95% at times of high wind and solar generation. This means lower costs and less emissions, and a far more secure future for the island’s power and drinking water – which are critical to maintaining tourism.


The WREN project takes the tourist experience one important step further: educating tourists about power and water sustainability through digital educational materials that allow real-time interaction with the cutting-edge power/water system, delivered via mobile apps.

The success of the WREN project has obvious application for remote, off-grid or island communities worldwide – but the strength of the technologies and their integration and control are equally applicable to the creation of ‘dispatchable’ renewables at any scale.

If you would like to discuss how Entura can support your hybrid renewables journey, please contact Patrick Pease or Shekhar Prince on +61 412 402 110.

About the author

Seth Langford is a specialist renewable energy engineer at Entura and has been working in the renewable energy industry for more than ten years. Seth has been involved with major hybrid renewables and wind power projects as a technical specialist and a team leader for feasibility studies and due diligence projects in Australia, India, China, , Sri Lanka, South Africa and New Zealand.


Identifying Australia’s best sites for pumped hydro development

There are many thousands of potential sites for pumped hydro energy storage developments across Australia, but how can a developer filter these down to the best few?


As Australia’s energy market progressively transitions from ageing thermal generation to increasing amounts of wind and solar, there are ample chances to explore and develop the energy storage solutions needed to mitigate the challenges that may come with the introduction of more renewables into the energy market.

With increased intermittent renewables, we will require more storage to smooth out the variability of weather-dependent generation so that energy is available on demand. As well, we will need storage that provides the inertia, voltage and frequency control required for a stable, reliable grid.

The key to successfully embracing these energy storage opportunities will lie in identifying the right mix of technology, capacity and site; however, pinpointing potentially viable projects is complex. A theoretical or academic approach won’t be enough to ensure a future project’s success in the real world.

Pumped hydro is a highly efficient, longer-duration solution with a proven track record, and its future is bright as Australia seeks cost-effective, reliable options to make intermittent renewables ‘dispatchable’.

There are thousands of potential pumped hydro sites across Australia. This means that developers and investors need smart methods of filtering to reduce the many possibilities to just a few ideal sites.

A pumped hydro project is a major capital investment. Getting site selection right is the foundation for success, as it will determine the likelihood of achieving a design that is both technically and commercially feasible with the right mix of capacity and costs.

Pumped Hydro Atlas of Australia offers a head start in site selection

Entura has produced a practical atlas of pumped hydro energy storage opportunities to support development of dispatchable renewable energy generation across Australia’s National Electricity Market (NEM).

Through an exhaustive process, the atlas filtered many thousands of potential sites down to the best 20 around Australia. It is already being used by leading renewable energy company Hydro Tasmania to shortlist potential pumped hydro sites for the ‘Battery of the Nation’ initiative (a major Tasmanian initiative looking at how Tasmania could deliver more clean, reliable and cost competitive energy to Australia’s NEM). Identification of promising pumped hydro sites through the atlas also offers opportunities for developers in states such as South Australia and Queensland, which have set ambitious renewables targets and must maintain energy security.


Entura’s Pumped Hydro Atlas of Australia takes into account far more than the basics of identifying ideal topography and a source of water. It also accounts for other practical factors that can make or break a project: such as proximity to and location within the transmission network, land-use constraints and environmental risks, and the practicalities and costs of construction and ongoing operation. This makes it a real-world, relevant resource identifying the best sites for pumped storage projects across the NEM.

Developing the Pumped Hydro Atlas of Australia

Originally commissioned by Hydro Tasmania, the Pumped Hydro Atlas of Australia was completed in October 2017. The journey began with a literature review, appraising previous studies. This informed the development of a set of rules, assumptions and algorithms for a GIS-based study of different reservoir types and pairing mechanisms, which were tested on pilot sites.

Using these algorithms, more than 200 000 pairing reservoirs were identified across the NEM states (Queensland, New South Wales, Victoria, Tasmania, South Australia and the Australian Capital Territory). State-based heat maps of potential sites for pumped hydro development were prepared, along with a summary of all key characteristics for each pairing reservoir set, such as installed capacity, energy storage, distance from the nearest substation, gross head, approximate headloss in the waterways, and active reservoir volume.

A subsequent stage of refinement prioritised high-potential sites in some states. This process took into account greater practical detail, such as costings, practical engineering aspects, environmental approvals and risks, realistic high-level arrangements, proximity to other generators, and characteristics of hydrology and energy storage. This stage identified more than 5000 unique potential sites, which were then further refined with a set of rules to select the best pairing reservoir at each site. The approximately 5000 sites were reduced to approximately 500 of the most attractive options: those with an average head of more than 300 m with relatively short distances between the reservoirs.



This exhaustive refining process ultimately resulted in a shortlist of twenty promising sites across different states, with a desktop review of geology, high-level engineering arrangements, and approvals requirements. For each site a map was prepared including locality, land use, planning zones, and key characteristics of the potential pumped hydro project.

The Pumped Hydro Atlas of Australia is an example of how applied hydropower engineering can be used to create practical outputs, which are ready to be applied in the real world. Overlaying the outputs of this atlas with any new wind and solar development across the NEM could result in opportunities to invest in dispatchable renewable energy generation hubs capable of replacing thermal generation assets as they retire.

Pumped hydro energy storage will no doubt play a major role in the development and expansion of networks powered by renewable energy – in Australia and around the world. As Australia’s electricity mix evolves, so will the economics of storage. While forecasting revenue for storage projects in the Australian electricity market is still somewhat uncertain, there are many opportunities in both the existing and emerging markets to guarantee project revenues to a level sufficient to satisfy a lender’s requirements. The opportunity for investors seeking a head start in this emerging market is now.

If you would like to discuss how Entura can help you with your pumped hydro or renewable energy project, please contact Richard Herweynen on +61 429 705 127 or Phillip Ellerton on +61 439 010 172.



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.


Is there an economic case for pumped hydro?

As the proportion of renewable energy in the grid continues to grow, pumped hydro energy storage offers a solution for greater reliability. But can the business case for storage stack up?


The future is bright for pumped hydro in Australia, and for storage in general. However, no energy solution can exist outside of the real and competitive pressures of the market. Technical viability and environmental benefits won’t be enough to get projects over the line if they can’t demonstrate their financial soundness.  

So how can pumped hydro generate sufficient revenue to be attractive to investors? And will that revenue continue to be predictable enough over the longer term?  

No doubt there are opportunities, but developers may need to explore a range of different revenue sources in both existing and emerging markets since the arbitrage opportunities of the past may not be present in the future.

Where to for energy arbitrage?

The traditional revenue source for pumped hydro is arbitrage – in other words, making the most of generating when the spot price is high, and pumping when the spot price is low. But this relies on a certain level of predictable variability in the electricity market, and for that variability to continue into the future.

The upcoming retirement of several coal-fired power stations and the continued investment in renewables are likely to cement a market in which variability in power generation and the consequent volatility in energy prices are the norm.

Forecasting revenue – no easy task

Financing an energy project requires a firm revenue forecast. Lenders may consider ‘firm’ to be a 90% confidence limit, which means the developer must demonstrate that the project can generate a certain amount of revenue 90% of the time, or, say, in 9 out of 10 years. This means that a robust and reliable forecast of project utilisation must be made.

Forecasting revenue for an asset with a lifecycle of up to 100 years requires detailed modelling of a wide range of factors influencing the electricity market, including supply (factoring in new entrants, storage, retirements and developments in the thermal sector, etc.), demand (including changes in industrial load, impacts of electric vehicles, etc.), fuel prices, government policies, and bidding strategies for large-scale wind and solar projects.

A business case for pumped hydro relies on all the assumptions that go into regular power plant financial modelling and adds the complexity of arbitrage. 

A further complication is the impact on market prices of the presence of the developer’s own project. In other words, how will the proposed project influence the market in which it participates?

For a storage project, the influence is likely to be both an increase in low prices and a decrease in high prices. If the market is robust enough and the proposed project is relatively small, the influence could be minor. However, a very large project is likely to influence the market to such an extent that the utilisation of the project may significantly reduce, which would reduce project returns.

Building a bankable business case

How can the confidence in a forecast be increased enough for a lender to commit funding to a project, given that variance of any one of these assumptions could disrupt the revenue streams for the project?  While the transition to a renewables-dominated market continues, it may be that lenders need assurance that other revenue streams exist to reduce the project risk.

Price insurance

High price events in the electricity market will certainly continue to occur, but it’s impossible to predict their timing. Energy storage projects can provide insurance to exposed customers (such as retailers and major industrial customers) through a cap contract in a similar way to gas turbines and other peaking plant.  In practice, this may mean that the storage project rarely operates unless the price regularly exceeds the cap.

Network support services

Storage projects have the ability to provide network support services such as frequency control, inertia and fault level control. These services have increasing value in a grid with significant amounts of non-synchronous generation. At this stage, the markets for these network support services are very shallow and competition is increasing. However, the need for such services is likely to increase to the point where more significant markets are required.

Renewable firming

Government energy policy continues to be fluid, yet under the proposed National Energy Guarantee it is possible that there will be value in providing firming services – in other words, pairing ‘dispatchable’ generators (such as storage projects or open-cycle gas turbines) with ‘intermittent’ renewable sources of energy to improve reliability.

‘Behind the meter’ generation

Storage projects are exposed to market prices during both modes of operation (pumping/charging and generating).  If, however, there was an option to pump/charge for ‘free’, wouldn’t that reduce the risk?

Genex Power’s world-first Kidston ‘K2 Project’ will pair a 250 MW pumped hydro project with a 270 MW solar PV farm. During the day, solar energy can be used to power the pumps in the pumped storage project. The pumped hydro project will then generate into the evening (and morning) peak. If the upper storage is ‘charged’ during the day, the K2 solar project can generate into the Queensland market and realise the benefits of large-scale generation certificates (LGCs). Of course, this arrangement relies on sufficiently high prices during peaks to recover the additional cost of the solar farm, transmission losses and any LGC liability.

As our electricity mix evolves, so will the economics of storage. While forecasting revenue for storage projects in the Australian electricity market is still an uncertain business, there are many opportunities in both the existing and emerging markets to guarantee project revenues to a level sufficient to satisfy a lender’s requirements.

If you would like to discuss how Entura* can help you with your pumped hydro project, please contact Nick West on +61 408 952 315 or Donald Vaughan on +61 3 6245 4279.


*Entura provides technical advisory services to prospective investors and developers. Financial advisory is not part of our suite of services, however, we partner with financial advisory firms supporting our clients. Entura is the consulting arm of Hydro Tasmania. Hydro Tasmania is licensed (AFSL 279796) to provide general financial product advice.  Hydro Tasmania is not licensed to provide nor will it provide advice which considers a person’s objectives, financial situation and needs and you must therefore rely on your own assessment or seek your own independent advice in respect of decisions in relation to any financial product offered.

About the authors

Nick West is a civil engineer at Entura with more than 16 years of experience, primarily in hydraulics and hydropower. Nick’s skills range from the technical analysis of the layout of hydropower projects to the preparation of contractual project documents and computational hydraulic modelling. Nick was a key team member of the Kidston Pumped Storage Project Technical Feasibility Study.

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.


Batteries vs pumped hydro – are they sustainable?

A sustainable grid needs sustainable energy sources. While there’s no doubt that it makes sense to store renewable energy, whether in batteries or in a pumped hydro scheme, just how sustainable are these technologies?


As we move rapidly towards ever-greater levels of wind and solar power in the network, increasing quantities of storage are needed to smooth intermittency and ensure secure supply. Pumped hydro energy storage and batteries are likely to do much of the heavy lifting in storing renewable energy and dispatching it when power demand exceeds availability or when the price is right.

We’ve previously compared the two technologies in terms of their costs, the speed with which they can be deployed, and their ability to support the grid. Here we compare their sustainability in terms of storage efficiency and capacity, safety, use of scarce resources, and impacts through all stages of their lifecycle.

Storage efficiency and capacity

For both batteries and pumped hydro, some electricity is lost when charging and discharging the stored energy. The round-trip efficiency of both technologies is usually around 75% to 80%. This level of efficiency for either technology represents a significant displacement of non-renewable generation if we assume that the stored generation would not otherwise occur.

A particular consideration for batteries is degradation. Batteries degrade as they age, which decreases the amount they can store. The expected life of the batteries that will be used for the recently announced battery storage project in South Australia is about 15 years (depending on how the batteries are operated). By the end of that time, the capacity of the batteries is expected to have dropped to less than 70% of their original capacity.

To maintain a reliable and steady capacity for storage as batteries age and degrade, large-scale battery plants will require ongoing staged installation and replacement of batteries. In comparison, the degradation of pumped storage is close to zero. With appropriate maintenance, peak output can be sustained indefinitely.


No storage solution can be considered sustainable unless it is safe. The greatest risk relating to pumped storage is dam safety. If it occurs, dam failure can affect downstream communities and the environment, with its impact potential likely to be far greater than a battery safety incident. Nevertheless, pumped hydro technology is mature, dam risks are generally well understood and managed, and the frequency of dam safety events is low.

The main safety concern for batteries is thermal runaway leading to explosions and fires. The severity of this risk will depend on how a battery project is implemented. In a modular arrangement, thermal runaway would be localised, not affecting the whole bank. However, because of the very rapid deployment of evolving battery technologies, safety standards may not be rigorously enforced.

Impacts on land and water

Pumped hydro and grid-scale battery plants may have environmental and land-use impacts. These impacts would vary depending on the sensitivity of the site selected.

A grid-scale battery facility needs a relatively small parcel of land and is likely to be able to be created very close to the energy demand or where generation occurs. Land in these areas has often already been disturbed and the new operations may have little extra environmental impact. Land and water impacts of batteries relate more to their disposal at the end of their effective life, and to the extraction of the resources to produce new batteries.  


Pumped hydro requires a relatively larger parcel of land with a very particular topography, and may be far from the location of the demand. Any potential environmental impacts associated with construction and operation need to be considered and mitigated, including those immediately associated with the site, as well as downstream.

In most construction of new pumped hydro, sites are selected where impacts can be mitigated to acceptable levels, for example by using existing reservoirs, or locating ‘closed loop’ systems away from rivers. Although these arrangements will have lower overall impacts, some environmental challenges may still occur during construction when existing water is removed from the site as well as finding a source of water without impacting the environment and other users.

Environmental impacts during operation of pumped hydro are minimal.  However, the ecology within the reservoirs will need to adapt to frequently changing water levels, reducing diversity in the system especially within fringing communities.

In all pumped hydro systems, water is re-used over and over again, extracting maximum value from the resource. Nevertheless, depending on the configuration of the pumped hydro project, there may be an ongoing demand for water to top up the storages to counter evaporation.

Minerals and materials

Batteries and pumped hydro require a range of different resources and materials. Lithium-ion batteries use common materials such as plastic and steel as well as chemicals and minerals such as lithium, graphite, nickel and cobalt. Although pumped hydro mainly relies on common building materials such as concrete and steel, the quantities of these materials and the construction impacts can be significant.

Image courtesy of Greensmith, a Wärtsilä Energy Solutions company.

Image courtesy of Greensmith, a Wärtsilä Energy Solutions company.

Determining the ultimate sustainability of the required resources and materials for both technologies needs to take account of the full lifecycle and supply chain (mining, processing, refining and manufacturing) as well as end-of-life issues such as recycling, disposal or decommissioning.

Currently, the environmental and health impacts of mining are a significant sustainability concern for the battery industry, and impacts are likely to intensify as worldwide demand for the necessary minerals rapidly increases. Short-term availability of many of the necessary minerals for battery development, such as lithium, appears sufficient, yet security of supply could be compromised by geo-political factors, and long-term availability will depend on levels of demand.

Ultimately, the minerals used in lithium-ion batteries are finite resources, so limiting or reducing their extraction (for example, through greater recycling or substitution for another battery technology) would increase longer term sustainability.

End of life

A battery’s life depends on the technology and on frequency of charging and discharging. Once their effective life is up, the batteries must be disposed of and replaced. Disposal of batteries is a problem we’re yet to face, but as large-scale battery storage proliferates, increasing numbers of batteries will enter the global waste stream. Without careful management of disposal, what cannot be recycled may end up in landfill and may be corrosive, flammable, or could leach toxins into soil and water.

The development of cost-effective and efficient battery recycling methods is still in its infancy.

Although most of the components of batteries can be recycled to some extent, recycling is currently expensive and there is insufficient volume to encourage commercial enterprises to take on recycling the new generation of batteries. In time, improved recovery and re-use of materials will certainly increase the sustainability of battery storage, preserving virgin resources and reducing the impacts of extraction and processing.

End-of-life considerations for pumped hydro seem very distant right now due to hydropower’s longevity, but sustainable decommissioning still needs to be planned for, including managing the impacts on the downstream environment if a dam is removed and rehabilitating the reservoir area.

Lifecycle analysis

At this early stage of development of large-scale battery technology, comprehensive lifecycle analysis is limited by the diversity of battery materials and widely different scenarios of charging, battery life and recycling.

In contrast, the full lifecycle of pumped hydro is better understood due to the maturity of the technology. Pumped hydro is not without impacts, but the risks are known and generally manageable. A major advantage of pumped hydro over batteries is that the expected life of pumped hydro is more than 100 years, or effectively unlimited with appropriate maintenance.

Batteries may have a lower upfront cost than pumped hydro and be easier to approve and install; however, they are likely to require greater management over time. If a projection is made based on current information, the full lifecycle cost and impact of batteries may be greater than hydro across the long term, particularly when mining, recycling and disposal are taken into account. Yet, battery technology is likely to improve very rapidly, which would tighten the gap on pumped hydro’s current lifecycle advantage.

A greener grid

Worldwide, increased levels of renewable energy will lead to a greener grid. It is easy to recognise the sustainability benefits of using a storage solution such as pumped hydro or batteries to further enable the decarbonisation of the network through greater uptake of renewable energy. However, the storage solutions that enable more renewables must also be sustainable – not only in the use phase, but also upstream and downstream.

It is difficult to make a straightforward comparison of the sustainability credentials of pumped hydro and battery storage technologies at their very different stages of maturity. As battery technology is still evolving, its overall sustainability is still somewhat uncertain, but this will change with experience and improvements in battery life and recycling. Meanwhile, pumped hydro projects can last up to a century and associated risks are known and can be mitigated.

Either way, as we redevelop the electricity grid, we will also need a mature approach to lifecycle analysis of our storage solutions.

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.

Nick West is a civil engineer at Entura with 16 years of experience, primarily in hydraulics and hydropower. Nick’s skills range from the technical analysis of the layout of hydropower projects to the preparation of contractual project documents and computational hydraulic modelling. Nick was a key team member of the Kidston Pumped Storage Project Technical Feasibility Study.  


Batteries vs pumped hydro – a place for both?

Two very different storage technologies – one old, one new; one that takes years to build, one that can be built ‘within 100 days (or it’s free)’. How else do they differ, and is there a place for both?

The rapid growth of renewable energy generation has been driven by two concurrent factors: the falling levelised cost of the energy produced by wind and solar, and the retirement of a number of coal-fired power stations. The recently released Finkel Review notes that by 2035, approximately 68 per cent of the current fleet of Australian coal generating plants will have reached 50 years of age.

The Clean Energy Target proposed by Dr Finkel is not yet confirmed but it recommends incentives for technologies with low or zero carbon emissions. More renewable energy generation brings new challenges in an increasingly complex grid. Dr Finkel therefore also proposes that energy storage be mandated for solar and wind farms.

Renewables can’t, on their own, meet the fluctuations in demand that occur throughout the day without some regulation as to when power reaches the grid. Power needs to be dispatchable. Dispatchable means that energy can be provided upon request. If the sun is not shining or the wind is not blowing, renewable energy cannot be dispatched unless it has been stored in some way.

There are a number of different types of storage but the two being discussed most widely right now are batteries and pumped hydro energy storage. These two technologies are very different and there are some limitations involved in comparing a well-known and established technology with one that is new and developing rapidly.

How do they support the network?

Pumped hydro is based on well-established synchronous generation, providing critical ancillary services to the grid, through the provision of inertia, frequency and voltage support and sufficient fault level support.


Battery inverter technologies are still catching up on most of these fronts. The potential for batteries to provide ‘synthetic inertia’ or fast frequency response is high but this is balanced by their reliance on system strength to be able to deliver this support. They offer minimal support with fault levels but can still provide some support to system frequency and voltage regulation.

How fast can they happen?

There’s no doubt that battery storage is quicker to implement than pumped hydro. South Australia has provided an example of just how quickly battery storage can be deployed.

In March 2017, the South Australian Government called for expressions of interest for the supply of grid-connected battery storage to be connected by the end of 2017. The overwhelming response from 90 interested parties tells us that this speed of deployment is within the realms of possibility.

Battery image courtesy of Greensmith, a Wärtsilä Energy Solutions company.

Battery image courtesy of Greensmith, a Wärtsilä Energy Solutions company.

Pumped hydro, by comparison, is a technology that takes much longer to implement. Typically, development activities (including optimising the technical solution, environmental and social assessments, arranging finance and finalising design) take two years or more to complete, and construction takes another two to three years.

How do the capital costs compare?

Pumped hydro boasts a very low price per megawatt hour, ranging from about $200/MWh to $260/MWh. Currently, battery costs range from $350/MWh to nearly $1000/MWh, with this cost reducing rapidly (costs reduced by about 25% during 2016).

According to the Lazard’s Levelized Cost Of Storage report, capital costs for pumped storage projects around the world range from about $1.5 million to $2.5 million per MW installed. The report also reveals that the cost of installing a grid-scale battery solution ranges from about $3.5 million to $7.5 million. This wide range of pricing for batteries is typical of a developing technology that is implemented in a variety of applications.

Ultimately, it’s difficult to predict how low the cost of batteries may go, but reports predict costs of lithium-ion batteries at somewhere around $120/MWh by 2025.

Considering that batteries need to be replaced once or twice a decade, with the currently available technologies, a battery facility will need to be replaced a number of times during the potential 100-year life of a pumped storage project. For batteries, assuming an economic life of 40 years, the initial cost plus replacements may mean whole-of-life costs fall in the range of $200/MWh to $330/MWh.

So, what does the future hold?

The rise of renewables will inevitably lead to a diversity of storage and supply solutions. The range of these solutions will depend on the resources of particular regions and locations. It is highly likely that the future for both batteries and pumped storage technologies will be extremely bright.

Batteries are here to stay and will undoubtedly play a significant role in future power systems as the technology develops and costs fall. However, while batteries can provide fast response times, they are yet to demonstrate their ability to provide the full range of ancillary services needed to support the grid. Pumped hydro remains a landmark, proven and reliable technology, able to meet the needs of the grid and provide sustained output for up to a century.

Ultimately, there is room for both batteries and pumped storage hydro, and they may even complement each other. Batteries are more cost-effective at delivering small amounts of stored energy over a short time at high power levels. Pumped storage is more cost-effective at storing and releasing larger amounts of stored energy. Achieving the optimum storage solution will depend on careful planning and finding the best fit for the particular circumstances.

What is certain is that both technologies will play important roles in the development and expansion of a network powered by renewable energy.

If you would like to discuss how Entura can help you with your next utility-scale battery or pumped hydro project, please contact Donald Vaughan on +61 3 6245 4279 or  Nick West on +61 408 952 315.

A version of this article was first published in RenewEconomy.

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.

Nick West is a civil engineer at Entura with 16 years of experience, primarily in hydraulics and hydropower. Nick’s skills range from the technical analysis of the layout of hydropower projects to the preparation of contractual project documents and computational hydraulic modelling. Nick was a key team member of the Kidston Pumped Storage Project Technical Feasibility Study.  


Overcoming the barriers to pumped storage hydropower

With energy reliability a hot topic in Australia, eyes are now turning to pumped storage hydropower… but what has been holding it back?


There are only three pumped storage hydropower projects in Australia, with the most recent completed more than thirty years ago. This is despite the ability of pumped storage hydropower projects to provide the large-scale storage that would complement increasing levels of renewable energy. Why is this, and what are the barriers to developing more Australian pumped storage hydropower projects?

Around the world, pumped storage hydropower projects make up the vast majority of grid energy storage and have traditionally been used by energy utilities to supply additional power to a grid during times of highest demand.

As part of a portfolio of power stations, a utility might operate a pumped storage project infrequently only, if the cost of pumping the water back to the upper storage exceeds the revenue that can be generated from its release.

The main issue facing developers trying to prove the viability of a new pumped storage project is that a sufficient price differential is required to pay for the pumping and to account for the efficiency losses in transmission, pumping and generation. The generation price needs to be sufficiently higher than the pumping price just to repay the variable pumping costs. To repay the heavy capital investment, a margin is required over and above the break-even cost of pumping. This is particularly true where proposed developments are ‘stand-alone’ and cannot be optimised as part of a corporate generation portfolio.

In recent years, electricity price spikes have been irregular with few occurrences each year. Due to the significant capital costs, a pumped storage scheme would require a certain number of pumping/generation cycles at high or maximum pricing to pay a return on investment. These price spikes are unpredictable, so building a business case around these events is risky.

Historically, the daily fluctuation of power prices has not been sufficient or regular enough to attract pumped storage developers. This is beginning to change with increasing penetration of renewable energy leading to an increase in both low and high price periods. More frequent, sustained periods of hot weather (as predicted by climate change models) will also drive up demand for power and therefore the market price.

In the last few months, volatility has greatly increased, creating a greater differential between baseload and peak pricing. This will increase the viability of pumped storage schemes, although the unpredictability and challenges of financing capital intensive assets will remain.

But, even when the economics are right, there are still some other barriers that proponents of pumped storage projects need to overcome:

Finding the right site

Pumped storage projects require significant capital for development. Minimising the cost of construction and operation is key to the successful development of a project. Choosing the right location is a matter of identifying a site with ideal topography, a source of water and good proximity to and location within the transmission network.

A wealth of information is available that is relevant to identifying potential pumped storage hydropower sites. Concept studies for pumped storage hydropower sites can screen potential sites quickly and offer developers greater insight into possible opportunities.

Negotiating access to appropriate sites for pumped storage

While a pumped storage project generally has a significantly smaller footprint than a traditional hydropower project, the features of natural topography that are ideal for pumped storage – high, steep hillsides or cliffs – tend also to be places of great natural beauty and are often designated as reserves, are expensive private land, or have high environmental or social value.

State governments can assist here through streamlined planning and approvals processes for infrastructure developments. This can make sure that the challenges of developing sites do not become insurmountable for developers.

Perceived environmental impacts

Pumped storage projects can occupy many square kilometres and also require transmission lines to connect to the electricity market. Like traditional hydropower projects, pumped storage projects need to attend to environmental issues associated with the project. Environmental impacts for pumped storage projects are assessed in the same manner as for all infrastructure developments.

If the impacts of a project can be mitigated to the satisfaction of the relevant regulatory body and international Standards (such as the International Hydropower Association and International Finance Corporation), a pumped storage hydropower project should face no greater hurdle than any other infrastructure project in this respect.

A pumped storage project may also have to deal with the perception that it uses carbon-intensive thermal power to pump water during the pumping cycle. This may be true unless there is a surplus of renewable energy available, in which case the pumped storage project could be seen to be using this excess renewable energy for pumping. As renewable energy penetration grows, the opportunities for storing surplus renewable energy will increase.

An unfavourable regulatory framework

Inconsistent and uncertain policy positions of the major political parties at both federal and state levels reduce confidence in the energy industry, which deters investment. With debate raging over energy security, a bipartisan view on energy policy, which transcends party politics and the electoral cycle, is urgently needed.

Existing mechanisms are in place to support the renewable energy industry. The Renewable Energy Target (RET) promotes investment in renewable energy projects; however, pumped storage is specifically excluded from the RET where the energy used for pumping exceeds the energy generated. Current policy would have to be amended or complementary legislation enacted in order to reward large-scale storage for the service it provides.

Such changes could include market mechanisms for large-scale storage that could offer incentives for providing inertia and ancillary services from storage at times of peak demand as well as power. Another possible change could be to ensure that large-scale storage asset owners are not penalised under the RET for energy used in the pumping process. This would encourage the development of energy storage as a complement to the growth of renewable energy.

High cost of development activities

The long lead times and high development costs of pumped storage projects are major deterrents to developers. Projects generally take more than 4 to 5 years from the point of conception to ‘power on’, and require millions of dollars of capital for development and hundreds of millions for construction. In other words, when funding is first committed, it may not see a return for five years or more.

In an effort to overcome this barrier, the Australian Renewable Energy Agency (ARENA) has indicated it will allocate at least $20 million to finance the accelerated development of flexible capacity and large-scale storage projects. The Clean Energy Finance Corporation (CEFC) has also committed to provide successful ARENA funding recipients with the opportunity to secure long-term debt finance to support their projects.

With an increasing interest and emphasis on storage in a power system that is becoming increasingly unreliable (e.g. load shedding in South Australia and lack of reserve events in New South Wales), and with finance from ARENA and CEFC for large-scale storage, the barriers to pumped storage development are gradually diminishing. This action can’t come soon enough for residents suffering through blackouts on days over 40°C.

If you would like to discuss how Entura can help you overcome the barriers for a pumped storage hydropower project, please contact Patrick PeaseNick West on +61 408 952 315, or Richard Herweynen on +61 3 6245 4130.

A version of this article has been previously published as an op-ed in the Adelaide Advertiser.

About the authors

Nick West is a civil engineer at Entura with 16 years of experience, primarily in hydraulics and hydropower. Nick’s skills range from the technical analysis of the layout of hydropower projects to the preparation of contractual project documents and computational hydraulic modelling. Nick was a key team member of the Kidston Pumped Storage Project Technical Feasibility Study and was involved throughout the development and construction of the Neusberg Hydroelectric Project in South Africa. Nick has successfully completed projects ranging from hydraulic design for small residential developments to the feasibility study of a cascade of four large hydroelectric projects in Malaysia.

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.


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


Is pumped storage hydro the key to increasing renewables in Australia?

Recent electricity price spikes and a state-wide blackout in South Australia have highlighted the need for reliable power to balance the potential volatility of some renewable power sources.


Pumped storage hydropower projects are a natural fit in an energy market with high penetration of renewable energy as they help to maximise the use of the renewables that are subject to the vagaries of the weather. Pumped storage provides a load when the wind is blowing and the sun is shining, and it also provides a reliable and immediate source of energy when the sun has set and the wind has dropped.

The recent completion of the feasibility study for Genex Power’s Kidston Pumped Storage Hydro Project in North Queensland shows this approach is now technically and commercially feasible.

Pumped storage hydro offers utility-scale storage and system stability

As the proportion of renewable energy in an energy market increases, the need grows for the stability and consistency provided by utility-scale energy storage. For example, South Australia needs system-wide storage of 500 MW for a period of 10 hours to improve the flexibility of wind farm operators, according to the Melbourne Energy Institute.

At the smaller scale of energy storage, the buzz about various types of batteries continues – but the only storage option with a proven track record at the utility scale is pumped storage hydropower.

Pumped storage hydropower works by pumping the water stored in a lower reservoir into a more elevated reservoir. The water stored at height can be passed through a turbine on its path back to the lower reservoir, creating electricity as and when needed, and making the best use of the water resource without waste.


Click image to view infographic.

In a recent article, my colleague Donald Vaughan stated that a functioning AC power system needs inertia, fault level, frequency and voltage control as well as energy sources to function to an acceptable standard. Pumped-storage assets can provide all of these important contributions to a stable and successful power system, levelling out the fluctuations in availability of wind and solar energy, and helping to regulate voltage and frequency.

New opportunities for pumped storage hydro in Australia

Despite the significant potential and benefits of pumped storage hydro projects, only three projects currently exist in Australia (two in New South Wales and one in Queensland). These schemes were built in markets in which generation was mainly thermal, where the pumped storage could supplement supply at times of peak demand.

A number of possible sites have been identified for new opportunities for pumped storage hydro, but so far very few have been developed beyond concept level. This means that opportunities exist for developers in states such as South Australia and Queensland that have set ambitious renewables targets and must maintain energy security.

Three factors for pumped storage hydro success

For successful pumped storage hydro projects, developers need to identify a viable site, achieve a technically and commercially feasible design, and make the most of the economics of the energy market.

1 – Identifying a viable site

For a pumped storage project, what’s needed is a source of water, and two reservoirs separated by a significant change in elevation. The water could come from a nearby river, an existing reservoir, or the sea. With many thousands of potential sites across the country, a developer needs smart methods of filtering to reduce the many possibilities to just a few ideal sites.  

An important consideration is the effect on the viability of pumped storage projects of the relative remoteness of sites, through both the efficiency of the power’s round trip and the marginal loss factors (factors applied to a generator or a load, and calculated based on the size and distance of the generator or load from a central point).  

As for any development, the process of identifying sites must also consider topography, land use and environmental constraints. Pumped storage projects generally present similar but reduced environmental risks as conventional hydropower projects as they tend to have smaller footprints.

2 – Achieving a technically and commercially feasible design

Entura’s experience on Genex Power’s Kidston pumped storage hydro project has shown that it is possible to construct low-cost pumped storage projects in Australia through careful site identification and clever project design. Where a pair of suitable reservoirs don’t already exist, constructing a turkey’s nest dam may offer a solution.

A turkey’s nest dam is a reservoir built by excavating earth from the centre of the reservoir and moving it to the edge to help form a continuous embankment. Turkey’s nest dams have been used successfully around the world in pumped storage hydropower projects, providing opportunities to build projects where elevation changes significantly over a short distance.

Additionally, turkey’s nest dams can help to minimise capital costs by reducing conduit lengths and maximising head (the difference in elevation between the upper and lower reservoirs).

3 – Making the most of the economics of the energy market

Understanding the opportunities and constraints in the energy market is critical to a pumped storage project’s financial viability.

When you can store energy, you can dispatch electricity at peak times, gaining the highest price point in the market. Conversely, water is pumped to the upper reservoir in off-peak periods or when supply from renewable sources is high and market prices are low. This ‘energy arbitrage’ makes the most of the price difference in the electricity market.

Selecting the optimum installed capacity of a pumped storage project also requires detailed understanding of energy markets. It is possible that a pumped storage project can act to flatten peak prices to the point where the returns on a project are insufficient to meet financiers’ hurdles, so detailed revenue modelling is essential to determine the tipping point between enough and too much installed capacity.

With careful selection of sites, clever design, and the right mix of capacity and costs, pumped storage hydro holds an important key to unlocking the full potential of renewables in Australia’s electricity market.

If you would like to discuss how Entura can help you explore potential opportunities for pumped storage hydropower projects, please contact Nick West on +61 408 952 315 or Richard Herweynen on +61 3 6245 4130.

About the author

Nick West is a civil engineer at Entura with 15 years’ experience, primarily in hydraulics and hydropower. Nick’s skills range from the technical analysis of the layout of hydropower projects to the preparation of contractual project documents and computational hydraulic modelling. Nick was a key team member of the Kidston Pumped Storage Project Technical Feasibility Study and was involved throughout the recently completed Neusberg Hydroelectric Project in South Africa. Nick has successfully completed projects ranging from hydraulic design for small residential developments to the feasibility study of a cascade of four large hydroelectric projects in Malaysia.