Addressing the risks of pumped storage hydropower for a net zero world

As the world transitions to renewable energy and away from fossil fuels, solutions for energy storage to absorb the production excesses and deliver energy when demand exceeds supply will be in high demand. Pumped storage is among a series of options but there are a few risk factors that need to be considered when investing in this technology.

Supply of electrical power to the grid needs to reflect demand fluctuations either from a matching variation in generation or through the use of storage as a buffer.

In a traditional fossil or nuclear electricity network, nuclear and coal power stations operate continuously with little variation in output. Fluctuating demand is typically matched by gas turbines or hydroelectric power stations.

Sunshine, wind speeds, tides and waves generating renewable energy cannot be controlled to follow demand fluctuations. To increase the share of renewable energy in the power mix will require efficient storage options as hydroelectric power stations alone won’t be able to absorb the fluctuations.

Pumped storage hydropower can be part of the solution. It consists of two water reservoirs at different elevations that can generate power as water moves down from one to the other (discharge), passing through a turbine. When demand is lower than supply, power can be used to pump water back into the upper reservoir (recharge). Pumped storage hydropower therefore can act similarly to a giant battery, storing power and releasing it when needed but it is much cheaper for large-scale energy storage (overnight or several days) than batteries. The technology also has a much longer technical lifetime (50–100 years). Unsurprisingly, pumped hydro energy storage comprises the vast majority of global storage power capacity and global storage energy volume.

Pumped storage hydropower can work with an existing hydro power dam that’s enhanced with an option to pump back water when power costs are low for example from a river or as a closed loop off-river pumped hydro system where water is cycled repeatedly between two closely spaced small reservoirs located away from a river. Planning and approvals are generally easier, quicker, and lower cost for an off-river system compared with a river-based system. Large-scale storage is needed sooner in regions where solar and wind penetration is higher and where there are weak or absent transmission links to neighbouring regions or countries.

Advantages of pumped storage hydropower

  • High volatility between on-peak/off-peak electricity prices drives energy arbitrage opportunities

  • Pumped storage is often considered the only proven grid-scale energy storage technology

  • A strong push for “carbon free generation” creates immense demand for energy storage products

  • Potential incentives for energy storage, including capacity payments and reduction of transmission interconnection fees

  • A comparably cheap solution for large-scale energy storage

Despite of the advantages of the pumped storage hydropower has over batteries, an investment into this technology does carry some risks, not least because the relatively long licensing and construction process.

Risks related to a project may include:

  • Obtaining project licence to construction can take several years

  • Construction can take three to five years for large projects, incorporating renewable energy integration can add several years

  • Financial institutions may hesitate to finance such long-lead projects

  • Construction costs and viability depend on local geology, geography and hydrology, road access and distances for transmission, land ownership, indigenous rights, environmental impacts or social opposition

  • Changing energy policy

  • Potential changes in market rules and product definitions may impact the value of energy storage systems and deter investors seeking revenue certainty

  • Uncertain revenues need conservative cost calculation

  • Potentially unclear regulation defining ownership structures and flexible business models incorporating both energy generation and consumption

  • Heavy civil infrastructure risk – A high proportion of construction costs (typically 30-60%) will go towards the civil works. Civil works will include the construction of major structures such as dams, significant tunnelling, and excavation (e.g., for temporary river flow diversion during construction or for penstock tunnels) and temporary works such as coffer dams to protect the construction area from water flow

  • Requires heavy tunnelling and underground structures – The method of tunnel construction depends on such factors as the ground conditions, the ground water conditions, the length and diameter of the tunnel drive, the depth of the tunnel, the logistics of supporting the tunnel excavation, the final use and shape of the tunnel and appropriate risk management

  • Unknown ground conditions – It's important to understand how the ground conditions may affect the works (in terms of cost/time) and which were not known or anticipated when the contract was entered into

Financings will not close until all risks have been catalogued and covered. With the advent of environmental, social, and governance (ESG), the environmental aspect is likely to require more attention and communication capabilities to address potential concerns from stakeholders.

Environmental concerns:

  • Dams alter the ecology systems

  • River may need to be diverted during construction

  • Risk of major flooding during construction or subsequently

  • During droughts, the water supply might be needed elsewhere

  • Flooding the land within reservoirs

  • Construction of roads, pipes or tunnels for water conveyance, a powerhouse and switchyard, and high voltage transmission lines.

Investors and developers should work directly with the environmental community to reduce or mitigate the environmental impact. Locating the reservoirs in areas that are physically separated from existing river systems can lower the impact on existing river systems. Clearly splitting responsibilities and liabilities among all stakeholders from the outset through a contract should be a priority. To ease the financing pressure and the risk of the project, developers and investors should pursue long-term storage agreements with energy transmission.

Modernising existing infrastructure

Although there is much attention given to new hydropower development, there is also an increasing need to modernise and optimise the current assets to ensure hydropower’s vital role in energy systems is sustained and enhanced. Hydropower has an aging fleet, with nearly half of its global capacity more than 30 years old (600 GW) and about one-third older than 40 years old (400 GW).

By 2030, over one-third of the existing capacity will have undergone, or be due for, modernisation. This rises to 50 per cent when excluding China.

The need for modernisation is important as the performance and reliability of components are reduced as stations age, impacting output, revenue and safety. Modernisation programmes from repairing and replacing components to implementing innovative technologies are required to extend the lifespan of stations and maintain or even increase their output. There is also an opportunity to use modernisation to deliver additional co-benefits such as providing greater flexibility services to support higher penetrations of variable renewables, addressing environmental and social legacy issues, and building climate resilience to address more frequent droughts and flood events.

Although Pumped Storage Hydro technology has been around for many years, it is still evolving as it integrates innovative concepts being deployed across the infrastructure spectrum. This is a rich innovation space, and many new Pumped Storage Hydro concepts and technologies are being proposed or actively researched. These can include both modifications and improvements of current technologies, as well as some concepts that are very different from traditional Pumped Storage Hydro plants. These proposed Pumped Storage Hydro technologies can support various aspects of power grid operations, from bulk power generation and transmission to distribution systems.


In 2009, a turbine in the hydroelectric power station in Russia failed catastrophically, killing 75 people and severely damaging the plant. The turbine hall was flooded, and a section of its roof collapsed. All but one of the ten turbines in the hall were destroyed or damaged. The entire power output of the plant, totalling 6,400 megawatts, was lost, leading to widespread power outages in the area.

This was primarily caused by the turbine vibrations which led to the fatigue damage of the mountings of turbine 2, including the cover of the turbine. It was also found that at the moment of the accident at least six nuts were missing from the bolts securing the turbine cover. After the accident 49 recovered bolts were investigated, of which 41 had fatigue cracks.

Damage caused by the incident:

  • Turbine 6: Flooded

  • Turbine 5: Flooding and electrical damage

  • Turbines 3 and 4: Moderate electrical and mechanical damage / some damage to the concrete structures around them

  • Turbines 1, 8, and 10: Severe electrical and mechanical damage / some damage to the concrete structures around them

  • Turbines 7 and 9: Destroyed, with extreme damage to the concrete structures around them

  • Turbine 2: Destroyed completely, including the concrete structures around it

For further information, please visit our Energy and Power page (opens a new window), or contact:

Robert Wilson – Senior Vice President Lockton Global Energy & Power


Mark Lockyer – Senior Broker


Michael Bogdan – Partner Global Energy


Stephanie Baker Dean – Client Executive


This is part of a series of articles to be published on about the energy transition to renewables. Subscribe to the Lockton Insight Newsletter here (opens a new window) and look for our next instalment.