PSH and BESS: hybrid storage, not either/or

Janice Goodenough does not hesitate when asked about the future relationship between pumped storage hydropower (PSH) and battery energy storage systems (BESS). For her, the idea that the two technologies are competing for the same role, or even comparable, is not only misguided but also risks undermining the stability of the future power system.

“The two technologies complement each other well,” she says. “Batteries provide super-fast response, but they don’t typically have a lot of storage capacity. Hydropower is a completely different order of magnitude in both lifetime and long-duration storage potential.”

Goodenough is the CEO of HYDROGRID, a company delivering digital production planning and optimisation software for hydropower plants in 15 countries across four continents. Her perspective is shaped by both the physical realities of these assets and the rapidly shifting operational environment they must navigate. On one side of the storage spectrum sits pumped storage hydropower, capable of storing vast amounts of energy for days, weeks or even months. On the other sit batteries, engineered for sub-second response, intra-day balancing and participation in increasingly granular reserve markets.

She argues that the pitfall of comparing the two directly – GW to GW – creates a distorted picture, in which battery capacity could soon “catch up” with hydropower. But that picture changes quickly when comparing storage volume, i.e., GWh to GWh, where hydropower will continue to “dwarve” batteries for decades to come. However, the grid needs both fast response and deep endurance: “What we need is a stacked system,” she says. “Short-duration storage layered on top of long-duration storage.” In that layered model, each technology strengthens the other and aligns with the current grid cost mechanisms.

While this hybrid configuration fits well into current power market dynamics, Goodenough sees a widening gap between what the energy system requires and what current markets reward. Policy frameworks overwhelmingly favour technologies that operate on short timescales. Long-duration storage, which ensures resilience during multi-day renewable droughts, receives almost no differentiated value. “If the market doesn’t incentivise long-duration energy storage, it will eventually go away,” she warns. “And by the time it goes away, it will be too late to react.” She refers to the inherent lifecycle of hydro investment, in which today’s decisions will bring consequences in 2035 and beyond.

What follows is a detailed journey through that warning. Goodenough explains why duration matters, how hybrid operation works in practice, why digitalisation is essential, and what must change for storage to support the next phase of the renewable transition.

Complementary by design: why hydro and batteries serve different roles

When asked how the hydropower sector should think about battery storage, Goodenough identifies three factors driving complementarity. The first is deployability. Hydropower remains largely centralised because it requires specific geography. Batteries, on the other hand, “can be deployed decentralised,” enabling flexibility where hydropower cannot physically exist.

The second factor is response time. Batteries can react in milliseconds, offering ultra-fast balancing. Hydropower responds more slowly, but “modern pumped storage plants can get from standstill to full capacity in probably the order of magnitude of 90 seconds,” which is already extremely fast for most grid needs.

The third and most critical factor is storage duration. Lithium-ion batteries typically offer three to six hours of storage. Hydropower storage durations of 6-24 hours are considered minimal; most reservoirs hold days, weeks, months or even years of energy. Because of this difference, Goodenough stresses that comparing capacity alone “cannot draw any meaningful conclusions.” She notes that unused hydropower storage volume alone is likely comparable to the entire volume now being built in batteries globally.

In short, response speed is not a substitute for endurance, and endurance is what supports entire systems through prolonged renewable droughts.

The value of hybrid configurations

There is growing industry interest in co-locating batteries with hydropower plants. According to Goodenough, this makes sense primarily because of grid-fee structures rather than physical necessity. In many markets, injecting or withdrawing power triggers grid charges linked to megawatt-hours or capacity. When batteries and hydropower operate behind the same meter, energy can be shifted and stored locally, which helps in avoiding those charges.

For grid health, however, co-location is not required; it is just a response to cost system setup. “If both are connected to the grid, it doesn’t really matter where they’re connected,” she says. Their impact on the system is the same.  

The real issue is that grid-cost systems were designed for an earlier era, with fewer, bigger producers, and no prosumers to speak of. As rooftop solar and distributed generation proliferate, the number of actors paying grid fees becomes smaller even as system costs are still calculated based on total injections and extractions. Goodenough believes that this trend will inevitably lead to future renegotiation of how grid costs are allocated between producers and consumers.

Hybridisation brings significant operational benefits for plants with limited flexibility. For run-of-river hydropower, pairing with batteries can introduce several hours of controllability, allowing operators to shift generation and participate more effectively in markets. This can also reduce grid fees when energy is stored rather than exported at moments of congestion.

How hydropower supports batteries

When asked how hydropower can support battery deployment, Goodenough reframes the issue. “I wouldn’t say that hydro directly helps batteries,” she explains. Instead, hydro and long-duration energy storage as a whole supports the renewable transition. By balancing the increased share of intermittent renewables – wind and solar – hydropower improves the carbon footprint of the energy system and reduces dependence on imported fossil fuels.

Energy autonomy, she adds, is the highest motivator behind green field hydro. 

She points to China, which is building more PSH “than the entire rest of the world combined.” This is not driven by environmental concern, she argues, but because China recognises the economic need for long-duration storage to stabilise the grid and support economic growth.

Operational complexity

Managing hybrid assets raises significant operational challenges. Goodenough explains that battery operation is simpler than hydropower because batteries are not constrained by environmental flows, meteorology, water rights or concession requirements. Hydropower optimisation must consider turbine capacity, efficiency curves, reservoir storage levels and mandated water releases. Batteries add their own set of constraints: maximum charge and discharge rates, temperature effects, cycle limits and degradation. Unlike hydropower turbines, which may run for decades, batteries reach end-of-life after 4,000 to 10,000 cycles.

This introduces a fundamentally different optimisation problem. Every MWh dispatched from a battery has a wear cost. Every deep cycle shortens asset life. Over-cycling a BESS in pursuit of short-term market gains can destroy long-term project value.

This complexity is amplified by changes in reserve markets. In many countries, secondary and tertiary reserves that were once auctioned weekly are now procured daily, with some places auctioning hourly delivery blocks. For operators, this means what was once a single weekly optimisation task has become 24 separate tasks per day. Manual processes are no longer viable. Forecasting, scheduling, trading and reserve bidding must all be automated.

When batteries are added to portfolios, fast operational cycles become even more important. A battery with a few hours of storage must be managed in near real-time. “Unless you are operationally able to react optimally within minutes, that scenario is too slow,” Goodenough explains.

Because of these differences, Goodenough believes hydropower operators are better positioned to expand into batteries than battery operators are to expand into hydro. The former already manage complex, multi-constraint assets; the latter do not.

Hybrid operation therefore must account for:

• Battery degradation costs
• Market price volatility
• Physical constraints
• Tariff structures and grid costs
• Environmental requirements

Reserve markets and a growing design flaw

One of Goodenough’s concerns is the evolution of flexibility products. She describes three layers procured by grid operators:

• Primary reserve – ultra-fast response providing inertia.
• Secondary reserve – response within two to three minutes.
• Tertiary reserve – response within approximately fifteen minutes.

Historically, assets were required to provide these services continuously for a week at a time. This implicitly favoured long-duration assets like pumped storage hydropower. But in recent years, these commitment periods have been reduced dramatically. In some countries, assets can participate for a single day, or even a single hour.

This shift reduced the purchase cost on the grid operator side, but it also created a systemic vulnerability: the grid is increasingly relying on assets that cannot sustain flexibility beyond a few hours. During typical operations, deviations are short. During major events, they may not be. Goodenough highlights the recent Iberian blackout in which low levels of hydropower and inertia were among the contributing factors.

The core flaw, she argues, is that “a battery which can deliver flexibility for two hours is treated the same in terms of revenue as a hydro pump storage plant which could deliver that flexibility for five months.” As long as market design values fast response but not duration, long-duration storage will not receive adequate investment.

 We don’t see the effects of this flaw in today’s energy landscape, because a lot of the infrastructure live or in development has already sunk their capital investments.  But without long-duration market signals, upgrades, reinvestment and new builds will stall. “By the time they go away, it will be too late to react.”

To correct this imbalance, Goodenough says that markets need products that explicitly reward long-duration storage. This could come in two forms:

• Longer auction windows for secondary and tertiary reserve-restoring weekly commitments for part of the market.
• New products focused on long-duration flexibility, potentially analogous to a fourth reserve category.

She emphasises that policymakers must make a clear decision: either maintain purely market-driven structures or introduce policy tools such as tax incentives or investment support. But something must change. Hydropower projects have long development cycles. A failure to incentivise them today means they will not exist in 2035. That timeline matches exactly when system-wide renewable penetration is expected to peak.

Without action, she warns, the industry could face a decade of curtailments or blackouts while waiting for long-duration storage to be built.

A practical hybrid scenario

To illustrate hybrid potential, Goodenough describes a solar-rich country with predictable midday production peaks. Installing enough pumped storage to absorb the entire peak would be costly and unnecessary. Instead, a combination of 2GW of pumped storage and 500MW of batteries could balance the system efficiently. Batteries would shave the highest part of the solar peak, shifting energy into shoulder hours. Pumped storage would store the lower portion of the surplus. Across each 24-hour cycle, nearly the full solar oversupply could be stored. The battery serves the daily problem; the hydropower plant serves the seasonal one.

This model also addresses extended periods of low renewable generation. Stored hydropower can support the grid during two or three weeks of low wind and solar-a capability batteries alone cannot provide. In short, battery storage delivers rapid frequency and voltage support, while pumped storage provides inertia and spinning reserve, therefore working together they ensure a resilient, stable grid.

Digitalisation as the enabling layer in the energy transition

Digitalisation is central to hybrid storage becoming viable. HYDROGRID plans to release an extension to its HYDROGRID Insight platform in 2026 to handle joint hydro-battery optimisation. Although often labelled as AI, Goodenough emphasises that the Insight  platform uses a machine learning optimisation model that improves over time taking into account all physical and operational constraints. She differentiates this from large language models, stressing that grid operations require reliability, not probabilistic generation.

Goodenough expands on this point, explaining that the real challenge lies in the nature of the problem itself: “Optimally choosing between hydro and battery dispatch is a deterministic task, defined by clear physical boundaries. For most energy applications, security and dependability are non-negotiable. That’s why cutting-edge mathematical optimisation models often outperform AI or LLMs in the strict sense. Our system already acts as an agentic AI –it aggregates data from multiple sources and autonomously determines optimal decisions –but its strength lies in precision and robustness rather than generative capabilities.”

Investment signals and risk

Goodenough says the industry has been discussing hybrid hydro-battery projects for at least five years. There are now several concrete projects in development, though not yet at the stage of final investment decisions. Hybridisation is both “over and underestimated” because while the benefits are clear, uncertainty remains high. Small changes in grid-cost structures or reserve markets can dramatically affect profitability. Battery economics are especially sensitive. Investors therefore wait for policy stability before taking the final step.

Beyond market design, Goodenough highlights permitting as a critical barrier. Hydropower permitting is often very slow, significantly limiting capacity expansion. Batteries face less complex permitting but are still affected. Clearer, faster processes would accelerate deployment.

She also notes that advances in battery technology could shift the landscape. Solid-state batteries, long discussed in the industry, have seen first commercial-scale production in China. If they deliver lower costs and higher storage capacity, they could accelerate battery deployment significantly.

Goodenough expects most hybrid systems to emerge at existing hydropower sites because grid connections and electrical infrastructure are already in place. Hydropower siting is geographically constrained, making retrofit logical. Batteries, by contrast, “you can just place behind the powerhouse in principle almost everywhere.”

Regional leaders

Asia is clearly leading in hybrid potential. China alone has roughly 90GW of pumped storage under construction – more than the rest of the world combined – and dominates global battery production. Centralised decision-making and less stringent permitting accelerate this trend. Goodenough expects Asia – China in particular – to host the earliest large-scale hydro-battery hybrid systems.

On the other hand, she mentions that North America is emerging as an innovation hub, with a robust pipeline of hybrid projects and real-world success stories like Idaho Falls Power’s water-powered microgrid, which demonstrates black start capability and grid resilience. On top of that, federal and state incentives for grid modernisation, alongside research leadership from institutions such as Lawrence Berkeley National Lab, reinforce this trend.

Nonetheless, Goodenough points out that Europe still remains a global leader in pumped storage technology but faces a catch-up challenge in battery deployment. While policy frameworks and renewable integration goals are strong, permitting complexity and slower investment cycles have limited hybrid adoption. However, Europe’s expertise in PSH and commitment to decarbonisation position it as a key player in the next wave of hybrid solutions.

By 2035: hydro still dominates stored energy 

By 2035, global battery storage capacity is expected to reach 135-200GW. Pumped storage hydropower is projected at around 225GW. But looking at storage volume, hydropower will still dominate: batteries will hold 350-2300GWh, while hydropower will hold around 13,000GWh, “dwarfing” batteries by at least a factor of five.

Hydropower will therefore remain the backbone of global storage, even as batteries grow significantly. HYDROGRID expects to play a central role in this future, supporting both hydropower optimisation and hybrid systems. Goodenough describes hydropower as “the storage giant that orchestrates and enables moving towards a much more carbon-neutral form of energy generation,” with a role that will extend far beyond the next decade. 

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