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Harry Michael Blog 31/07/25

Watt Happens Next: Can Flow Batteries Still Find Their Place in the Energy Storage Race?

Round 3 of Watt Happens Next!

The window for new energy storage technologies to gain ground is narrowing. Lithium-ion batteries have already achieved the kind of speed, scale, and cost-reduction trajectory that makes market entry increasingly difficult for alternatives. Gigafactories are springing up across the globe, and the cost curve continues to bend downward.

Against this backdrop, flow batteries face a steep climb. On paper, they offer real advantages for long-duration energy storage (LDES): deep discharge capability, long lifespans with minimal degradation, and flexible sizing. But, performance alone is no longer a compelling sell. The market now demands speed to scale and clear cost trajectories – areas where lithium-ion and its adjacent chemistries have a growing head start.

Recent investments underscore the accelerating momentum behind lithium-based and adjacent storage technologies:

These technologies benefit from the ability to piggyback on equipment stack used in incumbent lithium-ion production infrastructure, leveraging familiar cell formats, manufacturing equipment, and integration pathways. That compatibility gives them a shortcut up the learning curve, something flow batteries currently lack.

Still, the opportunity isn’t closed. As grid needs evolve beyond four-hour durations and toward daily or seasonal shifting, the case for flow batteries strengthens. The question is whether they can overcome CapEx obstacles, supply chain immaturity, and slow sales cycles fast enough to claim a meaningful share of that emerging market.

Flow Battery 101

New to flow batteries? Here’s a quick explainer. If you’re already familiar, feel free to skip ahead.

Flow batteries store energy in liquid electrolytes that circulate through a central electrochemical stack where chemical energy is converted to electricity and vice versa. Unlike lithium-ion, where energy and power are tightly coupled in each cell, flow batteries separate them: energy capacity comes from the volume of electrolyte, while power output depends on the size of the stack.

This decoupling makes them uniquely suited to long-duration applications. Need more hours of energy? Just scale up the tank size. Most commercial flow batteries today are vanadium-based, but newer chemistries, including organic, iron, and zinc variants, are gaining traction due to lower cost and reduced environmental risk.

Flow batteries tolerate deep cycling with little degradation, making them ideal for applications that require frequent charge/discharge or extended runtime, like industrial backup, microgrids, and seasonal load shifting.

Lithium-Ion Is Eating the Duration Curve – Can Anything Catch Up?

Lithium-ion has long dominated Short-Duration Energy Storage (SDES) as the default choice for grid operators seeking fast-response storage.

Technically, lithium-ion can operate at longer durations, but the economic challenge becomes apparent as system-level costs, balance-of-plant (BoP), power electronics, and cooling all scale alongside energy capacity. Beyond a certain point, these costs erode their economic viability for LDES.

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That threshold, however, is shifting. LFP-based lithium-ion has creeped into Medium-Duration Energy Storage (MDES), driven by falling costs and improved pack designs. Some start-ups developing flow batteries initially targeting MDES are pivoting to LDES applications to avoid direct competition, expecting lithium-ion to keep moving up the duration curve.

For a deep dive on LFP Batteries, check out my previous blog “LFP is taking over – Here’s why it matters”.

The pressure has only intensified with CATL’s announcement that LFP cell-level costs have dropped to 400 RMB/kWh (around $55/kWh). While this figure doesn’t capture pack or system-level costs, it still sent shockwaves through the market. Naturally, there’s room for scepticism; how closely does this number reflect real-world pricing? Even if it holds, it says little about the broader picture, particularly lifetime economics like levelised cost of storage (LCOS), where flow batteries may still have an edge.

The U.S. Department of Energy (DOE) report from August 2024 titled Achieving the Promise of Low-Cost Long Duration Energy Storage found that flow batteries offer the lowest LCOS of any non-geologically constrained technology. The DOE estimated that flow batteries could achieve an LCOS of $0.055/kWh, lower than lithium-ion’s projected $0.070/kWh.

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Note: LCOS projections assume 8–12 hour storage durations and DOE usage profiles

Regardless of this, the investor confidence in non-LFP energy storage has cooled down, particularly in a high-interest-rate environment where CapEx-heavy projects are already struggling.

If LFP-based Li-ion batteries continue their downward price trend, alternative MDES technologies may have to find niche use cases or pivot toward true LDES, where lithium-ion struggles to compete. For flow batteries, their future may depend on proving value in areas where lithium-ion falls short, whether in safety, lifetime economics, or operational flexibility.

Can Flow Batteries Unlock Value Where Lithium-Ion Hits Its Limits?

a) Safety-Conscious Applications

Aqueous electrolytes and thermal stability matter for mission-critical sites.

While lithium-ion systems carry risks of thermal runaway and degradation at deep states of charge, flow batteries can be inherently safer. They operate at ambient temperatures, can use non-flammable, water-based electrolytes, and maintain performance even under deep cycling. This positions them well for mission-critical, safety-sensitive environments like data centres, hospitals, defence sites, and dense urban grids.

Flow batteries can discharge nearly 100% of their stored energy with minimal capacity fade, making them well-suited for high-throughput applications like industrial backup, grid stabilisation, and critical facility redundancy. In sectors where uptime is paramount and thermal or chemical hazards are tightly regulated, their low-risk operating profile offers a compelling safety and compliance advantage.

Additionally, flow batteries open the door to novel, safety-conscious deployment models. For example, underground storage approaches, long used in the oil and chemical sectors, can also be used for flow battery tanks. While often considered a space-saving strategy, it also provides added protection in disaster-prone areas. Subsurface deployment can shield systems from fire risk, extreme weather, or physical damage in conflict zones.

b) Scale: Decoupling Energy and Power

Built for Flexibility in a Duration-Driven Future

Flow batteries’ biggest structural advantage lies in their architecture: they decouple energy and power by scaling energy through larger tank volumes rather than increasing cell count. In contrast, lithium-ion systems integrate both energy storage and power delivery within each individual cell, so increasing energy capacity also means adding more power output, whether it’s needed or not. This tight coupling makes it difficult to optimise system design for specific use cases, especially where energy duration matters more than instantaneous discharge. By separating these functions, flow batteries allow operators to tailor power output for peak demand while scaling energy capacity independently and inexpensively. This enables cost-optimised right-sizing in sectors managing fluctuating loads or requiring extended backup, making flow batteries particularly well-suited for long-duration applications (8+ hours), where system-level economics increasingly reward the ability to customise and optimise energy-to-power ratios.

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Illustration of installed system cost by storage duration (PNNL, 2022). While Li-ion (LFP) is more cost-effective at short durations, flow batteries become lower-cost per kWh beyond ~7 hours, due to their ability to scale energy capacity (electrolyte volume) without adding proportional power hardware. Note: figures reflect 2022 data and may not capture current market shifts.

I’ve long argued that this structural advantage gives flow batteries a niche where cost benefits are realised from decoupled design. If they can overcome deployment barriers, this could become a defining cost advantage at scale.

Moreover, when the energy component (electrolyte) can scale independently, it opens the door to treating energy capacity like a tradable, serviceable commodity. Applications prioritising duration over ramp rate could benefit from this scalable, modular storage format, setting the stage for new business models like electrolyte-as-a-service.

c) Electrolyte-as-a-Service: A New Business Model

Selling Storage Like Fuel – Without Owning the Hardware

In conversations with startups in the space, one theme keeps surfacing: the rise of the electrolyte-first model, where companies focus on supplying the core energy storage medium (the “fuel”), rather than the entire system.

As more startups enter the space, many are opting to source standard flow battery hardware from established suppliers, allowing them to focus R&D efforts on electrolyte development while forming strategic partnerships to deploy early systems. This shift opens a range of new commercial strategies:

This model borrows from more mature industrial sectors like fuels and speciality chemicals, where materials are commoditised, and supply chains are optimised for scale. But unlike those sectors, flow batteries still depend on physical systems to convert stored energy into usable power. Paired with next-gen hardware like membraneless cells and advanced electrodes, these shifts in chemistry and business models can form a cohesive path to scale.

By shifting the core offering from hardware deployment to electrolyte supply, companies can create a recurring revenue stream, selling and refilling electrolytes rather than committing to full-system manufacturing. However, even with an electrolyte-first model, scaling electrolyte sales to meaningful volumes will ultimately depend on system deployment. Without sufficient physical installations, the industry won’t reach the inflexion point where economies of scale and recurring electrolyte revenues can take off.

Permitting requirements differ across jurisdictions and often involve time-consuming safety and environmental reviews that delay deployments. At the policy level, while funding for LDES is increasing, flow battery incentives remain inconsistent and fragmented, adding uncertainty for developers and investors. Flow battery developers still face the challenge of proving bankability at scale, an essential hurdle to unlock project finance and institutional investment.

One way to perhaps bypass this constraint? Leverage what already exists.

d) Repurposing Infrastructure

Turning Legacy Industrial Assets into Energy Storage Platforms

The traditional model for flow battery companies, designing, manufacturing, and deploying full systems, is capital-intensive and slow to scale.

Unlocking the full potential of the electrolyte-first model may ultimately depend on what infrastructure we can repurpose. While new system deployments are slow and capital-intensive, retrofitting existing assets can be a workaround by offering a way to scale without starting from scratch.

This model is gaining traction in part due to the legacy of decommissioned vanadium flow battery (VFB) systems. Many of these were shut down not because of technical failure, but because of volatile vanadium prices. These systems can be reactivated with a cost-effective electrolyte supply, avoiding the need for new infrastructure and reducing capital investment requirements.

Global installed capacity of flow batteries is still modest, estimated to be <1 GW, barely a blip compared to lithium-ion grid storage (68 GW installed in 2024 alone). While companies like CellCube Enerox and Sumitomo Electric have deployed hundreds of MWh globally, most systems remain relatively small and bespoke. Flagship projects like China’s 100 MW / 400 MWh Dalian Rongke Power Station or Japan’s 15 MW / 60 MWh Minami Hayakita Substation are exceptions.

The flow battery storage tanks are required to hold thousands of cubic meters of electrolyte, which accounts for the bulk of a flow battery’s physical footprint, drives much of the permitting complexity, and contributes heavily to overall capital costs in LDES projects.

As David Reber details in Nature Energy (January 2025), electrolyte tank costs are an overlooked factor in flow battery economics. While many technoeconomic models tend to underestimate their contribution, Reber’s analysis reveals that the tank alone, excluding the electrolyte, can account for approximately 27% to 40% of the total energy component cost in MWh-scale systems. For instance, in a standard 1 MWh vanadium flow battery using two 37.5 m³ tanks, the electrolyte may cost around $125,000, while the tanks themselves range from $47,000 to $84,000. This finding challenges the prevailing assumption that tanks are a minor cost driver and highlights the importance of considering tank sourcing, standardisation, and potential repurposing when assessing system economics at scale.

This brings us to a provocative but increasingly relevant question: could oil and gas infrastructure be repurposed for flow batteries? While it may sound speculative at first, the idea is grounded in practical engineering. Flow batteries store energy in liquid electrolytes, and legacy oil and gas infrastructure, such as decommissioned fuel tanks and chemical storage facilities, are designed to handle large volumes of industrial fluids. Many of these sites come with existing permits for hazardous liquids, integrated pumping and conveyance systems, and completed civil works such as reinforced foundations and containment basins. These attributes could align closely with the physical and regulatory requirements of next-generation large-scale flow battery deployments.

Aramco’s recent deployment of a 1 MWh flow battery at a remote gas site points to this early traction in oil & gas environments. While not a repurposing of legacy infrastructure, it signals that industrial energy systems can accommodate flow batteries in operational settings, offering a potential stepping stone toward larger retrofit opportunities.

Corrosion remains a hurdle: strongly acidic electrolytes such as vanadium degrade traditional carbon steel tanks, a standard material used in oil and gas infrastructure. Without suitable chemistry adaptations or protective modifications, reusing these tanks at scale could be prohibitively costly or technically infeasible.

That said, companies like Quino Energy are developing organic electrolytes that operate under mild pH conditions, reducing corrosiveness and enabling compatibility with existing carbon steel tanks, making retrofits more technically viable.

According to the U.S. Energy Information Administration (EIA), converting the country’s existing oil storage capacity for flow battery use could yield up to 4 terawatt-hours (TWh) of energy storage. Just two 75,000 m³ tanks common in petroleum terminals could store ~3 GWh of energy, at a third of the land area needed for an equivalent LFP battery installation.

Turning Infrastructure from Liability to Asset

The timing is critical. The International Energy Agency (IEA) projects global oil demand will plateau by 2030, suggesting we are either at or very near peak oil. Petrochemical demand will remain, but bulk storage infrastructure could soon become stranded. For infrastructure owners, this presents a stark choice: write it off, or repurpose it.

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Figure Adopted by IEA Oil 2024 Analysis and forecast to 2030

Of course, location matters. Not all oil storage sites are viable for grid-scale storage. But those near transmission lines, ports, or heavy industry could serve as prime hubs for redeployment.

Repurposing storage tanks offers a potential path to reduce capital costs, streamline permitting, and create opportunities for fossil incumbents to participate in the energy transition. These assets, once symbols of the old energy order, could be reimagined as critical enablers of long-duration energy storage.

Historically, fossil fuel incumbents have slowed clean energy progress through lobbying, regulatory inertia, and market dominance. But if retrofitting becomes economically viable, resistance could give way to reinvention. The convergence of public pressure, private investment, and government incentives may unlock a pragmatic shift, where sustainability is no longer a cost but a competitive strategy.

Tying it all Together: What it Takes to Scale Flow Batteries

Scaling flow batteries isn’t just about chemistry. It’s about building a flexible, capital-efficient ecosystem, one that borrows from industrial models, leverages legacy infrastructure, and redefines how we think about storage.

It increasingly feels as though we are approaching an inflexion point in the industry. Oil demand is peaking. Data centre loads are growing. Modular business models are emerging. Public pressure is mounting for technologies that offer duration, safety, and flexibility.

Flow batteries don’t need to displace lithium-ion. They need to thrive in the corners where lithium-ion fails: longer-duration, retrofit-ready deployments, and safety-critical niches.

The traditional model of constructing full, bespoke flow battery systems has shown its limits. The electrolyte-first approach offers a modular and capital-light alternative, treating the electrolyte as a standardised input that can be produced, distributed, and financed independently of full system builds.

Without a growing network of system integrators and hardware partners, even the most efficient electrolyte supply model will stall. If the sector can align both sides, chemical supply and system deployment, it could shift from capital-heavy, bespoke infrastructure projects toward a more modular, recurring-revenue platform.

That’s where legacy energy infrastructure comes in. As fossil fuel assets edge toward obsolescence, they offer a physical foundation on which to build. Storage tanks, pipelines, and permitting frameworks already exist; they just need to be reconfigured for a new purpose.

Watt’s Next?

If you’ve made it this far, thanks for reading! If there are specific topics in energy storage, investment trends, or emerging tech you’d like me to explore in future blogs, feel free to reach out.