Hydrogen Investments Are Surging – Costs, and Opportunity, Promise and Reality - Part 1

Hydrogen has re-emerged as a focal point in the global clean energy transition, attracting unprecedented government and private investments. As countries pursue net-zero goals, "green" hydrogen (produced from renewable electrolysis) and "blue" hydrogen (derived from natural gas with carbon capture) are viewed as twin pillars of a future hydrogen economy. This article explores recent high-profile hydrogen investments, compares green and blue hydrogen in terms of cost and feasibility, and critically examines the technology, physics, and economics shaping the industry. The next article will address the challenges to hydrogen project economics arising from policy dependence and fundamental technical and chemistry considerations.

A Surge in Hydrogen Investment: Government and Private Initiatives

Governments around the world have committed billions to kickstart the hydrogen industry, aiming to leverage public funds to catalyze even greater private investments. In the United States, the Biden administration's Bipartisan Infrastructure Law allocated $7 billion to establish regional clean hydrogen hubs, which are expected to produce over 3 million metric tons of clean hydrogen annually and trigger more than $40 billion in private investment (?$7 Billion Pledged For Clean Hydrogen Hubs By Biden-Harris Administration). These hydrogen hubs, positioned across various states, incorporate different production methods (ranging from renewable-powered electrolysis to natural gas with carbon capture) and promise tens of thousands of jobs. Similarly, the U.S. Inflation Reduction Act introduced a Production Tax Credit of up to $3 per kilogram of clean hydrogen produced, providing a lucrative incentive for green hydrogen projects (Treasury proposes rules to qualify for IRA clean hydrogen tax credits). These policies aim to unlock a wave of investment – for instance, officials estimate that the $7 billion hubs program will spur an additional $40 billion to $50 billion in private sector funding.

Europe is also increasing its support. In the first half of 2024, investments in European hydrogen projects nearly doubled from $376 million to $712 million year-on-year, despite a slight dip in global investment levels ( [Europe's Hydrogen Leap: €712 Million Boost Fuels Green Revolution). The EU has launched its Hydrogen Bank with contract-for-difference auctions to subsidize green hydrogen production, recently awarding €800 million to projects to secure a premium price for their hydrogen (European Hydrogen Bank - European Commission -?energy.ec.europa.eu). Individual countries are advancing their initiatives—such as Germany's H2Global program and the UK's hydrogen business model featuring CfD-style support—all aimed at bridging the cost gap for clean hydrogen. In Asia, Japan and South Korea have established long-term hydrogen roadmaps, while oil-producing nations like Saudi Arabia and the UAE are investing in large-scale "green hydrogen" and ammonia projects to position themselves as exporters of clean fuels.

The private sector is responding strongly to these signals. Global companies are making significant investments in hydrogen supply chains, which include everything from electrolyzer manufacturing to large-scale production projects. According to the Hydrogen Council, the number of clean hydrogen projects has increased seven-fold since 2020, reaching a total of?1,572 projects?with?$680 billion?in announced investments through 2030. (Global hydrogen industry reports $75 billion in committed capital but climate targets at stake due to project delays | Hydrogen Council). More significantly, the share of projects reaching final investment decision (FID) has surged – committed capital increased from $10 billion in 2020 to?$75 billion in 2024?(a seven-fold rise) as numerous major projects move toward execution (Hydrogen Insights 2024, Mckinsey). Energy giants like Shell, BP, TotalEnergies, and various industrial players are backing many of these initiatives. For instance, Shell took FID on a?200 MW electrolyzer in the Netherlands, which is set to become Europe's largest green hydrogen plant when it is online in 2025 (Shell Plans to Build Europe's Largest Green Hydrogen Plant). A consortium is constructing one of the world's largest green hydrogen facilities in NEOM (Saudi Arabia) at an estimated cost of $8.4 billion, supported by companies like Air Products.

Yet, despite the excitement, 2023 served as a reminder to temper expectations. Progress on many projects relies on effective policy support. In fact, the implementation of some subsidy programs fell short of initial hopes, leading to slower growth in 2023 than anticipated and postponing final investment decisions. However, a?"new sense of realism"?has emerged – industry players are concentrating on feasible projects as policies become clearer, and 2024 is expected to be a pivotal year for hydrogen scale-up (Review of 2023 | The key developments and trends in the global hydrogen sector (Part 1: Production) | Hydrogen Insight). However, fundamental questions remain about how and where hydrogen will be produced most economically.

Green vs. Blue Hydrogen: Costs, Technology, and Feasibility

Green hydrogen?refers to H? produced by splitting water (H?O) through electrolysis using renewable electricity, resulting in zero-carbon hydrogen fuel.?Blue hydrogen?refers to hydrogen derived from fossil fuels (typically natural gas through steam methane reforming) with the CO? emissions captured and stored. Each has distinct advantages and challenges, and it is critical to have a balanced view of both.

Production Costs:?Currently, green hydrogen is significantly more expensive to produce than blue hydrogen—roughly?2 to 3 times the cost, according to most estimates (Green hydrogen cost reduction). The European Commission estimates conventional fossil-based hydrogen (without CCS) at around?$2 per kg,?even with recent higher natural gas prices, while green hydrogen can range from?$4 to $6 per kg?depending on renewable electricity costs (Electrolyzer advances reduce cost of green hydrogen - Gas Turbine World). Blue hydrogen (natural gas + CCS) typically falls in between: the reforming process is relatively inexpensive like gray hydrogen, but the addition of carbon capture equipment and operational costs can add approximately $0.5–$1 per kg. In practice, blue hydrogen costs often settle around the $2–$3 per kg range (sensitive to natural gas prices and CO? capture rates), still significantly cheaper than most green H? produced today. This cost gap is why nearly all hydrogen in use (~95 million tonnes annually, primarily for refining and fertilizers) is "gray" (from unabated fossil fuels).?Without support, green hydrogen isn’t yet economically competitive.

However, green hydrogen costs are on a steep downward trajectory, thanks to declining renewable power prices and advancements in electrolyzer technology. Industry and analysts project that by the late 2020s, green hydrogen may approach cost parity with blue. IRENA (International Renewable Energy Agency)?finds?that if current trends continue,?green hydrogen could become cost-competitive with blue by 2030. In favorable locations—such as a desert solar farm or windy plain—renewable power at 2-3 cents/kWh and high electrolyzer utilization could bring green H? costs close to $2/kg by the end of this decade. Meanwhile, blue hydrogen's future costs are contingent on fossil fuel prices and carbon policy; if natural gas prices rise or carbon emissions are penalized, blue won't remain cheap. Additionally, blue hydrogen is not zero-emission: some CO? inevitably escapes capture, and upstream methane leakage during natural gas production can diminish climate benefits,?raising questions about its long-term viability in a net-zero world.

Technological maturity:?Blue hydrogen depends on?steam methane reforming (SMR)?or similar processes, which are well-established and implemented on a large scale worldwide. SMR technology has existed for decades; the new aspect of "blue" involves the addition of carbon capture equipment. Carbon capture for hydrogen (typically through solvent-based CO? absorption) is technically validated but introduces complexity and expense – usually, only about 90% of CO? can be captured. Nevertheless, from an engineering perspective, blue H? plants can be constructed on a large scale (hundreds of tons per day) using readily available technology. In contrast, green hydrogen relies on?electrolyzer?units – a field experiencing rapid innovation. Traditional alkaline electrolyzers have been industrially utilized for many years (e.g., in chlor-alkali processes) and are relatively cost-effective, but newer designs such as?PEM (proton exchange membrane)?electrolyzers provide more flexible operation (better suited for variable solar and wind energy) at a higher price due to the use of precious metal catalysts. The latest addition is?AEM (anion exchange membrane)?electrolyzers, which seek to merge alkaline's low-cost materials with PEM's adaptability. AEM technology is still developing, but early indicators are encouraging: AEM electrolyzers could reach costs similar to alkaline units (avoiding costly platinum and iridium catalysts) while enabling rapid adjustments in output (Demystifying Electrolyzer Production Costs - Center on Global Energy Policy at Columbia University SIPA | CGEP). The primary concern for AEM is durability; several experts are cautious about how quickly the membranes deteriorate. If these challenges are addressed, AEM could substantially reduce green hydrogen costs.

In terms of feasibility,?the biggest hurdle for green hydrogen is scaling up manufacturing and infrastructure. Components such as electrolyzer stacks and power electronics need to be mass-produced, similar to today's solar panels and batteries, to achieve significant cost reductions. The challenge for blue hydrogen is largely economic and environmental: can it serve as a low-carbon "bridge" solution, and will investors support new fossil-based facilities given uncertain long-term demand and potential carbon pricing risks? There is likely a role for both green and blue hydrogen in the 2020s. Blue hydrogen can provide bulk supply in regions with inexpensive gas and suitable geologic CO? storage—such as hubs on the U.S. Gulf Coast or in the Middle East—essentially offering lower-cost hydrogen in the short term for industrial uses while green hydrogen scales up. However, in a fully decarbonized scenario by 2050,?green hydrogen is the ultimate goal,?produced from abundant renewable sources with no emissions. Blue hydrogen, while beneficial for ramping up volumes now, remains dependent on a fossil fuel supply and the need to store CO? indefinitely.?

Economic feasibility:?Ultimately, the economic factors will determine which form dominates. For blue hydrogen to be viable, there must be confidence in the long-term availability of natural gas at reasonable prices and in regulations concerning carbon storage. For green hydrogen, economics improve significantly with each reduction in the cost of renewable electricity or each increase in electrolyzer efficiency. An important metric is the?levelized cost of hydrogen (LCOH). The current LCOH for green hydrogen is often cited in the range of?$3 to $6 per kg?(depending on assumptions), while blue hydrogen's LCOH can be 50 to 60% lower than that of new projects today (Electrolyzer advances reduce cost of green hydrogen - Gas Turbine World). That said, direct comparisons can be misleading due to regional factors; in an area with excellent renewable resources and high natural gas prices (e.g., Australia or Chile), green H? may already be cheaper than blue. Conversely, in a region with cheap gas but high electricity costs (e.g., the Middle East, if renewables are not developed), blue may remain less expensive for a long time. Policymakers are actively adjusting these economics through carbon pricing, fuel standards, and incentives (discussed further below). The key point is that both green and blue hydrogen have feasible technical pathways—the main question is how quickly green hydrogen can close the cost gap and surpass blue hydrogen, and how much blue should be developed in the meantime.

Electrolysis Advancements: Can New Tech (like AEM) Compete with SMR?

One of the hottest areas of R&D is driving down the cost of electrolysis, since electrolyzer CAPEX and efficiency directly affect green hydrogen cost. The goal, often termed achieving "fossil parity," is to produce green hydrogen at the same price as hydrogen from steam methane reforming (SMR). Today, green hydrogen from wind/solar is roughly 2-3× more expensive than SMR-based blue hydrogen, but several tech advances are closing the gap.

• Bigger, better electrolyzers:?Manufacturers are increasing unit sizes and factory throughput. Alkaline electrolyzers, known as the workhorse technology, already provide the lowest capital cost (approximately $800–$1,000 per kW installed) but historically came in relatively small modules. Now, companies like Thyssenkrupp Nucera are delivering?large 20 MW alkaline modules?and planning?gigawatt-scale factories, which should generate economies of scale in both construction and production. Larger stacks and more automated production can significantly reduce costs – one analysis found that increasing plant size from 1 MW to 20 MW could lower the electrolyzer capital cost by over one-third. (Green hydrogen cost reduction).
• Modular mass production:?Alternatively, some companies highlight a modular approach—manufacturing many small standardized electrolyzer units (similar to "appliances") and linking them together. This method resembles how solar panels are mass-produced as modules that can scale to any size farm. For instance,?prefabricated skid-mounted electrolyzer modules?can be deployed in multiples; Thyssenkrupp's systems are designed this way to customize capacity by adding modules as needed. Enapter, a startup promoting AEM electrolyzers, likewise produces compact modular electrolyzers that can be stacked to scale from kilowatts to multi-megawatts.?(Hydrogen production electrolyzer - AEM - Enapter GmbH - DirectIndustry). Mass-producing uniform modules could unlock cost reductions via learning-curve effects, even if each unit is smaller, just as modular IT servers outcompeted bespoke mainframes in computing.
• AEM and new materials: Anion Exchange Membrane (AEM) electrolyzers are an especially intriguing innovation. They operate in alkaline conditions but with a polymer membrane, allowing use of cheap catalysts (no precious metals) and flexible operation. In principle, AEM units could be as low-cost as conventional alkaline electrolyzers while also ramping quickly with renewables. This would avoid one major cost driver for PEM electrolysis (the need for platinum-group metals). Several companies are field-testing AEM systems; early data suggests they can achieve respectable efficiency. If durability issues are resolved, AEMs could drastically lower electrolyzer stack costs – one study estimated AEM stack material could be just ~19% of total system cost (much lower than PEM) (Demystifying Electrolyzer Production Costs - Center on Global Energy Policy at Columbia University SIPA | CGEP %). In short, AEM might hit the sweet spot: "potentially competitive with alkaline on cost" and able to handle intermittent operation. These improvements, combined with ongoing R&D in solid oxide electrolyzers (SOEC) (high-temperature units with very high efficiency when waste heat is available), paint an optimistic picture of continual electrolysis innovation.
• Efficiency gains: Besides CAPEX, improving electrolyzer efficiency reduces the electricity needed per kg H? – a key cost lever. The theoretical minimum energy to split water into 1 kg of H? is about 39 kWh (based on hydrogen's enthalpy).?In practice, today's alkaline and PEM electrolyzers require approximately 50–55 kWh per kg, translating to about 70-75% efficiency (based on lower heating value). Research and development are driving toward that theoretical limit: new electrode designs, improved membranes, and higher-temperature electrolysis (like SOEC) can bring the kWh/kg down to around 40. Each efficiency improvement means that you can produce the same amount of hydrogen with fewer solar panels or wind turbines. Some solid oxide designs have demonstrated efficiencies below 45 kWh/kg in lab settings (over 80% efficiency). Although these may compromise durability, it illustrates that the physics is not static.?In summary, ongoing technical advances—larger scales, modular manufacturing, new membranes, and efficiency enhancements—are consistently lowering the cost of green hydrogen.?Many analysts now anticipate that green H? costs will drop below $2/kg in the next 5-10 years in the best-case regions, potentially making it competitive with fossil-based H? sooner than previously predicted (with some forecasts even suggesting before 2030, such as McKinsey & Co., Hydrogen Council report H2 Insights 2021).

Can these advances truly compete with SMR (the incumbent)? SMR is a mature and optimized process, and without carbon capture, it produces hydrogen cheaply—often around $1-1.5/kg when gas is inexpensive. Adding carbon capture raises SMR costs, but it remains a relatively low-tech, continuous process. Electrolysis will likely continue to be more capex-intensive per unit output. However,?the gap is closing rapidly, especially when external factors are considered: if renewable electricity is extremely cheap (or effectively free during surplus periods), green hydrogen can undercut even $2/kg targets. Furthermore, if one accounts for the upcoming carbon price or emissions constraints, SMR without capture is not a viable comparison—the real competition is between green and blue hydrogen. In this context, the industry's?"major goal"?is clear: achieve cost parity between green H? and SMR-based blue H?. With expected reductions in electrolyzer capex (over 50%) and cheaper renewables, analysts such as McKinsey (for the Hydrogen Council) have concluded that?renewable hydrogen could break even with?grey?(unabated) hydrogen before 2030?in many regions. Each year, that goal appears more achievable, but with the support of favorable policies.

CAPEX, OPEX, and the Economics of Hydrogen Production

Hydrogen production economics involve balancing?CAPEX (capital expenditure)—the initial cost to build production facilities—and?OPEX (operating costs)—the ongoing expenses for feedstock, energy, maintenance, and more. Green and blue hydrogen exhibit significantly different cost structures in this respect:

• Blue hydrogen (SMR+CCS):?The capital cost for a large SMR plant with CO? capture is considerable (hundreds of millions for a world-scale facility). However, when assessed per unit of capacity (per kg of H? produced per day), it has typically been lower than that of new electrolyzer plants. SMR units benefit from economies of scale (larger is more efficient) and decades of cost optimization. The OPEX for blue hydrogen is primarily driven by?natural gas feedstock. Approximately?9-10 cubic meters of natural gas?(or about 0.3 MMBtu) are required per kg of H? produced, and that gas cost (plus a bit more for heating) can add around $1-2 to the overall cost, depending on gas prices. There is also an energy penalty and the need for sorbents in carbon capture, but fuel remains the primary factor. Consequently, blue H? OPEX can fluctuate significantly with gas market volatility—as observed in 2022 when a surge in European gas prices rendered blue H? temporarily uneconomical. Maintenance of reformers and carbon capture units contributes to OPEX but is relatively minor per kg. In summary,?blue hydrogen generally exhibits lower CAPEX per capacity but higher sensitivity in OPEX to fuel costs.
• Green hydrogen (electrolysis): The CAPEX for electrolyzers is currently high – on the order of $500 – $1,000 per kW for alkaline/AEM and up to $1,500+/kW for PEM systems. In terms of hydrogen output, 1 kW of electrolyzer produces roughly 0.02 kg H? per hour (at ~50 kWh per kg), so a 1 MW electrolyzer (~$1 million for alkaline, more for PEM) makes ~20 kg H? per hour. That works out to capital costs of $50,000+ per kg/hour, which must be amortized into the hydrogen cost. As manufacturing scales and costs fall, these numbers will improve dramatically. The OPEX for green hydrogen is almost entirely electricity cost. Producing 1 kg of H? typically requires around 50–55 kWh of electricity; if power costs $0.05 per kWh, that amounts to $2.50-$2.75 in electricity per kg. When using dedicated renewable plants, the levelized cost of solar or wind energy is important. Some projects assume extremely low electricity rates (around $0.02/kWh or less during surplus), bringing the energy cost down to under $1 per kg. Water consumption is a minor expense (approximately 9 liters per kg of H?, costing only a few cents). Additionally, there are operation and maintenance costs for the electrolyzer plant (e.g., stack replacements every few years due to degradation, which serves as a capital expenditure renewal cost).?Therefore, the operational expenses for green hydrogen are primarily influenced by electricity prices and electrolyzer efficiency.?Unlike steam methane reforming (SMR), having periods of zero-cost excess renewable power can nearly eliminate your operational expenses—but you need storage or flexible operation to take advantage of that, which can limit utilization.

A key difference is capacity factor/utilization: SMR plants typically run near 90% capacity year-round (they prefer steady operation). Electrolyzers tied to renewables might run lower capacity factors (solar only produces ~20-25% of hours at full power annually, wind 30-50% depending on location). If an electrolyzer is underutilized, its high CAPEX is spread over fewer kg of H?, raising the effective cost per kg. This is why new projects often pair renewables with some grid power or oversize renewables with storage, to maximize electrolyzer use. Alternatively, some designs oversize electrolyzer capacity relative to average renewable output, accepting that not all units run at once, which lowers utilization but ensures you can capture all the renewable energy when available. There's a trade-off between curtailing renewable output vs. idling electrolyzers – project developers optimize this balance for cost.

Modularity vs. Scale:?Large-scale centralized hydrogen plants (whether blue or green) benefit from economies of scale, but they also face?distribution costs?when hydrogen needs to be transported to end-users. Smaller, modular electrolyzers placed on-site (for instance, at a fueling station or a fertilizer plant) might eliminate transport costs and leverage local renewable energy, though they sacrifice scale. Modular electrolyzers can also potentially be mass-produced using assembly-line techniques, which would reduce their unit costs (similar to how microchip fabs produce numerous small units inexpensively instead of one large unit). The hydrogen industry is likely to adopt a blend of methods: massive hubs (like the planned >100 MW electrolyzer farms or large SMR+CCS complexes)?alongside?decentralized production for specific applications (e.g., hydrogen fueling stations generating H? on-site through electrolysis to prevent the need for trucking in compressed hydrogen). Prefabricated, modular electrolyzer systems are enabling this distributed model, allowing quick installation and scaling just by adding more modules. This modularity is an advantage green hydrogen has – you can produce at small scale efficiently – whereas SMR generally only makes economic sense at large refinery-scale plants.

Regarding?CAPEX/OPEX trends,?electrolyzer CAPEX is expected to decline, which will shift the cost of green hydrogen more toward the electricity OPEX. Meanwhile, if carbon capture technology improves and economies of scale are realized, blue hydrogen CAPEX may decrease slightly, but there's limited potential for significant reductions since SMR is already a mature technology. The OPEX for blue hydrogen will always include fuel costs, so unless there is a future with ultra-cheap gas (without a carbon penalty) or a breakthrough such as affordable methane pyrolysis (turquoise hydrogen), blue hydrogen is unlikely to get much cheaper than its current marginal cost. Green hydrogen OPEX could decrease if renewable electricity becomes less expensive or if electrolyzers become more efficient. We are witnessing both—record-low solar PPAs and improved electrolyzers—so the trend favors green hydrogen.

Summary

In summary, blue hydrogen investments rely on utilizing existing infrastructure and short-term cost advantages but could encounter rising OPEX if fossil fuel or carbon costs increase. Green hydrogen investments focus on technology-driven cost reductions and the long-term inevitability of zero-carbon energy dominance. Many energy companies are hedging by investing in both approaches (for instance, a project involving some blue hydrogen now with plans to incorporate green hydrogen as more renewables become available). Sound economics will depend on project-specific calculations, but in general, each year of innovation and scale appears to increasingly favor green hydrogen.

The next article will provide a reality check, surveying the policy and incentive landscape, and examining the dependence of hydrogen projects on it, along with the fundamental technical issues related to hydrogen economics and the limitations to its adoption as a major fuel source for future economies. These aspects deserve serious consideration in today's investment decisions and strategies.