18至25元对15元：绿氢成本逼近灰氢那一刻，8%至10%的项目收益是靠什么撑起来的18 to 25 yuan versus 15 yuan: When the cost of green hydrogen approaches that of gray hydrogen, what supports the 8% to 10% project returns?

Round One: The gap between 18–25 yuan and 15 yuan that hasn't disappeared

The cost difference between green hydrogen and gray hydrogen is the most direct measure of whether this industry has reached the commercial threshold. Current data shows: industry estimates indicate that in resource-rich regions like the northwest and northeast, the cost of green hydrogen has dropped to 18–25 yuan/kg, while the cost of gray hydrogen is about 15 yuan/kg. Placing the two numbers together, the gap ranges from 3 to 10 yuan/kg. This gap deserves serious attention because it has significantly narrowed compared to a few years ago—the narrowing is driven by simultaneous improvements in three curves. The first is electricity price: wind and solar electricity prices in the northwest and northeast have dropped to 0.15–0.2 yuan/kWh, and some areas, such as Inner Mongolia, have launched special prices for green electricity, as low as 0.168 yuan/kWh. Electricity costs typically account for 60% to 80% of the total cost in water electrolysis hydrogen production. A price drop from the 0.3 yuan/kWh range to 0.168 yuan/kWh essentially cuts nearly half of the largest component of the cost.

Article 2 is equipment: China’s alkaline electrolyzer production capacity accounts for more than 50% of the global total. The scale effect, combined with technological iteration, has driven the price down from $250/kW to below $100/kW, and leading domestic equipment suppliers have already reduced the unit price of electrolyzer systems to below 1,500 RMB/kW. Article 3 is carbon pricing: the domestic pilot carbon price is about 50 to 70 RMB/ton, while the EU carbon price is as high as 80 to 100 euros/ton, corresponding to carbon reduction benefits of about 2,000 RMB per ton of hydrogen. When all three curves shift downward simultaneously, green hydrogen is pulled from being "more than twice as expensive as gray hydrogen" to being "30% to 70% more expensive." But the gap still exists. 18 to 25 RMB is a range rather than a point, which means that even within the advantage regions, there is about a 40% cost difference among projects; the 15 RMB gray hydrogen cost line corresponds to the steady-state cost of mature petrochemical processes and will not automatically rise just because green hydrogen is approaching. Second round: three pillars of multi-party arguments and one empirical case.

The evidence structure of multiple perspectives is fairly complete and can be summarized as three pillars plus one empirical point. The first pillar is the regional differentiation of resource endowments. China’s wind and solar resources are geographically mismatched with hydrogen demand—the resources are in the northwest and northeast, while the demand is in the eastern coastal areas. This mismatch was once a disadvantage for green hydrogen, but the 'Western Hydrogen to the East' initiative along with the green ammonia and green methanol systems are turning it into an industrial chain opportunity: green ammonia and green methanol can solve the problem of absorbing renewable energy in the west while filling the hydrogen gap in the east. The second pillar is the sustainability of equipment cost reduction. The path of reducing electrolyzer costs from $250/kW to below $100/kW is highly similar to the cost reduction paths of photovoltaic modules and lithium battery cells, both of which combine economies of scale with technological iteration. Moreover, electrolyzers still have cost reduction potential on the materials side—the domestic rate of core materials such as proton exchange membranes and catalysts has exceeded 90%, and Dongyue Group's proton exchange membranes have been supplied in bulk to mainstream domestic PEM electrolyzer companies. The third pillar is the price spread advantage of carbon pricing.

The domestic pilot carbon price of 50 to 70 yuan/ton compared to the EU's 80 to 100 euros/ton results in a carbon reduction benefit of about 2,000 yuan per ton of hydrogen. This benefit is particularly important for export-oriented green hydrogen products—it also serves as a pass under the pressure of carbon tariffs. One empirical example is: an investor in a central enterprise wind-solar hydrogen project estimated that for a 30 billion yuan wind-solar hydrogen project, under conditions of high-quality wind and solar resources combined with long-term contracts and carbon benefits, the internal rate of return could reach 8% to 10%. This investor's judgment is that this is not purely policy-driven; high-quality projects already have semi-market-based economics. At the same time, he provided a key judgment regarding roles: central enterprises, holding the triple advantages of capital, resources, and policy, are the only entities in China capable of rolling out 30 billion yuan wind-solar hydrogen projects in bulk. The weight of this judgment lies in linking the implementation capability of green hydrogen projects with the attributes of the entity—not every company can execute projects based on an 8% to 10% model.

Third round: The triple premises of bearish arguments and the cooling of the order side.

The bearish side does not deny the fact of cost reduction; their arguments focus on three points. The first is the fragility of the triple premise. An internal rate of return of 8% to 10% is based on the simultaneous fulfillment of three premises: high-quality wind and solar resources, long-term contract lock-in, and carbon revenue. Note the nature of these three items: high-quality wind and solar resources are determined by resource endowment and are non-replicable; long-term contract lock-in is determined by transactional structure and requires long-term commitment from downstream buyers; carbon revenue depends on carbon price levels and the stability of accounting rules. Among the three premises, long-term contract lock-in and carbon revenue are institutional variables; once policies adjust or downstream demand slows, the return model will shift down significantly. Taking 8% to 10% as the industry average return is a misinterpretation of the premises—it is more like the upper-end performance of high-quality projects under the current policy window. The second point is the cooling on the order side.

S&P Global's "Quarterly Power-to-X Report (Q2 2026)" shows that in the first half of 2026, China's electrolyzer market OEM orders totaled approximately 1,062 MW, of which overseas orders accounted for 293 MW. Compared with the same period in 2025, China's electrolyzer orders fell by about 29%. Equipment orders are a leading indicator of project investment intentions: the year-on-year decline in orders indicates that owners are more cautious when making investment decisions, which usually occurs at a stage when project yield calculations are not robust. The third point is scenario dependency. In the first half of the year, the winning scale of alkaline electrolyzers was 797.625 MW, accounting for 96.54%, while PEM and AEM combined accounted for less than 4% — this structure indicates that current orders are highly dependent on large-scale wind and solar hydrogen integration and industrial scenarios such as synthetic ammonia and methanol, where the investors are concentrated in state-owned enterprises and a few leading private companies. Once the investment pace of these entities slows down, equipment demand will lack compensation from distributed and transportation scenarios. This point is crucial: the demand structure for green hydrogen is currently unipolar, not multipolar.

Round Four: How Rigid is the Demand Side Really?

The arguments from both bullish and bearish sides on the demand side need to be evaluated separately, because the term "demand rigidity" carries very different significance in different contexts. Industrial decarbonization is currently the main rigid demand: the three major areas of coal chemical, steel, and synthetic ammonia are simultaneously facing the dual pressures of carbon tariffs and domestic dual-carbon assessments, and the policy direction has firmly favored green hydrogen replacing gray hydrogen. Industry statistics show that the proportion of green hydrogen substitution in the chemical sector is expected to reach 15% by 2026, becoming the second-largest engine driving the electrolyzer market growth. In terms of demand structure, three types of downstream applications—chemical synthetic ammonia, methanol production, and refinery hydrogenation—consume more than 70% of the electrolytic water hydrogen nationwide. This concentration of over 70% indicates two things: the demand for green hydrogen is real and scalable, but it is also highly concentrated. This concentration is a double-edged sword— in the short term, it ensures demand certainty because the raw material replacement decisions of chemical companies have long cycles and are not easily reversed once made;

In the long term, it means that the demand curve for green hydrogen is highly tied to the prosperity of the chemical industry and the ability to transmit carbon costs. Looking at the transportation sector: the number of fuel cell vehicles is expected to reach 80,000 by the end of 2026, driving the growth of hydrogen demand for refueling stations. This scale is still very small compared to the industrial side and mainly serves as a reserve for future growth. Therefore, demand assessments should be layered: the industrial side represents current rigid demand, the transportation side is a long-term option, and the export side has relatively strong certainty under the carbon tariff framework. The result of this layering is that the 'rigidity' of green hydrogen demand is actually built on a relatively narrow industrial scenario, and what can truly leverage demand expansion is whether a second growth curve beyond chemicals can emerge.

Fifth round: to achieve an 8% to 10% return, three accounts need to be reconciled.

An internal rate of return of 8% to 10% is currently the focal number in the long and short debate, and it needs to be broken down into three accounts to verify. The first account is the electricity price account. The special green electricity tariff of 0.168 yuan/kWh is a special condition in advantageous regions, while the essence of wind and solar tariffs is volatility—if hydrogen production projects cannot obtain long-term stable low-cost electricity supply agreements, the actual electricity cost will fluctuate with the spot price. This is particularly crucial after the full entry of electricity into the market: as the volume of renewable energy connected to the grid in principle fully enters the electricity market, the cost of obtaining green electricity will increasingly depend on trading structures rather than administrative pricing. Whether the project's electricity price account can be locked in depends on whether long-term green electricity direct supply or green electricity trading agreements can be signed. The second account is the equipment account. The unit price of electrolyzer systems is pushed below 1,500 yuan/kW, which corresponds to the large-scale products of the alkaline route;

For scenarios with large load fluctuations that require frequent start-ups and shutdowns, the adaptability of alkaline equipment decreases, and it may be necessary to configure PEM, which has a significantly higher unit investment. Therefore, the figure of 1,500 yuan/kW applies to specific scenarios and cannot be directly applied to all projects. The third account is carbon revenue. A carbon reduction revenue of about 2,000 yuan per ton of hydrogen is the result of converting the price difference between domestic pilot carbon prices and EU carbon prices, and its realization depends on two conditions: first, that the emissions reductions generated by the project can be recognized and enter the carbon market for trading; second, that the carbon footprint certification of exported products can be accepted by the importing party. Both belong to institutional conditions and require time to coordinate. Calculating these three accounts, an 8% to 10% rate of return is realistic, but its applicable scope is clear: high-quality wind and solar resources, long-term low-cost green electricity agreements, large-scale continuous hydrogen production scenarios with alkaline solution compatibility, and products targeted at downstream customers facing carbon cost pressures. Missing any of the four conditions will lower the rate of return. Judgment: The watershed is not in the technology, but in the dual realization of electricity price and carbon price.

Provide a clear judgment. First, the watershed for the economic viability of green hydrogen is neither in the efficiency of electrolyzers nor in the equipment price, but in whether electricity prices and carbon prices can be realized simultaneously. Cost reductions in equipment have already largely removed electrolyzers from the cost bottleneck—from $250/kW down to below $100/kW. In the future, even if the cost drops by another half, the improvement in total costs will be much smaller than the effect of electricity prices dropping from 0.3 yuan/kWh to 0.168 yuan/kWh. This means that the core variables for the industry going forward lie on the power side and in the carbon market: whether long-term low-cost green electricity can be secured, and whether carbon prices can converge from domestic pilot levels to EU levels. Second, 2026 to 2027 is the window period that will determine the true starting line of the industry. There are two bases for this judgment: first, the cost range has narrowed to 3 to 10 yuan/kg, making the space for policy and market mechanisms to play a role very sensitive; second, equipment orders in the first half of 2026 showed a year-on-year decline, indicating that investment decisions are waiting for clearer profit expectations.

Third, there are three direct implications for investment and industrial layout. First, priority should be given to areas where long-term power purchase agreements can be secured, rather than simply chasing the areas with the best wind and solar resources—the lock-in of power prices is more important than the absolute level of power prices. Second, priority should be given to downstream scenarios with clear carbon cost pressures (such as synthetic ammonia, methanol, and refining hydrogenation, which together consume more than 70% of electrolytic hydrogen), rather than vague industrial substitution concepts. Third, the path to realizing carbon revenue should be evaluated as an independent variable of project feasibility, rather than as an additional item to the rate of return—because it is the most uncertain of the three premises. Green hydrogen has already reached a stage where 'quality projects can account for costs, while general projects still need policy support,' and at this stage, the biggest mistake is to regard the returns of individual quality projects as representative of the industry average.

[Benchmark Debate Style · Position] The cost of green hydrogen is 18 to 25 yuan/kg compared to 15 yuan/kg for grey hydrogen, narrowing the gap to 3 to 10 yuan. However, an 8% to 10% project return depends on the simultaneous fulfillment of three conditions: high-quality resources, long-term electricity prices, and carbon revenues. The watershed lies not in equipment technology, but in the lock-in of electricity prices and the realization path of carbon prices; 2026 to 2027 is the window for establishing the industry’s true starting line.