Chapters:
00:00 Agenda & Introduction
01:05 Why Green Hydrogen Matters
08:31 Global Policy Landscape & Incentives
19:34 Green Hydrogen Value Chain
23:22 Life Cycle Assessment (LCA)
29:27 Carbon Market Opportunities
38:16 Challenges, Action Plan & Outlook to 2030
48:59 Audience Q&A
Agenda
Today's session covers how hydrogen matters across hard-to-abate sectors — steel, fertilizers, refining, shipping and beyond — and the policy landscape behind it, since producing and storing hydrogen remains expensive. We'll look at how countries are evolving their policies and incentives, the green hydrogen value chain, life cycle assessment (LCA) — what it is, what framework and mandates apply — and carbon market opportunities that can generate extra project revenue. We'll close with the key challenges, an action plan, and the outlook to 2030.
1. Why Green Hydrogen Matters
Under the Paris Agreement, all participating countries committed to limiting global warming to 1.5°C above pre-industrial levels. This is an ambitious revision: an earlier target introduced in 1996 through the Clean Development Mechanism (CDM) proved far too difficult to achieve, so in 2015 the target was tightened to 1.5°C.
Hard-to-abate sectors — refineries, steel, fertilizers — cannot simply stop operating, so they need to decarbonize. That means minimizing fossil fuel use and introducing synthetic and e-fuels wherever possible. Yet current green hydrogen production is nowhere near the scale required: it is not even 1% of the UN's target of 60 million metric tonnes by 2050. This gap is why every signatory of the Paris Agreement has started introducing green hydrogen policy, from tax credits to carbon pricing linked to schemes such as the EU ETS.
Key sectors where green hydrogen can play a prominent role:
Steel — hydrogen can replace coke and coal as the reducing agent in DRI-based steelmaking. Steelmaking currently accounts for 7% of global CO₂ emissions.Fertilizers — hydrogen plus nitrogen produces ammonia, the base material for urea. The fertilizer industry represents 2% of global emissions.Refining — hydrogen is used in hydrocracking and hydrotreating to reduce sulphur in petroleum products. Refining contributes 6% of industrial CO₂ emissions.Chemicals — hydrogen can be infused into methanol and ethanol production as e-methanol or e-ethanol.Shipping — storing and transporting green hydrogen is difficult, so it is more likely to be used as a solid fuel or converted into e-synthetic fuel.Aviation — hydrogen can similarly be infused into e-fuel or synthetic aviation fuel.Market outlook: green hydrogen production stood at roughly 0.1 million metric tonnes in 2024, against a near-term target of 4 to 10 million metric tonnes — a very ambitious jump. Electrolyzer capacity is currently around 5 GW, while 100–200 GW is needed by 2030 to support at least 4 million metric tonnes of green hydrogen production by that date.
Cost remains the central constraint. Green hydrogen currently costs around $6/kg; the target is to bring this down to $2/kg, or even below $1/kg, by 2028–2030. Water is also a critical raw material: producing 1 kg of hydrogen requires about 9 litres of water, which must be treated to a demineralised, iron-free standard before it can feed an electrolyzer — pushing countries toward "water-positive" strategies.
2. Global Policy Landscape & Incentives
European Union — targeting climate neutrality by 2050 under the European Hydrogen Strategy, with 40 GW of renewable electrolyzer capacity targeted by 2030. Under REPowerEU, reducing dependence on Russian fossil fuels is a core driver. The European Hydrogen Bank provides a premium subsidy per kg of hydrogen produced, designed to close the gap between the EU ETS carbon penalty a company would otherwise pay and the higher cost of deploying a green hydrogen plant. For example: if a company would pay roughly $5 in penalties but a green hydrogen plant costs the equivalent of $7, the EU Hydrogen Bank subsidy is designed to cover that $2 gap.
India — under the National Green Hydrogen Mission, the government has approved ₹19,744 million through the SIGHT program (Strategic Intervention for Green Hydrogen Transition), split into two incentive tracks: one for green hydrogen production and one for electrolyzer manufacturing. There is no minimum capacity or eligibility threshold — any entity in any sector (refineries, fertilizers, cement, etc.) can apply. Of this, ₹1,400 million is earmarked for pilot projects, with additional allocations for R&D and technology upgrades.
United States — a tax credit incentivizes green hydrogen production, conditional on emissions staying below 0.4 kg CO₂-equivalent per kg of hydrogen. A gap-subsidy mechanism, similar in spirit to the EU's, helps cover the difference between the policy-driven cost target and actual plant cost.
Japan — lacking land and renewable resources for large-scale domestic production, Japan's strategy centers on a centralized, LNG-style import model: signing agreements with other countries to import hydrogen molecules for use in its steel, fertilizer and cement industries. An incentive subsidy is available for 15 years.
China — aims to become the world's largest electrolyzer manufacturer, with a production target of 100,000–200,000 tonnes of green hydrogen per year and a goal of 50,000 hydrogen fuel-cell vehicles by 2030. Rather than a direct per-kg subsidy, support comes through government financing, land access and tax incentives.
Australia — pursuing a strategy similar to the Middle East, aiming to become a global hydrogen supplier, backed by an incentive of AUD 2 per kg for 10 years.
South Korea — its hydrogen economy roadmap targets 5.26 million tonnes of hydrogen per year by 2050, supported by a public investment fund rather than a direct per-kg incentive.
Middle East — no specific subsidy or incentive program, but the region leverages its very large renewable energy production capacity, positioning itself as the world's largest RE producer integrated with green hydrogen output.
Incentive duration compared: United States and the EU offer roughly 10 years, India 5 years (with R&D funding limited to 1 year), Japan 15 years, and Australia around 7–8 years.
Why this matters for manufacturers: the incoming Carbon Border Adjustment Mechanism (CBAM) creates a direct financial reason to decarbonize rather than pay border tariffs. Beyond CBAM, green hydrogen adoption supports ESG performance across Scope 1, 2 and 3 emissions, reduces carbon liability, and can unlock premium market access, since funding agencies and investors increasingly favour green hydrogen producers. Carbon pricing for hydrogen specifically is still limited today, but is expected to become far more robust by the end of the decade.
3. Green Hydrogen Value Chain
Renewable energy — roughly 40% of total project cost. Sufficient renewable capacity is the starting point for any green hydrogen project.Water treatment — a major concern given the 9 litres of water needed per kg of hydrogen; water quality must be tightly controlled, with no iron or other contaminants, since lab-scale results can differ significantly from what an industrial-scale, less-controlled environment delivers.Electrolysis (PEM, alkaline, or other technologies) — roughly 50% of total project cost.Purification and drying — hydrogen leaving the electrolyzer must be purified and dried, since other gases may be co-produced; some leakage risk exists at this stage.Storage — still not commercially mature. Green hydrogen must be compressed to around 700 bar, and (particularly in the Indian context) storage technology remains under development.Transport — also still largely at the R&D stage, whether via pipeline, ship or other vessel.End users — steel, fertilizer, cement and shipping facilities exist in most countries; aviation is now exploring hydrogen-based fuel R&D as well, partly driven by CORSIA's emerging interest in carbon markets given the sector's high emissions baseline. Green hydrogen can also help balance power grids.Each stage of the chain — renewable energy procurement, water treatment, electrolysis — carries embodied emissions, which is exactly what a life cycle assessment is designed to quantify.
4. Life Cycle Assessment (LCA)
LCA can follow three different framework boundaries:
Cradle-to-gate — from raw material to the factory gate (i.e., through manufacturing only).Cradle-to-grave — from manufacturing through to waste processing and recycling.Cradle-to-cradle — from manufacturing through to recycling by-products back into the same process.ISO 14040 sets out the principles and framework for LCA — what parameters to capture and what guidelines and product category rules (PCR) to follow. ISO 14067 covers the carbon footprint of products specifically, giving direction on how to calculate emissions at each process step.
LCA modelling is typically done using dedicated software — SimaPro, GaBi, OpenLCA — or in Excel for simpler cases. The process starts by defining a system boundary, then feeding in raw material, electricity and water consumption data. The output is a set of indicators covering carbon, water use, acidification, eutrophication, ozone depletion, and more — enabling a producer to know, for example, that their process emits "3 or 4 kg CO₂-equivalent per kg of hydrogen," and to benchmark that figure against alternative technologies (e.g., water electrolysis versus methane cracking).
LCA also underpins incentive eligibility. In the United States, production must stay under 0.45 kg CO₂-equivalent per kg of hydrogen to qualify for the tax credit — simply building a plant is not enough; emissions have to be actively controlled throughout the process. In India, the BIS standard sets a threshold of 2 kg CO₂-equivalent per kg of hydrogen.
Indicative benchmark figures shared during the session (cradle-to-gate global warming potential):
Grey hydrogen: ~9–10 kg CO₂-eq/kg H₂Blue hydrogen: ~3–7 kg CO₂-eq/kg H₂Green hydrogen: ~1–2 kg CO₂-eq/kg H₂Natural gas: ~9–11 kg CO₂-eq/kg H₂In the EU, the Renewable Energy Directive III (RED III) sets a threshold of 3.8 kg CO₂-eq/kg H₂, while a separate EU certification requirement caps emissions at 4.4 kg CO₂-eq/kg H₂.
LCA also connects to CBAM through the Digital Product Passport (DPP) — a QR-code-based system that consolidates a project's process data and emissions indicators (as generated by LCA software) into a single verifiable record.
5. Carbon Market Opportunities
Beyond government incentives, carbon markets offer a second revenue stream for green hydrogen projects, through two frameworks:
Voluntary carbon market (VCM) — projects register with recognised registries (Verra, Gold Standard, ECC, CR Carbono, ICR) to generate carbon credits, which are then sold to buyers seeking green certification or emissions reductions. As an indicative order of magnitude shared in the session: roughly 14,000 carbon credits per MW of electrolyser capacity, at around $12 per credit — a meaningful additional revenue line on top of any government subsidy.
Compliance market — tied to a government-set carbon target; deploying a decarbonization (or "DECAP") plant can exempt a company from an emissions tariff or target.
Typical project cycle:
1. Pre-feasibility assessment of the project.
2. Additionality test (particularly where government funding is involved) — demonstrating the project would not have happened without the carbon finance.
3. Methodology selection — e.g., Verra's AMS-III.C-type methodology, or the CDM's ACM0124 — which defines exactly how to calculate credits per kg of hydrogen produced.
4. Project Design Document (PDD) drafting and submission of a verified report to the registry, following the methodology's guidelines rather than a project's own calculations.
The underlying formula is: carbon credit = baseline emissions − (project emissions + leakage emissions), requiring a clearly established baseline scenario (what the facility was doing before switching to hydrogen).
Article 6 of the Paris Agreement (adopted at COP21, 2015) provides two relevant compliance mechanisms:
Article 6.2 — bilateral agreements between two countries (e.g., a technology-provider country funds or supplies technology to a hosting country, which develops the project and registers the resulting carbon credit).Article 6.4 — focused on the private sector, with stricter requirements: a clearly established baseline, demonstrated additionality, defined SDG alignment for each project, and no allowance for project or leakage emission overruns.As of this session, no dedicated compliance-market methodology for hydrogen has yet been released — CDM methodologies are being used as an interim reference. A methodology expert panel decision is expected after November; a comparable methodology has already been released for green ammonia, which may serve as a precedent.
When strong policy support and carbon market access come together, green hydrogen projects can become genuinely bankable, with an internal rate of return (IRR) in the region of 12–18%. Indicative revenue figures shared in the session: hydrogen sale prices of roughly $3–5/kg in the US, €4–6/kg in the EU, and $3–5/kg in India — with carbon credit revenue adding a further (comparatively small, around $0.15/kg) uplift on top of a policy incentive in the order of $3/kg.
6. Challenges, Action Plan & Outlook to 2030
Key challenges and barriers:
High production costInfrastructure gapsCertification complexity, particularly in the US and EU marketsHigh electrolyser capexWater availability — India, for example, is exploring "water-positive" strategies (more lakes and dams to offset consumption), though this policy has not yet been formally releasedDemonstrating additionality to carbon credit buyers, who scrutinise credit quality closelyThe carbon market itself is still in transition: a dedicated hydrogen methodology is expected once the expert panel completes its review, following the precedent already set for green ammoniaRecommended action plan for developers and manufacturers:
Run an LCA to benchmark your chosen technology against alternatives before committing.Carry out a carbon-market pre-feasibility assessment to understand registration potential.Assess your renewable energy sourcing strategy — for example, combining solar with wind in a hybrid setup to cover generation gaps outside daylight hours.Establish a robust MRV (Monitoring, Reporting, Verification) system to track real-time emissions from raw-material sourcing through to production — this is also a practical way to manage Scope 1, 2 and 3 emissions with daily, hourly or monthly granularity.Evaluate every relevant national policy — cross-border collaboration is possible, with one country acting purely as a technology provider while another leads project development.Pursue third-party certification (DNV, Bureau Veritas, or similar bodies) to give investors and buyers a verified, independent record of your project's emissions performance.Outlook to 2030 — key takeaways:
Policy momentum is strong and continues to build, with the EU, US, India, Japan, Australia and the Middle East all prioritising green value chains.LCA-based certification is likely to become mandatory in more jurisdictions, following the lead already set by the US, EU and India.Article 6.4 and the voluntary carbon market continue to evolve, with meaningful additional revenue potential for well-structured projects.Green hydrogen is positioned as a cross-sector replacement fuel — transportation, shipping and industrial applications alike — supporting broader industrial decarbonization strategies.The cost trajectory remains uncertain: even as emissions performance improves, the need for high-quality raw materials and rigorous water treatment limits how far costs can realistically fall.
Audience Questions
On green hydrogen pricing versus grey hydrogen
Q (Sonia Gomez): Green hydrogen currently starts at around $5/kg — higher than grey hydrogen. Why is it expected to eventually become cheaper than grey hydrogen?
Green hydrogen doesn't yet have a real market price, since production is still largely at lab scale — so any figure quoted today is an expectation, not an observed market price. Depending on whether a company is facing an EU ETS-style carbon tax or tariff penalty, the effective cost of choosing green hydrogen could exceed $5, potentially reaching $10–20. Realistically, green hydrogen is expected to remain more expensive than grey hydrogen in the near term, not cheaper. Whether a company adopts it often comes down to whether they'd rather pay the penalty and keep running on grey hydrogen, or invest to voluntarily lower their emissions.
On cost reduction drivers
Q: What are the key drivers for green hydrogen cost reduction?
This is a genuinely difficult question — cost-cutting isn't really the right frame here, because producing green hydrogen responsibly is inherently expensive: it requires large volumes of high-quality raw material and rigorous water treatment (water cannot be used directly and must be treated before use). The one real lever available is government incentive — funding or subsidy programs can offset cost, but outside of that support, there isn't a clear path to reducing the underlying cost of production today.
