Over 5 million tonnes per annum of low-carbon hydrogen projects have reached Final Investment Decision (FID), yet a stark disconnect persists between preliminary commitments and binding commercial agreements. This gap exposes fundamental structural weaknesses in hydrogen market development that threaten to undermine the sector’s projected growth trajectory.
Recent high-profile deals signal growing commercial engagement across the clean hydrogen value chain. ExxonMobil and Marubeni’s May 2025 agreement for 250,000 tonnes of low-carbon ammonia annually, alongside RWE and TotalEnergies’ 15-year contract for 30,000 metric tons of green hydrogen starting in 2030, demonstrate that first movers are willing to commit to long-term arrangements. However, these transactions remain outliers in a market where most contracting activity centers on non-binding preliminary arrangements.
Financing Structures Drive Contract Duration Compromises
Hydrogen Sale and Purchase Agreements (H2SPAs) are emerging as the dominant contractual model, but with significant modifications from traditional energy commodity contracts. Contract terms typically span 10-15 years—substantially shorter than the 20+ year durations common in first-generation LNG and gas agreements. This reduction reflects buyer caution in an emerging market characterized by anticipated cost declines and evolving policy support mechanisms.
The financing landscape reveals why traditional contract structures require adaptation. Unlike conventional gas projects that relied heavily on debt financing requiring rigid revenue guarantees, hydrogen projects involve higher equity contributions from sponsors, utilities, and industrial users. Government subsidies and support schemes provide additional revenue certainty, reducing pressure for inflexible offtake guarantees. Take-or-pay commitments in hydrogen contracts typically range from 60-80%, compared to the 90%+ levels historically seen in early LNG agreements.
Cross-Commodity Indexation Creates Pricing Instability
The absence of transparent hydrogen market pricing forces contracts to rely on cross-commodity indexation, creating structural problems that mirror historical oil indexation issues in gas markets. Green hydrogen contracts typically link to electricity prices, while blue hydrogen references natural gas hubs like TTF or Henry Hub. This approach exposes hydrogen pricing to volatility in external markets with fundamentally different supply-demand dynamics.
Electricity-linked formulas for green hydrogen transmit power market volatility directly into hydrogen pricing, undermining the price stability essential for project bankability. Similarly, gas hub indexation for blue hydrogen creates exposure to global gas cycles unrelated to hydrogen market fundamentals. The resulting price misalignments risk triggering the same type of contractual disputes that have plagued oil-indexed gas contracts for decades.
Government Support Integration Remains Contractually Immature
Unlike gas and LNG markets that developed through largely market-driven processes, hydrogen contracting is fundamentally shaped by state policy intervention. Subsidies, tax credits, and certification regimes function as contractual building blocks rather than peripheral incentives. This dependency creates unique risks that traditional energy contracts are ill-equipped to address.
Contracts must establish transparent mechanisms for applying subsidies to pricing structures, implementing robust reporting requirements for subsidy utilization, and allocating liability for misreporting. The risk of subsidy withdrawal or reduction requires careful contractual treatment, as these events could render projects financially unviable. Some agreements include termination rights triggered by material changes to government support, though lenders typically prefer renegotiation mechanisms over outright contract dissolution.
Force Majeure Provisions Inadequately Address Hydrogen-Specific Risks
Standard force majeure categories from gas and LNG contracts provide insufficient coverage for hydrogen’s unique operational vulnerabilities. Green hydrogen production faces distinct risks, including electrolyzer failures, renewable energy supply interruptions, and equipment failures at third-party facilities. Blue hydrogen projects encounter steam methane reformer malfunctions, carbon capture system failures, and natural gas supply disruptions.
Hydrogen infrastructure introduces additional failure points largely absent from conventional gas operations. High-pressure storage systems face hydrogen embrittlement risks, compression failures can prevent delivery, and cryogenic systems for liquid hydrogen storage present novel operational challenges. Hydrogen blending into natural gas pipelines creates unprecedented risks from grid operator restrictions, pipeline incompatibility issues, and regulatory limits on blending ratios.
The nascent state of ammonia cracking facilities for hydrogen reconversion adds another layer of operational uncertainty. These facilities lack the operational track record of established LNG regasification terminals, creating ambiguity around risk allocation between sellers and buyers.
Regulatory Change Mechanisms Require Precision Engineering
Change in law clauses assume heightened importance in hydrogen contracts due to the sector’s policy dependence, but current drafting approaches often lack the precision required for effective implementation. Unlike traditional gas contracts, where regulatory changes were relatively uncommon, hydrogen agreements must anticipate frequent policy modifications affecting carbon pricing, certification standards, blending mandates, and financial incentives.
The interplay between price review, force majeure, and change in law provisions creates potential overlap that requires careful delineation. Regulatory developments might trigger any of these mechanisms depending on their nature and impact. New certification requirements could prevent performance entirely (force majeure), increase compliance costs (change in law), or necessitate pricing adjustments (price review). Contracts lacking clear trigger definitions risk jurisdictional disputes and enforcement delays.
Transportation Arrangements Expose Infrastructure Dependencies
Transportation terms in hydrogen offtake agreements must address significantly greater complexity than conventional gas contracts. Pipeline transport requires consideration of hydrogen’s material compatibility issues, including potential pipeline degradation and changes to gas quality and calorific value. Blending arrangements introduce safety risks from hydrogen’s high diffusivity and require sophisticated monitoring systems for maintaining consistent blend ratios.
Maritime transport, primarily via ammonia or liquid hydrogen carriers, involves logistical challenges that exceed those of established LNG shipping. Liquid hydrogen requires storage at extremely low temperatures with sophisticated boil-off management systems. While ammonia shipping benefits from established trade practices, its toxicity and corrosiveness create operational hazards that require specialized handling protocols.
The choice between embedding transportation terms within offtake agreements or structuring separate Hydrogen Transportation Agreements affects risk allocation and operational flexibility. Embedded arrangements simplify transactions but reduce adaptability as infrastructure evolves. Separate agreements provide greater operational control but introduce coordination complexities across multiple contractual relationships.
Market Evolution Trajectory Suggests Accelerated Development Timeline
The hydrogen contracting landscape is expected to evolve more rapidly than historical gas and LNG market development, compressed into three overlapping phases. The 2020s will likely see continued dominance of long-term foundations with emerging shorter-term alternatives as market structures mature.
The 2030s may witness the rise of diversified contracting approaches, including hybrid gas-hydrogen contracts that embed low-carbon alternatives into natural gas supply arrangements. Initially structured as future options, these arrangements could evolve into flexible real-time mechanisms allowing buyers to choose between molecules based on price dynamics or regulatory mandates.
By the 2040s, hydrogen contracting should mature into a global framework supported by traded benchmarks and financial hedging instruments. However, the path to this outcome depends on resolving current structural weaknesses in pricing transparency, risk allocation mechanisms, and regulatory frameworks.
The hydrogen offtake agreements now being negotiated face an exceptionally demanding environment, requiring structure with limited precedent under evolving policy frameworks while managing exposure to regulatory changes and investment priority shifts. The success of these early contracts will determine whether the clean hydrogen economy can scale beyond its current project-by-project development approach to achieve the market liquidity and standardization required for global energy system integration.
