RED III RFNBO Targets 2030: Europe's Hydrogen Demand Gap, National Compliance and Investor Risk

By the Green Fuel Journal Research & Intelligence Team

Published 14 October 2026 under the ISSN 2979-3777

All facts as of 14 October 2026 | Reader focus: Energy investors

Last reviewed: October 2026 · Next review trigger: Commission publication of its proposal to revise Delegated Regulation (EU) 2023/1184

Legal Disclaimer

This report is published for information only. It is not investment, legal or tax advice, and it does not recommend buying, selling or financing any asset. Figures come from third-party sources as of 14 October 2026 and may change. Scenarios reflect analyst judgement and are not forecasts or probabilities. Readers should consult qualified advisers before acting.

Full terms are at greenfueljournal.com/disclaimers.

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Executive Summary

Industry estimates of 2030 demand under the RED III RFNBO targets 2030 run from 1.3 Mt to up to 3.3 Mt of renewable hydrogen a year, against projected supply of about 1.7 Mt in Hydrogen Europe's Monitor 2025. Only 8 of 27 Member States had both transport and industry RFNBO mandates in law by May 2026, a year after the 21 May 2025 transposition deadline. RFNBO hydrogen cost €7–10/kg in 2025 against roughly €2.00/kg for grey hydrogen (ACER, relayed by pv magazine; a single origin), and at least 9 of the 13 projects that reached final investment decision in 2025 had public support (Westwood Energy; a single source). The law sets 42% of the hydrogen used in industry as renewable fuels of non-biological origin (RFNBOs) from 2030 and 60% from 2035, plus a 1% RFNBO share inside a 5.5% combined transport sub-target.

The three demand estimates measure different things. The 1.3 Mt figure covers the industry target alone (Hydrogen Europe, June 2026), 2.8 Mt is the Monitor 2025 estimate across industry, road transport and refining, aviation and maritime, and up to 3.3 Mt is Hydrogen Council demand with a positive business case, including derivatives (May 2026). Supply of about 1.7 Mt covers roughly 60% of the 2.8 Mt figure, and we found no Commission or IEA estimate of mandated demand. Enforcement looks soft: Czechia's rules and the Netherlands' draft set industry obligations below 42%, and the Commission referred Greece, Malta and Portugal to the Court of Justice in April 2026. Wood Mackenzie expects the Commission to accept a retreat on the industry target and says Germany will not impose binding industry mandates (single source). A BloombergNEF analysis cited by the Hydrogen Council says effective enforcement needs penalties above €10–12/kg, while Hydrogen Europe cites a €600/tCO2 Green Gas Quota penalty in units that cannot be compared with it (both single-source figures).

The production rules may also change. The Commission's promised Q2 2026 revision of the RFNBO production rules (AccelerateEU, 22 April 2026) was still unpublished on 21 September 2026. Operating electrolysis in Europe stood at 571.7 MW at the end of 2025, with 3,272.5 MW under construction. Our conclusion for the energy investor: underwrite on contracted, subsidised volumes, treat statutory demand as upside, and test each project against national law, rule-change risk and post-2030 exposure.

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1. Executive Intelligence Synthesis

Quick answer  The main investor risk is that statutory demand and contracted demand are different things. Industry estimates of 2030 RFNBO demand run from 1.3 Mt to up to 3.3 Mt, and projected supply of about 1.7 Mt covers roughly 60% of the 2.8 Mt estimate. Whether any of it becomes bankable depends on national enforcement, which is incomplete: only 8 of 27 Member States had both mandates in law by May 2026 (European Hydrogen Observatory).

Signal 1: The mandate is not the market

• FINDING: Three industry estimates put 2030 demand at 1.3 Mt (industry target only), 2.8 Mt (Monitor 2025) and up to 3.3 Mt (business-case demand incl. derivatives), while Hydrogen Europe's Monitor 2025 projects supply of about 1.7 Mt, roughly 60% of the 2.8 Mt figure.

• SO WHAT: A supply shortfall against statutory demand does not create a buyer, because only contracted volumes service project debt.

• NOW WHAT: Ask every sponsor for the signed offtake volume and the counterparty before relying on any national target.

Signal 2: Transposition is late and, where done, diluted

• FINDING: The European Hydrogen Observatory counted 8 of 27 Member States with both mandates in law by May 2026, and Hydrogen Europe's June 2026 paper says Czechia and the Netherlands (in draft) set industry obligations below 42%.

• SO WHAT: A national law that dilutes the EU target produces less physical demand than the headline implies.

• NOW WHAT: Read the national obligation, not the EU target, for each market a project plans to serve.

Signal 3: The price gap is wide and penalties are unproven

• FINDING: RFNBO hydrogen cost €7–10/kg in 2025 (HYDRIX average about €8.20/kg) against about €2.00/kg for grey hydrogen, according to ACER as relayed by pv magazine on 3 December 2025 (single origin).

• SO WHAT: Buyers face a gap of roughly four times on these averages (GFJ arithmetic), and public data cannot show that national penalties exceed it.

• NOW WHAT: Treat penalty strength in each Member State as a diligence item and establish who pays the gap.

Signal 4: The production rules may change

• FINDING: The Commission's AccelerateEU communication of 22 April 2026 promised a targeted revision of the RFNBO production rules, and an industry letter of 21 September 2026 said no proposal had been published.

• SO WHAT: Projects cannot fix their compliance costs, and the grandfathering that industry has requested remains unconfirmed.

• NOW WHAT: Price projects on current rules, treat any relief as upside, and record where each commissioning milestone sits against 1 January 2028.

Signal 5: The pipeline is subsidy-led

• FINDING: At least 9 of the 13 projects reaching final investment decision (FID) in 2025 had grants or state aid, and about 82% of 2026 electrolyser additions come from five projects with €2.0–2.1bn of public support (Westwood Energy, January 2026, single source).

• SO WHAT: The projects that exist are financed by subsidy and captive offtake, not by the mandate.

• NOW WHAT: Favour projects with secured support and binding offtake, and discount merchant exposure.

Table 1: The five executive signals

Signal	Key evidence	Source and date	Investor consequence
Mandate is not the market	1.3 / 2.8 / up to 3.3 Mt demand; about 1.7 Mt supply	Hydrogen Europe; Hydrogen Council (2026)	Demand is estimated, not contracted
Late and diluted transposition	8 of 27 states; Czechia and the Netherlands below 42%	Observatory (May 2026); Hydrogen Europe (June 2026)	National law sets real demand
Wide price gap	€7–10/kg vs about €2.00/kg	ACER via pv magazine (3 Dec 2025); single origin	Penalty strength decides who pays
Rule-change window	Revision promised Q2 2026; unpublished on 21 Sep 2026	Industry letter (21 Sep 2026)	Compliance cost cannot be fixed
Subsidy-led pipeline	At least 9 of 13 FIDs supported; 82% of 2026 additions from five projects	Westwood Energy (Jan 2026); single source	Underwrite support and offtake

Source quality: Secondary for all rows except the industry letter (Primary, advocacy). Rows rely on third-party relays of the underlying reports.

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2. Macro Context and Strategic Drivers

Quick answer  RED III requires 42% of industrial hydrogen to be RFNBO by 2030 and 60% by 2035, plus a 1% RFNBO share within a 5.5% combined transport target by 2030. Member States can cut the industry targets by 20% if they meet conditions on their contribution to the EU target and cap fossil-based hydrogen at 23% in 2030 or 20% in 2035. Transposition was due on 21 May 2025 (European Hydrogen Observatory, current to May 2026).

2.1 What RED III requires: industry and transport

• FINDING: RED III sets separate RFNBO obligations for industry (42% in 2030, 60% in 2035) and for transport (a 1% RFNBO share inside a 5.5% combined target by 2030), according to the European Hydrogen Observatory page current to May 2026.

• SO WHAT: The two sectors have different buyers, compliance routes and volumes, so a single blended "RED III demand" figure hides the risk.

• NOW WHAT: Model industrial and transport offtake separately, and name the obligated party for each volume.

Both industry targets can be reduced under the flexibility set out in the Quick answer and Table 2. This report does not compute an adjusted target, because we reviewed the flexibility through secondary summaries and did not check its exact wording in the legislative text.

Readers following the aviation side of the transport multipliers can compare our earlier analysis of ReFuelEU Aviation 2026–2030.

Table 2: RED III RFNBO targets, flexibilities and deadlines

Element	Industry	Transport
2030 target	42% of hydrogen used in industry must be RFNBO	5.5% combined advanced biofuels and RFNBO, with a 1% RFNBO sub-target
2035 target	60%	Not covered in the evidence reviewed
Flexibility	Both targets can be cut by 20% if the Member State meets its expected contribution and keeps fossil hydrogen at or below 23% (2030) or 20% (2035)	Multipliers: RFNBO counts 1.5x (aviation, maritime) and 2x (other transport)
Transposition deadline	21 May 2025	21 May 2025

 Source: European Hydrogen Observatory, "Renewable Energy Directive", page text current to May 2026 (Primary, EU-funded). The directive number, (EU) 2023/2413, is taken from secondary references and was not checked on EUR-Lex.

2.2 Why 2026–2027 is the decision window

• FINDING: The Commission's AccelerateEU communication of 22 April 2026 committed to propose a targeted revision of the RFNBO production rules, yet an industry letter of 21 September 2026 said the proposal was not published, citing "the continued postponement of the review".

• SO WHAT: Installations commissioned before 1 January 2028 are exempt from additionality until 1 January 2038 under the current rules, so investors have just over 14 months from this report's publication date to weigh a commissioning date against a rule that may change.

• NOW WHAT: Run every project model on both the current rules and a revised-rules case, and mark the commissioning date against the 1 January 2028 line.

In March 2026, Germany, Spain, the Netherlands and Austria, together with Poland's State Secretary, asked for an early targeted review of Delegated Regulation (EU) 2023/1184, and Italy and Czechia later backed the request (Stibbe, 27 May 2026; joint industry letter of 8 July 2026). The Commission confirmed the early review on 22 April 2026, and in April 2026 it referred Greece, Malta and Portugal to the Court of Justice of the EU (CJEU) for missing the transposition deadline (Recharge). A joint industry letter of 8 July 2026 asked for additionality to run to 2035 and for grandfathering, meaning protection for projects built under today's rules. The statutory review, due in 2028, is the fallback if the early proposal slips again.

Public funding moved in the same window. The third European Hydrogen Bank auction reported on 7 May 2026: a €1.3bn budget, €1.09bn allocated, 1.1 GW of electrolysis, 58 bids from 11 countries and 9 winning projects in 7 countries (Greece, Spain, Denmark, Austria, Finland, Germany and Norway). Fixed premiums ran from €0.44/kg (Cloudberry, Finland) to €3.49/kg (RogalandH2, Norway), and bids exceeded the budget more than six times (pv magazine, 7 May 2026). The same article quotes a Commission range of €0.57–3.49/kg, and the sources do not reconcile the two lower bounds. Reported on 24 September 2026 (review-energy), 170 companies called for binding RFNBO targets beyond 2030, a sign that industry sees the post-2030 position as unsettled.

2.3 Non-EU comparators: where legal demand exists and where it does not

• FINDING: Among the jurisdictions reviewed, only the EU creates a legal offtake obligation: the US offers a production credit of up to $3/kg with a construction-start deadline of 31 December 2027, and China's goal of 2 Mt a year of green hydrogen by 2030 is a production target (Hydrogen Insight, 26 June 2026, single source; headline only).

• SO WHAT: Non-EU exporters depend on European demand that national law has yet to turn into contracts.

• NOW WHAT: Treat a non-EU project selling into Europe as carrying the same enforcement risk as an EU merchant project, plus certification risk.

The One Big Beautiful Bill Act, passed on 3 July 2025, moved the US 45V construction-start deadline from 1 January 2033 to 31 December 2027 (GH2.org for the 2033 date; H2-Tech for the 3 July passage), and Hydrogen Insight reported on 9 April 2026 that the administration proposed cancelling more than $3bn of hub funding (single source). Canada is the clearest export case: the EU's executive branch approved €200 million in January 2026 to support Canadian supply to Germany, unlocking matching Canadian funds, with auctions of up to 300 MW scheduled for 2027 (Energy Now, 22 January 2026). Hydrogen Europe's June 2026 paper instead describes €200 million from each of Germany and Canada, about €400 million jointly for about 300 MW, so the sources differ on who funds the first €200 million.

China drove the doubling of installed electrolysis to just over 4 GW in 2025 and holds about 60% of global manufacturing capacity (IEA, via Argus Media, 19 June 2026). It has no RED III-style obligation, so its relevance is competitive: it sets electrolyser cost. In the Gulf, Wood Mackenzie expects at least three large Middle East projects to be cancelled or significantly scaled back (outlook of 9 January 2026).

For the wider molecule picture, see our Green Molecules Economy 2035 analysis.

Table 3: Regional instruments compared

Jurisdiction	Instrument	What it does	Evidence quality
EU	RED III; Delegated Regulations 2023/1184 and 2023/1185	Binding RFNBO shares for industry and transport; production criteria; greenhouse-gas methodology	Primary page and law-firm summary; legal texts not opened
United States	45V credit (OBBBA, 3 Jul 2025)	Production credit up to $3/kg; construction start by 31 Dec 2027	Secondary (GH2.org, H2-Tech)
Canada	EU and Canadian support for exports to Germany	€200 million EU approval with matching Canadian funds (Jan 2026); auctions up to 300 MW in 2027	Secondary (Energy Now); Hydrogen Europe describes the funding differently
China	15th Five-Year Plan energy strategy	Target of 2 Mt a year of green hydrogen by 2030; no consumption mandate	Secondary, single source; issuing document not identified
India	SIGHT green ammonia auctions via SECI	Fixed-price procurement with named offtakers	Secondary (pv magazine India, H2-Tech)
Gulf	NEOM (Saudi Arabia); Oman background	Project-level; no consumption mandate in the evidence	NEOM source undated; Oman article from April 2024

 Research limitation: we gathered no verified evidence for the United Kingdom, Brazil, Australia, Southeast Asia or Sub-Saharan Africa, so this report does not describe them.

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3. India-Specific Analysis: Export Readiness for the EU RFNBO Market

Quick answer  Indian green ammonia can qualify for the EU RFNBO market in principle, because the EU production rules apply to third-country producers. Cost, certification and offtake remain unproven. India's contracted volumes sit with Indian offtakers, we found no confirmed EU export contract, and over 40 GW of Indian projects lacked confirmed purchasers in November 2025 (H2-Tech, citing Reuters). India's SECI auction price of INR 55.75/kg applies to a contract with a named Indian offtaker (Paradeep Phosphates), not to European delivery.

3.1 Why India matters to RED III demand

• FINDING: India is a potential RFNBO supplier, not a regulated jurisdiction, and Stibbe (27 May 2026) confirms that the EU production rules apply to producers outside the EU who sell into it.

• SO WHAT: Indian exporters cannot rely on Indian policy to create European demand, so their volumes depend on European buyers and on the timing of EU rule changes.

• NOW WHAT: Judge an Indian export project on its signed offtake, not its nameplate capacity.

• Of the non-EU markets reviewed, India offers the clearest public price evidence, through the ammonia auctions run by the Solar Energy Corporation of India (SECI). That evidence describes contracts with Indian offtakers, and the sections below keep that distinction in view.

3.2 What India has actually contracted

• FINDING: SECI's first green ammonia auction under SIGHT Mode 2A cleared at INR 55.75/kg (about $641/t) for 75,000 t/yr on a 10-year fixed price, won by ACME Cleantech with Paradeep Phosphates as offtaker (pv magazine India, 31 July 2025).

• SO WHAT: The price sits between the $515/t grey ammonia and $1,153/t H2Global comparators quoted in the same report, but it is a fixed-price contract with an Indian offtaker and says nothing about delivered cost in Europe.

• NOW WHAT: Do not read the SECI price as an EU delivered price; ask exporters for a full delivered-cost build-up including certification.

That auction was the first of 13 covering 7.24 lakh t/yr. A follow-up headline reports a second price of INR 51.8/kg (pv magazine India, 5 August 2025), though we did not read the article body. Wood Mackenzie (single source) puts the bids at $550–700/t. Of 725 ktpa auctioned, it expects about 439 ktpa to be commissioned, while about 285 ktpa faces steeper odds. It also notes that some winners plan greenfield plants of 800,000 tpy to serve contracts under 100,000 tpy, so those plants would be far larger than the contracts they serve (outlook dated January 2026).

Our earlier report on green ammonia exports from India and China covers the wider export picture.

3.3 Export reality check

• FINDING: Renewable Energy Secretary Santosh Sarangi was reported as saying that India now expects its 5 MMtpy green hydrogen goal by 2032 rather than 2030, with 3 MMtpy by 2030 (H2-Tech citing Reuters, 11 November 2025; paraphrase, not a direct quote). The same report puts Indian projects without confirmed purchasers at over 40 GW.

• SO WHAT: H2-Tech reports a shift toward domestic uses in shipping, methanol and refineries, which leaves export projects without confirmed purchasers waiting for buyers.

• NOW WHAT: Discount any Indian export pipeline that lacks named buyers, and ask whether its volumes could fall back on domestic demand.

A Hydrogen Insight interview with Gautam Reddy, chief executive of AM Green, published on 17 June 2026, carries a headline saying the company will be ready to export RFNBOs for RED III deadlines but questioning whether Europe will be ready. We could not read the interview body, so we do not quote it. Domestic outlets such as methanol are one fallback; readers can weigh them in our comparison of green methanol versus green ammonia.

3.4 EU certification exposure

• FINDING: Additionality, temporal correlation and geographic correlation apply to third-country producers selling RFNBOs into the EU, and hourly matching starts in 2030 (Stibbe, 27 May 2026).

• SO WHAT: An Indian project's power-sourcing design is exposed to the same pending revision as a European one.

• NOW WHAT: Ask Indian sponsors how their power supply meets monthly matching now and hourly matching from 2030, and where their commissioning date falls against 1 January 2028, the date the current exemption refers to.

No source we reviewed quantifies the compliance cost for an Indian producer. The EU-wide estimates of $1–2/kg for the rules (Wood Mackenzie) and about €2/kg for hourly matching (S&P Global), each from a single source, are not Indian figures, and we do not apply them here.

Table 4: India export-readiness checklist

Checklist item	Evidence found	What the evidence shows
Export-oriented projects with named volumes	Partial	75,000 t/yr ACME Cleantech contract has an Indian offtaker (Paradeep Phosphates); 725 ktpa auctioned; no export volume tied to an EU buyer
EU certification of Indian output	Partial	Production rules apply to third-country producers (Stibbe); no certified Indian project identified
Delivered cost, India to EU	None	No delivered-cost data in the evidence; we do not estimate one
Named EU target markets and buyers	None	AM Green headline only; body text not read
Interaction of Indian incentives with EU rules	None	No source reviewed addresses it
Barriers to FID	Partial	Over 40 GW without confirmed purchasers (H2-Tech, 11 Nov 2025); about 285 ktpa of auctioned volume at risk (Wood Mackenzie)

Sources: pv magazine India (31 Jul 2025); pv magazine (9 Jan 2026); H2-Tech (11 Nov 2025); Stibbe (27 May 2026). All Secondary. No PIB, MNRE or SECI primary document was retrieved, and no named India quote falls inside the 12-month window.

Methodology note. Structured analyst judgement. "Partial" means at least one retrieved source addresses the item but not the full question; "None" means no retrieved source addresses it. The grades record the state of the evidence, not the state of Indian projects, and carry no score or ranking. The evidence set is the six sources listed above, read up to 14 October 2026.

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4. Operational and Technical Deep-Dive: Demand, Compliance and Cost

Quick answer  Industry estimates of 2030 RFNBO demand under RED III are 1.3 Mt a year (industry target only, Hydrogen Europe, June 2026), 2.8 Mt (industry, road transport, aviation and maritime, Hydrogen Europe Monitor 2025) and up to 3.3 Mt of business-case demand including derivatives (Hydrogen Council, May 2026). Projected supply of about 1.7 Mt covers roughly 60% of the 2.8 Mt figure. How much demand is bankable cannot be measured from public data, because contracted volumes are not published.

4.1 The three demand measures: mandated, achievable and contracted

• FINDING: The three demand estimates differ in scope as well as size: 1.3 Mt covers the industry target alone (Hydrogen Europe, June 2026), 2.8 Mt covers industry, road transport and refining, aviation and maritime under current rules (Monitor 2025) and up to 3.3 Mt counts renewable hydrogen and derivatives demand with a positive business case in Europe by 2030 (Hydrogen Council, 3 May 2026).

• SO WHAT: All three come from industry-sector bodies, and no Commission or IEA figure exists to arbitrate between them.

• NOW WHAT: State the scope with every demand number, and use the industry-only figure when sizing industrial offtake.

This report separates three measures. Mandated demand is what the law requires, achievable demand is what projected supply could meet, and contracted demand is what buyers have signed for, the only measure that services project debt. The first is estimated, the second projected and the third unpublished. The Hydrogen Council's 3.3 Mt is a fourth type, demand with a positive business case, and is shown separately.

On achievable demand, the Monitor 2025 projects 1.43 Mt of domestic supply plus 0.25 Mt of imports, about 1.7 Mt and about 60% of its 2.8 Mt demand estimate. The implied gap of roughly 1.1 Mt is our arithmetic, not a figure the source states. Hydrogen Europe's June 2026 paper adds that at a cost gap of €5/kg, 1.3 Mt implies about €6.5bn a year to close (p. 5). Contracted demand remains the blind spot, because no retrieved source reports signed RFNBO volumes by country or buyer.

Table 5: Three measures of 2030 RFNBO demand

Measure	Scope	Figure	Source and date
Mandated demand	Industry target only	About 1.3 Mt/yr	Hydrogen Europe, June 2026 (Primary, industry body)
Mandated demand	Industry (about 1.3 Mt), road transport and refining (about 1.1 Mt), aviation and maritime (at least 0.45 Mt), current rules	2.8 Mt	Hydrogen Europe Clean Hydrogen Monitor 2025 (Primary, industry body); also relayed by HydroNews, 2 Oct 2025
Business-case demand (not a mandate estimate)	Renewable hydrogen and derivatives with a positive business case in Europe by 2030	Up to 3.3 Mt/yr	Hydrogen Council, 3 May 2026 (Primary, industry body)
Achievable demand	Projected supply, 1.43 Mt domestic plus 0.25 Mt imports	About 1.7 Mt (about 60% of 2.8 Mt); implied gap about 1.1 Mt	Monitor 2025 via HydroNews; gap is GFJ arithmetic
Contracted demand	Signed offtake for RFNBO volumes	Not measurable from public data	No source found

 The 1.3 Mt and 2.8 Mt figures are advocacy-sector estimates of mandated demand, and the 3.3 Mt figure is advocacy-sector business-case demand. No Commission or IEA estimate of 2030 RFNBO mandated demand was retrieved.

Methodology note. The 1.7 Mt supply and the roughly 60% coverage are the Monitor 2025 projection as relayed by HydroNews (1.43 Mt domestic plus 0.25 Mt imports; 1.68 ÷ 2.8). The implied gap of about 1.1 Mt (2.8 − 1.7) is GFJ arithmetic. Scope is stated as each source describes it, and the figures are not additive.

4.2 National implementation scorecard

Quick answer  The European Hydrogen Observatory counted 8 of 27 Member States with both transport and industry RFNBO mandates transposed as of May 2026, naming Romania, Czechia, Slovakia, Lithuania, Latvia and Italy. Finland, Denmark and the Netherlands transposed transport elements only. Greece, Malta and Portugal were referred to the CJEU in April 2026. Other sources give different counts because they define transposition differently.

• FINDING: Hydrogen Europe's June 2026 paper says that more than a year after the deadline implementation across the EU "remains largely incomplete", and that some Member States apply no company-level obligation.

• SO WHAT: Legal status, ambition against 42% and enforcement vary state by state, so country selection matters more than the EU headline.

• NOW WHAT: Use the scorecard below to shortlist markets, then verify the national text before committing to offtake assumptions.

The scorecard grades evidence, not countries, and "Not found" means the retrieved sources are silent. Counts differ because definitions and dates differ. ACER, relayed by HydroNews on 2 December 2025, said only Denmark and Ireland had transposed the amended directive as a whole. Wood Mackenzie said only three states had set quotas by the end of 2025, two of them inadequate. The Commission sent letters of formal notice to 26 of 27 Member States in 2025, with only Denmark, reported as the one state to have fully transposed, excluded (SNEC-H2, 25 July 2025). BloombergNEF, cited by the Hydrogen Council on 3 May 2026, counted only 12 of 27 Member States with legislated RFNBO quotas. The Observatory counts RFNBO mandates specifically, which is why Denmark appears there as transport-only.

Italy and Germany show the spread. Italy transposed through Legislative Decree No. 5 of 9 January 2026, and Alberto Dossi, President of H2IT, said on 21 January 2026 that the decree "reserves an important role for renewable hydrogen", though Hydrogen Europe says Italy lacks credible enforcement. Germany enacted a transport quota (Bundestag in April, Bundesrat in early May 2026) starting at a 0.1% RFNBO share in 2026, but we found no German industry quota, and Wood Mackenzie says Germany will use subsidies instead of binding industry mandates. Hydrogen Europe also models that a Green Gas Quota could raise gas prices by over €13/MWh in Lithuania but under €1/MWh in Spain or France (p. 8).

Table 6: Evidence-graded implementation scorecard, selected Member States

Member State	Legal status	Ambition against 42%	Enforcement signal	Support signal	Evidence date
Germany	Transport quota enacted; industry quota not found	Not found	Transport RFNBO 0.1% in 2026; no binding industry mandate expected (Wood Mackenzie)	67 projects operating or under construction; Hydrogen Bank winner	Jan–May 2026
Italy	Transposed (Decree No. 5, 9 Jan 2026)	Not found	Lacks credible enforcement (Hydrogen Europe)	7 operating projects (25 MW)	Jan–Jun 2026
Czechia	Transposed	Below 42%	Not found	Not found	May–Jun 2026
Netherlands	Transport only; industry in draft	Draft below 42%	Not found	ELYgator 200 MW FID; Holland Hydrogen 1	May–Jun 2026
Spain	Not found	Not found	Not found	Hydrogen Bank winner; Cartagena 100 MW FID	Jan–May 2026
Lithuania	Transposed	Not found	Not found	Not found	May 2026
Romania, Slovakia, Latvia	Transposed	Not found	Not found	Not found	May 2026
Denmark	Transport only (Observatory); amended directive transposed (ACER)	Not found	Excluded from 2025 infringement wave	Hydrogen Bank winner	May 2026; Dec 2025
Finland	Transport only	Not found	Not found	Hydrogen Bank lowest bid, €0.44/kg	May 2026
Greece, Malta, Portugal	Not transposed; CJEU referral	Not applicable	Court referral; Recharge reports fines are possible	Greece: Hydrogen Bank winner	Apr 2026
France	Not found	Not found	Not found	25 projects operating or under construction	Feb 2026
Poland	Not found	Not found	Not found	Joined the March 2026 request for early review	Mar 2026

Sources: European Hydrogen Observatory; Hydrogen Europe (June 2026); HydroNews (24 Feb, 2 Dec 2025, 21 Jan 2026); WasserstoffNet (13 May 2026); Recharge (30 Apr 2026); pv magazine (7 May 2026). Member States not listed were not assessed.

Methodology note. Derived by structured analyst judgement, not a numerical model. For each Member State we record four criteria: legal status (transposed, partial, draft, not found); ambition against the 42% industry target (at, below, unknown); enforcement signal (penalty or obligated party identified, unclear, none found); and support signal (named public funding or auction wins). Each cell shows evidence or "not found" with a source date. No composite score or ranking is shown, and states with no retrieved evidence are listed as "not assessed". Ratings reflect public sources up to 14 October 2026 and will date quickly.

4.3 Production rules and the pending review

• FINDING: Under Delegated Regulation (EU) 2023/1184, hydrogen must match renewable power monthly until 2029 and hourly from 2030, and installations commissioned before 1 January 2028 are exempt from additionality until 1 January 2038 (Stibbe, 27 May 2026).

• SO WHAT: The exemption turns a commissioning date into a compliance asset, while the 36-month commissioning window offers no relief for permitting delay.

• NOW WHAT: Sequence permits and power contracts around the 1 January 2028 line, and ask whether the revision will grandfather projects built under current rules.

Additionality means the renewable power used must come from new capacity, and temporal correlation means production must match renewable generation within a set period (Delegated Regulation (EU) 2023/1184; Stibbe, 27 May 2026). Grid power can still count as renewable through three alternative routes: a bidding zone more than 90% renewable; a zone below 18 gCO2eq/MJ combined with a power purchase agreement; and curtailment periods. Developers securing matching power through contracts can compare structures in our Corporate PPA 2027 analysis.

Table 7: Delegated Regulation 2023/1184: current rule, requested change and Commission status

Element	Current rule	Requested change	Commission status
Temporal correlation	Monthly until 2029; hourly from 2030	Monthly matching to 2035 (Member States' request, Mar 2026)	Not addressed in a published proposal
Additionality	Installations commissioned before 1 Jan 2028 exempt until 1 Jan 2038	Transition to 2035 with grandfathering to 2040 (Member States); extension to 2035 and grandfathering (industry letter, 8 Jul 2026)	Targeted revision promised on 22 Apr 2026, protecting existing investments; unpublished on 21 Sep 2026
Bidding-zone threshold	More than 90% renewable	Assess lowering the threshold (Member States)	Not addressed in a published proposal
Commissioning window	36 months; no exemption for permitting delay	None identified in the evidence	No change reported
Review timing	Statutory review due in 2028	Early review requested	Promised for Q2 2026; still unpublished

Sources: Stibbe (27 May 2026); HydroNews (23 Apr 2026); joint industry letter hosted by Hydrogen Europe (8 Jul 2026); VDMA-hosted industry letter (21 Sep 2026, a position, not a statement of Commission intent). All Secondary except the letters, which are Primary advocacy documents.

4.4 Cost and enforcement economics

Quick answer  Public data cannot show that RED III penalties are high enough. Hydrogen Europe cites a Green Gas Quota penalty of €600/tCO2, while a BloombergNEF analysis cited by the Hydrogen Council says effective enforcement needs penalties above €10–12/kg and that penalties are too low in most Member States. The units differ and no emission factor links them. For scale, RFNBO hydrogen cost €7–10/kg in 2025 against about €2.00/kg for grey.

• FINDING: RFNBO hydrogen cost €7–10/kg in 2025 against about €2.00/kg for grey and €2.80/kg for carbon-abated hydrogen, and the production rules add $1–2/kg according to Wood Mackenzie and about €2/kg for hourly matching according to S&P Global.

• SO WHAT: The compliance gap runs at several euros per kilogram, so penalties must exceed it to move buyers, and the evidence does not show that they do.

• NOW WHAT: Ask each obligated buyer for its national penalty in €/kg terms before assuming it will purchase RFNBO hydrogen to comply.

The price gap rests on ACER's 2025 monitoring report as relayed by pv magazine (3 December 2025) and HydroNews (2 December 2025), so we treat it as a single origin. The relays also report ACER figures of about four times fossil hydrogen cost in 2024 and electricity at up to 50% of renewable hydrogen cost. The ACER webinar deck of 9 December 2025 that we read gives about €8/kg for renewable and about €4/kg for methane-based low-carbon hydrogen and does not contain the €2.00, €2.80 or €7–10/kg figures. Hydrogen Europe assumes a cost gap of €4–6/kg and says indirect cost compensation in Germany would cut cost by €1–2/kg. The IEA (via Argus Media, 19 June 2026; single source) puts 2025 electrolyser systems at $500–1,100/kW when Chinese-made and installed in China and $1,900–2,500/kW when made elsewhere.

The evidence does not support a penalty comparison. A penalty per tonne of CO2 can only be turned into a penalty per kilogram of hydrogen with a cited emission factor, and none is available, so we do not convert it. For a worked penalty comparison in another regulated fuel market, see our FuelEU Maritime 2026–2027 analysis.

Table 8: Cost and enforcement benchmarks

Benchmark	Figure	Source and date	Evidence strength
Grey hydrogen (SMR)	A little over €2.00/kg	ACER via pv magazine, 3 Dec 2025	Single origin, two relays
Carbon-abated (SMR with CCS)	€2.80/kg, excluding CO2 transport and storage; some estimates just under €3.00	ACER via pv magazine, 3 Dec 2025	Single origin
RFNBO hydrogen	€7–10/kg; HYDRIX average about €8.20/kg in 2025	ACER via pv magazine, 3 Dec 2025	Single origin
Cost of production rules	$1–2/kg; about €2/kg for hourly matching	Wood Mackenzie, 9 Jan 2026; S&P Global, 28 Apr 2026	Two single-source figures
Assumed cost gap	€4–6/kg	Hydrogen Europe, June 2026	Industry assumption
Electrolyser capex, 2025	$500–1,100/kW (China-made, in China); $1,900–2,500/kW (made outside China); $1,500–1,900/kW outside China possible by 2030	IEA via Argus Media, 19 Jun 2026	Single source
Green Gas Quota penalty	€600/tCO2	Hydrogen Europe, June 2026	Single source
Penalty needed for enforcement	Above €10–12/kg	BloombergNEF analysis via Hydrogen Council, 3 May 2026	Single-source relay; original not retrieved

 The last two rows use different units and are shown side by side only because both are sourced; no verified conversion exists.

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5. Named Company Case Studies: Who Has Offtake, Support and FID

Quick answer  Named final investment decisions are mostly subsidy-backed, and offtake terms are rarely disclosed. At least 9 of the 13 projects reaching FID in 2025 had grants or state aid (Westwood Energy, January 2026). The six cases below show captive refinery supply, a corporate tender and exporters waiting for buyers, and none discloses a price for RFNBO offtake. Investors should therefore ask who buys, on what term, and who funds the cost gap.

• FINDING: The 13 projects reaching FID in 2025 totalled about 450 MW, with the largest being Air Liquide's ELYgator at 200 MW and Repsol's Cartagena at 100 MW (Westwood Energy, January 2026, single source).

• SO WHAT: FIDs are happening where support or a captive buyer exists, which tells an investor to look for those two features and not for the mandate itself.

• NOW WHAT: Use the six cases below as a template for the questions to ask any sponsor: who buys, at what term, and who funds the gap.

Shell shows the captive-offtake model. Holland Hydrogen 1 in Rotterdam is a 200 MW alkaline electrolyser supplied by Thyssenkrupp Nucera, producing 60 t/day for the Pernis refinery (404,000 b/d), where it covers about 5–10% of hydrogen demand. It is powered by the 759 MW Hollandse Kust Noord wind farm, and operations are expected later in 2026 (S&P Global, 28 April 2026).

Andy Beard, Head of Hydrogen at Shell, told Platts in an interview on 22 April 2026:

"It's not easy, you see the complexity."

The article does not mention RFNBO or RED III, so we do not present the plant as a compliance response. The limit of the evidence is that the buyer and producer are the same company.

TotalEnergies and RWE show corporate procurement. TotalEnergies ran a tender for 500,000 t/yr of green hydrogen for its European refineries, with 40% secured, including a 15-year deal for 30,000 t/yr from RWE for Leuna (Energy Intelligence, 12 March 2025). That report is older than 12 months, and no price was disclosed, so it shows buyer intent, not current economics.

Air Liquide and Repsol represent the FID cohort. ELYgator (200 MW, Netherlands) and Cartagena (100 MW, Spain) were the two largest of the 13 projects reaching FID in 2025. At least nine of the 13 had grants or state aid, but the source does not say which, so we cannot attribute support to either project.

Everwind Fuels and Abraxas Power show exporters waiting for buyers. Everwind, at Point Tupper in Nova Scotia, will not break ground without offtake. Its Chief Financial Officer, Matthew Tinari, said in a Canadian Press report of 22 January 2026 that

"the last key piece of this whole thing is locking in the offtake contract".

Abraxas, a joint venture with EDF Power Solutions, plans a Botwood, Newfoundland project of 180,000 t of hydrogen and about 1 Mt of green-certified ammonia a year, with construction possibly starting in the first quarter of 2027 if approvals arrive. Chief Executive Colter Eadie said in the same Canadian Press report of 22 January 2026:

"we really don't see ourselves being uncompetitive in the market".

The report also notes that Pattern Energy withdrew its Newfoundland project and that World Energy GH2 shifted to wind, reportedly because a European green hydrogen market had not materialised.

Air Products at NEOM in Saudi Arabia is a 2.2 GW project in which Air Products is owner, operator and sole offtaker. Start-up is described as end-2026, with plans to deliver to Europe delayed and no immediate sales of molecules to European industry. The gasworld analysis is undated and paywalled, so treat the timing as unverified.

ACME Cleantech in India holds the 75,000 t/yr SECI contract at INR 55.75/kg described in Section 3. Wood Mackenzie warns that some winners plan 800,000 tpy greenfield plants to serve contracts under 100,000 tpy. The contract has a named offtaker, Paradeep Phosphates, and no European buyer.

Table 9: Project risk register

Project	Stage	Offtake evidence	Support evidence	Main risk
Shell Holland Hydrogen 1 (200 MW)	Construction; operations expected later in 2026	Captive: Pernis refinery, about 5–10% of its hydrogen	Not stated in source	Construction complexity (Beard)
TotalEnergies / RWE Leuna	Offtake contract	30,000 t/yr for 15 years; price not disclosed	Not stated	Evidence dated March 2025
Air Liquide ELYgator (200 MW)	FID 2025	Not disclosed	Project-level support not stated	Offtake and rule-change exposure
Repsol Cartagena (100 MW)	FID 2025	Not disclosed	Project-level support not stated	Offtake and rule-change exposure
Everwind Fuels (Nova Scotia)	Development	None yet; will not break ground without it	EU and Canadian support for exports to Germany (general)	No signed offtake
Abraxas Power (Newfoundland)	Development; construction possible Q1 2027	Not disclosed	EU and Canadian support for exports to Germany (general)	Approvals; offtake
Air Products NEOM (2.2 GW)	Start-up described as end-2026, delayed	Captive: Air Products sole offtaker	Not stated	No immediate European sales; source undated
ACME Cleantech (India)	Auction awarded; later stage not stated	Domestic: Paradeep Phosphates, 10-year fixed price	SECI/SIGHT procurement	No European buyer; plant sizing exceeds contract

 Sources: S&P Global (28 Apr 2026); Energy Intelligence (12 Mar 2025); Westwood Energy (Jan 2026); Energy Now (22 Jan 2026); gasworld (undated); pv magazine India (31 Jul 2025). All Secondary.

Methodology note. Stage labels follow the evidence available: announced, development, FID, construction, operating. The offtake and support columns record only what each source states, and "not disclosed" or "not stated" is used where terms are unpublished. No project is rated bankable or unbankable. The register shows exposure, not a credit opinion.

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6. Friction, Risk and Systemic Bottlenecks

Quick answer  The biggest bottleneck is that regulatory demand is not yet bankable demand. Flexibilities can dilute the 42% target, penalties may be too low, the production rules may change, and most FIDs depend on public money. Secondary bottlenecks include electrolyser overcapacity of about 58 GW/yr against about 9% utilisation (IEA via Argus Media, 19 June 2026), a tight 36-month commissioning window and policy reversal in the United States.

6.1 The critical unresolved issue: regulatory demand is not yet bankable demand

• FINDING: Wood Mackenzie's January 2026 outlook expects the Commission to accept dilution of the industry target instead of enforcing it, with Germany relying on subsidies and not binding industry mandates (single source, 9 January 2026).

• SO WHAT: If the largest economy meets its target through subsidy and the enforcer accepts dilution, statutory demand will not translate into offtake contracts at scale.

• NOW WHAT: Weight your underwriting toward volumes with a named buyer, and treat the legal target as a ceiling on demand, not a floor.

Most RED III analysis stops at the 42% target and the transposition count and does not test whether national designs create an enforceable, financeable obligation. Seven pieces of evidence point in the same direction.

1.    Design leakage. Hydrogen Europe's June 2026 paper (pp. 4–18) describes flexibilities including a Green Gas Quota with a 3x multiplier, transport-credit routes, imports and statistical transfers. A headline target can be met on paper with less physical RFNBO hydrogen.

2.    Penalty level. The €600/tCO2 penalty and the BNEF-cited requirement of above €10–12/kg cannot be reconciled from the public data, and the Hydrogen Council says penalties are too low in most Member States.

3.    Inconsistent demand estimates. The 1.3, 2.8 and up to 3.3 Mt figures come from industry bodies, and supply covers about 60% of the middle one.

4.    Enforcement credibility. The Commission referred three states to the CJEU in April 2026, but that route addresses missing transposition, not weak quotas in states that transposed.

5.    Rule-change risk. The revision promised for Q2 2026 was unpublished on 21 September 2026. The industry letter of that date says "projects cannot reliably assess their business cases, financing conditions or future compliance costs." Grandfathering is requested by industry and not confirmed by the Commission.

6.    Post-2030 pressure. Reported on 24 September 2026, 170 companies asked Brussels to keep binding targets beyond 2030. Jorgo Chatzimarkakis, Chief Executive of Hydrogen Europe, said: "This is a test of Europe's credibility". François Paquet, Managing Director of the Renewable Hydrogen Coalition, said in the same report: "Europe needs investment. Investment needs certainty. Certainty needs binding RFNBO targets".

7.    Offtake reality. Murray Douglas, Vice President, Hydrogen and Derivatives Research at Wood Mackenzie, said in the firm's outlook reported on 9 January 2026: "Projects advance where policy and offtake align, and stall where either remain uncertain." The evidence matches: most 2025 FIDs were supported, and Canadian developers and NEOM wait on buyers.

Three questions remain open in every source we reviewed:

the penalty per kilogram in each Member State, the share of the 42% that flexibilities can absorb, and the grandfathering text in any Commission draft. Until they are answered, bankable demand cannot be sized from public information.

6.2 Secondary bottlenecks

• FINDING: Global electrolyser manufacturing capacity reached about 58 GW/yr at the end of 2025 against output under 5 GW, a utilisation near 9% (GFJ arithmetic), and the IEA says the sector is "entering a consolidation phase as overcapacity, weak demand and financial strain force a shake-out" (Argus Media, 19 June 2026, relayed by a secondary source).

• SO WHAT: Equipment is available, so the constraint is demand and finance, and supplier strain is itself a counterparty risk.

• NOW WHAT: Check warranty, service and supplier-solvency terms in every electrolyser contract.

The IEA adds that the strain on electrolyser firms "also poses a risk to reducing the cost of renewable hydrogen production", and Cummins halted electrolyser sales after filling existing orders. Europe holds 20% of global manufacturing capacity, and EU capacity of 13.1 GW/yr online at the end of 2025 far exceeds local demand (Hydrogen Insight, 23 February 2026). On the supply side of the project, the 36-month commissioning window has no exemption for permitting delay (Stibbe), and developers who also need new renewable generation can follow capital trends in our offshore wind investment intelligence report. Outside Europe, the US moved its 45V construction-start deadline forward by five years and proposed cancelling more than $3bn of hub funding, and Wood Mackenzie expects at least three large Middle East projects to be cancelled or scaled back.

Table 10: Risk matrix

Risk	Evidence	Likelihood	Investor impact	Who is exposed
Flexibilities dilute the 42% target	Hydrogen Europe, June 2026 (industry body)	High	High	Merchant producers selling to industry
Weak or unproven penalties	Hydrogen Council citing BNEF; Hydrogen Europe (single-source)	Medium	High	Producers relying on compliance purchasing
Delegated-act revision delayed or unfavourable	Industry letters, 8 Jul and 21 Sep 2026	High	Medium	Projects commissioning near 1 Jan 2028
Commission accepts retreat on industry target	Wood Mackenzie, 9 Jan 2026 (single-source)	Medium	High	All EU merchant projects
Post-2030 targets weakened	Call by 170 companies, 24 Sep 2026	Medium	High	Projects with debt tenor beyond 2030
Subsidy dependence	Westwood Energy, Jan 2026 (single-source)	High	Medium	Projects without secured support
Electrolyser overcapacity and supplier stress	IEA via Argus Media, 19 Jun 2026 (single-source)	High	Medium	Equipment buyers needing long warranties
Export projects without EU contracts	H2-Tech, 11 Nov 2025; Energy Now, 22 Jan 2026	High	High	Canadian, Indian and Gulf exporters

Methodology note. Structured analyst judgement. Each risk is rated Low, Medium or High for likelihood and for investor impact, using the number of independent sources, the recency of the evidence (within 12 months) and whether a regulator or only industry stated it. Risks supported by a single source are labelled "single-source". The ratings are not probabilities.

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7. Capital and Investment Implications

Quick answer  Investors should screen RFNBO hydrogen projects on four inputs: the target market's national law status, offtake status, public support and exposure to the production rules. Projects with binding physical offtake, secured support and commissioning before 1 January 2028 carry the lowest regulatory-demand risk. Merchant and export projects without contracts carry the highest. The screen is a risk aid, not a valuation.

7.1 Where bankable exposure exists

• FINDING: The evidence shows bankable exposure in three places: captive refinery supply such as Shell's Holland Hydrogen 1, grant-backed FIDs, and the Hydrogen Bank, whose third auction awarded fixed premiums of €0.44–3.49/kg to 9 projects (pv magazine, 7 May 2026).

• SO WHAT: Each puts a contract or a subsidy between the project and the mandate, which is what lenders can rely on.

• NOW WHAT: Prefer projects where at least one of these supports sits in a signed document, and identify which government pays it.

Westwood Energy reports that about 82% of 2026 electrolyser additions come from five projects with €2.0–2.1bn of public support, and Hydrogen Bank bids exceeded the budget more than six times. In this evidence, capital sits behind contracts and grants.

7.2 Where it does not

• FINDING: Three exposures lack a supporting contract in the evidence: merchant sales into Member States with diluted or absent obligations, export projects without EU contracts, and projects exposed to the pending delegated-act revision.

• SO WHAT: These projects carry the full cost gap, or the full rule-change risk, on their own balance sheets.

• NOW WHAT: Require price or volume protection in the term sheet, or size the position as an option on policy.

NEOM does not plan immediate sales to European industry, Canadian developers wait on offtake, and over 40 GW of Indian projects lacked confirmed purchasers in November 2025. For wider deal flow, see our New Energy M&A Playbook 2026–2027. No return, internal rate of return or project valuation data exist in the research behind this report, so we do not offer any.

7.3 The investor decision screen

• FINDING: Four inputs separate exposure levels in the evidence: national law status (Table 6), offtake status (Table 9), public support (Section 5) and production-rule exposure (Table 7).

• SO WHAT: A project can score well on three inputs and still fail on the fourth, so the screen needs all four.

• NOW WHAT: Apply the rules in Table 11 to each project, record the missing evidence, and re-run the screen when the amended delegated act appears.

Table 11: Investor decision matrix, RFNBO Project Exposure Screen

Exposure tier	Rule (all conditions must hold)	What would change the tier
Lower	Binding physical offtake; public support secured; target market's law at or above 42% for industry; commissioning before 1 January 2028 or a qualifying grid route	Loss of support; a revised delegated act that removes the commissioning exemption
Moderate	Any combination that meets neither the Lower nor the Higher rule	Signing binding offtake or securing support (moves toward Lower); losing either (moves toward Higher)
Higher	Offtake is not binding (MoU, tender participation or none) and the target market's law is below 42%, has no company-level obligation, is in draft or was not found	Binding offtake; adoption of a national obligation at or above 42% with enforceable penalties

Methodology note. Structured analyst judgement. The screen combines four inputs (national law status, offtake status, public support, production-rule exposure) into three tiers: Higher, Moderate and Lower exposure to regulatory-demand risk. The criteria are that contracted physical offtake outweighs statutory demand, that public support reduces but does not remove risk, and that commissioning before 1 January 2028 changes additionality exposure under the current delegated act. The screen is a risk-screening aid, not a valuation or investment recommendation.

Worked example: the cost gap an obligated buyer faces, and the screen applied to an illustrative project

Illustrative parameters (not sourced): an industrial site uses 100,000 t/yr of hydrogen; a developer proposes a 20,000 t/yr project that would supply 47.6% of the 42,000 t obligation (20,000 ÷ 42,000); the national obligation is tested at 42% and at 30%. Sourced figures: RFNBO price of €8.20/kg (HYDRIX average, 2025) and grey hydrogen at €2.00/kg (both from ACER via pv magazine, 3 December 2025), and Hydrogen Europe's cost-gap assumption of €4–6/kg (June 2026).

Formula: annual gap = site hydrogen use × obligation share × (RFNBO price − grey price).

1.    Gap per kilogram: €8.20 − €2.00 = €6.20/kg.

2.    Obligated volume at 42%: 100,000 t × 0.42 = 42,000 t, or 42,000,000 kg. Annual gap = 42,000,000 kg × €6.20 = €260.4m. Spread across all 100,000 t, that is 0.42 × €6.20 = €2.60/kg, about 130% on top of the €2.00/kg grey price.

3.    Sensitivity to Hydrogen Europe's gap range: at €4/kg the annual gap is €168.0m; at €5/kg it is €210.0m; at €6/kg it is €252.0m.

4.    If the national obligation is 30% (illustrative): 30,000 t, or 30,000,000 kg, × €6.20 = €186.0m, or €1.86/kg blended. The buyer's annual gap falls by €74.4m (28.6%), and the producer's addressable volume falls by the same 12,000 t.

5.    Screen: assume the project targets a market whose law sits below 42%, holds only a memorandum of understanding for offtake, has applied for support, and commissions after 1 January 2028. Offtake is not binding and the law is below 42%, so the project screens as Higher exposure. A binding offtake and a secured support award would move it to Moderate, not Lower, because the law is still below 42% and commissioning falls after the exemption date.

The example uses average prices and an illustrative site. It converts no penalty into €/kg and is not a return calculation. Replace the volume, obligation share and prices with your own. All outputs are GFJ arithmetic on the stated inputs, and the two price inputs share the single-origin caveat in Table 8.

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8. Future Scenarios and Forecast, 2026–2035

Quick answer  A weaker post-2030 RFNBO mandate would raise risk for projects that depend on statutory demand, but returns cannot be quantified from public data. The effect would run through offtake volumes, plant utilisation, margins and refinancing. Projects with contracted volumes and public support are the most resilient, and merchant and export projects the most exposed. No law weakening post-2030 targets has been adopted or proposed in the evidence reviewed.

• FINDING: Five dates anchor the outlook: 1 January 2028 (commissioning line), 2028 (statutory review), 2030 (hourly matching), 2035 (60% industry target) and 1 January 2038 (end of the additionality exemption for pre-2028 installations).

• SO WHAT: Each date moves risk to a different group of projects, so the relevant scenario depends on when a project is financed and when it commissions.

• NOW WHAT: Map each project's debt tenor and commissioning date against these five dates before assigning weight to any scenario.

Scenario A:

mandates hold and are enforced. The Commission publishes a revision that grandfathers existing projects, and Member States adopt obligations at or near 42% with enforceable penalties. Contracted demand and utilisation rise, refinancing risk falls, and Indian exporters gain a real route to market, though cost and certification still decide who wins. We rate this Low in likelihood because transposition is incomplete and the revision is overdue.

Scenario B:

mandates are diluted by national design and non-enforcement. This is the outcome Wood Mackenzie expects. Obligations stay below 42% or lack company-level teeth, the Commission accepts the retreat, and subsidy replaces mandate as the demand driver. Contracted demand and utilisation stay low, refinancing risk is high for merchant projects, and exporters without European contracts bear the loss. We rate this High in likelihood.

Scenario C:

the framework is redesigned after 2030. The call by 170 companies on 24 September 2026 to keep binding targets beyond 2030 is the only evidence in our research that the post-2030 position is in question. No proposal or adopted law exists, so this is a scenario and nothing more. If binding targets were weakened, projects with debt running past 2030 would carry the most refinancing risk, and the 2035 target of 60% would lose its anchor. We rate this Medium in likelihood.

Table 12: Scenario matrix, 2026–2035

Scenario	Trigger	Contracted demand	Utilisation	Refinancing risk	Indian exporter exposure	Likelihood
A: Mandates hold	Revision with grandfathering; obligations at or near 42% with enforced penalties	High	High	Low	Medium	Low
B: Mandates diluted	National design below 42%; Commission accepts retreat	Low	Low	High	High	High
C: Post-2030 redesign	Binding targets not extended beyond 2030 (not adopted law)	Low after 2030	Medium	High for debt beyond 2030	High	Medium

Methodology note. Derived by structured analyst judgement. Scenarios A, B and C are defined by policy triggers: full enforcement, national dilution and post-2030 redesign. Likelihood is shown as Low, Medium or High, not as a percentage, using four criteria: current transposition evidence, penalty adequacy, Commission enforcement behaviour, and industry and Member State pressure. No probability weights are applied because no source supports numeric probabilities. Scenario C draws on reporting about possible changes to the post-2030 framework, which is not adopted law.

Four observable indicators would move a reader between scenarios: publication of the amended delegated act and whether it grandfathers existing projects; the number of Member States with industry obligations at or above 42%; disclosure of national penalty levels in comparable units; and the Commission's response to the call by 170 companies. Signed offtake announcements with named counterparties would be the strongest single signal of a shift toward Scenario A.

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9. Strategic Recommendations

Quick answer  Investors should underwrite on contracted, subsidised volumes and treat RED III statutory demand as upside until national enforcement and the delegated-act revision are clear. Producers should secure permits and power contracts to commission before 1 January 2028 where feasible. Policymakers can lower risk by publishing the revision with explicit grandfathering and by disclosing national penalty levels in comparable units. This guidance reflects evidence up to 14 October 2026.

9.1 For investors

• FINDING: At least 9 of the 13 projects reaching FID in 2025 had public support, and no source reports signed RFNBO offtake totals.

• SO WHAT: Statutory demand is unproven upside, so the downside case must work without it.

• NOW WHAT: Require four documents before allocation: a binding offtake agreement, a support award, a price or volume adjustment if the production rules change, and evidence of national enforcement.

Size merchant exposure small, and re-run the Table 11 screen when the revised delegated act appears. Keep the 1 January 2028 commissioning line in every model.

9.2 For industry and producers

• FINDING: Installations commissioned before 1 January 2028 keep the additionality exemption, and the 36-month commissioning window offers no relief for permitting delay (Stibbe, 27 May 2026).

• SO WHAT: A producer that slips past the date could face a stricter rule than the one it financed on.

• NOW WHAT: Fix permits and power contracts first, then pursue offtake from industrial buyers that face company-level obligations.

Producers weighing outlets beyond industry can compare the shipping fuel market in our Green Shipping Fuels 2027 analysis.

9.3 For policymakers

• FINDING: Industry letters of 8 July and 21 September 2026 ask for a timetable and a final proposal before year-end, and the Hydrogen Council says penalties are too low in most Member States.

• SO WHAT: Investors cannot price compliance without a published revision, grandfathering terms and penalty levels.

• NOW WHAT: Publish the delegated-act proposal with explicit grandfathering, and disclose national penalties in comparable units.

Action for the energy investor: before approving the next RFNBO hydrogen allocation, ask the sponsor for the signed offtake agreement, the national penalty in €/kg, the support award letter and the commissioning date relative to 1 January 2028, then run the Table 11 screen and decline to rely on statutory demand where any of the four is missing.

Continue reading part II; https://www.greenfueljournal.com/post/red-iii-rfnbo-targets-2030-part-ii