The Department of Climate, Energy and the Environment published the Draft Heads of the Renewable Heat Obligation Bill 2025 in July 2025, setting out the framework for a new obligation on fossil fuel suppliers to ensure that a prescribed percentage of the energy they supply for heating comes from renewable sources.

The Renewable Heat Obligation (RHO) mirrors the existing Renewable Transport Fuel Obligation (RTFO) operated by NORA, but applies it to the heating sector, a part of Ireland’s energy system where decarbonisation has lagged well behind electricity and transport.

The Bill is currently in priority drafting, having been notified to the European Commission under Directive (EU) 2015/1535 on 23 December 2025. On 29 March 2026, the Commission issued a formal Detailed Opinion finding that one of the Bill’s central design features, a multiplier favouring indigenously produced biomethane, is incompatible with EU internal market rules. The standstill period has been extended to 29 June 2026, and a redesign in some form is now inevitable. For renewable fuel producers, fossil fuel suppliers, and investors in Ireland’s energy transition, this article sets out what the draft legislation contains, who it catches, what the Commission has said, and what it all means in practice.

The Obligation in Outline

The Bill establishes a Renewable Heat Obligation Scheme to run until 31 December 2045. Suppliers of fossil fuels used for heating – natural gas, LPG, mineral oils, and solid fuels (coal, coal products, and petroleum coke) – will be required to demonstrate that a specified percentage of the energy they place on the market is from renewable sources. Commencement was originally targeted for mid-2026, with the first obligation period running as a six-month stub year to end-2026 and the second covering the full calendar year 2027. That timing is no longer realistic; commencement is now expected in 2027.

The National Oil Reserves Agency (NORA) is designated as the Scheme Administrator, reflecting its existing role under the RTFO. NORA will open and maintain accounts for each obligated party, issue renewable heat obligation certificates, monitor compliance, and collect the renewable heat levy.

Compliance operates through a certificate system. For each gigajoule of renewable heating fuel disposed of in the State, an account holder receives one certificate. These certificates are then debited against the obligated party’s annual obligation. Certificates are valid for the obligation period in which they are issued plus two further years, providing a degree of banking flexibility, though from a date to be specified, banked certificates may not discharge more than 15% of any subsequent year’s obligation.

Who Is Caught, And Who Isn’t

The obligation applies to suppliers of heating fuels who are liable for excise duty or other Government levies on those fuels. The draft sets the threshold at 400 GWh of fuels used for heating purposes per annum. Suppliers below that volume are exempt. According to the Bill’s explanatory notes, the 400 GWh threshold captures approximately 93% of the fossil fuel for heat market, targeting larger suppliers with the administrative capacity to operate within the scheme.

The Minister retains power to adjust this threshold by regulation, including the ability to prescribe individual thresholds for different fuel categories. Any adjustment requires consultation with a broad

group of statutory bodies, including the Ministers for Finance, Public Expenditure, and Transport, as well as the EPA, NSAI, SEAI, and NORA, followed by a 28-day public consultation period.

Renewable fuel producers and suppliers who are not themselves obligated parties can also open accounts under the scheme, enabling them to earn and trade certificates. This is a deliberate design choice to create a functioning certificate market.

Obligation Rates: A Cautious Start

The initial obligation rate is set at 1.5% across all four fuel categories (natural gas, LPG, mineral oils, and solid fuels) in the first obligation period, rising to 3% in the second. The Bill’s explanatory notes indicate that market analysis confirmed sufficient renewable fuel capacity to meet these levels.

From year three onwards, the Minister will set rates by regulation, informed by further market analysis and subject to the same multi-party consultation process. The trajectory beyond year two is therefore uncertain; it will depend on the pace at which the renewable fuel supply chain develops and on broader heat policy objectives. For anyone modelling long-term compliance costs or investment cases, that uncertainty is a material factor.

Certificate Trading and Cross-Fuel Flexibility

To reduce compliance costs and provide flexibility, the Bill allows certificate trading between account holders and limited cross-category transfers. Head 9 sets an initial cap of 50% on cross-fuel category transfers for natural gas, LPG, and mineral oils, meaning an obligated party must source at least half of its obligation through renewable fuel corresponding to its own fuel type. Solid fuels are excluded from cross-category trading entirely.

These caps are adjustable by ministerial regulation. The intent is to maintain a minimum level of renewable fuel penetration within each fuel category while giving obligated parties room to manage supply constraints. The Minister can also set conditions on the minimum and maximum number of certificates transferable in any obligation period.

For biomethane producers, the certificate structure is the central commercial question. Head 14 provides that domestically produced biomethane receives an additional 0.5 certificates per gigajoule on top of the standard one certificate, a multiplier of 1.5 in total. The explanatory notes are candid about the rationale: analysis during the design process found that without this uplift, imported biomethane would dominate the scheme and no indigenous biomethane would be used. The multiplier was expressly described as a “measure of equivalent effect” under Article 34 TFEU and notified to the European Commission on the EU’s Technical Regulations Information System (TRIS) on 23 December 2025 under Directive (EU) 2015/1535.

On 29 March 2026, the Commission issued a formal Detailed Opinion. It found that the multiplier is a measure of equivalent effect to a quantitative restriction on imports under Article 34 TFEU and cannot be justified under Article 36. Applying the four-limb proportionality test, the Commission concluded that the measure failed at every stage:

1. the justification advanced was characterised as purely economic, which is not a legitimate public interest;
2. biomethane produced in other Member States would equally contribute to the renewable energy objective;
3. less restrictive alternatives, including direct support measures targeted at domestic producers, had not been ruled out; and
4. the temporary nature of the measure was not adequately substantiated.

The Commission also flagged the disguised restriction limb of Article 36 and indicated it stands ready to bring infringement proceedings under Article 258 TFEU if the measure is enacted unchanged.

The procedural consequence is a six-month standstill, running until 29 June 2026, during which Ireland cannot adopt the measure and must respond formally to the Commission’s objections. The substantive consequence is that the multiplier as drafted will not survive enactment without redesign. The Government has three broad options:

1. build an alternative support mechanism for indigenous producers operating outside the obligation (a direct producer-side subsidy or capital grant uplift, designed to comply with State aid rules);
2. remove the multiplier and accept the consequences for domestic biomethane economics; or
3. proceed with the measure unchanged and meet infringement proceedings.

Each option carries materially different consequences for offtake values, project finance, and the timing of investment decisions in the indigenous AD sector.

The Buy-Out Mechanism

Where an obligated party fails to discharge its obligation in full through certificates, it must pay a buy-out charge calculated as the shortfall in gigajoules multiplied by a prescribed buy-out price per gigajoule. The buy-out price is set by ministerial regulation, with the Minister required to have regard to market prices for heating fuel, wholesale availability and market prices for renewable heating fuel, and the level needed for the obligation to operate effectively.

Unpaid buy-out charges accrue interest, and the Administrator can recover amounts as a simple contract debt. All buy-out moneys are paid to the Exchequer, not recycled into the scheme. This is a policy choice worth noting: unlike some comparable schemes in other jurisdictions, the buy-out fund does not directly subsidise renewable fuel production.

The Renewable Heat Levy

Separately from the buy-out charge, the Bill imposes a renewable heat levy on account holders to fund the scheme’s administration. The levy is set at €0.001 per litre of relevant disposals of renewable heating fuel per month. NORA administers collection, and standard provisions apply for volume assessment, levy notices, interest on unpaid amounts, and recovery.

The levy is modest in isolation but will be a recurring cost for account holders. Claims for overpayment must be made within 18 months of the end of the year in which the overpayment occurred, with a minimum claim interval of three months.

Enforcement and Penalties

The enforcement framework follows the NORA Act model. Authorised officers (including Customs and Excise officers, auditors appointed by the Administrator, and officers appointed by the Minister) have broad inspection and entry powers, including the right to enter premises, inspect records, remove documents, take photographs, and carry out tests on plant and equipment. Search warrants may be obtained from the District Court. Officers who discover non-compliance or health and safety risks during inspections are required to report to the relevant authority, which may include the Gardaí, the HSA, the EPA, the local authority, or Revenue.

Criminal penalties on summary conviction are a fine of up to €5,000, imprisonment of up to six months, or both. Continuing offences attract a further fine of up to €250 per day. The absence of indictable offence provisions is notable, the enforcement regime relies entirely on summary proceedings, with a two-year limitation period from the date of the alleged offence.

Interaction with Existing Frameworks

The RHO sits within a crowded policy landscape. It implements a specific commitment under the Sectoral Emissions Ceilings decision (S180/20/10/2704) and is intended to drive progress towards Ireland’s RES-H (Renewable Energy Share – Heating) targets. It operates alongside the Support Scheme for Renewable Heat (SSRH), the National Energy and Climate Plan (NECP), and the broader Climate Action Plan framework.

At EU level, the Bill cross-references the recast Renewable Energy Directive (RED III, Directive (EU) 2023/2413) and the original RED II (Directive (EU) 2018/2001). Sustainability and greenhouse gas emissions criteria for renewable fuels under the scheme are aligned with Article 28(5) of RED II and the European Union (Biofuel Sustainability Criteria) Regulations 2012. High ILUC-risk feedstock is excluded, bioliquids and biogas produced from such feedstock cannot earn certificates under the scheme.

The RTFO provides the closest domestic comparator. Both schemes use NORA as administrator, both operate through a certificate and buy-out mechanism, and the Bill’s drafting draws heavily on the NORA Act. Obligated parties already managing RTFO compliance will find the administrative architecture familiar, though the fuel categories, threshold levels, and certificate multipliers are distinct.

Key Risks and Uncertainties

Several aspects of the Bill deserve scrutiny.

First, the obligation rates beyond year two are entirely unspecified. The Bill provides a framework for the Minister to set rates by regulation, but there is no indicative trajectory, no ratchet mechanism, and no statutory floor. Investors and project developers will need to make assumptions about the rate pathway without legislative certainty beyond 2028.

Second, the redesign of the biomethane support mechanism is unresolved. The Detailed Opinion has determined the legal direction of travel but not the policy outcome. Whether the Government replaces the multiplier with a producer-side subsidy, removes domestic preference altogether, or pursues some hybrid will materially change the investment case for indigenous AD projects. Until the redesign is settled, business plans built on the 1.5x certificate value should not be relied upon.

Third, the buy-out price is left to ministerial regulation. This is the single most important variable determining whether the obligation drives genuine renewable fuel deployment or simply generates Exchequer revenue. If set too low, obligated parties will pay rather than source renewable fuel. If set too high, heating costs for consumers increase disproportionately. The criteria in Head 10 give the Minister broad discretion but limited constraint.

Fourth, enforcement is exclusively summary. The €5,000 fine ceiling and six-month imprisonment maximum may not provide a credible deterrent for large fuel suppliers whose compliance shortfalls could involve significant volumes and values.

Finally, the legislative timetable has slipped. With the standstill running until 29 June 2026 and a Commission response still to be formulated, mid-2026 commencement is no longer realistic and 2027 has become the working assumption. Several critical dates, scheme commencement, obligation period start and end dates, the date from which banking restrictions apply, remain to be fixed in the formal Bill. Until they are, the practical timeline for compliance preparation remains uncertain.

What to Do Now

Fossil fuel suppliers above or near the 400 GWh threshold should begin assessing their exposure. That means quantifying their heating fuel volumes, identifying which fuel categories they supply, and modelling the cost of compliance at the initial 1.5% and 3% obligation rates.  This should include the relative economics of sourcing renewable fuel versus paying the buy-out charge.

Renewable fuel producers, particularly biomethane developers, should stress-test their business plans against a no-multiplier scenario. The Detailed Opinion makes the 1.5x certificate value unsafe as a planning assumption. Where investment cases were predicated on the multiplier, the realistic question is whether projected obligation volumes, buy-out price levels and the rate trajectory beyond year two are enough on their own, and what additional support – capital grants, a producer-side subsidy outside the obligation, or higher initial obligation rates – would close any gap. Engagement with the Department on the redesign of the support mechanism will matter more in the coming months than engagement on the obligation rate.

Investors and lenders should factor the RHO into project finance models for anaerobic digestion, biomethane injection, and other renewable heat projects. The scheme’s 2045 duration provides a long-term policy signal, but the reliance on ministerial regulation for rate-setting introduces a layer of political risk that will need to be priced.

All market participants should monitor the legislative timetable closely. Priority drafting is underway, the TRIS notification has issued, and the Commission has formally responded; Oireachtas scrutiny and commencement orders still lie ahead, with the standstill period running until 29 June 2026 at the earliest. The next signals worth watching are the Government’s formal response to the Detailed Opinion, any redesign of the biomethane support mechanism, and whether the Bill is brought forward before the summer recess or held over to the autumn term. Early engagement with the Department, particularly on the buy-out price, the rate trajectory, and any replacement support mechanism for indigenous renewable fuel producers, will be important for those with a commercial stake in the outcome.

Please contact Jason Milne for further information.