Welcome to the first issue of 2025 of our Energy Sector Update series. In this issue, we examine a selection of topics and trends impacting our clients during the course of the coming year.
Eoin Cassidy, Energy Sector Lead Partner, shares his insights on the key developments for businesses and investors to look out for in the coming year.
Some of our featured articles include:
• Ireland’s Investment Screening Regime - Key Considerations for Energy Transactions
• Data Centres in Ireland – Energy Concerns
• Ireland’s New Small-Scale Renewable Electricity Support Scheme
• Changes to Energy Audit and Management Obligations
Should you wish to discuss these topics or any other issues impacting your organisation, please contact a member of our Energy Sector team.
Key Contacts
Eoin Cassidy Partner, Energy Sector Lead ecassidy@mhc.ie
Peter McLay Partner, Construction, Infrastructure & Utilities pmclay@mhc.ie
Contact our Energy Sector team
Ireland’s Investment Screening Regime
is Now in Effect
Tara Kelly Partner, Head of Competition, Antitrust & Foreign Investment
+353 86 145 5201
tarakelly@mhc.ie
The Screening of Third Country Transactions Act 2023 (the Screening Act) came into effect on 6 January 2025.
The Screening Act gives the Minister for Enterprise, Trade and Employment the power to review certain acquisitions by foreign investors that relate to, or impact on, a number of broad categories of sensitive and strategic sectors or activities, including the energy sector.
Parties to a transaction that meets the relevant criteria set out in the Screening Act must now notify and obtain approval from the Minister prior to completing the transaction. Failure to do so is a criminal offence, punishable by fines. Therefore, in the case of energy transactions directly or indirectly involving foreign acquirers, careful consideration is required as to whether the transaction triggers a notification requirement. Helpfully, the Minister recently published the final ‘Inward Investment Screening Guidance’ (the Guidance), which clarifies several elements of the Screening Act, including aspects of the notification criteria.
How the Screening Act applies to the energy sector
Similar to the existing Irish merger control rules, the Screening Act creates a mandatory and suspensory notification regime for transactions meeting certain criteria. A transaction will be notifiable to the Minister where all of the following four criteria apply:
Laura Durning Partner, Competition, Antitrust & Foreign Investment
+353 87 776 2593
ldurning@mhc.ie
1. A “third-country undertaking”, ie from outside the EU/EEA and Switzerland, or a person connected with such an undertaking:
• Acquires control of an asset or an undertaking in the State, or
• Changes the percentage of shares or voting rights it holds in an undertaking in the State:
• From 25% or less to more than 25%, or
• From 50% or less to more than 50%
2. The cumulative value of the transaction and any related transactions in a period of 12 months prior to the date of the transaction is at least €2 million.
This threshold relates to the entire value of the consideration being paid by the acquirer. In other words, the threshold is linked to the total purchase price paid by the acquirer, including any international dimension.
3. The same undertaking does not, directly or indirectly, control all the parties to the transaction, ie the transaction is not an internal re-organisation.
4. The transaction relates to, or impacts on, one or more of the following matters referred to in the EU Screening Regulation:
• Critical infrastructure, whether physical or virtual, including infrastructure in the energy sector, among other critical sectors
• Critical technologies and dual use items
• The supply of critical inputs, including energy, raw materials, and critical medicines
• Access to sensitive information, including sensitive personal data, or
• The freedom and pluralism of the media
A broad range of transactions required to be notified
The Screening Act captures not only outright acquisitions, but also minority investments and joint ventures. Examples of the types of transactions that could fall within the scope of the Screening Act include where a “third country undertaking” or a person connected with such an undertaking:
• Directly or indirectly, acquires sole or joint control of assets in the State or an undertaking in the State
• Directly or indirectly, acquires or increases its percentage of shares or voting rights in an undertaking in the State to more than 25%
• Makes a greenfield investment involving the purchase of land where the land is necessary for operating critical energy infrastructure
Critical energy assets and entities in scope
Assets and/or entities providing services in the energy sector often come within scope of the definition of “critical infrastructure”. However, other categories, such as the “supply of critical inputs” may also be relevant. Therefore, it is expected that many transactions in the energy sector directly or indirectly involving a “third country” acquirer will require notification to, and clearance by, the Minister before the transaction can close. This could include, for example, the acquisition of all or part of an asset or an entity in the State whose activities involve the production, distribution, supply, storage, operation or transmission of electricity, oil, gas, or hydrogen.
The Guidance helpfully clarifies the meaning of “critical infrastructure” for the purposes of the Screening Act. The Guidance states that, in determining whether a notification is required, parties should consider:
• The EU’s Critical Entities Resilience Directive (EU Directive 2022/2557), which identifies essential services across 11 critical sectors, including the energy sector, and
• An “assessment of criticality”
According to the Guidance, the criticality assessment involves considering, by reference to a list of criteria set out in the Guidance, whether an incident would have significant disruptive effects on the provision of one or more essential services. While we expect the criticality assessment will narrow the types of “critical infrastructure” in scope of the Screening Act, many transactions will still come within its remit. These transactions can include those in the energy sector that may satisfy the criticality assessment or fall under one or more of the other critical matters outlined in the EU Screening Regulation. Therefore, decisions about the notifiability of a transaction must be made on a case-by-case basis.
Residual regulatory risk
Even if a transaction does not satisfy the criteria for a mandatory notification under the Screening Act, the Minister may ‘call-in’ a transaction for review if he/ she has “reasonable grounds for believing that the transaction affects, or would be likely to affect, the security or public order of the State.” While this would appear to be a relatively low bar, the Guidance also states that, in the case of non-notifiable transactions, the call-in power is particularly aimed at new or emerging technologies or sectors that are not captured by the mandatory criteria. This suggests that the power will be used selectively.
Despite this, non-notifiable transactions should be assessed on a case-by-case basis to determine the extent of any risk that the Minister would decide to call-in the transaction pre- or post-closing. The deadline for exercising the call-in power for nonnotifiable transactions is 15 months post-completion.
The Minister has broadly the same powers to impose mitigations on completed transactions as it does on transactions that are notified precompletion.
There is no option to make a voluntary notification. As a result, parties to a non-notifiable transaction that presents substantive risk of call-in will need to carefully consider their options for maximising regulatory certainty, if required.
Comment
Ireland’s investment screening process needs to be considered in the context of all transactions for the sale or purchase of, or investments in, energy and renewables assets or undertakings in Ireland. A mandatory notification has the potential to impact significantly on deal timelines as a split signing and completion will generally be required. Therefore, specific condition precedents to closing will need to be incorporated into the transaction documentation and timelines to completion and longstop dates will need to be mapped accordingly.
Early in the M&A process, investors should start thinking about key questions such as:
• Does the transaction meet the criteria for a mandatory notification?
• Are investment screening warranties required in the deal documentation?
• Should the deal documentation provide for a potential notification?
• What impact would a notification have on the deal timeline?
• What mitigations could be imposed by the Minister to address any public order and/or security concerns?
• Is there a risk, if the transaction is closed or nonnotifiable, that it would be called-in for review by the Minister?
For more information and expert guidance on how the new regime will impact any anticipated projects or transactions, please get in touch with a member of our Competition, Antitrust & Foreign Investment or Energy teams.
Data Centres in Ireland: Energy Concerns
Micheál
Grace Partner, Financial Services
+353 86 805 7812
mgrace@mhc.ie
Ireland’s data centre market faces significant energy challenges, with facilities consuming a substantial share of the national electricity supply. We explore the growing strain on Ireland’s grid, the regulatory landscape, and sustainable energy solutions like wind, solar, hydrogen, and battery storage. While progress is being made, the compatibility of renewable energy with 24/7 data centre operations remains a critical issue for Ireland’s leadership in this sector.
Energy constraints for data centres
According to a study by Bitpower in October 2024, €15 billion has been invested in building data centre facilities in Ireland. The study found that a future construction pipeline of €8 - €10 billion is at risk due to energy constraints and planning delays. The study outlines that data centres in Ireland are using around 6TWh of electricity per year, out of Ireland’s total annual electricity demand of 28TWh. These findings coincide with the Irish Central Statistics Office’s calculations that data centres used approximately 21 percent of Ireland’s electricity in 2023.
The problem at hand is not unique to Ireland, however. To keep pace with the rapid adoption of AI in the USA, data centre power needs are projected to roughly triple by 2030, rising from 3–4% of total US power demand today to 11–12%. Similarly, Europe’s data centre power demand is also expected to triple by 2030, according to McKinsey.
Eoin Cassidy Partner, Energy Sector Lead
+353 87 784 9353
ecassidy@mhc.ie
Connection agreement constraints
The substantial electrical load, both current and anticipated, required by Irish data centres has already triggered a significant regulatory response. The Commission for the Regulation of Utilities (CRU) published a decision in 2022 regarding the future regulation of the electrical connection of data centres in Ireland. The decision was effectively the first major intervention to regulate the way that electrical load, as opposed to electrical generation, can access the Irish grid. Under this policy, the electricity system operators are required to apply the following criteria on a case-by-case basis to determine whether a connection offer should be made to an applicant data centre:
• The location of the data centre applicant, relative to whether it is within a “constrained” or “unconstrained” region of the electricity system, and
• The ability of the data centre applicant to provide flexibility in their demand by reducing consumption when requested to do so by the relevant system operator in times of system constraint. This criterion includes both with, and without, the use of dispatchable onsite generation and/or storage, which meets appropriate availability and other technical requirements as may be specified by the relevant system operator.
Application of this decision, including as to which areas in Ireland are regarded as “constrained”, is reviewed on an ongoing basis.
Aside from issues of electricity availability, the further development of data centres has also been the subject of debate due to its implications for Ireland’s ability to reach the targets set under its Climate Action Plan. As part of setting out its approach to these issues, the Government published a “Statement on the Role of Data Centres in Ireland’s Enterprise Strategy” in July 2022. This Statement included a set of national principles or “preferences” for data centre development that aligned with national policy.
In response to this statement, the CRU commenced a policy consultation for new large energy users seeking connection to the electricity and gas systems, with the aim of minimising their impact on national carbon emissions and having regard to Ireland’s grid infrastructure capacity.
The new Large Energy User policy decision is expected imminently and should provide significant clarity on the viability and timeline for new data centre infrastructure in Ireland.
Drain on the national grid – examples of renewable energy solutions
To address the current drain on the national grid, many in the data centre industry voice the need for any investments in data infrastructure to proceed alongside investments in wind and solar electricity generation capacity. For example, in 2024, Microsoft signed a power purchase agreement to procure energy from the 30MW Lenalea Wind Farm in Co. Donegal. This initiative supports Microsoft’s goal of powering its data centre operations with 100 percent renewable energy.
There are clear drawbacks with the use of renewable electricity by a data centre. The primary issue is the intermittency of energy, which must be balanced against the 24/7 baseline operation of data centres and the electricity needs of the wider grid.
Wind power varies constantly and is dependent on wind speed and atmospheric conditions. Similarly, solar power is available only during daylight hours and, even then, will vary depending on season and cloud cover.
Electricity storage solutions, including the use of batteries, can help remedy the issue of intermittency. However, sceptics are not convinced that renewable energy alone can provide adequate power to sustain the requisite development of data centres to power the digital economy and the ever-increasing demands of AI. In addition, Ireland’s Climate Action Plan commits the Irish Government to review its policies on data centre growth to keep it in line with emissions and renewable energy targets.
Alternatives to wind and solar
The growth of data centres and the adoption of AI rely on the availability of electric power, so what can be done in Ireland to address the issue?
Natural gas
To overcome local power constraints, many Irish data centres are exploring the use of on-site natural gas-fired electricity generation. One of the obvious issues with using natural gas to power data centres is that this would make it more difficult for Ireland to meet its climate-related targets. It is worth noting that Gas Networks Ireland, the operator of the Irish natural gas grid, is not currently providing new natural gas connections pending finalisation of the CRU’s Large Energy Users Connection Policy.
Battery energy storage systems
Utility-scale battery technology may assist with improving the efficient application of renewable energy in this space. Battery storage systems can be charged during periods of plentiful, cheap renewable electricity and then used to run the host data centre during periods when renewable electricity is unavailable.
However, batteries remain prohibitively expensive when priced against the objective of completely shielding a data centre from the consequences of renewables intermittency. In addition, the business case for BESS installation tends to favour their location in proximity to renewable electricity generators, rather than load.
Hydrogen
Hydrogen has been described as a ‘zero emissions fuel’, as the cells do not produce carbon emissions or other pollutants. Hydrogen could be used for the storage of energy generated from renewable sources, that is then transported and stored before being used to power data centres. In this context, hydrogen could replace diesel generators, as the cells convert stored green hydrogen to electricity, producing no more than pure water as a byproduct.
Ireland’s adherence to the EU’s Gas and Hydrogen Markets Directive (Directive (EU) 2024/1788) and Regulation (EU) 2024/1789, as well as international requirements, will determine whether the hydrogen solution ultimately deployed qualifies as lowcarbon or green hydrogen. Ireland has until mid2026 to transpose Directive 2024/1788 into national law.
Nuclear
In the USA in 2024, Google signed a deal to use small nuclear reactors (SMRs) to provide 500 MW of 24/7 carbon-free power. Similarly, Amazon entered into an agreement with Energy Northwest to develop four SMRs, which are expected to provide up to 960 MW of capacity. Data centre developers in the UK and US are also developing their own designs. In Ireland, the use of nuclear fission for electricity generation is banned in law, and there is no discernible political will to revisit this ban.
Comment
The capacity constraints in the Irish electricity grid and Ireland’s commitment to its Climate Action Plan highlight the need for action. In the recently published Programme for Government, the new government has recognised the central role that data centres play in contributing to economic growth and the enterprise economy in Ireland.
The government has committed to the development of a comprehensive plan to guide the development of data centre infrastructure in alignment with Ireland’s decarbonisation objectives. Included in the proposals is the expedition of a private wires policy framework, which should unlock opportunities to connect data centres directly with renewable electricity generators.
The focus should be on facilitating the development of new sources of renewable electricity, such as wind or solar power, to support the energy needs of data centres. However, it remains to be seen if the new Large Energy User Policy, allied with the ambition of the new Irish government, presents viable solutions for data centre energy requirements and if Ireland can continue to claim leadership in its ability to host data centres.
For more information and expert advice, contact a member of our Financial Services or Energy teams.
Ireland’s New Small-Scale Renewable Electricity Support Scheme
Peter McLay Partner, Construction, Infrastructure & Utilities
+353 87 919 1555
pmclay@mhc.ie
The Minister for the Environment, Climate and Communications has published the Terms and Conditions (the Terms) for Ireland’s Small-Scale Renewable Electricity Support Scheme (SRESS 1). SRESS 1 is due to open for applications on 27 January 2025. The SRESS 1 - Terms and Conditions Non-Technical Guide has also been published, along with the SRESS 1 - Application Information Pack.
Unlike Ireland’s existing Renewable Electricity Support Schemes (RESS), which are available to utility-scale onshore and offshore projects, SRESS 1 support will not be allocated or priced using an auction process. Instead, SRESS 1 support will be provided at centrally set tariff rates. Support will be available to qualifying projects until aggregate quantitative limits are reached. These limits are applied across technology and sponsor types.
Support for renewable self-consumers having 50kW – 1MW renewable energy projects have been available since July 2023. The new SRESS 1 Support Scheme, however, is focused on projects that will export electricity to the grid. SRESS 1 is not open to autoproducers.
The Terms explain that the selection process includes ordering the fully completed and compliant applications by date received in their relevant generator and technology categories. Applications will then be processed based on their
Eoin Cassidy Partner, Energy Sector Lead
+353 87 784 9353
ecassidy@mhc.ie
ranked order and Letters of Offer will be issued until the available support is fully allotted for the relevant category. Complete and compliant applications that are subsequently received will be placed on a reserve list in the order of the date they were received.
Eligible projects
The projects eligible to receive support under SRESS 1 are:
• Community Projects: SRESS 1 Projects which are always 100% legally and beneficially owned by a Renewable Energy Community (the Relevant REC), and where all profits, dividends and surpluses derived from the SRESS 1 Project are returned to the Relevant REC.
• SME Projects: SRESS 1 Projects that must always be 100% legally and beneficially owned by an SME. “SME” has an established meaning under EU law and refers to an enterprise which employs fewer than 250 persons and which has an annual turnover not exceeding €50 million, and/or an annual balance sheet total not exceeding €43 million.
• Other Export Projects: SRESS 1 Projects that: (1) are neither Community Projects nor SME Projects, and 2) rely on solar energy with an installed renewable capacity greater than 50 kW and up to, but no greater than 1 MW, to produce electricity and export it to the national grid.
In the context of Community Projects, “Renewable Energy Community” is defined as a legal entity:
• This is based on open and voluntary participation in accordance with applicable law. The entity is autonomous and effectively controlled by its shareholders or members. These shareholders or members must be located nearby, in the case of SMEs or local authorities, or resident in the proximity of the SRESS 1 Project, in the case of natural persons. The Project must be owned and developed, or proposed to be owned and developed, by this legal entity.
• The legal and beneficial shareholders or members of which are natural persons, SMEs, local authorities including municipalities, notfor-profit organisations or local community organisations.
• For any legal and beneficial shareholder or member, with the exception of “Sustainable Energy Communities” as registered with SEAI, that shareholder or member’s participation does not constitute their primary commercial or professional activity
• The primary purpose of this is to provide environmental, economic, societal or social community benefits for its legal and beneficial shareholders or members or for the local areas where it operates, rather than financial profits.
• Each shareholder or member is entitled to one vote, regardless of shareholding or membership interest, and
• Which is, or which has at least one shareholder or member that is, registered as a “Sustainable Energy Community” with SEAI.
All of the above criteria must be evidenced to the satisfaction of the Minister.
Applications for SRESS 1 support will not be open to any proposed Community Project, SME Project or Other Export Project where:
• The Applicant is active in the primary production of agricultural products or is active in the primary production of fishery and aquaculture products, and
• The Applicant does not qualify as an SME.
Eligible technology
The SRESS 1 tariffs vary according to generation technology. The renewable generation technologies that are eligible for support under SRESS 1 are:
• Solar with an Installed Renewable Capacity greater than 50 kW and up to, but no more than, 1 MW
• Solar with an Installed Renewable Capacity greater than 1 MW and up to, but no more than, 6 MW
• Wind with an Installed Renewable Capacity greater than 50 kW up to, but no more than, 6 MW, or
• Wind and Solar both located behind the meter of the SRESS 1 Project and having a combined Installed Renewable Capacity greater than 50 kW up to, but no more than, 6 MW.
In each case, the output of the project must be exported to the national grid.
Export tariff rates
The following export tariff rates will apply:
(50 kW < capacity ≤ 1 MW)
(1 MW < capacity ≤ 6 MW)
(50kW < capacity ≤ 6 MW)
MWh Ineligible for SRESS 1 support Ineligible for SRESS 1 support
For wind and solar hybrid projects, the two technologies will not be metered and funded separately. Instead, the Minister will determine a single applicable SRESS 1 Tariff for the hybrid project. The tariff rate will be allocated to the solar and wind technologies in proportion to the capacity each contributes to the overall project. Each capacity will first be multiplied by its applicable capacity factor, which is 35% for wind and 11% for solar.
In common with the other RESS schemes, SRESS projects will not be permitted to seek a Guarantee of Origin for any exported electricity that is also supported by SRESS.
Planning permission
SRESS 1 Projects must have a full and final grant of planning permission. The permission must cover the construction of the electricity generating plant at the site, which must be an Eligible Technology. The planning permission must not have an expiry date or a decommissioning requirement prior to the expected end of the term of SRESS 1 support, ie the date which falls 15 years after the start of SRESS support.
Grid connection
SME Projects and Other Export Projects: In each case, the proposed SRESS 1 Project must have accepted a grid connection offer and be party to a Grid Connection Agreement.
Community Projects: The proposed SRESS 1 Project must have a Grid Connection Assessment for a potential grid connection agreement. If entered into, this agreement must provide sufficient capacity to accommodate the Installed Renewable Capacity of the SRESS 1 Project. It must also have a term lasting at least as long as the SRESS 1 Support Period.
The Terms also state that several SRESS 1 Projects are not eligible to apply for SRESS 1 under certain conditions. These conditions include proposed SRESS 1 Projects and projects that received a Letter of Offer, which connect to the national grid at the same location or a near-contiguous location.
Configurations involving a SRESS 1 Project and one or more non-SRESS 1 Projects connecting to the national grid at the same or a nearby location are also affected unless specific criteria are met:
• Each project has a unique grid connection agreement
• The projects are not under the control of the same person or have a material contractual relationship with each other such as a PPA, management agreement, cooperation agreement, co-development agreement, shared construction or operational contracts or similar arrangements, and
• The relevant SRESS 1 Project has not been included, in whole or in part, in an offer for a RESS Project in a RESS Competition
Site
Applicants must have control of the relevant site and the right to access this site to develop and operate the proposed SRESS 1 Project. Proposed SRESS 1 Projects cannot be reliant on any infrastructure or rights attaching to another SRESS 1 Project or any other project.
• For Community Projects: 57 months from the date of the Letter of Offer for the relevant SRESS 1 Project, and
• For SME Projects and Other Export Projects: 48 months from the date of the Letter of Offer for the relevant SRESS 1 Project
However, a later date may be permissible, once it is extended under the Terms.
The generator is required to achieve commercial operation by 57 months from the date of the Letter of Offer, ie the Longstop Date. The consequence for not meeting this milestone by this date is that the Letter of Offer may be revoked by the Minister.
SRESS 1 Export Tariff indexation
30% of each SRESS 1 Export Tariff will be adjusted (upwards or downwards) on 1 January each year. The adjustment will reflect any movement in the EU Harmonised Index of Consumer Prices between 27 January 2025 and the relevant indexation date.
Review of the SRESS 1 Export Tariffs
The Minister will review and potentially revise the SRESS 1 Export Tariffs offered to new applicants after three calendar years have passed since the SRESS 1 Commencement Date. However, this will not occur if the Scheme has already closed to applications by that time.
2-way floating feed In premium (FIP)
As with Ireland’s other Renewable Electricity Support Schemes (RESS and ORESS), financial support under SRESS 1 is structured as a ”2-way floating feed in premium”. This means that, again in common with RESS and ORESS, a project supported under SRESS 1 will need to sell its exported electricity under a power purchase agreement where a licensed electricity supplier is the off-taker.
SRESS 1 withdrawal
Withdrawal from SRESS 1 is provided for, where:
• A Generator has received a Letter of Offer but SRESS 1 support has not yet commenced, or
• The project has achieved commercial operation by the Longstop Date in accordance with the Terms and its Letter of Offer. In addition, the project must have also satisfied obligations to pay difference payments and reconciliation payments.
An additional feature of SRESS 1 is that all SRESS 1 projects must establish a Community Benefit Fund. However, the Minister has the discretion to exempt any Other Export Project that has received a Letter of Offer from the obligation to establish and contribute to a Community Benefit Fund. Instead, the Minister can require an Other Export Project to put in place an alternative arrangement that is appropriate for the size and nature of the project.
Comment
SRESS 1 represents a welcome addition of State support for renewable electricity installations. It is designed for projects that could not avail of or were not best suited to the RESS, ORESS or the Microgeneration Support Scheme (MSS).
The absence of an auction procedure is a welcome feature of SRESS 1, as it streamlines the process. Successful applicants are still required to satisfy the various criteria and submit their applications on time. However, the process is not a competitive process and applicants will not run the risk of making an unsuccessful bid, which is a risk under the other RESS schemes. The Terms note that SRESS has been designed to promote investment in small-scale renewable energy generation by certain project owners for which a competitive auction-based framework would not be cost-effective or feasible.
The webpage accompanying the Terms explains that the tariffs depend on whether a project is an SME or a REC. A higher rate is provided for RECs due to the additional hurdles they face when setting up projects. It goes on to explain that this includes planning, grid connection and financing. In addition, it is reflective of a public policy preference for community involvement in renewable energy projects.
The Terms represent a key step in Ireland’s promotion of electricity generation from renewable sources.
For more information, please contact a member of our Energy team.
Changes to Energy Audit and Management Obligations
Jay Sattin Partner, Planning &
Environment
+353 86 078 8295
jsattin@mhc.ie
In this article, we review the changes to the energy audit and energy management system obligations that are coming under the recast EU Energy Efficiency Directive1 (the Directive).
Under the previous version of the Directive (2012/27/ EU), “enterprises that are not SMEs” are required to carry out an energy audit every four years.
The revised Directive is set to change the scope of this obligation. The application of the obligation will no longer depend on the size of the enterprise, ie whether it is an SME or not. Instead, the scope of the obligation will be entirely dependent on an enterprise’s average annual energy consumption.
In addition, the revised Directive introduces new requirements to implement energy management systems and prepare energy action plans.
Who do the obligations apply to?
Energy thresholds
Articles 11(1) and 11(2) of the revised Directive require that:
1 Directive (EU) 2023/1791 of the European Parliament and of the Council of 13 September 2023 on energy efficiency and amending Regulation (EU) 2023/955 (recast)
2 An energy management system is a set of interrelated or interacting elements of a strategy which sets an energy efficiency objective and a plan to achieve that objective. It includes the monitoring of actual energy consumption, actions taken to increase energy efficiency, and the measurement of progress. It is defined in the revised Energy Efficiency Directive 2023/1791.
1. Enterprises with an average annual consumption higher than 85 TJ of energy over the previous three years, taking all energy carriers together, must put in place an energy management system (EMS)2 by 11 October 2027.
2. Enterprises without an EMS in place and below the 85 TJ threshold must comply with certain requirements if they have an average annual consumption higher than 10 TJ of energy over the previous three years, taking all energy carriers together. Such enterprises must carry out energy audits (EAs)3 every four years. The first audit is due by 11 October 2026. Following each EA, they must prepare and publish an Action Plan which sets out how they will implement the recommendations.
Enterprises with an average annual consumption higher than 85 TJ are described by the European Commission as “large energy users”. However, the Commission appears to anticipate that even “smaller companies” may meet the lower 10 TJ threshold.4
Member States must transpose the provisions of Article 11 into national law by 11 October 2025. These provisions do not have direct effect in Ireland until they are reflected in transposing national legislation.
3 An energy audit is a systematic procedure with the purpose of obtaining adequate knowledge of the energy consumption profile of a building or group of buildings, an industrial or commercial operation or installation, or a private or public service. It identifies and quantifies opportunities for cost-effective energy savings. It also identifies the potential for cost-effective use or production of renewable energy. It is defined in the revised Energy Efficiency Directive 2023/1791.
4 See European Commission Document “Questions and AnswersMaking our energy system fit for our climate targets” 9 October 2023
The Irish transposing legislation has not been published as yet.
An “enterprise”
The term ‘enterprise’ is not defined in the revised Directive. However, the Commission’s recommendation5 on Article 11 (the Recommendation), notes that the term is defined widely in other EU publications to include “any entity engaged in an economic activity, irrespective of its legal form”.
In the context of the revised Directive, the Commission considers this to mean that:
• Only enterprises within the territory of a Member State are obliged to comply. However, when assessing their energy consumption, all “linked enterprises” within the territory of the EU should be included, and
• Enterprises which are partly or wholly owned or controlled by public bodies are also covered by the obligations of Article 11(1) and Article 11(2).
The term “linked enterprises” is not defined in the Directive or the Recommendation. However, the Recommendation includes some worked examples and a recommended approach for calculating the average energy consumption of enterprises with complex structures.
How is ‘average energy consumption’ calculated?
The average energy consumption of an enterprise is based on the preceding three-year period, taking all of an enterprise’s energy carriers together. The term “energy carrier” is not defined in the Directive or the Recommendation.
The Irish transposing legislation is not yet available. In practice, it is likely that enterprises will be required to self-assess their energy consumption and report to a national authority. The Recommendation
5 Commission Recommendation (EU) 2024/2002 of 24 July 2024 setting out guidelines for the interpretation of Article 11 of Directive (EU) 2023/1791 of the European Parliament and of the Council as regards energy management systems and energy audits
states that, in order to identify enterprises that come within the scope of Articles 11(1) and 11(2), Member States may require all enterprises to report every year on their annual energy consumption to a national authority. However, this is not included in the text of the Directive. It remains to be seen whether Ireland will adopt this approach in the transposing legislation.
Member States have some discretion to establish their own rules on how ‘average annual consumption’ is to be calculated. We would expect this to be detailed in the Irish transposing legislation, along with accompanying guidance.
The Recommendation proposes a recommended calculation method, which may be adopted by Member States but is not mandatory. This method largely relies on the energy bills invoiced to the enterprise, but states that a “more accurate estimate” should be used if available.
The Directive sets deadlines of 11 October 2026 for the first EA and 11 October 2027 for the first EMS, if required. This means that all enterprises should assess their energy consumption for 2023, 2024 and 2025 in order to ensure that they are aware of which obligations, if any, will apply to them.
Action plans
An enterprise that has carried out an EA in accordance with the revised Directive must also prepare a concrete and feasible “Action Plan”.
The Action Plan must identify measures to implement each recommendation made in the EA, provided it is technically or economically feasible to do so.
The revised Directive contains limited detail on the contents of the Action Plan. It does not include a specific obligation on the enterprise to implement the measures set out therein, or to achieve certain levels of energy saving. The Recommendation states that it is Member States that must define the content of the Action Plan, so we expect more detail on this to be available in the Irish implementing legislation.
The Recommendation suggests that the Action Plan “could provide a structured summary of energy performance improvement actions (EPIAs) which are part of the energy audit”, but this is a recommendation rather than a mandatory requirement.
The Action Plan must be submitted to the enterprise’s management. The Action Plan, and its implementation rate, must also be published in the enterprise’s annual report and made publicly available. However, this is subject to both EU and national law protecting trade and business secrets and confidentiality.
The Recommendation encourages Member States to avoid duplication of reporting. It advises that Member States should allow enterprises to fulfil the requirement to publish an Action Plan by integrating the necessary information into their Climate Transition Plan, as required under the Corporate Sustainability Reporting Regulations 2024 if applicable.
Exemptions
An exemption from the EMS and EA requirements applies to enterprises that implement an “energy performance contract” (EPC) or an “environmental management system” (EnvMS). However, this is subject to the relevant EPC or EnvMS incorporating the necessary elements of the Directive.
Penalties
The Directive requires Member States to impose penalties for infringements. We expect penalties to be set out in the Irish implementing legislation.
Non-mandatory measures and encouragement
The Directive also provides that Member States should introduce measures designed to encourage enterprises to go further in their reporting or report on a voluntary basis. For example, Member States must “bring to the attention of SMEs” concrete examples of how an EMS could help their business. They must develop programmes to encourage enterprises that are not subject to the EMS or EA obligations to undergo energy audits.
Conclusion
The revised Directive raises the bar in terms of energy efficiency targets and obligations. It changes the criteria which determine whether enterprises are required to carry out energy audits, and introduces new requirements to implement an EMS and an Action Plan. This means that more entities, including SMEs, could now be caught by the obligations, while some entities might be facing a new obligation to implement an EMS or prepare and publish an Action Plan.
The Directive also provides scope for Member States to introduce additional measures to encourage all enterprises to report on their energy use and undergo energy audits on a voluntary basis.
Recent EU legislation has required increased reporting of sustainability metrics, including energy efficiency. Reporting and data collection is often viewed as the first step towards improved sustainability and efficiency. The next step after measurement is management. The requirement to implement energy management systems and disclose energy audit action plans increases the emphasis on this next step. Given significant energy costs, the requirements could create long-term value for enterprises that identify energy-saving opportunities.
It is up to Member States to decide how to transpose these obligations into national law. The Irish transposing legislation is awaited so it remains to be seen exactly how these measures will apply in Ireland. These provisions must be transposed into national law by 11 October 2025. Enterprises have until 11 October 2026 to comply with EA obligations, and until 11 October 2027 to comply with EMS obligations. However, as the energy consumption threshold is calculated over a three-year period, enterprises should already have procedures in place for recording their energy consumption dating from at least 2023. This is so they can determine whether they will be subject to these EA and EMS obligations when they come into force.
For more information, contact a member of our Planning & Environment team.
RESS Community Benefit Funds –Consultation Open
Eoin Cassidy Partner,
Energy Sector Lead +353 87 784 9353
ecassidy@mhc.ie
The consultation on Community Benefit Funds (CBFs) is now open. The Department of Environment, Climate and Communications (DECC) is seeking feedback on proposed changes to the CBF rules under Ireland’s Renewable Electricity Support Schemes (RESS). The DECC is conducting a consultation to gather feedback from all stakeholders on the operation of the CBFs. This includes insights into the learnings, successes, and challenges encountered now that the first RESSsupported projects have reached commercial operation and the initial CBFs have been registered and begun funding local communities. This consultation is proceeding simultaneously with the consultation on the RESS 5 Terms and Conditions, and it is open to submissions until 14 February 2025.
Consultation on Community Benefit Funds
One of the terms and conditions of the RESS auctions is the requirement for CBFs. Successful generators must establish a fund to be used for the benefit of the community located in proximity to the project. Since the first RESS 1 project reached commercial operation, a number of CBFs have been established and have provided funding in the designated areas. The DECC is now conducting a public consultation which seeks feedback from all stakeholders regarding the operation of the scheme.
Introducing the new Community Benefit Funds Rulebook
The DECC first published a Good Practice Principles Handbook in 2021 which provided guidance on the establishment and operation of CBFs. The Handbook supplemented the principal obligations set out in the Terms and Conditions (Ts&Cs) of each of the RESS schemes. Now the DECC is consulting on a set of new proposals with the aim of publishing a new Community Benefit Funds Rulebook. It will replace the Handbook with a set of binding rules that updates some aspects of the operation and governance of the CBFs that are not currently covered by the Handbook.
The consultation indicates explicitly that the new Rulebook may also require updates to be made to the RESS 2, RESS 3 and RESS 4 Ts&Cs relating to CBF obligations.
The consultation is now seeking stakeholders’ views and feedback on thirteen areas, including:
• Increasing the level of transparency: the consultation will welcome view on the introduction of a list of measures and requirements to improve the level of transparency of the CBFs. It is anticipated that these measures will apply to all projects supported by any of the RESS schemes. The measures would include the publication of the name of beneficiaries of funds received and information on successful and unsuccessful projects that applied for funding annually. This may be sensitive!
• Compensation for local authority-mandated funds: the RESS Ts&Cs allow generators to offset, against their CBF obligations, contributions paid to separate local authority-mandated funds. The DECC is considering removing this provision in the RESS 5 Ts&Cs with the aim of providing clarity and certainty for the local communities. Also, where set-off is permitted, the DECC is seeking feedback on how developers should be permitted to confirm that the relevant payments made to Local Authority-mandated funds have also complied with RESS Ts&Cs.
• Near Neighbour Payments: the RESS Ts&Cs set a mandatory minimum payment of €1,000 to neighbours within 1 km of a wind project and optional payments to neighbours located within 1 km to 2 km of a wind project. The DECC is now considering setting a fixed amount instead of a minimum one. The RESS Ts&Cs also set out that all households in the vicinity of a wind project and within 2 km from the nearest turbine are currently eligible to receive either mandatory or optional Near Neighbour Payments from the project developer.
• The DECC is now asking for feedback on the amendment of the eligibility criteria of “household” to refer to the tenant or owner who has the property as their primary residence at the time the project achieves commercial operation. The DECC is also considering introducing a limitation to the overall amount spent on Near Neighbour Payments to 50% of the overall CBF. The proposed limit centres on the fact that payments can prove problematic in instances where projects have a large number of neighbours.
• Simplified governance structure for smaller Community Benefit Funds: Small Community Benefit Funds face challenges regarding their governance and decision-making procedures compared to bigger funds. The DECC is proposing introducing a simplified governance structure for small funds. It is also seeking feedback on what level of deemed annual energy generation, or annual Fund amount would be an appropriate threshold.
• Role and structure of the Fund Committee: the DECC is reviewing the current role of each Fund Committee, which is currently the decisionmaking authority on selecting CBF recipients. It is proposing to change its role to an advisory one. Additional guidelines on how the Fund Committee is selected are also being considered to avoid conflicts of interests and enhance transparency on the decision-making process of CBFs.
• Administration costs: at present, up to 10% of the annual CBF is allowed to be used to cover the administration costs of the Fund. The DECC is considering increasing this amount during the first year of operation of the Fund to an amount between 15% and 20% of the Fund, given the initial costs involved in setting up the CBF.
• Application of UN sustainable development goals: with the current CBF requirements, a minimum of 40% of the Funds must be allocated to local initiatives linked with any of the 17 UN sustainable development goals. The DECC is now considering relaxing this limit so that a broader range of local community projects can be eligible for CBF funding.
The DECC has clarified that there will be no amendments to the level of contribution required to be made to the CBF by a RESS-supported project. This remains at €2 per Megawatt hour of electricity generated during a year and it is considered as a minimum payment, not a cap. The CBF rules do not prevent the projects from making other payments to locals during the planning or construction periods as required. However, the DECC does not recognise, for CBF purposes, any funds distributed in advance of reaching the commercial operation date.
For the purposes of the RESS 5 Ts&Cs, it is proposed that projects that produce electricity, regardless of whether they remain part of RESS, will have to maintain the CBF for the duration of their support period, which is usually 15 years. This principle was already introduced in the RESS 4 Ts&Cs.
Key dates
Consultation on CBF opened for submissions 20 December 2024
Consultation on CBF closes for submissions 14 February 2025
Publication of the RESS Community Benefit Funds Rulebook April 2025
Comment
Stakeholders have until 14 February 2025 to submit their feedback to the DECC by email or post. A workshop is also expected, with event details to be published in early 2025 and held in the following weeks. The CBF consultation will then culminate with the publication of the CBF Rulebook, which will also helpfully provide updated guidance to the Ts&Cs for RESS 1-4.
The RESS 5 Terms and Conditions are also currently under consultation. Responses to the CBF consultation are expected to inform the development of the RESS 5 T&Cs. The final version of the RESS Community Benefit Funds Rulebook and the RESS 5 Ts&Cs are planned to be published in April 2025.
For more information on the provisions of the new Rulebook and how it may impact any anticipated projects, contact a member of our Energy or Construction, Infrastructure & Utilities teams.
Court Ruling Could Curb Climate Litigation Against Private Companies
Deirdre Nagle Partner, Head of Planning & Environment
+353 87 296 2198
dnagle@mhc.ie
The Hague District Court previously ordered Shell1 to reduce the annual volume of CO2 emissions from its business activities and the end users of its oil and gas products by 45% relative to 2019 levels by the end of 2030.
The case was taken by Milieudefensie, a Dutch environmental group, and the decision represented a landmark victory for environmental activists. It built on the earlier Urgenda2 decision which established that the human rights protections under Articles 2 and 8 of the European Convention on Human Rights required the Dutch government to protect its citizens from the threat of climate change.
The 2021 Shell decision was a key part of the increasing trend of climate litigation, which we previously reported on. Importantly, it extended the scope of this trend to include actions taken directly against private companies. It was a landmark decision because it was the first time a private company was ordered by a court to comply with the Paris Agreement, and determined that a private company had a duty to mitigate its emissions.
However, Shell successfully appealed the 2021 decision with the Hague Court of Appeal delivering its judgment on 12 November 2024.3
1 Case number C/09/571932 / HA ZA 19-379, The Hague District Court, 26 June 2021
2 Decision 19/00135, Supreme Court of the Netherlands, 20 December 2019
3 Case number 200.302.332/01, The Hague Court of Appeal, 12 November 2024
Shell sought to appeal the decision on ten separate grounds. In particular, its appeal centred on the argument that corporate emission reduction targets were not for the courts to determine but instead were a legislative matter. In the absence of a percentage reduction target being imposed under legislation, Shell argued that the District Court erred in its decision to bind the company to a 45% reduction standard, or indeed to any other percentage.
Emission reduction targets
The Court of Appeal found that Shell has an obligation to reduce its emissions, based both on legislation and an “unwritten social standard of care”. However, the Court concluded that it is not for the courts to determine and impose specific reduction obligations on private companies.
In reaching this conclusion, the Court considered the various scientific analyses, sector targets and EU regulations applicable to Shell. The Court pointed to the lack of consensus on the rate of reduction to be achieved by private companies. The Court stated that “the available figures do not provide the court with sufficient support to oblige Shell to reduce its CO2 emissions by a certain percentage in 2030”.
Scope 3 emissions
A significant portion of the judgment was devoted to a consideration of Shell’s obligations regarding its scope 3 emissions.
Significantly, the 2021 judgment determined that Shell’s emission reduction obligations applied to its entire company portfolio, including its scope 1, 2 and 3 emissions.
Scope 1 emissions are the direct emissions produced and generated by a company in carrying out its activities. Scope 2 emissions are generated indirectly and relate to emissions generated upstream through Shell’s supply chain. Scope 3 emissions are generated indirectly downstream by the end users of its energy products. The extent of a company’s obligations regarding indirect emissions and impacts, in particular scope 3 emissions, has been a topic of some debate in recent decisions. These included the Kilkenny Cheese case that we previously reported on and the decision of the UK Supreme Court in the Finch4 case.
In this case, the Hague Court of Appeal concluded that “Shell may have obligations to reduce its scope 3 emissions” but that this did not mean that the Court could impose a binding target.
The Court of Appeal commented that it would be particularly complicated and difficult to enforce any scope 3 emission reduction targets imposed on private companies. This is due to the nature of scope 3 emissions, being generated by end users of the company’s products.
In addition, the Court found that it could not be established that an obligation on Shell to reduce its scope 3 emissions by a certain percentage is effective. On that basis, the Court noted that “Milieudefensie et al. have no interest in their scope 3 claim”
Consequences for private companies
The Hague Court of Appeal restated the need for private companies to ensure their climate plans are consistent with the Paris Agreement’s climate targets. However, the decision handed down suggests that in the absence of specific sectoral or legislative targets, it is for each company to determine how it will comply with these goals.
For environmental activists, the decision will be seen as a setback. Groups such as Milieudefensie will likely find it difficult to enforce specific emission reduction targets against private companies where specific targets have not been prescribed by legislation. It remains open for Milieudefensie to appeal the decision to the Dutch Supreme Court.
For more information and expert advice on related matters impacting your organisation’s ESG goals, contact a member of our Planning & Environment team.
4 R (on the application of Finch on behalf of Weald Action Group) (Appellant) v Surrey County Council and others (Respondent) [2024] UKSC 20
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