Energy #19 Legislative focus

Romanian authorities published a series of draft acts that begin to define the full development route for offshore wind projects, from the selection and concession of areas to exploration, construction and completion of works.

A revised Government decision reduces the initial list from five perimeters and one future development area, representing an estimated 11.5 GW, to three perimeters with a combined estimated capacity of 3.1 GW. Perimeter 1 accounts for 1.9 GW, while Perimeters 2 and 3 account for 600 MW each. All three are intended for fixed-bottom projects.

The areas removed from the current proposal may be reconsidered through subsequent government decisions. Where offshore wind areas overlap with existing petroleum concessions, the approval of the National Authority for Mineral Resources, Petroleum and Geological Storage will be required before the concession procedure begins.

A separate draft decision establishes the competitive concession procedure. The Ministry of Energy will organise prequalification and evaluate the technical and financial components of each offer. Applicants will have to demonstrate relevant experience, financial capacity and access to the resources required to develop the project.

The financial offer may include an optional concession premium. Not offering a premium will not lead to rejection, but the applicant will receive no points for that criterion. Information provided during the procedure concerning grid connection will be indicative and will not reserve transmission capacity for the winning bidder.

ACROO also published the procedure for obtaining the development approval required before construction begins. Applicants must first complete exploration, obtain the relevant sectoral approvals, secure the grid connection permit and obtain ANRE’s establishment authorisation. The project must also undergo independent technical verification by a certification body recognised under the IECRE system.

ACROO will issue the approval within 60 working days after receiving the complete documentation. The approval may cover the entire project or individual stages and categories of works. Construction must begin within 12 months after the approval is issued.

Additional ACROO rules introduce a notification and acceptance procedure for critical activities during exploration, including geotechnical and geophysical investigations, vessel operations and the installation of offshore equipment. Developers must include a minimum 60-day notification period in their project calendars and remain responsible for activities performed by contractors and subcontractors.

These proposals provide developers with a more visible route from access to an offshore area to the start of construction. They also clarify the documentation, certification and risk-management requirements that must be built into project planning.

The framework creates substantial front-loaded costs. Developers will need to finance exploration, technical studies, certification, permitting and connection work before obtaining the development approval. They must also account for concession payments, guarantees and decommissioning obligations.

Grid access remains a major uncertainty. Winning a concession will not reserve transmission capacity, and the connection information provided during the tender will be indicative. Developers could therefore secure an offshore perimeter without having certainty that the required onshore network capacity will be available under commercially workable conditions.

The short consultation periods are also important. Several requirements that could influence project costs and bidding strategies are still open to amendment.

ANRE published two draft orders implementing the changes introduced by Law No. 160/2026, which entered into force on 26 July.

The first draft governs existing contracts and contracts concluded by 31 December 2026. For electricity supplied after 26 July, surplus electricity will no longer be carried forward in kWh for up to 24 months. It will instead be billed and settled financially in the month in which it was supplied.

Suppliers will have to recalculate billing operations performed between 26 July and the entry into force of the order. Any kWh balances created for this period must be cancelled and replaced with monthly financial settlement. Corrective documents must be issued within 30 days after the order enters into force.

Distribution operators must provide monthly validated data for electricity consumed and supplied. Where a billing cycle includes both periods before and after 26 July, quantities may initially be separated proportionally but must subsequently be corrected using validated meter readings.

Suppliers must also inform affected prosumers of the new arrangements within ten working days after the order enters into force.

The second draft introduces the permanent methodology applicable from 1 January 2027. Prosumers will be able to use the financial value generated at one production and consumption site to cover electricity bills for other eligible sites belonging to the same prosumer.

As a rule, the sites must be supplied by the same supplier and connected to the network of the same distribution operator. Individuals with installations of up to 27 kW will have broader options, including allocation across different distribution areas or, alternatively, the payment of natural gas bills issued by the same supplier.

Suppliers must send the option form and framework addendum to prosumers by 1 November 2026. They must publish their draft internal procedures by 15 November, adopt and submit the final procedures to ANRE by 15 December, and complete all IT and operational changes by 31 December.

The transitional order creates an immediate correction exercise for suppliers. Billing operations already completed under the previous practice will have to be separated, recalculated and reissued within a limited period.

The permanent methodology adds another layer of operational complexity. Suppliers will have to validate multi-site lists, apply a regulated allocation order, manage bills with different due dates and settle any unused amounts. Existing balances will not transfer when a prosumer changes supplier.

Distribution operators will also face greater pressure to provide complete monthly data in both directions. Delayed or corrected measurements could affect billing across several sites rather than a single contract.

For business prosumers, multi-site allocation may reduce electricity costs across their own portfolios. The benefit is narrower than the wording of the primary law may initially suggest because eligible sites generally need to remain with the same supplier and distribution operator.

The Ministries of European Investments and Projects, Energy, Development and Environment proposed a common methodology for designing public programmes that replace older heating systems using forest biomass or solid fossil fuels.

The programmes will cover units older than ten years or with an efficiency below 65%, used by households and social buildings operated by local authorities. The framework implements Law No. 168/2026 and is linked to Reform 6 and Milestone 128 under the energy component of Romania’s Recovery and Resilience Plan.

Local authorities will apply a calculation instrument to assess technical feasibility and compare the total cost of available technologies over 15 years.

A technology will generally be considered economically justified if its total cost does not exceed twice the cost of the reference solution. Among the eligible options, the least-cost solution will be recommended.

Autonomous fossil-fuel boilers will not be eligible for support. Natural gas may remain in the calculation only as a reference against which other technologies are compared.

Support intensity will depend on the beneficiary and the funding programme. For certain vulnerable households financed through the Social Climate Fund, support may cover up to 100% of eligible expenditure.

Funding may be provided through reimbursement, direct payment to the supplier or installer, or an advance followed by final settlement. Each programme will establish its own application and payment arrangements.

The methodology will influence demand for heating equipment, installation services, district-heating connections and related infrastructure. Manufacturers and installers will need to assess whether their technologies meet both the technical criteria and the 15-year cost test.

The exclusion of autonomous fossil-fuel boilers gives low-carbon technologies a clearer position in future support programmes. However, the cheapest eligible option will generally be preferred, which could limit access for technologies with higher initial and operating costs even where they offer stronger emissions reductions.

Local capacity will affect implementation. Municipalities will be responsible for applying the feasibility instrument and linking beneficiaries to suitable technologies or district-heating systems. Weak local data or limited technical expertise could slow project preparation.

The methodology does not itself open a funding programme. Actual demand will depend on the subsequent financing guides, available budgets and the conditions attached to each call.

The Ministry of Energy formally launched the Modernisation Fund call supporting stand-alone battery storage, following the approval of the applicant guide reported in the previous Legislative Focus.

Applications may be submitted through MySMIS2021 between 1 September and 30 October 2026.

The call has a budget of EUR 150 million and targets at least 2,174 MWh of new storage capacity. Projects must have a minimum installed power of 1 MW, a discharge duration of at least two hours and a direct connection to the transmission or distribution network.

Projects will be ranked primarily according to the amount of aid requested per MWh. The aid is capped at EUR 69,000 per MWh and EUR 15 million per undertaking.

Separately, the Ministry of Environment proposed an AFM programme for installing batteries for individual prosumers. Eligible systems must have a minimum capacity of 12 kWh and must serve the existing production and consumption site.

AFM would finance up to 75% of eligible project costs, subject to a maximum grant of RON 15,000 and a cost ceiling of RON 1,250 per installed kWh. Applicants must contribute at least 25%. Where a compatible hybrid inverter is required, its cost must be covered by the beneficiary.

Projects will be selected by score rather than solely in the order of registration. The scoring system favours higher own contributions, larger battery capacity and greater installed photovoltaic power.

Installation will be performed exclusively through AFM-approved installers. Participating companies must hold an ANRE type B certificate, or an equivalent document, for at least 12 months and may not subcontract battery and inverter installation.

Together, the two programmes target approximately 2.57 GWh of new storage capacity across different parts of the electricity system.

The stand-alone call creates an immediate application window for commercial storage developers. The ranking system rewards projects seeking less aid per MWh, so applicants must balance grant intensity against their probability of selection. Connection, permitting, design and other ineligible costs must be financed separately.

The household programme could create a separate market for smaller batteries, but its effect will depend on the final budget allocated to each session and the number of validated installers. The minimum 12 kWh requirement and the funding ceiling also mean that many beneficiaries will need to contribute more than the formal minimum of 25%, particularly where a new inverter is required.

The programmes support additional storage capacity, but they do not resolve grid connection constraints or determine how the assets will participate in flexibility and balancing markets.