Romania is introducing competitive auctions for access to electricity-grid connections, making network capacity an explicitly priced investment requirement. The change may affect project valuations, financing costs and the market for existing electricity assets. National transmission operator Transelectrica will hold the country’s first competitive capacity-allocation sessions on October 30, offering 1,566 MW of future connection capacity across designated network zones, subject to additional network development.
Published opening prices range from approximately €136,000 to €719,000 per MW, depending on location, connection year and network classification; winning prices may be higher. The capacity on offer is concentrated between 2032 and 2037, indicating long waits for certain categories of new electricity projects. The reform replaces the traditional first-come, first-served approach for qualifying projects with a system requiring developers to demonstrate their willingness and financial ability to pay for scarce network access.
Allocation schedule and prices vary by zone and year
Transelectrica’s published allocation schedule covers 2028–2037, but the latest assessment identifies no capacity available through the new auction mechanism before 2032. The operator is offering 412 MW in 2032, 80 MW in 2035, 862 MW in 2036 and 212 MW in 2037. The 2036 allocation is the largest, representing approximately 55% of the total capacity offered.
These figures concern capacity made available through identified additional network development works. They do not mean Romania has prohibited all new electricity connections before 2032: existing connection approvals, other applicable connection procedures and projects outside the auction mechanism must be assessed separately. The new system divides the electricity network into 10 allocation zones, each with its own capacity volumes and opening prices.
The lowest published starting price is approximately €136,000/MW for capacity offered in Zone D in 2036. The highest is approximately €719,000/MW for a different network-category allocation in Zone D in 2037. These prices show substantial differences in network-capacity economics, but they are not directly comparable options for an identical project.
A hypothetical 100 MW development facing those respective opening prices would pay approximately €13.6 million or €71.9 million for capacity allocation, before additional connection expenditure. This calculation illustrates potential financial exposure, not the actual cost of a specific eligible project. Developers must separately fund substations, connection lines, installation works and other applicable infrastructure; the winning auction price is an additional cost for securing capacity, not an all-inclusive construction budget.
Guarantees add financial requirements for applicants
The new mechanism also imposes stricter financial requirements. Qualifying developers had to provide a participation guarantee of €20,000/MW when submitting applications, equivalent to €2 million for a 100 MW project before competitive bidding. Under Transelectrica’s procedures, unsuccessful bidders can recover their guarantees, while successful participants recover them after completing the prescribed contractual steps.
Successful bidders must also provide a further guarantee equal to 1% of the allocation contract value before finalising their capacity-allocation agreements. Failure to sign the required agreement and provide the prescribed guarantee within the applicable deadline can lead to the loss of allocated capacity and enforcement of the participation guarantee. The requirements are intended to deter applications from developers without adequate financial resources or credible implementation plans, while also adding liquidity requirements for legitimate investors.
For project-finance banks, the auction creates another expenditure category to assess alongside land acquisition, environmental approvals, construction, equipment procurement and conventional connection costs. The challenge is particularly significant for projects expected to begin commercial operation six to eleven years in the future. Long development periods expose investors to higher financing costs, regulatory changes, equipment-price fluctuations and uncertainty over future electricity-market revenues.
A project that appears profitable before connection-rights expenditure may become unattractive once the auction price and additional development costs are included. Romania’s mechanism also changes project-finance assumptions: infrastructure lenders generally assess construction expenditure, projected electricity revenues, operating costs, debt-service obligations and downside scenarios. Network-capacity expenditure must now be included in the capital budget before financial close.
Timing matters because funds committed years before construction or electricity delivery leave investors without operating income for longer. A future connection dependent on several network reinforcement projects also creates technical and scheduling dependencies beyond the developer’s immediate control. Banks may therefore require more detailed independent-engineering assessments and stronger contractual protection before accepting proposed commissioning dates.
Investment committees will need to distinguish between the price paid to secure allocation, the cost of physical connection, the cost of financing the development period and the probability of completing a project on schedule. The auction could also create demand for specialist advice on grid-rights due diligence, capacity-allocation strategy, engineering assessment and project restructuring. Developers may reconsider connection locations, capacity sizes or ownership structures when auction costs exceed what their projects can support.
Applicants and the first allocation process
The initial application phase attracted 12 projects representing 491 MW, according to published Transelectrica application data. Romanian state-controlled energy producer Romgaz submitted proposals for two photovoltaic projects with storage of 20 MW each and a 100 MW standalone storage installation near Iernut. Other applicants include companies linked to Turkish investment groups.
Energy Capital Group, associated with the Güris group, submitted a 51 MW storage project. Hessmaier, linked to the FIBA group, registered several proposed generation and storage developments. Applications cover different technologies, locations and intended commissioning dates, and include both established energy companies and private investors examining the new framework.
Applications are not completed investments, financing commitments or awarded connection rights. Nor can the 491 MW of initial requested capacity be compared directly with the 1,566 MW offered across different zones and years to determine whether individual auctions are oversubscribed. A project may need capacity in a location or year where the relevant allocation is unavailable, even if capacity exists elsewhere in the system.
The key issue is whether the auction can match technically suitable capacity with projects willing to pay the required price and accept the resulting implementation timetable. The first allocation process is scheduled to run on successive working days until November 12, with separate sessions for the relevant allocation years. As bidding begins, final prices, winning allocations and successful contracts remain to be established.
Grid rights and project bankability across Southeast Europe
Competitive allocation creates a distinction between projects with established grid-access arrangements and those still seeking connection capacity. An operating installation with secure injection rights and proven physical access to the electricity system may have a different risk profile from a comparable development that still requires a future auction award. This difference could become more apparent in acquisitions, refinancing and project-portfolio valuations.
Investors acquiring electricity assets will increasingly need to check the legal validity, technical scope and contractual restrictions of grid-connection arrangements. Relevant matters include permitted export capacity, connection date, validity of technical approvals, required reinforcement works, and conditions affecting changes of ownership or project configuration. Connection approvals should not be treated as freely transferable financial instruments: their value depends on the applicable legal framework, contractual provisions and technical obligations.
Scarcity could nevertheless create a commercial premium for projects able to demonstrate reliable, enforceable and timely network access. Investment funds may shift towards acquiring advanced projects with completed permits and credible grid rights rather than large early-stage development pipelines. For banks, a valid connection position could become more important in collateral assessment and project due diligence, although it cannot replace a bankable revenue model.
The market may place greater value on demonstrated deliverability than on announced installed capacity. For lenders, assessment of repayment capacity will need to account for the separate cost of securing network access as well as physical connection and project development. The timing of expenditure and the likelihood of meeting the proposed commissioning schedule are also relevant to investment decisions.
Regional considerations for neighbouring markets
Romania’s approach offers a regulatory case study for the wider Southeast European electricity market. Serbia faces substantial pressure on transmission connection capacity and increasing uncertainty over when new projects can access the grid, but has not introduced an equivalent general competitive auction regime for allocating transmission connection rights. The Romanian experience illustrates how scarce capacity could influence electricity-investment financing and valuations.
For Serbia’s independent power producers, acquisition targets and infrastructure lenders, the practical issue is the cost and reliability of securing a deliverable grid connection. Montenegro faces a different challenge because its electricity system and domestic investment market are smaller. There, the timing and technical conditions of grid access can strongly affect the economics of individual projects.
A competitive capacity-pricing system may not suit every network or market structure. Romania’s framework nonetheless provides a reference for assessing transparent allocation, financial guarantees and the handling of speculative connection applications. Comparable questions arise in Bulgaria, Croatia and North Macedonia, where developers must align investment plans with limited network availability and changing technical requirements.
For investors active in several regional electricity markets, connection rights may become a substantial and unevenly priced component of infrastructure expenditure. Romania’s first capacity auction marks a change in the relationship between electricity infrastructure developers and the transmission network. Alongside technology costs, financing conditions and expected electricity-market revenues, the cost of obtaining network access at a particular location and date is now a measurable economic factor.
The effectiveness of the system will depend on whether the auction attracts credible projects, establishes commercially sustainable prices and helps turn planned network reinforcement into operational capacity. High opening prices and distant connection dates could strengthen financial discipline in the development market, but could also deter otherwise viable investments. The first results will show whether developers accept the costs and whether available allocations match actual demand.
For lenders and infrastructure investors across Southeast Europe, the reform provides an early indication of a broader change in electricity-investment economics. Grid connection is no longer only a technical milestone to complete before construction; it is a separately priced investment requirement that can determine whether a project is financially viable. An asset’s value will increasingly depend not only on how much power it can produce, but also on when and where that power can reach the market and under what enforceable conditions.