Romania will allocate scarce electricity grid connection capacity through competitive auctions, making network access a separately priced investment requirement with potential effects on project valuations, financing costs and existing electricity assets. The first allocation sessions, organised by transmission system operator Transelectrica, begin on October 30. They will offer 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; final winning bids may be higher. The capacity on offer is concentrated in the 2032–2037 period, reflecting long waits for some categories of new electricity projects. Romania is moving away from the traditional first-come, first-served approach for qualifying projects towards a system that requires developers to demonstrate both their willingness and financial ability to pay for limited network access.
The change reaches beyond grid engineering. A project’s connection rights, the contractual security attached to them and the date when electricity can physically enter the network are becoming central to its financial value. Investors and lenders will need to account for these factors alongside the project’s other costs and risks.
Capacity is available from 2032, with varying prices
Transelectrica’s published allocation schedule spans 2028–2037, but its latest assessment identifies no capacity available through the new auction mechanism before 2032. The operator is offering 412 MW for 2032, 80 MW for 2035, 862 MW for 2036 and 212 MW for 2037. The 2036 allocation is the largest, representing approximately 55% of the total capacity on offer.
These figures cover capacity made available through identified additional network development works; they do not mean that Romania has barred all new electricity connections before 2032. Existing connection approvals, other applicable procedures and projects outside the auction mechanism need to be considered separately. Under the new system, the electricity network is divided 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 in Zone D in 2036. The highest is approximately €719,000/MW for a different network-category allocation in Zone D in 2037. The figures show substantial variation in the economics of network capacity, but they are not directly comparable options for the same project.
At those respective opening prices, a hypothetical 100 MW project would face an allocation cost of approximately €13.6 million or €71.9 million, before additional connection expenditure. This calculation indicates potential financial exposure, not the actual cost for a particular eligible project. Developers must separately fund their substations, connection lines, installation works and other applicable infrastructure, so the winning bid is an additional cost for securing capacity, not an all-inclusive construction budget.
Guarantees raise the cost of speculative applications
The allocation mechanism also imposes stricter financial requirements. Developers seeking to qualify had to provide a participation guarantee of €20,000/MW with their 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 can do so after completing the required contractual steps.
Successful bidders must also provide a further guarantee equal to 1% of the allocation contract value before finalising their capacity-allocation agreements. If a bidder fails to sign the required agreement and provide the prescribed guarantee by the applicable deadline, it risks losing the allocated capacity and having its participation guarantee enforced. These requirements are intended to deter applications from developers without adequate financial resources or credible implementation plans, while also creating additional liquidity needs for legitimate investors.
Project-finance banks will need to assess the auction expenditure alongside land acquisition, environmental approvals, construction, equipment procurement and conventional connection costs. The challenge is particularly pronounced for projects whose expected commercial operation is six to eleven years away. Such long development periods expose investors to higher financing costs, regulatory changes, equipment-price fluctuations and uncertainty about future electricity-market revenues.
A project that appears profitable before connection-rights expenditure may become uneconomic once the auction price and other development costs are included. The connection charge must therefore be considered before a project reaches financial close, as part of its overall capital budget. Investors also need to account for the period between committing funds and generating operating income.
Romgaz and private developers apply for capacity
Published Transelectrica application data show that the initial phase attracted 12 projects requesting a combined 491 MW. Among the applicants is Romanian state-controlled energy producer Romgaz, which submitted proposals for two 20 MW photovoltaic projects with storage and a 100 MW standalone storage installation near Iernut. Other applicants include companies associated with Turkish investment groups.
Energy Capital Group, associated with the Güris group, applied for a 51 MW storage project. Hessmaier, linked to the FIBA group, registered several proposed generation and storage developments. The applications involve different technologies, locations and intended commissioning dates, and show that both established energy companies and private investors are examining the new framework.
Applications are not completed investments, financing commitments or awarded connection rights. Nor can the 491 MW of initially requested capacity be compared directly with the 1,566 MW offered across different zones and years to determine whether particular auctions are oversubscribed. A project may need capacity in a specific location or year where none is available, even if capacity exists elsewhere in the system.
The allocation process must match technically suitable capacity with projects prepared to pay the required price and accept the resulting timetable. Separate sessions for the relevant allocation years are scheduled on successive working days through November 12. As bidding starts, final prices, winning allocations and successful contracts have yet to be established.
Established grid rights may gain strategic value
The competitive allocation system sharpens the distinction between projects with established grid-access arrangements and those still seeking 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 dependent on a future auction award. That distinction could affect acquisitions, refinancing and project-portfolio valuations.
Investors buying electricity assets will increasingly need to check the legal validity, technical scope and contractual restrictions of their grid-connection arrangements. Relevant points include permitted export capacity, the connection date, the validity of technical approvals, required reinforcement works and conditions governing changes in 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.
Even so, limited capacity could create a commercial premium for projects with 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 assessments and project due diligence, although it cannot replace a bankable revenue model.
The market may consequently place greater value on demonstrated deliverability than on announced installed capacity. The distinction matters when investors compare projects that have similar planned output but different prospects for reaching the network. Grid access, its terms and its timing can therefore shape an asset’s risk profile as well as its development costs.
Connection costs alter project-financing assumptions
Romania’s auction mechanism adds a further cost to traditional project-finance structures. Infrastructure lenders generally assess repayment capacity against construction expenditure, projected electricity revenues, operating costs, debt-service obligations and downside scenarios. The price of network capacity must now also be included in the capital budget before financial close.
Timing is a key concern when significant funds must be committed years before construction or electricity delivery, extending the period before a project earns operating income. A future connection dependent on several network reinforcement projects also creates technical and scheduling dependencies beyond the developer’s immediate control. Banks may respond by requiring more detailed independent-engineering assessments and stronger contractual protection before accepting proposed commissioning dates.
Investment committees will need to distinguish the price paid to secure allocation from the cost of physical connection, the financing cost of the development period and the likelihood of completing the project on schedule. The auction may also create demand for specialist advice on grid-rights due diligence, allocation strategy, engineering assessment and project restructuring. Developers may have to reconsider connection locations, capacity sizes or ownership structures if auction costs exceed what their underlying projects can support.
Implications for Serbia and Montenegro
Romania’s approach offers a regulatory case study for the wider Southeast European electricity market. Serbia faces significant pressure on transmission connection capacity and growing uncertainty over the timing of access for new projects, but has not introduced an equivalent general competitive auction regime for allocating transmission connection rights. Romania’s experience nevertheless illustrates how limited grid capacity could increasingly affect the financing and valuation of electricity investments.
For Serbian independent power producers, acquisition targets and infrastructure lenders, a practical concern 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. In that market, the timing and technical conditions of grid access can strongly influence the economics of individual projects.
A competitive capacity-pricing system may not suit every network or market structure, but Romania’s framework offers a reference for assessing transparent allocation, financial guarantees and the handling of speculative connection applications. Similar issues arise in Bulgaria, Croatia and North Macedonia, where developers must align investment plans with limited network availability and changing technical requirements. For investors active across several regional electricity markets, connection rights risk becoming a substantial and unevenly priced part of infrastructure expenditure.
Grid access becomes a factor in project bankability
Romania’s first capacity auction marks a structural shift in the relationship between electricity infrastructure developers and the transmission network. Investment discussions have traditionally focused on technology costs, financing conditions and expected electricity-market revenues. The competitive allocation system adds another measurable factor: the cost of obtaining network access at a particular location and date.
The mechanism’s effectiveness will depend on whether it attracts credible projects, produces 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 indicate whether developers accept the costs and whether the available allocations match actual demand.
For lenders and infrastructure investors across Southeast Europe, Romania’s reform provides an early indication of a broader change in electricity investment economics. Grid connection is no longer merely a technical milestone to complete before construction; it is becoming a separately priced investment requirement that can determine whether a project is financially viable. As competition for network access grows, an electricity asset’s value will 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.
