Hybrid Renewable & Storage Projects in Romania: From Co-Location to Bankability

Short answer for investors

Hybrid renewable and battery storage projects are becoming essential in Romania's energy transition, but bankability depends on legal structure, grid access, licensing, PPAs, CfDs and interface risk.

Why this matters in practice

The next renewable project will not be judged only by installed capacity

For many years, renewable energy investment in Romania was relatively easy to describe. A project was attractive if it had good land, a valid grid connection solution, permitting progress, a credible EPC route and a clear path to commercial operation. In practice, investors were mostly buying or developing megawatts: photovoltaic megawatts, wind megawatts, grid megawatts.

That logic is changing.

In a market increasingly shaped by solar cannibalisation, negative price intervals, grid congestion, balancing costs and curtailment risk, the most valuable renewable project is not necessarily the largest one. It is the project that can deliver electricity when the system needs it, avoid selling when prices collapse, reduce imbalance exposure and convert intermittent production into a more flexible commercial product.

This is why hybrid renewable and storage projects are becoming central to the next phase of the Romanian energy market. A photovoltaic project with a battery is not just a solar park with additional equipment placed on the same site. It is a different investment product. It combines generation, storage, grid capacity, market optimisation, balancing exposure, route-to-market strategy and contractual risk allocation.

The business logic is already clear. The regulatory framework is catching up. But the bankability case is still being built.

The legal starting point: storage is now part of the Romanian electricity architecture

The first legal anchor is Law no. 123/2012 on electricity and natural gas. The law now expressly reflects the role of decentralised resources, demand response, storage and flexible production in the electricity sector. Its objectives include the development of services using decentralised energy resources, including demand response and energy storage, as well as investments in variable and flexible production, storage, electromobility and interconnections.

This is important because hybrid projects depend on the legal recognition of storage as more than a technical add-on. If the law treats storage only as consumption or only as generation, the commercial model becomes distorted. In reality, a battery can charge, discharge, optimise, support balancing, participate through aggregation, reduce curtailment and improve the shape of renewable output.

Law no. 123/2012 also defines relevant market concepts such as aggregation, active customers, components of the network that may include storage, balancing, congestion and dynamic price contracts. These definitions matter because a hybrid project may involve several legally distinct activities even if, commercially, the investor sees one integrated asset.

That is the first bankability lesson: the legal structure must follow the revenue model. A PV+BESS project cannot be drafted as a conventional solar project with a battery annexed at the end.

Licensing: the battery follows the business model

The second legal anchor is the ANRE licensing framework, based on Law no. 123/2012 and ANRE’s licensing rules. For hybrid projects, the key point is simple: there is no single universal “BESS licence” that solves every structure.

If the battery is added to a renewable generation asset, it may be treated as storage attached to a production capacity. If it is a standalone battery, it requires a different analysis, closer to the commercial operation of a storage installation. If the battery is used for trading, aggregation or balancing, the project must also clarify who has the relevant market rights and who bears balancing responsibility.

This is not administrative detail. It defines ownership of revenue and allocation of risk.

For example, in a 100 MW PV + 50 MW / 200 MWh BESS project, one structure may have the project SPV owning both the PV plant and the BESS, with a trader or optimiser providing route-to-market services. Another structure may separate the battery into a different SPV and use a tolling or optimisation agreement. A third model may rely on an aggregator or licensed supplier/trader to access balancing and short-term markets.

Each structure raises different legal questions: who dispatches the battery, who sells the energy, who is responsible for imbalances, who receives ancillary-service revenue, who bears degradation risk and what rights lenders have over the battery, EMS, O&M agreement and route-to-market contract.

The legal answer is therefore not simply “obtain a licence”. The correct answer is: define the commercial activity first, then align the licensing and contractual structure with that activity.

Grid connection: the ATR is where the business case becomes real

The third and probably most important legal anchor is ANRE Order no. 59/2013, approving the Regulation on connection of users to public electricity networks.

The connection regulation now expressly covers several relevant BESS and hybrid situations: new consumption and/or production sites with storage, production sites with storage and HVDC systems, new storage installations, and modifications of existing sites by adding storage. The regulation also confirms that the technical connection approval — the ATR — contains the technical and economic conditions for connecting a consumption and/or production site and/or a storage installation.

This is critical. In a hybrid project, the ATR is not just a regulatory milestone. It is almost the business model.

A developer must understand exactly what the ATR allows. Does the project have export capacity only, or also import capacity?
Can the battery charge from the grid, or only from the renewable plant?
Can the battery discharge independently?
Is the battery allowed to participate in balancing services?
Is the approved power based on installed generation capacity, installed storage capacity, maximum export capacity or a controlled net profile?
Are there N or N-1 limitations?
Is evacuation conditional upon network reinforcement works?
Are there dynamic operational restrictions?

These questions determine whether the financial model works.

A common example illustrates the issue. A 100 MW solar project adds a 50 MW battery but does not increase its maximum export capacity above 100 MW. From a system perspective, the battery may reduce pressure on the grid by absorbing midday solar production and shifting it to evening hours. But if the grid operator treats the project as if it automatically adds 50 MW of new burden, the economic and legal treatment may become inefficient.

This is why hybrid projects need a more sophisticated grid-access logic. The question should not be only “how many MW are installed?” The question should also be “what is the maximum controlled export profile and what flexibility does the battery provide to the system?”

The 2026 capacity allocation regime: grid access becomes an economic competition

The fourth legal anchor is ANRE Order no. 53/2024 and the related methodology for allocating grid capacity for connection of electricity production sites. The methodology enters into force on 1 January 2026 and introduces allocation through auction for new production sites with installed production capacity of at least 5 MW. It also applies to additional production or storage installations installed at existing production / consumption and production sites, and to storage installed at existing consumption sites where the relevant installed capacity is at least 5 MW.

The methodology expressly states that, throughout the document, the concept of “electricity production site” also includes, as applicable, “consumption and production site with/without storage installation” and “individual storage installation”. It also confirms that production sites may be with or without storage.

This is a major change for hybrid projects.

Until now, the Romanian renewables market has been heavily shaped by the race for ATRs. Grid capacity was often treated as a development asset. From 2026, for relevant projects, grid access becomes more explicitly linked to capacity allocation, network zones, commissioning years and auction logic.

For serious developers, this can be positive. It may reduce speculative grid blocking and make the queue more disciplined. But it also creates new risks: bid strategy, allocation cost, timing, network-zone selection and the possibility that grid capacity becomes a priced input in the business model.

For hybrid projects, the key practical question will be whether adding BESS requires additional allocated capacity or whether the battery can operate within the existing approved export limit. This distinction can materially change project economics.

A well-designed framework should not penalise a battery that reduces grid stress. If a BESS increases flexibility without increasing maximum export capacity, the regulatory treatment should reflect that.

Double charging: a key improvement, but not the full answer

The fifth legal and economic anchor is the elimination of double charging / double taxation of stored electricity.

This was one of the most important reforms for storage economics. A battery is not a final consumer when it charges. It stores electricity and later reintroduces it into the system. If the same electricity is charged with network tariffs, contributions or regulated fees when it enters the battery and then again when it returns to the grid, the arbitrage margin can be destroyed.

Romania has moved to correct this. Industry reporting notes that ANRE approved rules exempting stored and reintroduced electricity from regulated tariffs, while DNV’s 2026 assessment states that Romania improved the storage framework in 2025 by eliminating double taxation of stored electricity and exempting charging and discharging volumes from network tariffs and related fees.

This is a real improvement. It makes the economics of BESS more rational and aligns regulation with the physical function of storage.

But it does not solve everything. Removing double charging improves the margin. It does not create a bankable revenue floor. A hybrid project still needs a clear route-to-market strategy, predictable balancing access, an appropriate PPA structure and bankable grid rights.

Permitting and fast-track: useful reform, but implementation will decide

The sixth legal anchor is RED III and Romania’s partial transposition through GEO no. 59/2025, which amended the national renewable energy framework, including GEO no. 163/2022.

GEO 59/2025 introduced the logic of renewable acceleration areas, coordinated mapping of renewable potential and dedicated infrastructure zones for grid and storage projects. Public legal analyses note that the ordinance partially transposes RED III and requires coordinated mapping of areas with renewable potential, including “go-to” areas for renewables and dedicated infrastructure zones for grid and storage projects.

This matters for hybrid projects because permitting is one of the most underestimated barriers in PV+BESS development. A solar project already requires land rights, urbanism, environmental screening, building permit, grid route rights and technical approvals. Adding BESS introduces additional questions: fire safety, container layout, access roads, emergency response, environmental treatment, hazardous components, insurance, noise, civil works and local authority interpretation.

Romania’s one-stop-shop and fast-track logic can help, but it should not be oversold. It does not eliminate permits. It does not replace environmental, construction, grid, fire-safety or local approvals. It should make procedures more coordinated, more digital and more predictable.

For investors, the real test is not whether the law uses the language of acceleration. The real test is whether local authorities, environmental agencies, grid operators and the Industrial Licensing Office implement it consistently.

CfD and hybrid projects: useful for renewables, incomplete for storage

The seventh legal anchor is the Romanian CfD framework, approved through the relevant Government and Ministry of Energy framework, including the 2024 State aid scheme for renewable electricity from onshore wind and solar PV.

The CfD framework is important because it can stabilise revenue for eligible renewable generation projects. The scheme documentation refers to eligible technologies, project capacity, technical and financial bids, reference prices and strike prices within the CfD mechanism.

However, for hybrid PV+BESS projects, the CfD framework does not automatically create a complete commercial model for the battery. A CfD may support the renewable generation component, but the BESS component still needs its own revenue logic. The battery may earn from arbitrage, balancing, ancillary services, curtailment reduction or optimisation of the PPA/CfD position. But this requires careful structuring.

This is especially important where a battery charges from the grid. Investors and offtakers must clarify how stored energy is treated, whether it affects renewable attributes, how guarantees of origin are handled and whether the battery can participate in other markets without disturbing the CfD or PPA economics.

In short, CfDs may support the renewable base case, but they do not by themselves solve hybrid project bankability.

Public support for storage: strong signal, but mainly standalone

The eighth anchor is the €150 million Romanian State aid scheme approved by the European Commission on 5 March 2026 for new standalone battery energy storage systems. The scheme is designed to support at least 2,174 MWh of new storage capacity and is financed through the Modernisation Fund, with aid granted as direct investment grants.

This is an important signal for the Romanian storage market. It shows that BESS is increasingly viewed as system infrastructure, not only as a private merchant asset.

But for hybrid renewable + storage projects, the effect is indirect. The scheme helps the standalone BESS market. It improves investor confidence. It may support supply-chain development and local know-how. But it does not automatically solve the contractual issues of co-located PV+BESS projects: grid capacity treatment, charging rights, PPAs, route-to-market, degradation risk, balancing responsibility and dispatch control.

Hybrid projects still require bespoke legal and commercial structuring.

The commercial barrier: the revenue stack is attractive, but not automatically financeable

The reason hybrid projects are attractive is clear. They can combine several revenue and value layers: renewable generation, time-shifting, arbitrage, balancing, ancillary services, reduced curtailment, improved capture price, shaped PPAs and possibly tolling or optimisation structures.

But not all revenue layers are equally bankable.

Equity investors may accept merchant upside. Lenders usually need downside protection. A model based entirely on future spreads, balancing revenue and optimiser forecasts may be commercially attractive but difficult to finance with conventional project debt.

This is where legal documentation becomes central. Hybrid projects need bankable contracts: route-to-market agreements, tolling agreements, optimisation agreements, PPAs, direct agreements for lenders, O&M agreements, battery supply warranties, EMS performance obligations and degradation rules.

The legal documents must answer operational questions: who dispatches the battery, who controls the EMS, who owns upside, who bears imbalance exposure, who pays for degradation, what happens if grid restrictions prevent operation, and what step-in rights does the lender have?

In hybrid projects, law is not only compliance. It is revenue architecture.

The PPA must evolve

A conventional as-produced PPA is often not enough for a hybrid project.

A PV+BESS asset can potentially offer shaped electricity, peak-block delivery, firmed green energy, reduced imbalance exposure or a more predictable supply profile. That additional value must be reflected in the contract.

The PPA should clarify whether the offtaker purchases as-produced electricity, scheduled electricity, firmed electricity or shaped electricity. It should address guarantees of origin, battery losses, storage of grid electricity, dispatch control, imbalance risk, degradation, arbitrage rights and ancillary-service revenue.

If these issues are not addressed, the battery may exist physically but not commercially.

A serious hybrid PPA should no longer be only an energy sale agreement. It should be an optimisation and risk-allocation instrument.

Technology and interface risk: the hidden bankability issue

Hybrid projects also carry technology and interface risk. A battery must interact with the PV plant, grid connection, metering system, EMS, trader, optimiser, SCADA, protection system and grid operator.

If there are separate EPC contractors for the PV plant and the BESS, who bears interface risk?
If the EMS underperforms, who pays?
If the optimiser cycles the battery aggressively, who bears degradation?
If warranties are breached because of the commercial dispatch strategy, who is liable?
If the grid operator imposes limitations, how are revenues and losses allocated?

These are not secondary issues. For lenders, they are central.

A bankable hybrid project needs alignment between EPC, battery supply agreement, EMS contract, long-term service agreement, route-to-market contract, PPA and financing documents. Otherwise, the project may have a strong headline business case but weak contractual foundations.

What Romania still needs

Romania has made meaningful progress. Storage is legally visible. BESS is included in the grid-connection framework. The 2026 capacity-allocation regime expressly captures storage and hybrid configurations. Double charging has been addressed. RED III-style acceleration and one-stop-shop logic are emerging. Public support for standalone storage has been approved.

But hybrid renewable + storage projects still need more clarity.

Romania needs clearer treatment of installed capacity versus maximum export capacity. It needs more predictable rules on charging from the grid versus charging from the co-located renewable plant. It needs bankable ATRs that address curtailment, N / N-1 limitations, reinforcement works and operational restrictions. It needs clearer permitting practice for BESS. It needs more sophisticated PPAs, tolling structures and optimisation contracts. It needs practical implementation of aggregation and balancing access.

Most importantly, Romania needs to recognise hybrid projects as integrated flexibility assets, not as separate legal boxes placed behind the same fence.

Conclusion: hybrid projects are the next test of Romanian energy bankability

Hybrid renewable + storage projects are no longer a futuristic concept. They are becoming the natural evolution of renewable investment.

Romania has the ingredients: solar growth, grid pressure, volatility, coal phase-out, public support, EU-driven reforms and improving recognition of storage. But the market will not be unlocked by installing batteries alone. It will be unlocked by aligning law, grid access, permits, contracts and revenue models.

The winners will be the investors and developers who understand that a hybrid project is not simply PV plus BESS. It is a legal, technical and commercial platform.

The best summary is this:

Romania has started to recognise storage. The next challenge is to make hybrid renewable + storage projects truly bankable.