Romania spent five years proving it could attract renewable energy capital. In 2026 it is rebuilding the rules that decide which of that capital actually turns into megawatts.
For most of the last five years, the question investors asked about Romania was whether the market would scale. That question has been answered. Romania added 2.2 GW of solar in 2025 and pushed cumulative installed capacity past 7 GW. In the first five months of 2026 alone it installed roughly 1.5 GW more, split almost evenly between utility scale plants and prosumers, putting the country on course to break its own record for a second consecutive year. On 19 June 2026, dispatchable solar plants delivered a record 2.952 GW into the national grid, while prosumers contributed an estimated 1.93 GW on top of that.
So the scaling question is settled. A harder one has replaced it: out of the enormous pipeline sitting in Romanian permitting queues, which projects will actually be delivered?
That is precisely the question Romania’s new energy framework was designed to answer. Across 2026, the country is replacing the mechanism that decides who gets to build. Grid access is moving from an administrative queue to a competitive auction. Financial guarantees are rising by a factor of four or more. Deadlines that were previously elastic now carry automatic forfeiture. For investors, developers, independent power producers, infrastructure funds and project financiers, this is not a policy footnote. It changes the underwriting model.
The one statistic that explains the entire reform
In early 2026, ANRE, Romania’s national energy regulator, published a figure that explains everything that followed. Of the projects that had posted the 5 percent grid connection guarantee introduced in August 2024, only 12 percent went on to sign a connection agreement. Just 3 percent obtained a building permit. And only 1 percent reached all three milestones of signed agreement, building permit and setting-up authorisation.
Read that again. Ninety-nine out of every hundred projects holding grid capacity were not converting it into construction. Capacity that appeared allocated on paper was, in economic terms, parked. Genuine investors were queuing behind positions that had no realistic prospect of being built, and the transmission system operator was planning reinforcement works against demand signals that were largely fictional.
A 5 percent guarantee, in other words, was cheap enough to make speculation rational. The 2026 framework is a direct response to that arithmetic.
Grid access has become a market, not a queue
The structural change is the replacement of first come, first served grid allocation with competitive auctions. Under ANRE Order 53/2024, capacity for generation and storage facilities of 5 MW or more is allocated through annual auctions covering a ten year allocation period beginning two years after the auction. Transelectrica, the transmission system operator, runs the process, and all bids go to the TSO even where the eventual connection point sits in a distribution network.
ANRE Order 79/2025, adopted on 16 December 2025, then reset the calendar for the first cycle. The published milestones run as follows:
• 30 June 2026: Transelectrica publishes available grid capacity.
• 14 July 2026: deadline for capacity allocation applications.
• 24 July 2026: the TSO finalises the list of eligible applications.
• 23 October 2026: completion and publication of the global solution study identifying required reinforcement works, together with available capacity, starting prices and auction dates.
• 30 October 2026: daily bidding sessions begin.
Starting prices are calculated by dividing the estimated value of the necessary grid development works by the total available capacity, which means the market, rather than an administrative fee schedule, sets the cost of scarce grid access.
Alongside the auction, the financial architecture has been tightened substantially. Following a public consultation in spring 2026 that drew submissions from both the Prime Minister’s Office and Transelectrica, ANRE announced on 24 April 2026 that connection rules will require a guarantee deposit of EUR 20 per kW simply to participate in the capacity allocation auction, a guarantee of 20 percent of the connection fee once the application is submitted and the solution study approved, and a further guarantee of EUR 30 per kW when applying for a setting-up authorisation. Missing statutory deadlines for building permits and setting-up authorisations triggers invalidation of the connection permit, automatic termination of the connection agreement, and forfeiture of the guarantees.
The message to the market is unambiguous. Holding grid capacity is now expensive, time limited and evidence based.
Revenue visibility now has a three round track record
Romania’s Contracts for Difference scheme is no longer a promise. It is a functioning mechanism with results investors can benchmark.
The first round, concluded at the end of 2024, awarded roughly 1.5 GW. The second round, run in August 2025 with support from the European Bank for Reconstruction and Development, awarded 2,751 MW across 49 winners: 1,488 MW of solar at an average strike price of EUR 40.35 per MWh, and 1,263 MW of onshore wind at an average of EUR 73.89 per MWh. Combined with round one, that took total awarded capacity to 4.2 GW, ahead of the 3.5 GW target set under Romania’s Recovery and Resilience Plan. A third round, dedicated exclusively to onshore wind, closed in December 2025 and awarded approximately 316 MW at strike prices between EUR 59.95 and EUR 74.9 per MWh.
The scheme carries an estimated budget of EUR 3 billion, financed through the EU Modernisation Fund and the National Recovery and Resilience Plan. Contracts run for 15 years, with Transelectrica acting as programme operator and OPCOM as contractual counterparty.
Two things matter here for anyone building a financial model. First, the solar clearing price fell sharply between rounds, from a range of EUR 45.05 to EUR 54.19 per MWh in the first auction to EUR 35.77 to EUR 45.2 per MWh in the second. That is a competitive market discovering its own cost base. Second, the wind quota in round two was undersubscribed, with only 1.26 GW awarded out of 2 GW available. Romanian onshore wind still carries a cost of capital and a permitting burden that solar does not.
Storage stopped being optional
The clearest argument for storage in Romania is not a policy document. It is a single day of price data.
On 19 June 2026, at the moment solar output hit its record, the spot price sat at RON 74 per MWh, roughly EUR 14. That evening, once solar faded, the price reached as high as RON 1,500 per MWh, roughly EUR 286. A twentyfold intraday spread in a system exporting around 2.2 GW at midday is not a market anomaly. It is a structural signal, and it is repeating.
Policy has caught up. On 5 March 2026, the European Commission approved a EUR 150 million Romanian state aid scheme for standalone battery storage, financed through the Modernisation Fund and designed to support at least 2,174 MWh of new capacity. Support is capped at EUR 69,000 per MWh installed with a maximum per beneficiary, awarded through competitive tendering, with eligibility requiring a minimum of 1 MW and a capacity to power ratio of at least two to one. Implementation runs to the end of 2030. The Ministry of Energy has since bundled this into a wider EUR 250 million Modernisation Fund allocation covering batteries and smart meters.
The market has responded faster than the subsidy. Around 400 MW of utility scale battery capacity was installed in Romania in the first half of 2026, taking the national total to approximately 1 GW and 2 GWh. The EBRD is providing up to EUR 44 million, including EUR 29 million backed by an InvestEU first loss guarantee, for the 127 MW and 254 MWh standalone project at Scornicesti co-owned by R.Power and Eiffel Investment Group, structured on a non-recourse project finance basis. That last detail is the important one. Standalone storage in Romania has now been underwritten as bankable infrastructure, not as a merchant experiment.
Co-location is following the same logic. In a single regulatory session in February 2026, ANRE approved close to 850 MW of new generation capacity alongside 596 MW of storage, with the largest single item a 550 MW photovoltaic plant in Giurgiu County paired with 534 MW of storage. Hybrid is becoming the default configuration, not the premium one.
The price signal is finally a real signal
Romania removed its electricity price cap on 1 July 2025, ending a scheme the OECD described as having weakened efficiency incentives, disrupted liberalisation and increased investor uncertainty. The transition was painful for consumers, with average bills rising by more than 60 percent in the first month, and it fed directly into inflation. But for anyone modelling merchant revenue, curtailment risk or storage arbitrage, Romanian wholesale and retail prices now reflect something closer to market fundamentals than at any point since 2021.
The contractual layer is maturing alongside it. Government Emergency Ordinance 59/2025, adopted in November 2025, established the legal foundation for an EU aligned guarantees of origin regime, with ANRE required to adopt issuance and tracking regulations by 30 September 2026. Romania became an observer at the Association of Issuing Bodies in 2025 and is working toward full membership. This matters commercially: the non tradability of Romanian guarantees of origin has been one of the main constraints on the corporate PPA market, which has produced close to 40 agreements since the bilateral PPA ban was lifted, split broadly between solar and wind with hybrid structures now emerging.
Permitting is moving too, if more slowly. Romania is progressively implementing RED III, and the government is required to approve plans designating renewable acceleration areas by 31 December 2026, prioritising rooftops, facades, transport and parking infrastructure, industrial sites, former mines, artificial water bodies and degraded land, while excluding Natura 2000 and sensitive protected areas.
What this actually changes in the investment case
Put the pieces together and the shift is straightforward to describe, if not to execute.
Project maturity is now the primary valuation driver.
A project holding only a technical connection permit is no longer comparable to a project holding a connection permit, a signed grid connection agreement, a valid building permit, an environmental act, an ANRE setting-up authorisation and secured land rights. The gap between those two positions used to be a timing difference. Under the 2026 rules, with automatic forfeiture attached to missed deadlines, it is a survival difference. Expect that to show up directly in acquisition pricing.
Capital intensity has moved earlier in the project lifecycle.
Guarantees of EUR 20 per kW to enter an auction, 20 percent of the connection fee thereafter and EUR 30 per kW at authorisation stage mean development capital is now committed further ahead of financial close. Developers running a broad, thinly capitalised option strategy across many sites will struggle. Balance sheet depth becomes a genuine competitive advantage.
Revenue strategy has to be designed, not assumed.
With three CfD rounds completed, a functioning if still shallow PPA market, an emerging guarantees of origin regime and an increasingly volatile merchant curve, Romanian projects can now be structured around a deliberate revenue mix rather than a single mechanism. Lenders will expect to see that mix stress tested.
The pipeline is about to be repriced.
If the auction and guarantee regime does what ANRE intends, a significant volume of speculatively held capacity will be released back into the system. For holders of advanced, deliverable projects, that is unambiguously positive. Their relative competitive position strengthens, and the grid zones they occupy become more valuable.
The risks worth naming
Objectivity requires stating what could go wrong.
• Timetable risk is real. The first capacity auction has already been deferred once, from January 2026 to October 2026, pending completion of the grid studies. Further slippage cannot be ruled out.
• Transitional treatment of legacy applications has been messy. Connection requests registered before 1 January 2026 without submitted solution studies triggered reimbursement obligations, and applications where the technical connection permit is not issued by 30 June 2026 face termination.
• Acceleration areas are not yet a shortcut. They become meaningful only once the government approves concrete plans, and they do not remove the need for land and environmental due diligence.
• The extra muros regime enabling renewable projects on land outside built-up areas under Law 254/2022 carries a 31 December 2026 effect date that has not yet been extended, with no transitional protection for projects still in permitting.
• Romania has a history of retroactive support scheme changes. The green certificate cuts from 2013 produced successful ICSID claims against the state under the Energy Charter Treaty. That history is priced into the country risk premium and should be acknowledged rather than ignored.
• Midday cannibalisation is arriving early. With solar already setting grid share records and exports running at 2.2 GW at peak output, unhedged solar merchant exposure in Romania is a deteriorating position, not a stable one.
Why Romania still compares well in the region
None of the above changes the underlying case, and on a regional comparison the case remains strong.
Romania combines a genuinely bankable resource base, with the Dobrogea wind belt and southern and western solar corridors, with something scarcer in Central and Eastern Europe: a state support mechanism that has actually cleared, three times, with published prices. Greece has a more developed dedicated storage support regime. Bulgaria has committed larger grant volumes to storage under the RESTORE programme. But Romania has combined revenue stabilisation through CfDs, capital grants for storage, a liberalised retail market and multilateral lender participation from the EBRD in a single, functioning package. Financing a project in the region has historically carried a materially higher weighted average cost of capital than in Western Europe, precisely because of the absence of instruments such as CfDs. Romania has closed a meaningful part of that gap.
Scale reinforces the point. Rezolv Energy’s Dama Solar project in Arad County, at 1,044 MW, is expected to become the largest solar plant in the European Union. Enery’s Ogrezeni project pairs 760 MW of solar with 1 GWh of storage. Transelectrica anticipates around 12 GW of new capacity by 2031 across solar, gas, wind and nuclear, and Romania’s National Energy and Climate Plan targets 38.3 percent renewables in gross final energy consumption by 2030, with the national strategy pointing to 44 percent low carbon by 2035. Interconnection with Hungary and Bulgaria adds export optionality that markets without it cannot offer.
The honest summary is this: Romania has stopped competing on the promise of opportunity and started competing on the quality of delivery. For investors who can execute, that is a better market to be in.
Momentum Energy’s View
We read the 2026 framework as a filter, not a brake. Romania has not become a harder market to invest in. It has become a harder market to speculate in, and those are very different things.
The practical implication for anyone allocating capital in the next twelve months comes down to three decisions.
First, audit the pipeline against delivery, not against megawatts.
Every project in a Romanian portfolio should now be scored on six gates: secured land rights, technical connection permit, signed grid connection agreement, environmental act, valid building permit and ANRE setting-up authorisation. Anything that fails three or more of those gates should be treated as an option, valued as an option, and funded as an option. We expect the market to reprice this distinction sharply once the October 2026 auction results are known.
Second, treat storage as part of the base case, not the upside case.
A twentyfold intraday price spread on a record solar day is the clearest possible signal that flexibility, not generation, is where the marginal value now sits. Projects designed today without a co-location pathway, whether built immediately or reserved in the connection capacity, are being designed for the price environment of 2022 rather than that of 2028.
Third, get the guarantee capital committed before the auction, not during it.
The EUR 20 per kW auction deposit and the subsequent 20 percent connection fee guarantee are not administrative line items. They are a real call on liquidity at a stage where many development vehicles are thinly funded. Investors who arrange this facility ahead of the bidding window will have a structural advantage over those negotiating it while the clock runs.
Romania is entering the phase where regulatory clarity and execution capability, rather than land banking and grid queue position, decide returns. That is the phase where experienced partners matter most, and it is the phase we believe Romania is best positioned to reward.
