Is a Romanian solar project still profitable for a 2027–2028 COD?

A Romanian solar project can remain attractive in 2027–2028, but not simply because the average electricity price is high. The decision must rest on the price actually captured during generation hours, curtailment exposure, balancing costs, PPA structure and grid obligations. A model that applies a single average day-ahead price to the entire output can materially overstate revenue. Neither legislation nor today's market data can guarantee a future electricity price.

Why is the day-ahead average not the project’s revenue price?

Capture price is the generation-weighted average price achieved by a particular production profile, not the arithmetic or generic market average. Solar assets produce disproportionately during sunny periods, when rising volumes from similar plants can depress prices. This is solar cannibalisation: it does not mean every sunny hour has a negative price, but that the market value of the generation profile may fall relative to the market-wide benchmark.

OPCOM publishes wholesale-market results and statistics. Use hourly or sub-hourly prices and an appropriate site-specific P50/P90 generation profile, rather than one monthly mean. The model should distinguish gross electricity revenue, net revenue after route-to-market and balancing costs, and sensitivity to zero and negative prices. A point forecast for 2028 should never be presented as certain.

Which risks are hidden inside a PPA?

A Power Purchase Agreement can reduce merchant exposure, but converts it into different contractual obligations. Check whether the price is fixed, indexed or shaped; whether floors or caps apply; how negative-price events are treated; who bears imbalance exposure; and how certificates or guarantees of origin are allocated. A pay-as-produced PPA does not offer the same protection as a firm-volume or sleeved structure.

Legal review must also cover offtaker creditworthiness, payment security, termination rights, lender step-in, change in law and security assignment. If the PPA requires delivery before the project can achieve COD because the grid is late, revenue loss may coincide with contractual damages. The offtake agreement must align with the ATR, connection agreement, EPC and financial model.

How should curtailment and grid constraints be modelled?

Reduced injection may result from technical limitations, connection design, operational restrictions or contract terms; these do not always have identical legal consequences or compensation rights. Therefore ATR and solution-study review belongs in revenue modelling, not merely in legal due diligence. Where reinforcement is required, identify limitations before completion and who controls the delivery schedule.

Transelectrica's grid development plan gives system context, not a guarantee for an individual connection point. Request scenarios for reduced injection, delayed energisation and changed market rules. Do not apply an unsupported generic curtailment rate across all Romanian counties.

Can co-located BESS repair solar project economics?

A co-located battery may reshape exports, reduce some low-price exposure and create additional market opportunities. But it does not automatically turn every low-value solar MWh into a high-value MWh. Charge/discharge power, duration, conversion losses, cycling, degradation, approved import capacity and dispatch constraints determine real value.

Before hybridisation, check whether the ATR and permits support the revised plant, what modifications are required, whether additional guarantees arise and who controls battery dispatch. A commercial “BESS revenue uplift” assertion without hourly modelling, network constraints and an optimisation agreement is a hypothesis, not an investable business case.

What should a buyer request before acquiring the project?

A PV project targeting a 2028 COD must be examined through two lenses. The legal lens covers land, zoning, environment, building permit, ANRE, ATR, connection agreement, guarantees and deadlines. The commercial lens covers yield, capture price, PPA/merchant allocation, imbalance costs, CAPEX, OPEX, cost of capital and downside cases. If one is missing, the claim of bankability remains unproven.

Request an editable model, technical evidence for its assumptions and documents supporting each material revenue or cost category. A low EUR/MW acquisition price can conceal a larger systemic risk than the apparent price difference between two assets.

Can anyone confidently predict Romanian solar prices in 2028?

No. Published market data, transmission planning and the ANRE development pipeline inform scenarios, not guaranteed prices. ANRE reports the scale of projects at different development stages, but MW holding an ATR do not equal MW that will achieve COD. A prudent buyer or lender tests faster competing build-out, slower network investment and different paths for electricity demand.

The practical output is a PV Revenue Risk Memo with base, downside and severe-downside cases, followed by actions available today: PPA, hedging, BESS configuration, financing timetable and maximum acceptable acquisition price.

Hypothetical example: the investment decision

*Hypothetical example, not a reference to an actual project.*

Suppose a hypothetical plant generates 100,000 MWh per year. At a realised capture price of EUR 70/MWh, gross energy revenue would be EUR 7 million; at EUR 45/MWh it would be EUR 4.5 million, before costs, imbalances and curtailment. The EUR 2.5 million annual difference illustrates price sensitivity, not a forecast for Romania. A buyer must verify what share can be covered under a PPA and what remains merchant-exposed.

Developer Action Checklist: what should be checked in the next 30–90 days?

1. Replace generic market averages with generation-weighted capture-price assumptions. 2. Model negative prices, imbalances, restricted injection and delayed COD separately. 3. Review PPA volume, shape, price, offtaker security, change-in-law and lender step-in provisions. 4. Build a separate PV-plus-BESS case accounting for losses and technical restrictions. 5. Ensure the legal grid-rights assessment is consistent with revenue assumptions.

Conclusion and next steps

A developer does not need to prove that solar will always be profitable. It must demonstrate under what assumptions the asset remains profitable and which actions are available if prices disappoint. That is the language investors and banks can underwrite.

Request a project-specific assessment. Grigorescu & Partners can review the key documents and prepare a focused risk, deadline and action report. Discuss a mandate or Email us the project details.

Primary sources and verification date

*Analysis updated on 12 October 2026.*

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Editorial note: For general information, not project-specific legal advice. Applicable rules depend on project history, documents, contracts and subsequent amendments.