Abstract

This article examines the legal status and economic impact of the N and N-1 rule in the solution study procedure for connecting a utility-scale PV plant above 50 MW to Romania’s electricity grids. Based on the national legal framework – Electricity Law no. 123/2012, the Grid Connection Regulation (ANRE Order no. 59/2013, as amended) and the Capacity Allocation Methodology – correlated with Regulation (EU) 2019/943, we argue that the evacuation limitations resulting from N-1 scenarios are mandatory in nature and become contractual obligations enforceable against the investor through the Connection Technical Approval (ATR) and the connection certificate.

From an economic perspective, these limitations constitute a structural risk that must be internalized in financial models, affecting IRR, the PPA/CfD structure and the bankability of the project. The analysis also integrates ENTSO-E technical security criteria and shows how these requirements are translated into contractual terms, financing covenants and guarantee policies. The article discusses implications on P50/P90 volume calibration, cost of capital, and mitigation strategies – from special protection schemes and reactive power management to integrating storage capacity or operational flexibility.

We conclude that only an integrated approach, aligning the ATR technical annex with the contractual structure and financial assumptions, can transform the N-1 rule from a constraint into a predictable framework for risk management and value maximization.

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Introduction

The connection of utility-scale PV plants requires navigating a methodological pathway where technical, legal and economic dimensions are inseparable. In Romania, acceptance for grid connection is conditional upon demonstrating compliance under both N (intact system) and N-1 (single contingency) regimes.

For above 50 MW plants, this test is not a technical formality but the starting point of a contractual and financial architecture that will accompany the project throughout its lifecycle. Beyond power flow calculations, the N-1 rule effectively determines how operational risks are distributed among the producer, the grid operator and commercial counterparties.

Grid connection is no longer an engineering checklist; it is the legal and financial DNA of a project.

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Legal framework and significance of N/N-1

The N regime represents the situation where the system is fully intact, with no outage or element out of service. Practically, it means that the entire transmission and distribution network is available, and the producer can evacuate power without restrictions. Commercially, this regime offers the premise of maximum production sold and a predictable revenue stream. Yet it is an idealized scenario that does not reflect day-to-day operational reality.

The N-1 regime describes the situation where a critical network element – a line, a transformer or major equipment – is out of service, whether due to a fault or scheduled maintenance. European and national rules require the grid to remain secure and stable under these conditions. For renewable producers, this translates into possible limitations on power evacuation, since the remaining infrastructure may not handle the flows in the absence of one element.

Commercially, the N-1 regime implies risks of revenue reduction, production losses, and the need to reflect these constraints in PPA or CfD contracts. It may also generate additional costs through the investor’s obligation to finance grid reinforcements or implement flexibility solutions.

In conclusion, the ATR must include both regimes – N and N-1 – to provide a realistic and complete picture of connection conditions. N shows the project’s maximum potential, but it is not robust enough to guarantee grid safety in case of fault. For this reason, N-1 is mandatory: it tests what happens when a critical element fails and imposes restrictions or reinforcements to maintain system security.

Practically, there is no option to “choose” only N – the ATR must include N-1, otherwise the approval would be null. Reinforcement costs arise under both N and N-1. In N, they may appear lower at first glance, as they relate only to normal system operation, but the risk is higher: if a fault occurs, energy cannot be evacuated, and commercial losses may be significant. In N-1, reinforcement costs may be higher, reflecting the European minimum security standards, but they ensure evacuation stability even under fault scenarios and reduce the risk of frequent disconnection.

In other words, N seems cheaper at first, but N-1 is costlier and more restrictive, while providing stronger commercial and operational protection. Commercially, N-1 may reduce available production and revenues, but this technical discipline prevents more severe situations such as widespread outages or loss of grid access. Thus, the investor pays more and accepts limitations but gains a solid connection right compatible with EU safety norms.

N shows potential, N-1 shows reality – investors must learn to live with both.

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Legal-economic dynamics of N-1 limitations

The explicit presence of N-1 scenarios in the ATR directly affects connection costs. If the analysis shows that the existing grid cannot sustain evacuation without overloads under N-1, the operator may condition connection on reinforcement works – building a new line, upgrading a transformer or expanding a substation.

These works can be classified as “reinforcement works” funded through grid tariffs, or as “connection works” directly borne by the investor. The distinction is crucial: in the first case, the cost is socialized and recovered through distribution or transmission tariffs. More concretely, the operator includes these expenses in the regulated asset base (RAB), and ANRE recognizes them in the regulated tariff paid by all final consumers. In practice, the investor who initially financed the works has the right to recover amounts from the operator under an ANRE-approved mechanism, usually via staggered deductions from tariffs, reimbursed annually over several years.

Thus, the investment burden is distributed across all network users, not permanently on a single producer’s balance sheet. From an accounting perspective, these expenditures are recorded as financial fixed assets or receivables from the operator, not as the plant’s own assets. In the case of “connection works”, costs remain fully with the investor, capitalized in CAPEX and reflected as tangible assets of the project. The ATR therefore becomes not only a technical document but also an instrument for distributing costs and recovery rights among system actors.

Economically, the inclusion of N-1 scenarios in the ATR requires careful assessment of curtailment risk and reinforcement costs. If limitations are moderate and manageable via protection schemes and automation, the impact on cash flows is relatively controlled. If, however, the ATR stipulates massive reinforcement works borne by the investor, the project may become financially unfeasible. Similarly, repetitive curtailment under N-1 scenarios may cause losses that significantly reduce IRR, even when initial connection costs were moderate.

Every euro spent on reinforcements is either a sunk cost or a lever of long-term stability – depending on how it is structured.

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Effects on commercial contracts

Compensation for undelivered energy is one of the most sensitive issues, both under N and N-1. In N, even if the producer seems protected, a fault can lead to total evacuation impossibility, and even in such cases current legislation does not oblige grid operators to compensate. In N-1, limitations are more explicit and integrated into the ATR, but again – commercial losses remain with the investor.

Consequently, the investor bears the full risk. Still, commercially, this risk can be partially transferred or shared through contractual mechanisms. In PPAs, some buyers may accept “make-whole” or “revenue floor” clauses, but only within carefully negotiated limits and usually at lower energy prices. In CfDs, the state does not compensate for technical curtailment, but the investor may calibrate the bid to account for this risk and avoid over-commitment.

Thus, while there is no automatic legal right to compensation, in economic terms protective mechanisms can be built through negotiation. It is crucial to distinguish: production losses due to technical N or N-1 limitations are not compensated by grid operators, but commercial imbalances in the market (when the producer notified firm energy but cannot deliver) are settled under balancing market rules.

In such cases, the financial responsibility lies with the producer or its BRP, by purchasing missing energy from the market, turning technical non-evacuation into an additional cost. Only via specific contractual clauses (revenue floor, insurance, PPA make-whole) can a form of commercial compensation be obtained. In their absence, the risk remains on the producer’s balance sheet and is reflected in the cost of capital. This explains why banks and institutional investors demand maximum clarity in ATR annexes and stress-test scenarios on curtailment and reinforcement costs.

Curtailment is not just lost energy – it is a contractual silence that investors must fill with negotiation.

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Implications for financing and project assessment

From the creditors’ perspective, the quality of the ATR technical annex and the traceability between this annex, the connection certificate and the implemented technical solution become due diligence criteria.

Banks require explicit modelling of N-1 scenarios and proof that curtailment automation is sized and tested to avoid uncontrolled overloads. For the simple N scenario, creditors generally do not consider it sufficient to validate bankability, since it does not cover fault risk; sometimes they do not treat it as relevant in financing analysis, because N-1 is the minimum European security standard.

Consequently, a project based solely on N has very low chances of securing financing. Lack of granular information – e.g. missing contingency lists or trigger thresholds – typically leads to higher loan margins or additional coverage requirements (reserve accounts, extended DSRA, technical performance covenants). For investors, the N-1 rule influences both commissioning timelines (if reinforcements are needed) and hedging strategies, with a careful alignment recommended between “firm volumes” in PPAs and the probabilistic curve of deliverable energy post-limitations.

For banks, N-1 is not a scenario – it is the only language of creditworthiness.

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Compatibility with EU law

At the European level, the principle of non-discriminatory grid access coexists with operators’ ability to impose restrictions strictly for system security. The N-1 rule, as applied in Romanian law, falls within this margin of appreciation, provided that limitations are transparent, proportionate and applied uniformly.

This compatibility does not remove the requirement of justification: the operator must demonstrate that the restriction derives from system analysis, not from discriminatory or arbitrary practices. If the investor considers transparency standards unmet, it has the right to challenge the ATR.

Procedurally, the challenge is first filed with ANRE as an administrative complaint under Law no. 123/2012 and the Grid Connection Regulation; ANRE must assess the legality and soundness of ATR conditions and may order their amendment or annulment. Subsequently, if ANRE’s solution is deemed unlawful or insufficient, the investor may file an administrative court action under Law no. 554/2004, with courts having the final competence to review ATR legality.

European law allows constraints, but never opacity – transparency is the price of legitimacy.

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Conclusions

The N-1 rule is the pivot connecting grid security with the bankability of large PV projects. Still, the N regime also has relevance: it shows maximum evacuation potential and serves as the base scenario for revenue modelling, even if insufficient for bankability validation. For investors, including N-1 scenarios in the ATR is mandatory and unavoidable, but how these translate into reinforcement costs or curtailment may decide the project’s financial viability.

Without a correct evaluation of N, financial projections may be over-optimistic, while without N-1, the project is not eligible for financing. Legally, there is no automatic right to compensation for undelivered energy, but commercially protective mechanisms may be negotiated.

Ultimately, the project only becomes credible if technical documentation, contractual clauses and financial models are aligned. Without such coherence, the investment remains exposed to double vulnerability: legal uncertainty and financial fragility. Conversely, an integrated approach – treating the ATR not just as a technical approval but as the founding document of the project’s economic and legal architecture – turns the N-1 rule into a tool for risk optimization and value maximization.

However, starting January 1, 2026, the modification of the capacity allocation methodology – moving to a competitive auction-based system – will amplify the relevance of these analyses. If until now the ATR functioned in a relatively administrative regime, from this date the ATR will be directly tied to auction results, and the costs and limitations associated with N and N-1 will decisively influence bidding strategy and project competitiveness.

In practice, investors will no longer be able to ignore the economic impact of these scenarios, as the bid price must be calibrated to a realistic deliverable energy profile, adjusted for grid restrictions and potential reinforcement works.