Romania’s Grid-Capacity Allocation for Generators (2026): Legal, Market & Operational Analysis
Abstract. Romania’s power market has been waiting for this moment. Transelectrica has published the long-anticipated Procedure on the Allocation of Grid Capacity for the Connection of Generation Sites, implementing ANRE Order no. 53/2024—the new Capacity Allocation Methodology that will redefine access to the grid starting 1 January 2026. The reform replaces administrative queues with a transparent, price-based competition for scarce network capacity and shifts value to developers able to execute, not just reserve.
Introduction
Romania is pivoting from first-come connection queues to market-based allocation for new generation. The instrument: an auction that awards a time-bound right to connect at specific nodes. The change complements the CfD programme: while CfDs stabilise revenues, capacity auctions rationalise who gets scarce evacuation rights—together strengthening bankability in utility-scale renewables. See our sector overview: Renewable Energy Romania and the content hub at Articles.
Business impact: grid access becomes a priced ten-year right of use—an explicit line in LCOE models. Legally: priorities are re-anchored in a competitive, non-discriminatory framework with enforceable obligations. Technically: sponsors must internalise nodal constraints (N versus N-1), reinforcement timetables, and storage for dispatchability.
Legal framework and governance
The regime draws authority from the Electricity Law (as amended by OUG 143/2021) and secondary ANRE rules enabling auction-based access. ANRE Order no. 53/2024 is the methodology; Transelectrica’s procedure is the operational playbook. Order 59/2013 continues to govern racordare (application, solution study, ATR, connection contract) after allocation. At EU level, Regulation (EU) 2019/943 and RED II/III provide the market-law and permitting context. Competition and state-aid rules remain relevant to auction design and information symmetry.
Governance: Transelectrica runs allocations and integrates DSO inputs into the annual capacity study. ANRE monitors compliance and arbitrates disputes. DSOs ensure coherence at the transmission-distribution interface.
What Transelectrica has just published
The Procedure translates the methodology into a unified workflow binding Transelectrica’s units, participating DSOs, and bidders. Annual node/voltage-level MW (the supply curve) is set under Order 137/2021 and published with auction documentation. Capacity is allocated for ten years (T+2 to T+11). The sole award criterion is the bid price (€/MW/year), pay-as-bid. Non-use or missed milestones triggers revocation and re-auctioning—an explicit anti-hoarding device.
Auction mechanics and economic signals
Auctions are announced with node-level MW, rules, and a calendar. Bidders file requests and guarantees, then compete on €/MW/year by node. Transelectrica ranks bids descending by price until MW is exhausted; winners pay their own price on the defined schedule, typically annually in advance through the ten-year window.
Micro-economics: constrained nodes clear higher; bidders with better technical solutions (lower curtailment, faster permits, credible reinforcement alignment) can rationally bid more and still meet DSCR/WACC constraints.
How the fee rolls into LCOE
The annual allocation fee becomes a straightforward cost item in LCOE. Illustrative arithmetic: €10,000/MW/year at a 24% capacity factor adds ≈€5/MWh; at 40% it adds ≈€3/MWh. Sponsors should run sensitivities for curtailment, delays, and production variance. For the revenue side, see Romania CfD Renewable Energy.
Post-award milestones and revocation
Allocation grants conditional access, not a connection. Winners must promptly file under Order 59/2013, obtain the technical solution and ATR, secure permits (urbanism, EIA where applicable), and contract connection works. Validity depends on timely progress and payment. Missed deadlines or non-payment trigger revocation and re-auction; carve-outs cover force majeure and operator-side delays.
Transferability and transaction practice
The allocation attaches to the project at the node. Share deals (selling the SPV) are generally feasible subject to project identity and a no-objection from the operator. Asset deals (assigning the allocation) typically require prior approval. Financing practice favours share-based transfers, lender step-in rights, and assignment of receivables linked to fee payments.
The interface with ATR and grid-code compliance
Winning capacity does not auto-issue an ATR. Projects traverse the full connection chain under Order 59/2013: application → study/solution → ATR → connection contract → works → commissioning. Compliance must meet the 2018 norms (NC RfG translation). PV, wind, and BESS are power-electronics-interfaced modules; storage can mitigate curtailment but remains subject to the same connection discipline.
Payments, guarantees, and lender perspective
The €/MW/year fee converts access into a predictable outlay. Auction documents define bid/performance guarantees, payment cadence, and consequences of non-payment (suspension, revocation). For financing, the allocation letter gains value as the project reaches ATR, then the connection contract, and energisation.
- No-objection language for change-of-control and security assignments;
- Extensions where operator-side reinforcements delay access;
- DSRA sized to the allocation-fee calendar; and
- Curtailment-aware P50/P90 stacks keeping DSCR ≥ 1.35–1.50×. See also Renewable Energy Insolvency in Romania.
Risk, enforcement, and execution discipline
Non-performance is costly. Revocation may follow missed milestones, unpaid fees, or unapproved changes to project identity. Execution priorities: N and N-1 dispatch modelling, EPC clauses on curtailment allocation and reactive capability, SCADA/telemetry readiness, and permit sequencing. Contracting must calibrate force majeure, change-in-law, operator-delay remedies, dispute resolution, and transparency obligations.
Business model and valuation implications
Treat the €/MW/year obligation as a semi-fixed LCOE component. In CfD projects the fee reduces headroom between strike and all-in LCOE; in merchant/PPA structures it compresses margins unless offset by higher capture prices or flexibility revenues (e.g., storage-enabled arbitrage). Optimal bidding blends node economics, reinforcement timing, and portfolio optionality.
Legal implications and remedies
- Transferability discipline (approval/no-objection);
- Revocation triggers and proportionality;
- Force-majeure calibrated to permitting and construction realities;
- Operator-delay remedies where reinforcements lag;
- Confidentiality and data-access rules around auction information; and
- Continued alignment with competition and state-aid law.
Robust change-in-law provisions should address connection tariffs, allocation-fee treatment, and balancing obligations.
Technical firmness and dispatchability
Firmness depends on N versus N-1 operation and completion of reinforcements. Sponsors should model curtailment bands, voltage profiles, and dynamic operating envelopes, and ensure plant controllers and inverters meet grid-code requirements with margin (reactive capability, ride-through, ramping). Storage can reshape output and provide ancillary services within the agreed connection profile.
Implications for 2026 and beyond
The capacity-auction regime will determine which projects reach COD, complementing CfDs by rationing access, not revenue. Policymakers should ensure predictable annual auctions and transparent reinforcement roadmaps. Sponsors must bid realistic €/MW/year after node-level diligence and secure ATR and permits within prescribed windows. Lenders will scrutinise the allocation/connection interface as a core credit dimension.
Related reading: Romania: CfD for Renewable Energy · Renewable-energy insolvency in Romania · All articles
References: ANRE · Transelectrica · EUR-Lex
