By Daniel Pintilie, Senior Energy Strategist and Founder of SolarCAP Investments (LinkedIn).
Abstract
Project delivery across Central and Eastern Europe consistently lags behind renewable energy targets, yet pipelines are overflowing with formally approved capacity. The explanation most commonly offered, including permitting delays, financing gaps, supply chain disruptions, misses the mechanism sitting upstream of all of them. Grid access is the binding constraint. Across CEE markets, the right to connect to the electricity grid is rationed through administrative mechanisms that assign no economic value to the scarcity they manage. Drawing on two decades of direct engagement in Romanian and CEE power markets, this paper reframes grid access as a scarce economic resource whose misallocation produces systemic investment distortions. Romania serves as the primary case study, with comparative evidence from Poland, Bulgaria, and Hungary. The paper concludes with six policy reforms that are technically feasible, politically tractable, and long overdue.
Key Policy Takeaways
- 1. The constraint is an allocation system designed for a different era, now managing volumes it was never built to handle.
- 2. Queue congestion is a structural market failure produced by underpricing a resource whose option value drives speculative accumulation. More enforcement of the same framework will not fix it.
- 3. Romania’s 2024-2026 reform sequence is directionally correct. Other CEE markets are running the same dysfunction without the same reform response.
- 4. The CfD scheme transfers grid access risk to the worst possible moment in a project’s lifecycle. One regulatory change fixes it.
- 5. EUR 584 billion in EU grid investment solves the physical infrastructure deficit. Without allocation reform, it produces a better-funded version of the same failure.
1. Introduction: The Wrong Diagnosis
There is a number that should be more widely discussed in European energy policy circles. Romania, a country with roughly 20 GW of total installed electricity capacity across all technologies, had over 60 GW of renewable projects holding valid grid connection permits as of April 2025. Of those 60-plus GW, exactly 11% had completed the full authorization process required to break ground.
That ratio is not a permitting failure or a financing failure. It is the signature of a grid access allocation system that has lost the ability to distinguish between a project that will be built and one that never will.
The author has spent over two decades working inside CEE energy systems, across asset operations, regulatory proceedings, project development, and investment transactions. The pattern is consistent: policy sets a capacity target, capital flows in its direction, and delivery stalls. The standard explanations, permitting timelines, financing conditions, grid codes, contain partial truth. But they sit downstream of the real constraint. The question that determines whether a renewable energy project in CEE can be built is simpler: can it connect to the grid?
60 GW of approved projects in a 20 GW system. That ratio is not a pipeline health indicator but a diagnostic of allocation dysfunction.
Bulgaria had approximately 40 GW in its grid connection queue. Poland’s grid operators declined 51 GW of new capacity in 2022 alone. These are the expected output of a system where the right to connect a genuinely scarce resource is allocated through a mechanism that assigns it no economic value.
Getting the diagnosis right changes the treatment. The policy response to “not enough generation” is more auctions and faster permitting. The policy response to “misallocated grid access” is market design reform. CEE energy policy has spent years applying the first response to a problem that requires the second.
2. Grid Access as a Scarce Economic Resource
A resource is scarce when demand persistently exceeds supply. Grid connection capacity in CEE is among the most acutely scarce resources in the regional energy economy, and the gap between what is requested and what is physically available has grown every year for at least a decade.
Yet the allocation mechanism treats connection rights as administrative outputs rather than scarce assets. An ATR in Romania grants a developer the right to inject electricity into the system at a defined network point. On its face, it is a technical document. In practice, it carries embedded option value, trades in secondary project markets at premiums reflecting its scarcity and directly determines project valuation at Ready-to-Build stage. The administrative system does not capture this value. The market does. What the market prices in bilateral transactions, the allocation mechanism loses in efficiency.
First-come, first-served queuing, technical validation checks, and deadline extension negotiations are not economic allocation tools. They are processing workflows designed for a time when queues were short and grid headroom was adequate. Applying them to today’s volumes produces a set of distortions that are predictable in theory and visible on the ground every week.
The system creates the incentive for speculative accumulation and then treats the resulting congestion as a developer behavior problem. It is a design problem. Those require different solutions.
If holding a connection right is cheaper than its market value, developers will hold more than they intend to build. This is not abuse. It is the predictable response to an underpriced resource. The answer is not stricter administration but economic allocation.
3. Structural Failures in Current Allocation Mechanisms
3.1 First-Come, First-Served Selects for Speed, Not Quality
Queue position determined by application speed advantages speculative developers over serious ones. In a market where project brokerage is common, the ability to generate ATRs at scale has become a commercial advantage entirely independent of the ability to build and operate generating assets. Development shops that move quickly through early-stage connection applications occupy queue positions that real developers then have to buy their way into.
The value transferred in those transactions represents queue position, not project quality. From a system perspective, it is pure friction: capital consumed by a financial transaction that the allocation design made both possible and necessary. Slovakia’s experience, with approximately 50 percent of reserved grid capacity going unused, illustrates the end state. Romania’s ATR population at its peak represented over 70 GW of nominal capacity, most of which had no realistic construction horizon.
3.2 Queue Congestion Is Mechanically Produced
Congestion is not random. It results from low entry cost combined with weak milestone enforcement. Once inside the queue, the cost of staying is modest relative to the option value of the position. Deadlines get extended. Guarantees are negotiated. Romania’s August 2024 reform changed the entry economics with a 5 percent financial guarantee before ATR issuance, and the effect was visible: some speculative applications withdrew. The harder problem is the legacy queue, accumulated over years of near-zero entry cost, which does not respond to entry-side reforms alone.
Clearing it requires milestone-triggered, automatic capacity release: rules that are clear in advance, non-negotiable in application, and operated by the system rather than decided case by case. Regulatory adjudication of individual ATR cancellations is slow, resource-intensive, and politically susceptible to pressure from developers with committed capital at risk.
3.3 The System Value Blindspot
Nowhere is the dysfunction more practically damaging than in storage. A battery system co-located at a congested node directly reduces the congestion that makes that node a problem. It absorbs curtailed renewables and provides frequency response. In a rational allocation system, it would receive priority access in constrained zones. Under first-come, first-served, it competes on identical terms with a speculative solar application at the same overloaded substation.
The result: of 1,228 projects holding valid ATRs in Romania as of April 2025, exactly 35 included storage, representing 2.5 % of approved capacity. Romania’s policy trajectory points to around 1.2 GW of battery storage by 2030, with higher system needs implied beyond that level. The current ATR population does not support that outcome.
The reason is design. The allocation mechanism does not differentiate between congestion-relieving assets and congestion-adding generation. Capital follows access, not system value. As a result, storage is underrepresented precisely where the system needs it most.
Hybrid projects (solar combined with co-located storage) face an additional layer of complexity at the interface between voltage levels. Medium-voltage constraints, governing most projects below 50 MW, are less predictably managed than transmission-level connections, and the regulatory interface between Transelectrica and distribution operators introduces coordination risk that the allocation framework does not resolve. The most flexible project type faces the most uncertain path to connection.
3.4 Capital Markets Price What Regulators Ignore
Regulators see the ATR as a binary: you have one or you do not. Lenders see something considerably more nuanced. An unconditional ATR at a node with available capacity is a different asset from a technically valid ATR at a congested node where reinforcement works may run past the financing window. Both documents look the same. They are not priced the same by anyone who has actually tried to close a project finance deal in Romania.
Romania gave the market a specific reason to be cautious. When new co-permitting requirements for grid connection lines were applied retroactively to wind projects already deep in development, the damage went well beyond the affected projects. Lenders repriced the entire Romanian wind pipeline. One regulatory decision, applied backward to commitments already made, communicated something that markets remember: grid access certainty in Romania has a shelf life. That kind of reputational damage does not wash out in a single auction cycle.
The financial consequence is straightforward. Every basis point of debt margin that exists because lenders cannot independently verify grid access conditions is a basis point working against the CfD scheme’s core purpose. The scheme was designed to lower the cost of capital. Regulatory opacity raises it. They are pulling in opposite directions, and the EUR 3 billion public capital behind the scheme is caught in the middle.
There is a fix that costs nothing. Operators already hold the data: available capacity by network node, committed capacity in the queue ahead of new applications, reinforcement timelines. Publishing it, at minimum quarterly, would allow developers to avoid connection points where their projects have no realistic prospect, and give lenders the independent reference point they currently cannot obtain. No new legislation. No new budget. No new institutions. Just data that already exists, made accessible to the people who need it. That combination is genuinely rare in energy policy, and it should not require a lengthy argument to act on.
Table 1. CEE Grid Access Dysfunction: Country Comparison
| Country | Queued capacity (GW, approx.) | Total installed capacity (GW, approx.) | Queue-to-system ratio | Primary dysfunction | Reform status (2025) |
|---|---|---|---|---|---|
| Romania | 60–70 (peak 2024; legacy queue under active clearance) | ~20 | 3 – 3.5x | Speculative ATR accumulation, weak milestone enforcement | Most advanced reform in CEE: Order 53/2024, Order 20/2025, Order 79/2025. Competitive auction framework effective Jan 2026. |
| Bulgaria | ~40 (early-stage applications incl. preliminary requests; active contracted queue materially lower at ~4 GW in early 2025) | ~15 | ~2.5 – 3x (on broad definition) | Opaque queue, no maturity-based prioritisation. Rapid solar growth (~6 GW installed by end 2025) intensifying pressure. | Limited. ESO grid investment programme targets 4.5 GW new connections; no competitive allocation framework introduced. |
| Poland | 51 GW declined in 2022 alone (2.5x year-on-year increase) | ~75 | n/a (declined volume metric) | No-refusal obligation; no quality prioritisation tool. Renewable capacity reached 37.8 GW by end 2025 (50% of total installed), curtailment rising sharply. | Partial. Grid code revisions and milestone expiry rules being developed (2025–2026); no competitive allocation reform introduced. |
| Hungary | De facto moratorium: prosumer connections blocked 2022–2024 in saturated zones; utility-scale projects constrained 2022–2024 under revised priority regime | ~14 | Hard stop without price signal | Two distinct blockages: (1) prosumer / residential moratorium in high-saturation distribution zones; (2) utility-scale connections subject to revised priority regime 2022–2024. Solar alone reached 8.4 GW by end 2025. | Prosumer moratorium lifted in selected zones from end-2024. Wind setback rules liberalised from Jan 2024. No systemic allocation reform; co-location rules amended 2025. |
Sources: ANRE (Romania, April 2025), Can-Europe (2024), Beyond Fossil Fuels (2025), national regulatory authority reports. Figures are approximate and reflect most recently available data at time of writing.
4. Romania in Detail
4.1 How the Queue Got to 70 GW
The ATR system has governed Romania’s grid connections since ANRE Order 59/2013. For most of its operational life it was adequate: connection requests were manageable and grid headroom sufficient. Both conditions stopped being true years ago. The framework did not adapt.
The economics of ATR accumulation are straightforward. Before the 2024 reforms, the cost of obtaining an ATR was low. The value of an ATR in the secondary project market was considerably higher, embedding the queue position’s scarcity value in project transaction premiums. The spread between acquisition cost and secondary market value created a systematic incentive for accumulation that the regulatory framework had no meaningful mechanism to counter. By late 2024, the queue exceeded 70 GW of nominal capacity, with commissioning deadlines already extended beyond 2030.
Table 2. Romania ATR Reform Sequence, 2013-2026
| Instrument | Effective date | Key change | Practical effect |
|---|---|---|---|
| ANRE Order 59/2013 (baseline) | 2013 | ATR framework established. First-come, first-served allocation. Financial guarantee capped at 20% of connection tariff for reinforcement projects only. | Low entry cost. Weak enforcement. Speculative accumulation begins. |
| ANRE Order 53/2024 | August 2024 | 5% financial guarantee mandatory before ATR issuance for all projects above 1 MW. Competitive capacity auction framework introduced for projects above 5 MW (effective Jan 2026). Milestone deadlines tightened. | Speculative entry declines. ~70 post-reform ATRs monitored by Transelectrica, representing ~3.5 GW of potential released capacity. |
| ANRE Order 20/2025 | June 2025 | Chronological processing of solution studies for fully documented applications. ‘Operational limitation’ concept introduced into ATR instrument. Automatic lapse triggers clarified. Two-month deadline imposed for 5% guarantee payment from solution study endorsement. | Reduces discretionary enforcement. Queue discipline strengthened. Failure to post guarantee within deadline results in rejection of connection application. |
| ANRE Order 79/2025 | December 2025 (effective Jan 2026) | Amends Order 53/2024. Confirms competitive auction scope: all generation/storage projects ≥5 MW registered from Jan 1, 2026, plus pre-2026 projects where solution studies not submitted by Dec 31, 2025 or ATR not issued by June 30, 2026. Reinforcement works financed through auctions cannot be reclassified as general works at expense of projects below 5 MW. | Closes scope ambiguities in Order 53/2024. Protects smaller developers from cross-subsidisation of large-project reinforcement costs. Provides transitional certainty for projects registered before Jan 2026. |
| Capacity auction framework | January 2026 | Projects above 5 MW allocated connection rights through annual competitive auctions by network zone. 10-year allocation period. TSO defines available capacity per zone annually by Jan 15. Auctions conducted via TSO website; no dedicated platform developed. | First price-discovery mechanism for grid access in Romania. Structural shift from administrative to economic allocation. Industry flagged risk of transitional disruption for projects mid-development. |
Sources: ANRE Orders 59/2013, 53/2024, 20/2025. Reform sequence compiled from official Romanian regulatory publications and practitioner analysis.
4.2 The CfD Sequencing Problem
Romania’s CfD scheme is backed by EUR 3 billion from the EU Modernisation Fund. Three auction rounds have been conducted. The design has a flaw that does not show up in headline participation numbers.
Developers may enter CfD auctions without a valid ATR, but must secure one within six months of contract signature or forfeit the performance guarantee at EUR 75,000 per MW. The intent is to widen the competitive pool. The actual effect is to transfer the primary execution risk to the post-award period, precisely when lenders are making credit decisions. A developer who wins a CfD award without an ATR faces a hard six-month deadline on an uncertain critical path, EUR 75,000 per MW at risk, and a financial close process to run simultaneously. Some lenders pass. Others price the risk into margins. Either way, the CfD’s core function is partially negated.
The fix is one regulation: require a valid ATR as a precondition for CfD bid submission, not a post-award obligation. Smaller auction pool in the short term. Materially higher commissioning rate on awarded capacity. Better return on EUR 3 billion of public capital.
4.3 The CEE Pattern
The pattern across Central and Eastern Europe is consistent, even if the manifestations differ by market.
In Romania, the queue reached over 60 GW of projects with valid grid connection permits in a system of roughly 20 GW installed capacity. The country has begun transitioning toward a competitive allocation framework, introducing financial guarantees, milestone enforcement, and auction-based capacity allocation starting in 2026.
In Poland, grid operators rejected 51 GW of connection requests in 2022 alone. By 2025, total installed capacity approached 75 GW, with renewables accounting for roughly half. Curtailment is increasing, and while reforms are emerging, including stricter milestone enforcement, there is still no system-wide mechanism to prioritise projects based on quality or system value.
In Bulgaria, the connection pipeline is often cited at around 40 GW in broad analytical estimates. However, this figure includes early-stage and non-binding applications. The subset of projects with advanced grid status is materially smaller, on the order of 4–5 GW in early 2025. At the same time, solar capacity has expanded rapidly, reaching close to 6 GW by the end of 2025. Despite this growth, grid access continues to be managed administratively, without a competitive allocation framework.
In Hungary, grid access constraints have been expressed through administrative limits rather than queues. Between 2022 and 2024, prosumer connections were effectively halted in saturated distribution zones, while utility-scale projects faced restrictive connection conditions under a revised priority regime. This occurred alongside rapid solar expansion, which reached approximately 8.4 GW by the end of 2025. The system hit its physical limits without a mechanism to signal scarcity through price or prioritisation.
Across all four markets, the underlying issue is the same. Grid access is treated as an administrative outcome rather than a scarce economic resource. First-come, first-served allocation, combined with weak differentiation between project types, directs capital toward queue positions rather than system value. The result is congestion, misallocation, and delayed delivery, regardless of the specific regulatory form each country applies.
5. Four Consequences That Don’t Show Up in the Data
The allocation failure does not stay contained in the queue. It travels downstream into capital markets, project valuations, storage investment, and the effectiveness of the public support schemes designed to accelerate the transition.
Capital follows queue access, not system value. When grid connection rights are allocated by application speed, investment gravitates toward queue positions rather than productive assets. Secondary market transactions regularly embed queue position value into project acquisition prices. That capital does not build a single megawatt. It transfers a regulatory entitlement from one holder to another. National energy plans track pipeline volume. None of them measure the share of development capital absorbed by these transfers rather than by actual project construction.
ATR premiums price in certainty that does not exist. Projects with valid ATRs at constrained nodes are routinely valued at Ready-to-Build premiums that assume connection is secured. It is not. The data needed to verify ATR quality independently, disaggregated capacity by network node, reinforcement cost exposure already committed in the queue ahead, realistic connection timelines, is not publicly available in Romania or most CEE markets. Investors either price the opacity into a risk premium or walk away. When the valuation assumption proves wrong and a project fails to commission, the failure enters the record as a project-specific problem. The common cause goes unmeasured and unreformed.
Storage gets built in the wrong places. Battery storage is the asset class best positioned to relieve congestion precisely where congestion is worst. The allocation mechanism cannot distinguish a battery system that reduces peak load at a saturated node from a solar project that adds to it. Both queue on identical terms. The result is storage deployed where access happens to be available, not where the grid needs it most. The 2.5 % storage share in Romania’s ATR population is not a market appetite problem. It is a direct output of a value-blind allocation system.
Public support capital leaks through a design gap. The CfD scheme exists to reduce the cost of capital for renewable projects. Every project that forfeits its performance guarantee, fails financial close, or commissions late is a reduction in the return on the EUR 3 billion behind the scheme. These are not edge cases or bad luck. They are predictable outputs of a support mechanism layered on top of an allocation framework that generates the exact bankability problem the scheme was built to solve. The two instruments are working against each other, and the public capital is caught between them.
6. Policy Recommendations
Six interventions, sequenced from immediately implementable to structurally transformative. None require new legislation. All require regulatory will.
- 1. Publish node-level capacity data. Transelectrica and distribution operators hold the data developers and lenders need to assess connection viability: available capacity by node, committed capacity in the queue ahead, reinforcement timelines. None of it is publicly available in usable form. Mandatory quarterly disclosure, ideally as a live feed, costs the system nothing in direct subsidy and would reduce the information premium embedded in project finance costs across every constrained zone in Romania. This is the highest-leverage, lowest-cost intervention available.
- 2. Make ATR lapse automatic. Miss a milestone, the ATR lapses, capacity is released. Connection agreement within 12 months. Building permit within 18 months. Financial close evidence within 24 months. Extensions available only for documented force majeure, at the cost of an enhanced guarantee. Rule-based, automatic, plannable. Not dependent on regulatory interpretation or adjudication.
- 3. Fix the CfD sequencing. Require a valid ATR as an eligibility condition for CfD bid submission. Not within six months of signing. Before the bid is submitted. This eliminates the cliff-edge bankability risk at financial close and increases the commissioning rate on awarded capacity without any increase in budget.
- 4. Weight auctions by system value. The competitive auction framework effective January 2026 allocates by price. The next step is weighting bids by measurable system value contribution: congestion relief, flexibility provision, co-location with existing infrastructure. Transelectrica has the network models to calculate these metrics by zone. Publishing them as part of auction documentation would direct capital toward high-value nodes and project types through a market mechanism rather than administrative discretion.
- 5. Clear the legacy queue. A 90 to 180-day structured review window for legacy ATR holders: certify project progress against milestones or enter automatic lapse. ATRs demonstrating genuine progress are grandfathered into the new framework with enhanced guarantees. The rest are released into the auction pool. Three years of grace, as some industry associations have proposed, is too long. It preserves non-performing inventory through the critical early period of the new allocation framework.
- 6. Build a CEE data framework through ENTSO-E. The December 2025 EU Grids Package acknowledged the systemic scale of the grid access problem but stopped short of mandating standardized data reporting. The Commission should go further: quarterly standardized queue data from all CEE TSOs to ENTSO-E, covering capacity requested, allocated, lapsed, and reinforcement timelines. This dataset does not currently exist in comparable form across national systems. Without it, the Commission cannot monitor progress, identify systemic failures, or apply enforcement authorities meaningfully.
7. Conclusion
The energy transition in Central and Eastern Europe is not running short of ambition, capital, or renewable resource. What it is running short of is an honest account of where the bottleneck actually sits.
Generation capacity targets will keep being set. Auctions will keep being conducted. Pipelines will keep growing on paper. Delivery will keep lagging, for the same reason it has always lagged: the infrastructure that connects all of that potential to the system is allocated through mechanisms that cannot distinguish a serious project from a speculative one, cannot direct capital toward storage where the system needs it, and cannot give a lender the information it needs to price grid-side risk accurately.
By any comparative measure available at time of writing, Romania’s regulatory response has been the most structured grid access reform in CEE. It should be studied carefully, learned from honestly, and replicated.
Romania’s reform sequence from 2024 to 2026, spanning Orders 53/2024, 20/2025, and 79/2025, is the most structured regulatory attempt to address grid access dysfunction that any CEE market has produced to date. That judgment is analytical, not established fact, and other markets may yet respond more decisively. But the direction is correct: financial guarantees at entry, milestone-triggered lapse, scope clarification for competitive allocation, and protection of smaller developers from cross-subsidisation of large-project reinforcement costs. These reforms represent a genuine attempt to treat grid access as the scarce economic resource it already is.
For EU institutions, the lesson is precise. The EUR 584 billion in grid investment projected to be needed by 2030 addresses the physical infrastructure deficit. It does not address the allocation governance deficit. A better-funded grid with the same speculative queue management produces a better-funded version of the same failure. Physical infrastructure investment and allocation governance reform are both necessary. Neither is sufficient without the other.
Grid access is not a technical formality somewhere in the project development checklist. It is the economic foundation that determines whether every other instrument in the energy transition toolkit, the auctions, the support schemes, the financing structures, the capacity targets, produces what it was designed to produce.
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