EMS’s connection restrictions through 2029 are creating a two-tier renewables market in which secured transmission access may become more valuable than the underlying wind resource.
Serbia’s wind industry has spent much of the past decade solving the conventional problems of renewable development: securing land, measuring resources, obtaining permits, negotiating finance and persuading international investors that the country could support utility-scale projects. The constraint now confronting developers is more fundamental. There may be plenty of wind and plenty of capital, but access to the transmission network has become scarce.
The decision by Elektromreža Srbije (EMS), Serbia’s transmission system operator, to postpone parts of the connection-study process for variable renewable generation until late 2029 has effectively divided the market into two categories. On one side are projects with sufficiently advanced and legally protected grid positions, alongside projects capable of meeting exemptions related to balancing capacity. On the other are developers whose projects may have land, permits, wind measurements and potential financing but no bankable route to the transmission system.
This is not formally a blanket moratorium on wind construction. Existing wind farms continue to operate, projects with protected connection rights can progress and certain developments can qualify through balancing arrangements. But for a new utility-scale wind farm without a protected grid position, the commercial distinction is increasingly academic. Without an EMS connection study establishing where and under what conditions a plant can connect, reaching conventional project finance is extremely difficult.
The result is a regulatory bottleneck whose effects could stretch well beyond 2029.
EMS’s latest project register illustrates both the narrow legal scope of the measure and the much wider investment consequences. Among projects explicitly identified as postponed is Vetropak Delivento, a 145MW wind development associated with ULJMA WIND ENERGY. Two solar developments, Palić II at 80MW and Global Sol at 50.24MW, are similarly affected. The explicitly postponed projects therefore amount to 275.24MW, including 145MW of wind capacity.
That number understates the economic exposure. It captures projects already visible at a particular stage of the connection process rather than the much larger universe of developments that might otherwise have entered the queue between now and the end of the decade.
Serbia has accumulated a substantial prospective wind portfolio. Projects appearing in the wider EMS connection pipeline include Maestrale Ring at 600MW, Lovćenac at 333.96MW, Torak at 300MW, Vetrozelena at 291MW and Crni Vrh at 150MW, although their individual development and connection status varies considerably. They sit alongside an operating wind fleet that has expanded through projects including Čibuk 1, Kovačica, Košava, Alibunar, Krivača, Pupin, Čibuk 2 and Kostolac.
For investors, that distinction between pipeline capacity and genuinely connectable capacity is becoming critical, explain from Energy.Clarion.Engineer
A Serbian developer could previously present a portfolio in terms of hundreds of megawatts under development and attach value to the probability that some proportion would reach construction. The EMS restrictions make that approach increasingly difficult. A megawatt with a durable connection position and a megawatt waiting for the 2029 study window are no longer economically comparable assets.
The underlying problem is not simply that Serbia has run out of transmission lines.
EMS’s analysis points to a deeper system constraint: balancing capacity. The prospective renewable queue considered by the operator contains approximately 8.37GW of wind and 11.12GW of solar, producing a theoretical variable-renewables pipeline approaching 19.5GW.
That is enormous relative to the Serbian electricity system.
Not all of it will be built. Some projects will fail to obtain permits, some will lose land rights, some will not secure financing and others will disappear through normal development attrition. But EMS has to assess the security consequences of granting connection rights to projects that could ultimately materialise.
Its modelling indicates requirements of approximately 2,189MW of downward frequency-restoration reserve and 2,289MW of upward reserve, including about 459MW of automatic frequency-restoration reserve. Even a scenario incorporating roughly 948MW of battery capacity and 3,236MWh of storage left material balancing deficits.
This is the uncomfortable centre of Serbia’s renewable investment debate. The TSO has a legitimate system-security problem. The investment market has an equally legitimate objection to solving it through a connection regime that leaves projects waiting several years without certainty over whether, where and at what cost they can connect.
The distinction matters particularly for wind.
Wind should not simply be treated as solar with different equipment. Serbian wind projects typically have materially higher capacity factors and different hourly and seasonal production profiles. Their output can extend through winter periods and nighttime hours when solar contributes nothing. Wind therefore has different system value, different curtailment exposure and different interaction with regional electricity prices.
It still creates balancing requirements, particularly when installed capacity becomes large relative to the size of the system. But assessing 8GW of prospective wind and 11GW of prospective solar primarily through their combined variable-generation characteristics risks obscuring significant differences between the technologies.
The consequence of the current framework is that Serbia has made grid rights unusually valuable.
Projects possessing valid studies, connection agreements and compliant guarantees are no longer simply more advanced than their competitors. They control a scarce development asset. That should eventually appear in transaction pricing.
A developer seeking to sell a 300MW Serbian wind portfolio without protected connection rights cannot credibly value those megawatts on the same basis as a project capable of moving towards construction. The former has effectively become a long-dated option on regulatory reform, balancing capacity or the reopening of the study process. The latter potentially represents scarce near-term generation capacity in a market still seeking substantially more renewable electricity.
This creates fertile ground for consolidation.
Utilities, infrastructure funds and industrial buyers that want Serbian renewable exposure may increasingly prefer acquiring project companies with existing grid positions rather than financing greenfield development from the beginning. Smaller developers, meanwhile, face the cost of maintaining land agreements, planning work, environmental documentation and development teams during several years in which the project’s central infrastructure right remains uncertain.
The financial effect begins long before construction.
Recent Serbian wind developments indicate an investment requirement broadly around €1.3mn-€1.6mn per MW, depending on turbine selection, connection works and what is included in the reported project cost. The roughly 95MW Pupin wind farm has been associated with investment of approximately €123mn-€144mn, while the 154MW Čibuk 2 project has a reported value around €239mn.
Applied illustratively to the postponed 145MW Vetropak Delivento project, that implies a potential capital envelope of roughly €190mn-€230mn. The full amount has not necessarily been committed, but it demonstrates the investment represented by even one delayed entry in the EMS register.
The cost of waiting can be substantial.
Moving an entire project cash-flow profile back by 3.5 years reduces its present value by roughly 28 per cent using a 10 per cent discount rate, before considering the fact that some construction expenditure is also deferred. At a 12 per centdiscount rate, the reduction approaches 33 per cent.
For developers that have already spent heavily on environmental studies, wind measurements, land rights, engineering and permitting, those are not theoretical accounting effects. Development costs continue while revenue moves further into the future.
Consider a 100MW wind project operating at an illustrative 35 per cent capacity factor. Annual generation would be approximately 307GWh. At around €53.5/MWh, close to the wind price emerging from Serbia’s second renewable auction, annual gross generation revenue would be about €16.4mn.
A delay of several years therefore shifts tens of millions of euros of prospective revenue beyond the original investment timetable. At the same time, turbine prices can change, land options need extending, development teams must be retained and financing assumptions have to be rebuilt.
More importantly, a project without a defined connection is difficult to finance at almost any discount rate.
Banks need to understand the connection point, required transmission works, cost allocation and expected energisation date before committing long-term non-recourse debt. Corporate electricity buyers face a similar problem when negotiating power-purchase agreements. A buyer cannot comfortably contract for firm renewable supply from a project whose commissioning timetable ultimately depends on a study that may not be completed until the final months of 2029.
The nominal 2029 date is therefore misleading when considering commercial operation.
A project entering the EMS study process in September-December 2029 still has to complete subsequent connection arrangements, financing, procurement and construction. Depending on maturity and reinforcement requirements, a significant part of Serbia’s currently unprotected wind pipeline may therefore be looking at commercial operation closer to 2031-2033.
That pushes the issue directly into Serbia’s 2030 energy strategy.
The country is targeting roughly 45 per cent renewable electricity by 2030 and has sought around 3.5GW of additional wind and solar capacity. Its first two renewable auction rounds demonstrated that international capital is available. The second auction alone awarded approximately 645MW of capacity associated with planned investment of around €782mn.
The EMS measure does not make Serbia’s renewable targets impossible. Operating projects continue generating. Auction winners and sufficiently advanced developments can still contribute. But it reduces the margin for error.
A project delayed by permitting, financing or construction would normally be replaced in the development pipeline by another scheme. That replacement mechanism becomes much weaker when new projects cannot progress through the normal transmission-study process. Serbia therefore becomes increasingly dependent on the projects that already possess advanced grid positions.
The legislation does provide an alternative route through balancing capacity.
Renewable projects can avoid postponement where they secure qualifying secondary-reserve capability. The framework requires regulation capacity corresponding to at least 20 per cent of the renewable plant’s installed active power. Where battery storage is used, minimum energy capacity is 0.4MWh for every MW of renewable generation capacity.
For a 100MW wind farm, this implies at least 20MW of regulation capability and, under a battery solution, at least 40MWh of storage. A 300MW development would require 60MW and at least 120MWh.
This is large enough to alter project economics.
Storage could create additional revenue through balancing services and electricity-market arbitrage, while improving the operational characteristics of a wind project. But batteries bring additional capital expenditure, degradation risk, replacement requirements and more complicated financing structures. A wind farm that originally worked economically as a standalone generation project may not produce the same equity return after being redesigned as a hybrid flexibility asset.
Contracting reserve capacity from another Serbian market participant can reduce upfront expenditure, but introduces long-term counterparty risk. Lenders financing an asset for 10 or 15 years will want to know what happens if the reserve contract expires, becomes uneconomic or the provider ceases to meet EMS requirements.
The exemption is consequently a genuine development route, but not a free escape from the moratorium.
There is another financial pressure on projects that already possess studies. Serbia’s connection framework requires substantial bank guarantees and contains deadlines capable of making existing rights vulnerable when projects fail to progress.
The standard producer guarantee is €25,000 per MW. A 100MW project therefore requires €2.5mn, a 145MW development €3.625mn, and a 300MW scheme €7.5mn.
The Renewable Energy Association of Serbia has warned that more than 1.15GW of projects supported by around €29mn of bank guarantees could be exposed where administrative delays prevent developers from meeting regulatory milestones. The arithmetic is almost exact: 1.15GW multiplied by €25,000/MW produces €28.75mn.
These guarantees are not construction equity, but they consume credit lines and collateral. More importantly, developers fear losing rights because of delays that may originate not with the investor but with planning authorities or other state institutions.
That makes due diligence on Serbian renewable acquisitions considerably more complicated, explain Energy.Clarion.Engineer
An investor can no longer accept the description “grid secured” without examining the underlying EMS documentation. The relevant questions concern when the study contract was signed, whether the study remains valid, whether revisions have been requested, when guarantees expire, what milestones must be achieved, whether the connection approval is still effective and whether network reinforcements depend on infrastructure outside the project company’s control.
The value of the project may depend more on those documents than on another year of wind measurements.
Serbia is meanwhile investing heavily in the transmission system. Projects including the North CSE Corridor, estimated at around €82mn, and the Pannonian Corridor, at approximately €108mn, are intended to reinforce regional and domestic transfer capacity. Additional links towards Romania and Hungary, together with new 400kV infrastructure and transformation capacity, should progressively improve the network towards the end of the decade.
This helps explain the significance of 2029. It is a point at which several important transmission investments should be considerably further advanced.
But transmission construction alone does not eliminate the balancing problem. Nor will every reinforcement be completed simultaneously. Some network investments extend into the 2030s, while local substations, transformation capacity and regional power flows can constrain individual projects even when headline cross-border capacity improves.
Serbia could therefore reach late 2029 with a stronger transmission network but still face difficult choices over which renewable projects receive access and how much balancing capacity must accompany them.
The policy challenge is ultimately one of allocation.
A system facing almost 20GW of theoretical wind and solar applications cannot simply connect everything. But freezing much of the ordinary queue for several years creates its own distortions. Projects that happened to secure earlier positions acquire scarcity value, while potentially efficient new projects cannot compete for network access.
A more dynamic approach would allocate capacity according to project maturity, location and system value, accompanied by strict milestones that remove speculative applications. Developers could accept defined curtailment exposure or non-firm connection arrangements in congested areas. Storage and balancing obligations could vary according to technology and node rather than operating as a broad threshold for variable generation.
Such mechanisms would also expose the difference between genuine projects and paper pipelines. Serbia almost certainly does not have 19.5GW of wind and solar projects capable of reaching financial close on anything resembling the same timetable. Requiring credible financing plans, land control, permitting progress and milestone deposits could reduce the queue without preventing new capital from entering the market.
Until that changes, Serbia’s wind sector will operate as a two-tier investment market.
Operating assets should become more attractive because they provide immediate exposure without development-stage grid risk. Projects with durable connection positions could command higher development premiums. Auction-backed schemes with secure grid access become strategically more valuable because the pipeline behind them cannot easily replace lost capacity.
Early-stage portfolios face the opposite pressure. Their headline megawatts remain physically possible but financially remote. Valuations will increasingly reflect the probability of securing balancing capacity, surviving until 2029 or benefiting from an earlier regulatory change.
For Serbia, this creates an unusual contradiction. The country has demonstrated that it can attract hundreds of millions of euros into competitive renewable auctions and has some of south-east Europe’s most credible wind development zones. Yet the most valuable asset in the next phase of the market may not be the turbine, the land lease or even the wind resource.
It may simply be the right to connect.
Elevated by Energy.Clarion.Engineer
