May 5, 2026

by AEA in News

Early-Stage Progress and Challenges Mark Energy Community’s Priority Infrastructure Projects

Most projects included in the first list of Projects of Energy Community Interest (PECI) remain at an early stage of development, with several challenges likely to affect their implementation timelines, according to an assessment by the Energy Community Regulatory Board.

The Evaluation Report on PECI projects provides a comprehensive overview of progress on initiatives selected in the 2024 PECI list. It covers six priority investments—five in electricity transmission and one in energy storage—identified as critical for strengthening cross-border interconnections, enhancing security of supply, and enabling greater integration of renewable energy across the Energy Community.

The projects under review include:

Completion of the 400 kV Albanian internal transmission ring;
Capacity expansion of the existing 220 kV interconnection between Bosnia and Herzegovina and Montenegro (Trebinje–Perućica overhead line);
The Trans-Balkan Corridor, specifically the 400 kV double overhead line linking Bajina Bašta in Serbia with Višegrad in Bosnia and Herzegovina and Pljevlja in Montenegro (with the latter two sections included in the PECI list);
Reconfiguration of Albania’s 400 kV grid alongside a new Albania–Kosovo* interconnection;
The 330 kV overhead line between Balti in Moldova and Dnestrovsk HPP-2 in Ukraine;
The 225 MW DTEK energy storage project.

To date, only the Bosnia and Herzegovina–Montenegro interconnection has secured direct financing, provided by the European Bank for Reconstruction and Development. Meanwhile, two projects—the Albanian internal ring and the Albania–Kosovo* interconnection—received financial backing in 2025 from the European Commission through the Western Balkans Investment Framework, as highlighted by the Energy Community Secretariat.

The report finds that most projects are still in conceptual, feasibility, or planning phases, with expected implementation timelines extending from 2028 to 2032. Throughout 2025, efforts have largely focused on feasibility assessments, preparatory activities, financing structures, and regulatory alignment, rather than physical construction.

Importantly, the evaluation notes that no systemic delays have been identified when measured against the expected level of project maturity following their designation in the 2024 PECI list.

However, the report underscores several structural challenges that could affect delivery in later stages. These include complex permitting and administrative procedures—particularly for cross-border infrastructure—ongoing financing constraints and rising investment costs, as well as external risks such as geopolitical and security factors, especially in relation to Ukraine.

The assessment emphasizes that early identification and mitigation of such risks will be essential to ensure a smooth transition from planning to construction in the coming years.

The ECRB also stresses the importance of continued regulatory oversight and proactive engagement by national regulatory authorities to maintain project momentum and ensure efficient implementation.

Looking ahead, the Energy Community Secretariat launched a public consultation in March on eight candidate projects for the next PECI list. The updated selection, aligned with the TEN-E Regulation framework, is expected to be adopted in December 2027, following an opinion from the ECRB anticipated by the end of August 2026.

April 23, 2026

by AEA in News

North Macedonia’s May 2025 blackout was a voltage-control failure, and Europe should read it that way

ENTSO-E’s final report on the Grid Incident in North Macedonia on 18 May 2025 turns what could look like a local technical failure into a broader system warning. At 04:59 CEST, North Macedonia’s power system split between the 400 kV and 110 kV networks, leaving the 110 kV system in blackout while the 400 kV network stayed operational. MEPSO restored the system by 07:47, and the wider Continental Europe system saw no major disturbance. The report therefore matters not because it describes a large geographic event, but because it exposes how voltage stress can cascade into a full loss of supply in a part of the grid that planners had already marked as vulnerable.

The key point is that this was not a surprise in the narrow sense. The factual report says MEPSO had already identified recurring nighttime overvoltage during the spring and autumn low-load season and had introduced countermeasures, including transformer-protection optimisation and the disconnection of one internal 400 kV overhead line. Even so, some 400 kV substations were still operating above the normal band, with voltages reaching 430-437 kV and, in some places over the preceding months, peaking even higher. In other words, the network was already being managed at the edge of its voltage envelope before the incident occurred.

Topology of the transmission system of North Macedonia

The report also shows that regional security tools did not flag an imminent crisis in the way operators would have liked. RCC analysis before the incident judged the grid secure based on the information available, yet it also detected that all 400 kV nodes in the MEPSO control area were expected to exceed acceptable voltage limits. At the same time, MEPSO did not deliver the individual grid model for 18 May, so the backup model used by the RCC relied on the last submission from 13 May. That combination – a system that was already voltage-stressed, plus imperfect visibility in the planning chain – is exactly the kind of operational blind spot the report is trying to highlight.

The final report’s diagnosis is structural, not accidental. Its root causes point to operating the system above defined voltage limits, reduced awareness of overvoltage risk in operational planning, insufficient reactive-power reserves with adequate activation time, and limited availability of effective voltage-control assets. That is an important distinction. The event was not simply about “too much generation” or “too little demand”; it was about a system that lacked enough fast, effective, and coordinated tools to absorb reactive power and hold voltage within bounds during a low-load operating regime.

That diagnosis is already driving a policy and investment response. The report points to three layers of recommendations: continuation of ENTSO-E work on voltage and reactive-power modelling quality and operationally useful KPIs; new regional SEE measures for monitoring voltage-limit violations and coordinating action among TSOs, RCCs and ENTSO-E; and MEPSO-specific changes to its System Defence Plan, including broader low-load and high-renewable scenarios and clearer coordination between TSOs and DSOs. The same logic is visible in the post-incident actions: MEPSO has moved to improve reactive-power support, including a 150 MVAr shunt reactor in SS Dubrovo, expected to be finalised by 2027.

For the wider European power sector, the lesson is straightforward. Security of supply in a more renewable, more dynamic grid is no longer only about enough megawatts and enough interconnection capacity. It also depends on voltage discipline, reactive-power capability, modelling quality, and the speed with which operators can see and correct abnormal conditions. North Macedonia’s blackout shows that a grid can remain “adequate” on paper and still fail in practice if voltage-control assumptions are too optimistic or if the operational toolkit is too thin. That is why this report should be read not as a post-mortem for one country, but as a warning for the entire South-East European system and, by extension, for any grid entering a lower-load, higher-renewables operating era.

March 23, 2026

by AEA in News

Tariff Methodologies in the Energy Community: Convergence, Cost Recovery, and Albania’s Reform Trajectory (ECRB 2025–2026 Analysis)

The Energy Community was created to extend EU electricity and gas market rules to the Western Balkans, Moldova, Georgia, and Ukraine through a legally binding framework. Within that system, the Energy Community Regulatory Board (ECRB) serves as the regional voice of regulators and, under Article 18 of the Electricity Regulation, prepares a biannual best-practice report on transmission and distribution tariff methodologies. The March 2026 report is the second such exercise and is explicitly designed to reduce market fragmentation by comparing how Contracting Parties set, update, and structure network tariffs.

That matters because tariff methodology is not just a technical exercise. It determines whether TSOs and DSOs recover efficient costs, whether users see price signals that reward efficiency and flexibility, and whether the network can absorb renewables, storage, EV charging, and other new uses without shifting hidden costs onto captive customers. The report frames tariff design around cost reflectivity, transparency, security of supply, and system efficiency, which is exactly where electricity-market reform and energy transition policy intersect.

Regional overview: nine Contracting Parties, one broad direction, uneven speed

Across the nine Contracting Parties—Albania, Bosnia and Herzegovina, Georgia, Kosovo*, Moldova, Montenegro, North Macedonia, Serbia, and Ukraine—the strongest common trend is not full harmonization but gradual convergence toward more incentive-based regulation. Since 2022, almost all regulators have introduced some form of change to improve cost reflectivity, investment incentives, or quality-of-service regulation; the most notable reforms are in Moldova, North Macedonia, Montenegro, Kosovo*, and Ukraine.

A useful way to read the region is by regulatory “maturity” rather than by simple tariff levels. Albania is the clearest price-cap case; Georgia has a sophisticated hybrid “building-blocks” design; Moldova and Kosovo* are moving toward more explicit EIP-aligned frameworks; North Macedonia and Montenegro are actively redesigning components of the charge to reflect flexibility, quality, and capacity; Bosnia and Herzegovina and Serbia remain more conservative and largely cost-plus on transmission; and Ukraine sits between emergency constraints and structural reform, with a major unbundling of renewable-support costs underway.

Table 1. Regional regulatory snapshot by country

Country	Transmission regulation	Distribution regulation	Update cycle / tariff revision	Transparency / stakeholder involvement	Main reform direction
Albania	Price-cap oriented, incentive-based	Price-cap oriented, with quality factor	3-year D-cycle; T updates mostly at end of period or via extraordinary review	Public consultations; tariffs and methodology publicly available	Incremental updates, quality, cost-reflectivity
Bosnia and Herzegovina	Cost-plus	Cost-plus / regulatory methodologies by entity	No fixed regulatory period; revisions when justified	Public and specific consultations; info public, incl. English	Stability, modest modernization
Georgia	Hybrid cost-plus + revenue-cap “building blocks”	Hybrid	5-year regulatory period	Public/specific consultations; info public incl. English	Fixed/capacity elements under review
Kosovo*	Allowed-revenue, annual approval under ex-ante regulation	New principles adopted in 2024; full methodology expected in 2026	5-year regulatory period	Public consultations	New users, injection tariffs, capacity signals
Moldova	Incentive-based revenue cap	Incentive-based, new methodology in 2025	Methodology indefinite; tariff updates annual	Public + specific consultations; multi-authority review	EIP alignment and innovation
Montenegro	Hybrid incentive/performance-based	Hybrid; now includes power-based distribution injection charge	Flexible multi-year practice; current period 2023–2025	Public consultations	Quality, storage, AIT/SAIDI, cost reflectivity
North Macedonia	Revenue cap; t-2 base year	Revenue cap; t-2 and lump sum access fee	3-year cycle	Public and specific consultations	Time-of-use, locational and flexibility signals
Serbia	Cost-plus	Cost-plus / mixed user basis	1-year cycle	Public consultations	Flexibility services under new by-laws
Ukraine	Cost-plus transitional; incentive-based not fully applied	Mostly incentive-based for most DSOs	1-year cycle for cost-plus DSOs; special periods for incentive regulation	Public and specific consultations	Separate RES-support costs; new connection logic

Deep dive: Albania

Albania is the report’s most important “special case” because it combines a comparatively mature regulatory philosophy with a relatively static formal methodology. The transmission methodology, approved in 2017, has not been materially amended since then. The report describes Albania’s transmission regime as price-cap oriented and incentive-based, with allowed revenue built from forecast OPEX and CAPEX, and with cost recovery limited to transmission-related items such as metering, maintenance, losses, ancillary services, third-party services, and taxes.

The distribution methodology is also rooted in a 2017 framework, but unlike transmission it has been incrementally adjusted since 2022 to reflect operational costs, investment plans, and, importantly, quality-of-service indicators. ERE now adds a performance-improvement factor to the D tariff formula, which is a meaningful step toward incentive regulation that is closer to EU practice. The report also notes that Albanian transmission tariffs are updated mainly at the end of the regulatory period unless extraordinary circumstances justify re-evaluation.

That said, Albania is not the most modern tariff system in the region. It remains strongly volumetric on the demand side, with no major transmission-methodology overhaul since 2017 and no reported planned reform program in the report. Compared with peers, Albania is ahead on the clarity of its price-cap logic and on the integration of quality signals, but behind Georgia, Moldova, Montenegro, and North Macedonia in methodological renewal and in preparing for capacity-based and flexibility-related network use.

Table 2. Albania in regional context

Dimension	Albania	Regional comparison
Transmission framework	2017 methodology, price-cap oriented	Less updated than Moldova, Kosovo*, North Macedonia, Montenegro
Distribution framework	2017 methodology, gradually refined	More advanced than purely static systems because of quality factor
Quality incentives	Yes, D tariff includes performance-improvement factor	In line with Georgia, Kosovo*, Montenegro, Ukraine
Injection charges	No transmission/distribution injection charges	More conservative than Montenegro, and ahead of countries that have not introduced them
Modernization pace	Incremental, not transformational	Middle of the pack: prudent but not frontrunner

Cost structure and cost recovery: the region still relies on the classic network model

Across the Energy Community, the default cost model remains the “average cost” approach: allowed revenue is divided by forecast volumes of energy or capacity. The report does not find meaningful adoption of incremental or fully forward-looking cost models. That means most systems still recover costs in a way that is structurally familiar, but not always well suited to emerging flexibility services or highly dynamic network use.

On the cost side, all Contracting Parties recover CAPEX, OPEX, and distribution losses through D tariffs, while TSOs also recover losses and ancillary services through T tariffs in most systems. The main divergence lies in “extra” categories: costs for data hubs, redispatching, market coupling, ENTSO-E contributions, R&D, and support schemes are only partially recognized or not recognized at all in many countries. The report is explicit that network charges should not absorb unrelated policy costs, and Ukraine is the clearest example of moving to separate renewable-support costs from the transmission tariff.

Investment treatment is also uneven. Loans are broadly recognized in tariffs and/or RAB, while grants are usually excluded from return. Anticipatory investments are rare in distribution and still selective in transmission, but Kosovo*, Moldova, Montenegro, and North Macedonia are already using forward-looking logic for strategic projects. That is a significant marker of policy maturity because it shows the region is beginning to treat network tariff design as an infrastructure-planning tool, not only a cost-pass-through mechanism.

Table 3. 2024 average transmission tariffs and 2020–2024 change

Country	2024 transmission tariff (EUR/MWh)	2020 tariff	Change 2020–2024
Albania	8.44	6.06	+39.3%
Bosnia and Herzegovina	5.25	4.97	+5.7%
Georgia	7.07	5.85	+20.8%
Kosovo*	9.58	5.37	+78.4%
Moldova	9.48	7.43	+27.6%
Montenegro*	27.97	29.99	-6.7%
North Macedonia	4.77	2.86	+66.8%
Serbia	5.21	4.25	+22.6%
Ukraine	12.16	6.46	+88.2%

* Montenegro’s figure is not directly comparable to all others because distribution-connected consumers are charged capacity fees without a clean T/D breakdown.

The tariff series show three striking facts. First, Ukraine and Kosovo* experienced the fastest transmission tariff growth, and by 2024 Ukraine had the highest clearly comparable T tariff among the nine CPs. Second, North Macedonia, Albania, and Moldova also show strong upward movement, reflecting reform and/or cost pressure. Third, Montenegro is a structural outlier because of its capacity-fee design and very high reported average transmission-related value.

Table 4. 2024 household and non-household distribution tariffs

Country	HH D tariff 2024 (EUR/MWh)	2020	Change	Non-HH D tariff 2024 (EUR/MWh)	2020	Change
Albania	58.21	38.69	+50.5%	N/A	N/A	N/A
Bosnia and Herzegovina	30.20	28.75	+5.0%	21.24	15.66	+35.6%
Georgia	30.99	19.54	+58.6%	30.99	12.80	+142.1%
Kosovo*	25.49	25.24	+1.0%	22.54	22.32	+1.0%
Moldova	33.22	27.00	+23.0%	33.22	27.00	+23.0%
Montenegro*	30.60	35.76	-14.4%	27.10	31.25	-13.3%
North Macedonia	38.96	25.03	+55.7%	38.96	25.03	+55.7%
Serbia	36.64	30.19	+21.4%	22.92	20.35	+12.6%
Ukraine	37.00	22.00	+68.2%	29.00	16.00	+81.3%

The distribution data show that Albania, North Macedonia, and Ukraine have seen especially strong growth in household distribution tariffs, while Georgia’s non-household tariff rose sharply. In contrast, Montenegro is the only country with a clear decline in both household and non-household distribution values over the 2020–2024 period. The cross-country average in 2024 is about EUR 35.7/MWh for household D tariffs and EUR 28.2/MWh for non-household D tariffs, underscoring how distribution still dominates the final network bill.

Tariff design and charges: the region is still dominated by withdrawal charges

All Contracting Parties apply withdrawal tariffs on both transmission and distribution. Injection charges are the exception, not the rule: they exist on transmission only in Bosnia and Herzegovina, Montenegro, and Ukraine, and on distribution only in Montenegro. Kosovo* and Georgia are explicitly preparing reforms in this direction.

The tariff base is also revealing. Transmission withdrawal tariffs are energy-only in Albania, Georgia, Moldova, and Ukraine, but energy-plus-power in Bosnia and Herzegovina, Kosovo*, Montenegro, North Macedonia, and Serbia. Distribution withdrawal tariffs are energy-only in Albania, Georgia, Kosovo*, Moldova, and Ukraine; energy-plus-power in Bosnia and Herzegovina, Montenegro, North Macedonia, and Serbia; and lump-sum elements are now visible in Bosnia and Herzegovina, Montenegro, and North Macedonia. That makes the latter three countries the most structurally diversified on D-tariff design.

Injection charges are particularly important because they show whether a country is moving away from the historic assumption that only consumers cause network costs. Montenegro is the clearest example of a system where producers share transmission and distribution costs in a measurable way: 34% of transmission costs are allocated to producers, and 0.16% of DSO costs are recovered from distribution-connected producers. Bosnia and Herzegovina and Kosovo* also recover part of transmission costs through injection charges, but Ukraine uses its dispatch tariff primarily to recover system-operation and ancillary-service costs.

Connection charges are another area where the region is differentiating. Albania and Montenegro use shallow connection charges at transmission and Albania uses a detailed multi-component D connection fee. Bosnia and Herzegovina and Ukraine use deep connection logic in several cases, while Georgia and Kosovo* are moving toward more detailed and differentiated rules for producers, small generators, EV charging, and storage. The policy message is clear: connection methodology is becoming a central instrument for shaping the next wave of grid users.

Table 5. Tariff-design signals and network-user treatment

Feature	Leaders / current practice	Where it is still limited
Injection charges	Montenegro; parts of BiH and Ukraine; future plans in Georgia and Kosovo*	Most CPs still have none
Time-of-use T tariffs	Montenegro and Serbia	Not widely applied elsewhere
Time-of-use D tariffs	Bosnia and Herzegovina, Montenegro, Serbia	No broader rollout yet
Locational signals	None currently applied	All CPs
Reactive charges	Widely used on D level; selective on T level	Many are administrative, not cost-based
New users (storage, EVs, prosumers)	Kosovo*, North Macedonia, Ukraine, Georgia moving fastest	Most systems still adapting

Energy transition and future trends

The report’s most important forward-looking conclusion is that tariff methodology is now being pulled into the energy-transition agenda. The EIP requires tariffs to reflect new users and new services, including flexibility, storage, distributed generation, smart grids, and renewable-energy communities. On that criterion, North Macedonia, Montenegro, Moldova, Serbia, Ukraine, Georgia, and Kosovo* are all in active reform mode, though with different starting points.

Ukraine is the clearest case of structural transition: renewable-support costs are being separated from the transmission tariff under a roadmap extending to 2030, which is the right direction if the goal is to remove unrelated policy costs from network charges. North Macedonia is preparing to empower time-of-use tariffs and locational signals under its new Energy Law. Montenegro plans AIT- and SAIDI-based incentives from 2027, while Moldova and Serbia are tasked to develop new EIP-aligned methodologies in 2025–2026. Georgia is considering fixed and/or power-based components in future regulatory periods, and Kosovo* has already adopted the principles that will underpin a new distribution-use-of-system methodology.

Comparative insights

The best-performing systems are not necessarily the cheapest. They are the ones that combine transparency, incentive compatibility, and room for new network users. On that basis, Georgia, Moldova, Montenegro, and North Macedonia are the most dynamic reformers; Albania is strong on regulatory clarity and quality signals; Kosovo* is making a significant methodological leap; and Ukraine is undertaking the most consequential structural separation of non-network costs.

The lagging systems are those where the methodology is still heavily cost-plus, the revision process is relatively static, and the tariff structure has not yet been redesigned for storage, EVs, distributed generation, or flexibility. Bosnia and Herzegovina and Serbia are the clearest examples on transmission; Albania is the clearest example of a system that is stable but too static; and Ukraine, while reform-minded, remains constrained by wartime conditions and transitional cost recovery.

There is also a visible convergence trend. Most CPs now publicly disclose tariff-related information, consult stakeholders, and use incentive-based language even where the practical model remains cost-plus. But there is still divergence in three areas: the share of cost recovered from producers, the treatment of losses, and the introduction of capacity-based or time-differentiated charges. Those are likely to be the decisive battlegrounds of the 2025–2027 reform cycle.

Conclusions and recommendations

The report shows a region that is no longer debating whether tariff methodology should change, but how fast and in what direction. The best systems are moving from simple volumetric pass-through toward more nuanced designs that reward efficient use of the grid, preserve cost recovery, and prepare for flexibility, storage, and electrification. The most important policy lesson is that network tariffs must stop carrying unrelated policy costs and must begin sending clearer signals to both consumers and producers.

For the region, the priority should be to widen the use of capacity-based and time-differentiated charges where smart metering and system conditions justify them; to standardize transparent treatment of losses and investment recovery; and to ensure that injection charges, where used, are designed around clear cost causation rather than purely administrative objectives. Regulators should also accelerate methodology updates so that storage, EV charging, demand response, and renewable-energy communities are not forced into legacy tariff rules.

For Albania specifically, the recommendation is not radical deregulation but methodological modernization. ERE should preserve the strengths of its price-cap framework and quality factor, but update the transmission methodology so it can explicitly accommodate new cost categories, emerging users, and possibly limited capacity-based or time-differentiated elements. Albania should also improve the linkage between tariff design and network modernization, because its current framework is credible but comparatively static beside Moldova, North Macedonia, Montenegro, and Kosovo*.

If Albania uses the next reform cycle to combine price-cap discipline with a more explicit treatment of flexibility, data, and new users, it can remain one of the region’s clearest regulatory references while closing the gap with the most dynamic reformers. That would align well with the Energy Community acquis and with the report’s central message: tariff methodology is now a core instrument of energy-transition governance, not a back-office accounting exercise.

February 16, 2026

by AEA in News

Bosnia and Herzegovina launches two-year national hydrogen strategy project.

Bosnia and Herzegovina has kicked off a two-year initiative to produce a draft national strategy and roadmap for hydrogen, a project officials say will help steer the country toward a cleaner, more competitive energy system.

The implementation phase of the project — CEI Support to Hydrogen Strategy Development and Know-How Transfer for Bosnia and Herzegovina — opened with an official meeting in Sarajevo. The effort is being carried out by a consortium led by Green Sustainable Solutions (based in Zagreb), the Association for Green Hydrogen and Renewable Energy Sources (H2OIE), state utility Elektroprivreda Bosne i Hercegovine (EPBiH), and local engineering firm Energoinvest. The project receives backing from the Central European Initiative (CEI) and the Ministry of Foreign Affairs and International Cooperation of Italy.

Project partners described the initiative as a decisive step for the country’s energy transition. At the opening meeting they exchanged experience, reviewed European and regional best practices, and reaffirmed their intention to embed hydrogen technologies in long-term national development plans.

According to H2OIE, the programme is designed to strengthen institutional capacity and accelerate knowledge transfer so that hydrogen can be introduced sustainably into the national energy mix. Activities will include expert workshops, study visits to the European Union, advisory missions, and the preparation of the draft national strategy and a practical roadmap.

Those workstreams are intended to map Bosnia and Herzegovina’s hydrogen potential, identify barriers, and define development priorities. Organizers say the roadmap will highlight practical steps for integrating hydrogen across power, industry and transport sectors, and for aligning national regulations with European standards.

Stakeholders argue hydrogen offers a major opportunity to boost energy security and to decarbonize energy-intensive industries. Energoinvest noted the country’s abundant renewable resources, established industrial base and strategic location make hydrogen development a strategically important path for economic and environmental progress.

As the project proceeds over the next two years, officials and experts will aim to translate international know-how into locally tailored policies and investments — positioning the country to compete in regional energy markets and to meet its climate commitments.

February 12, 2026

by AEA in News

PPC Renewables Romania Adds 60.12 MWh Battery to Sălbatica Wind Complex

PPC Renewables Romania plans to install a battery energy storage system (BESS) with a capacity of 60.12 MWh within its Sălbatica 1 wind farm, as the company accelerates its storage rollout alongside existing renewable assets.

The storage project is valued at RON 68.2 million (EUR 13.4 million), PPC Renewables Romania said. The company operates the Sălbatica 1 and Sălbatica 2 wind farms, which together total 140 MW, located in Tulcea County in southeastern Romania.

PPC Renewables Romania is a subsidiary of Greece’s state-controlled Public Power Corporation (PPC).

Modernization Fund support of EUR 1.9 million

The BESS investment will be supported by the European Union’s Modernization Fund, through a public call aimed at financing electricity storage capacities connected to existing renewable generation facilities.

From the overall investment, RON 9.87 million (EUR 1.9 million) will come from the Modernization Fund, while the remainder will be financed by PPC Renewables Romania.

According to PPC, the battery will contribute to the development of storage capacity and improve the flexibility and efficiency of electricity produced from renewable sources.

Broader storage pipeline underway

PPC Renewables Romania is developing a series of storage projects across the country. The company plans to install:

27 MWh at the Topolog wind farm,
80 MWh at the Corugea wind farm, and
120 MWh in total at the Nicolae Bălcescu and Târgușor wind farms.

PPC operates 1.3 GW of wind, photovoltaic, and hydropower capacity in Romania. Its 600 MW Fântânele–Cogealac–Grădina wind farm is the country’s largest wind facility and already includes a BESS installation.

Romania’s largest BESS commissioned in December 2025

Romania’s largest battery storage system was inaugurated in December 2025 by Nova Power & Gas, doubling the country’s total BESS capacity. The facility in Florești, Cluj County, has an operating power of 200 MW and an energy capacity of 400 MWh.

February 12, 2026

by AEA in Uncategorized

Next-Generation Geothermal Poised to Become Europe’s Mainstream Clean Power Option

Technological progress is rapidly expanding the areas where geothermal electricity can be produced, strengthening its position as a cost-competitive and secure alternative to fossil fuels—including for fast-growing loads such as data centres. With today’s emerging methods, geothermal could already replace 42% of electricity generation from coal and gas plants in the EU, Ember found. Enhanced geothermal systems (EGS) could also provide a form of indirect storage for surplus solar and wind power.

In its report Hot Stuff: Geothermal Energy in Europe, Ember said advances in drilling and reservoir engineering are unlocking geothermal electricity across far wider parts of Europe. Once confined to a handful of favourable locations, geothermal is now positioned to scale from a niche “volcanic” resource to a more mainstream technology.

New geothermal technologies could replace 42% of EU’s fossil electricity, at costs comparable to coal and gas

Ember’s latest figures indicate geothermal could replace 42% of the EU’s coal- and gas-fired generation for less than €100/MWh.

“Once restricted to a few geological hotspots like Iceland or Tuscany, modern geothermal is now cost-competitive with gas across much of the continent. As Europe seeks to slash emissions while meeting the energy demands of heavy industry and AI data centers, this untapped resource offers a clean, firm power supply that remains insulated from the price volatility of imported fossil fuels,” said Ember Policy Advisor Tatiana Mindekova, the report’s author.

Conventional geothermal historically depended on underground rock formations that were both hot and naturally permeable, enabling water at depth to circulate and transport heat. Despite this, geothermal’s global electricity output remains limited: 99 TWh in 2024, representing below 0.5% of worldwide generation.

Deeper, hotter—and less dependent on natural conditions

Over the past decade, progress in “next-generation” geothermal has reduced reliance on naturally occurring permeability—the open pores in rock that allow fluids to flow. New approaches can now create or enhance these flow pathways artificially.

While geothermal plants rarely operated deeper than three kilometers in the past, enhanced geothermal systems (EGS) are increasingly able to access heat from much deeper, hotter rock layers—often with little or no natural water or permeability.

These techniques, adapted from the oil and gas sector, allow a working fluid—typically water—to circulate through engineered pathways and extract heat.

Costs fall as flexibility rises

Ember noted that improvements in power conversion systems now allow electricity generation at lower temperatures. At the same time, well costs have fallen by 40% over the past decade.

The report also highlighted geothermal’s ability to operate flexibly. Reservoirs can be managed to indirectly absorb surplus wind and solar generation—primarily through increased pumping and injection—and later release stored thermal and pressure energy to produce additional electricity.

Beyond power, geothermal brines may offer a minerals opportunity. Ember pointed to the potential to extract valuable materials such as lithium directly from underground brines, with recovery rates of up to 95%, compared with around 60% from hard-rock mining, alongside far lower water use.

Cost competitiveness and growing global pipeline

Geothermal is already described as cost-competitive with fossil fuels in Europe. Ember put geothermal’s levelised cost of electricity (LCOE) at around $60/MWh, versus roughly $100/MWh for most fossil-fuel generation. LCOE reflects lifetime construction and operating costs.

Globally, by 2030, nearly 1.5 GW of new geothermal capacity is expected to come online each year—around three times more than in 2024. Ember said geothermal could meet up to 15% of growth in electricity demand by 2050.

Europe had 147 geothermal power plants operating in 2024, generating about 20 TWh from just over 3.5 GW—roughly one-fifth of global capacity. Turkey, Italy, and Iceland accounted for nearly all of Europe’s output.

Hungary leads EU potential below €100/MWh

Ember identified 43 GW of enhanced geothermal capacity in the EU that could be developed at costs currently below €100/MWh, translating to 301 TWh per year—equal to 42% of production in 2025.

43 GW of geothermal in the EU would cost less than gas-fired power

Hungary stands out within the EU with 28.3 GW of potential below €100/MWh. When including projects with LCOE between €100/MWh and €200/MWh, Hungary’s total rises to 39.6 GW. Only France is higher overall, at 52.7 GW. Iceland was highlighted for exceptionally large potential—191.9 GW at up to €100/MWh.

Across the wider region tracked by Balkan Green Energy News, Turkey is also in the top tier, with 5.7 GW at up to €100/MWh and another 12.9 GW above that threshold.

In Southeast Europe, Ember estimated potential below €100/MWh at 838 MW in Romania, compared with 631 MW in Serbia and 148 MW in Croatia. Croatia also has 607 MW in the higher-cost segment, while Slovenia is at 168 MW, all in the more expensive range.

Data centers, policy gaps, and a race to scale

Drawing on recent US trends, Ember said geothermal could cost-effectively meet up to 64% of the expected increase in data center electricity demand by the early 2030s.

The report warned that Europe—despite being an early tester of next-generation methods—risks falling behind due to lengthy permitting and the lack of a unified EU strategy. In contrast, the US and Canada are scaling projects more aggressively through targeted policy incentives.

Ember also referenced a Stanford University study suggesting EGS can complement wind and solar and significantly reduce the volume of renewables and battery infrastructure required for a clean transition. The US Department of Energy expects costs to decline substantially by 2035, and the first major EGS project in the US—a 2 GW facility in Utah—was approved in October 2024.