May 5, 2026

by AEA in News

Renalfa Advances Oslomej Solar Project with 50 MW Battery Storage Installation

Austria-based developer and independent power producer Renalfa IPP has commenced the installation of a battery energy storage system (BESS) at its solar power plant in Oslomej, North Macedonia. The system will have an operating power of 50 MW and a storage capacity of 200 MWh, marking a significant step in enhancing grid flexibility and renewable integration.

The co-located BESS is being deployed alongside the 65.8 MW Oslomej solar power plant, which is situated on the site of a former coal mine. The project reflects ongoing efforts to repurpose legacy fossil fuel infrastructure into clean energy assets. The solar facility was developed through a public-private partnership with state-owned utility Elektrani na Severna Makedonija (ESM).

Financing for the solar plant was provided by the Green for Growth Fund, which has also committed €24 million to support the deployment of the battery storage system. The combined investment forms part of a broader initiative to transition North Macedonia’s coal-based energy complex toward sustainable generation.

In 2025, Renalfa secured a €315 million loan facility from a consortium led by the European Bank for Reconstruction and Development. The financing underpins the company’s €1.2 billion regional investment program, which targets the development of approximately 1.6 GW of renewable generation capacity and 3.3 GWh of co-located battery storage across Bulgaria, Hungary, Romania, and North Macedonia.

These assets are expected to produce around 2.3 TWh of green electricity annually—sufficient to meet the energy needs of approximately 920,000 households—while supporting grid stability through integrated storage solutions.

Beyond North Macedonia, Renalfa is also advancing a major hybrid renewable project in Hungary. The company is developing a 450 MW solar power plant in Szihalom, complemented by a BESS with an operating power of 250 MW and a capacity of 1 GWh. The battery system is being supplied by HiTHIUM.

According to Renalfa, the Szihalom project represents the largest hybrid renewable energy development undertaken in Hungary to date and ranks among the most significant such projects in Europe.

May 5, 2026

by AEA in News

Zatriq Wind Farm Nears Completion as Kosovo Expands Renewable Capacity

Turkey-based Çalık Renewables, in partnership with Kosovo’s domestic firm Eurokos, is advancing the construction of a 72 MW wind power plant in Kosovo, with commissioning targeted for July.

During a recent site visit to the Zatriq wind park, Acting Prime Minister Albin Kurti and Minister of Economy Artane Rizvanolli reviewed progress on the project. The development is led by Çalık Enerji, part of Çalık Holding, which secured €112 million in financing last year. The project marks the group’s first renewable energy investment outside Turkey and represents the first wind initiative backed by Swiss Export Risk Insurance.

Construction is progressing steadily, with four of the planned twelve turbines already installed. According to Prime Minister Kurti, the Zatriq project underscores Kosovo*’s growing attractiveness for foreign direct investment, supported by an improving legal and regulatory framework. The construction workforce totals 175 personnel, including 130 local workers, highlighting its domestic economic contribution.

The total investment is estimated at €124.4 million, as confirmed by Eurokos. Minister Rizvanolli noted that two additional turbines are expected to be completed within weeks, keeping the project on track for full completion by July. Once operational, the wind farm is expected to enhance energy security, reduce reliance on imports, and generate annual savings exceeding €27 million.

With an anticipated annual output of 185 GWh, the Zatriq wind park will be capable of supplying electricity to approximately 45,000 households. The facility will be connected to the transmission network via a 110 kV overhead line.

Located near the village of Zatriq, the site benefits from one of the strongest wind resources in Kosovo*. The country’s existing wind capacity remains limited, comprising projects such as Selac Wind Farm (104.1 MW), Kitka Wind Farm (32.4 MW), and Golesh Wind Farm (1.35 MW).

For the Zatriq project, Çalık Enerji has partnered with GE Vernova to supply wind turbines featuring 79-meter blades. Beyond Kosovo*, the company operates two wind farms in Turkey with a combined capacity of 72 MW and is developing additional projects in Poland totaling 170 MW.

In the broader energy sector, Çalık Holding, together with Limak, jointly controls Kosovo’s electricity distribution operator KEDS and supplier KESCO.

April 30, 2026

by AEA in News

Bosnia and Croatia Advance Southern Gas Interconnection to Strengthen Regional Energy Security

Bosnia and Herzegovina and Croatia have formalized an intergovernmental agreement to advance the construction of the Southern Gas Interconnection, a strategic infrastructure project aimed at strengthening energy security and ensuring a more stable gas supply for Bosnia and Herzegovina.

The planned interconnection will provide Bosnia and Herzegovina with an alternative supply route via Croatia, reducing its current dependence on Russian natural gas delivered through Turkey, Bulgaria, and Serbia. By enabling access to new sources, the project is expected to significantly enhance supply resilience.

The agreement was signed in Dubrovnik during the Three Seas Initiative summit by Borjana Krišto, Chairwoman of the Council of Ministers of Bosnia and Herzegovina, and Croatian Prime Minister Andrej Plenković.

The pipeline network will span multiple routes, including Split–Zagvozd in Croatia, extending into Bosnia and Herzegovina through Posušje, and continuing across key locations such as Tomislavgrad, Kupres, Bugojno, and Travnik. Additional शाखing routes will connect areas including Mostar, Livno, Jajce, Tuzla, and Čapljina, creating a comprehensive distribution network.

According to the Council of Ministers of Bosnia and Herzegovina, the project will diversify both supply routes and energy sources, contributing to greater energy independence. The pipeline is expected to be supplied with gas from the liquefied natural gas (LNG) terminal on the Croatian island of Krk.

The signing ceremony was attended by US Energy Secretary Chris Wright and Vedran Lakić, Minister of Energy, Mining and Industry of the Federation of Bosnia and Herzegovina. US-based AAFS Infrastructure and Energy has been designated to manage the pipeline within Bosnia and Herzegovina.

Although the project has been under consideration for years, tangible progress accelerated recently. In January, authorities in Bosnia and Herzegovina indicated that AAFS Infrastructure and Energy would receive a 30-year concession. Subsequently, in late February, twelve countries from Central and Eastern Europe and the Balkans, including Bosnia and Herzegovina, reached an agreement with the United States to strengthen cooperation on LNG supply.

The Federation of Bosnia and Herzegovina, the entity through which the pipeline will pass, recently adopted a special legal framework (lex specialis) designating the US firm as the project investor. This decision has drawn criticism from the European Union, which warned of potential consequences.

Borjana Krišto emphasized that Bosnia and Herzegovina occupies a strategic position at the crossroads of energy flows in Southeast Europe. She noted that, beyond being a consumer, the country has the potential to play an active role in developing a more secure and resilient regional energy system. She also highlighted the importance of transatlantic cooperation in accelerating investment and improving market integration.

Prime Minister Andrej Plenković underscored that the agreement reinforces Croatia’s role as a regional energy hub, particularly by enabling the transport of gas from the Krk LNG terminal to Bosnia and Herzegovina. He also pointed to the broader significance of the Three Seas Initiative, which brings together 13 EU member states from Central and Eastern Europe to enhance connectivity between the Baltic, Black, and Adriatic seas, with a focus on infrastructure, transport, and energy integration.

April 29, 2026

by AEA in News

Aktor LNG USA–Albgaz Deal Signals Structural Shift in Western Balkans Gas Market

A landmark long-term gas supply agreement between Aktor LNG USA and Albania’s state-owned Albgaz marks a significant step in the transformation of Southeast Europe’s energy architecture, reinforcing both market diversification and geopolitical realignment.

The agreement, valued at approximately $6 billion, establishes a 20-year framework for the delivery of liquefied natural gas (LNG) sourced from the United States, with contracted volumes of around 1 billion cubic meters annually starting in 2030.

From Hydro Dependence to Gas Integration

For Albania, the deal represents a structural pivot away from near-total reliance on hydropower toward a more diversified energy mix. The introduction of long-term LNG supply contracts provides a stable foundation for baseload generation, system balancing, and regional trading capacity.

The agreement is not limited to commodity supply. It is complemented by a memorandum of understanding between Aktor Energy USA and the Albanian government to develop an integrated energy hub, including a planned gas-fired power plant with an estimated capacity of 380 MW.

This integrated approach reflects a broader transition strategy: linking fuel supply, infrastructure development, and power generation into a single investment framework.

Infrastructure First: Vlora and the Missing Gas System

A central component of the strategy is the planned development of LNG infrastructure in Vlora, which is expected to evolve into a key entry point for imported gas. Until domestic infrastructure is completed, supply will be routed through Greece, leveraging the Revythoussa LNG terminal and the Trans Adriatic Pipeline (TAP) for onward delivery into Albania.

This transitional routing underscores a critical reality: Albania’s gasification remains at an early stage, and the success of the agreement depends heavily on timely infrastructure deployment.

The Vlora energy hub concept—combining LNG import, regasification, and power generation—positions Albania not merely as a consumer, but as a potential transit and redistribution node for the Western Balkans.

The Vertical Gas Corridor: Strategic Context

The deal is embedded within the broader framework of the “Vertical Gas Corridor,” a US-backed initiative aimed at expanding north–south gas flows from Greece into Southeast and Central Europe.

According to Aktor leadership, the agreement is intended to unlock the corridor’s full potential, enabling the distribution of American LNG across multiple Balkan markets and reducing dependency on traditional supply routes.

The corridor concept is particularly relevant as Europe continues to recalibrate its gas supply strategy, with long-term LNG contracts increasingly viewed as essential for supply security beyond 2030.

Geopolitical and Market Implications

The presence of US and Greek stakeholders highlights the geopolitical dimension of the agreement. The United States is actively expanding its LNG footprint in Southeast Europe, using infrastructure and long-term contracts as instruments of strategic influence and market integration.

At the same time, Greece reinforces its role as a regional energy gateway, providing the initial infrastructure backbone for LNG imports and transmission into the Western Balkans.

The agreement also signals potential regional expansion. Discussions are already underway to extend LNG supply arrangements to additional Western Balkan markets, including Serbia and North Macedonia, as interconnection projects progress.

Commercial Structure and Market Significance

From a market perspective, the deal reflects several emerging trends:

Shift toward long-term LNG contracting as a hedge against future supply tightness and price volatility
Integration of infrastructure and supply agreements to de-risk investment in emerging gas markets
Growing role of private-sector intermediaries (such as Aktor LNG USA) in structuring cross-border energy flows

The estimated contract value—around $6 billion over 20 years—indicates a substantial commitment for a relatively small market, underscoring Albania’s ambition to scale beyond domestic demand and participate in regional gas trade.

Execution Risks and Critical Dependencies

Despite its strategic significance, the project faces several execution risks:

Infrastructure delivery risk, particularly the timely development of LNG import capacity and internal gas networks
Demand risk, given Albania’s currently limited gas consumption base
Regulatory and market integration challenges, especially in aligning with EU gas market frameworks

The reliance on interim routing through Greece also introduces transitional dependencies that must be carefully managed.

Conclusion: From Peripheral Market to Emerging Energy Node

The Aktor LNG USA–Albgaz agreement is more than a supply contract—it is a foundational step in repositioning Albania within the regional energy system.

If successfully implemented, it could transform the country from a hydropower-dependent system into a flexible, gas-integrated market with regional relevance. More broadly, it reinforces the Western Balkans’ gradual integration into European energy networks, underpinned by transatlantic LNG flows and new infrastructure corridors.

The real test, however, will lie not in the signing of the agreement, but in its execution—particularly the alignment of infrastructure, regulation, and market demand over the coming decade.

April 29, 2026

by AEA in News

The Border Wall of Carbon: How CBAM Rewrote Balkan Power Trade in Q1 2026

Q1 2026 marked an abrupt break in Southeast Europe’s electricity market structure. Exceptional hydro output pushed WB6 prices down, but CBAM prevented the old price convergence mechanism from doing its job. The result was a wider-than-usual spread of more than €30/MWh between WB6 and EU benchmarks, a 25% drop in scheduled cross-border commercial exchanges, and a visible re-routing of trade toward CBAM-free corridors. The data suggest that CBAM did not merely tax imports; it changed the geography of trade.

Origin of imported electricity	Default value (tCO2eq/MWh)	CBAM cost per imported MWh (€)
Albania	0	0
Bosnia and Herzegovina	1.148	86.513
Kosovo*	0.984	74.154
Moldova	0.530	39.941
Montenegro	0.979	73.777
North Macedonia	0.887	66.844
Serbia	1.041	78.450
Ukraine	0.907	68.352

Table 1. CBAM default factors and implied import costs in Q1 2026

The Hydro Paradox

The irony of Q1 2026 is that the region’s own luck partly disguised CBAM’s first-quarter damage. Hydro generation surged across the WB6 and neighbouring markets, rising regionally by 33% year on year, with Albania alone up 70%. That flood of carbon-free output softened domestic prices and kept some markets liquid, which made the underlying CBAM shock look less severe than it would have in a normal hydrological quarter. The report itself warns that these results are preliminary and heavily shaped by exceptional water conditions, not just the new carbon border regime.

Figure 1. Hydro vs coal generation in Q1 2026 versus Q1 2025

But the same hydro boom also exposed a second vulnerability: it showed how quickly the region can swing from shortage to surplus, which matters for solar and wind investment signals. The Energy Community Secretariat notes that growing solar capacity may generate renewed surplus conditions in spring and summer, even as hydro declines. That means renewable developers are now financing into a market where merchant upside can be sharply altered by a carbon border charge on exports, especially in systems that are not as clean as Albania.

Technical Deep-Dive: Trade Diverges from Physics

The most unsettling finding in the report is the widening gap between commercial schedules and physical reality. Commercially, WB6-EU trade contracted and transit-based trading weakened. Physically, however, electricity still moved according to network physics, not trader preferences. The report gives concrete examples: Albanian export schedules to Greece rose strongly, yet physical flows did not align proportionally; power continued to move through Albania toward Montenegro and Bosnia and Herzegovina and onward to EU border countries.

That divergence is not just a bookkeeping issue. It creates operational risk. The report links the pattern to unscheduled and loop flows, less efficient transmission capacity use, and a growing burden on balancing and security management. It also explicitly recalls the June 21, 2024 blackout, when near-simultaneous outages on 400 kV lines in Montenegro and Albania exposed the fragility of the South-North corridor and the costs of weak cross-border coordination. In the current setting, the same corridor could again become heavily loaded, but with less predictable commercial schedules to guide system operation.

Market Fragmentation: The Rise of CBAM-Free Routing

The report reads like a map of avoidance behaviour. Intra-WB6 exchanges intensified, while trade moved toward routes that do not trigger CBAM exposure. Albania’s zero default emission factor made it a natural winner, with export routes to Greece gaining importance. Greece then became a bridge to Bulgaria and Italy, effectively allowing some power to bypass the more exposed WB6 transit geography.

Figure 2. Average day-ahead prices across the region

This is why the Secretariat’s “CBAM-free route” language matters. It suggests that the market is not simply shrinking; it is reorganising itself around carbon liability. Transit-based trading through the WB6 is becoming less attractive, and that is a structural problem for regional integration because the WB6 has historically functioned not only as a set of markets, but also as a corridor between larger EU systems.

Financial Outlook

For project finance, the message is straightforward: ETS-linked carbon costs are now a core merchant-risk variable in the Western Balkans. The report states that the relevant Q1 2026 CBAM certificate price was based on an EU ETS quarterly weighted average of €75.36/tCO2eq, and that this price fell sharply after an initial increase as political debate over ETS reform intensified. That level of volatility matters because it directly changes export economics quarter by quarter.

Figure 3. Scheduled commercial exchanges between the WB6 and the EU

For EBRD-style underwriting, this means more conservative assumptions are unavoidable. Revenue cases for new renewable projects in the WB6 should be stress-tested not only against power-price volatility and hydrology, but also against CBAM-induced basis risk on export routes. Projects that depend on merchant access to EU markets will need stronger carbon-risk sensitivity, more robust route diversification, and a clearer view of whether they are selling into a CBAM-exposed corridor or a CBAM-free one. The report’s core warning is that low-carbon systems may send stronger investment signals, while more carbon-intensive systems face a worsening structural handicap.

Strategic Recommendations

The Secretariat’s own policy direction is the right one: better clarity in CBAM electricity rules, stronger coordination between market participants and TSOs, and continued alignment of carbon pricing and market design across the region. Building on that, the practical priorities are clear. WB6 TSOs need tighter coordinated capacity calculation, stronger congestion management, and more transparent handling of transit flows. Policymakers should also close the information gap around proof of transit and improve rules that currently reward route avoidance over efficient system use.

The deeper objective is to stop the region from sliding into transit-based trading collapse. That means preserving market integration even as carbon policy changes the economics of exchange. If WB6 markets are left to fragment into isolated hydro winners and carbon-heavy losers, the region will not simply lose trade; it will lose the very interoperability that made its system valuable in the first place.

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.

March 11, 2026

by AEA in News

Balkan power play: why the Western Balkans must ditch Russian fuels and fast-track EU market integration

A short, sharp truth: the Western Balkans sits at the crossroads of Europe’s energy security and its green ambitions, but patchy rules, lingering dependence on Russian fuels and slow market reforms mean the region risks being a weak link rather than a bridge. A new working paper from Bruegel lays out what’s at stake and what needs to happen next.

From leverage to liability: Russian ties still matter

Gas pipeline system in the Western Balkans

The report finds that several Western Balkan states remain exposed to Russian energy influence notably Serbia and Bosnia and Herzegovina on oil and gas which leaves them vulnerable to geopolitical pressure and imported price shocks. Negotiations and occasional extensions of Russian contracts in 2024–25 underline that diversification on paper does not always mean real independence. That dependence isn’t just political theatre: it alters investment choices, weakens bargaining power and complicates alignment with EU rules.

Why this matters beyond the region: the Western Balkans is a major transit corridor for electricity between the EU and Southeast Europe. The paper highlights that as much as “up to 70%” of electricity flows tied to the region actually pass between EU countries a signal that grid interdependence already exists and that isolation is neither realistic nor desirable. Faster regulatory alignment and market coupling would therefore strengthen European system resilience as well as the region’s.

Western Balkan electricity imports and exports (TWh), 2020-2024

Market coupling: planned, stalled, urgent

European market coupling the technical and regulatory merging of power markets is the single policy lever that could deliver immediate gains: better price signals, more efficient dispatch across borders, and a buffer against supply shocks. The Bruegel authors point out that integration planned for the mid-2020s (originally aiming around 2027) is running behind because national rulebooks and market institutions in the Western Balkans are not yet aligned with EU standards. That delay has real costs: lost efficiency, higher system operation expenses, and a slower rollout of renewables.

Day-ahead auction average prices (€/MWh), EU, Norway and Western Balkans, 2024

Uneven green progress leaders and laggards

Not all Western Balkan countries are on the same page when it comes to the green transition. The paper singles out Albania as a regional leader largely because of its hydropower legacy and relatively favorable renewables policies and Montenegro as advanced across several indicators. Meanwhile, solar and wind potential across much of the region remains largely untapped and constrained by underdeveloped grids, weak permitting frameworks and scarcity of private investment. Simply put: the natural resource advantage (sun, wind, hydro) is mostly unexploited.

This mix of actors creates both a challenge and an opportunity. Countries with stronger renewables backbones could become exporters and stabilizers for neighbors but only if cross-border trade is enabled and market rules are harmonised.

Domestic electricity prices (€/MWh), EU, Norway and Western Balkans, 2024 and 2014

Coal’s long shadow political economy vs. emissions

Phasing out coal is politically charged across the Western Balkans. Coal still provides baseload power and jobs in several countries, and switching it off without credible compensation or alternative industrial plans risks social backlash. The paper recommends phased, socially sensitive coal retirement plans tied to clear investment pathways for renewables and grid upgrades. In short: decarbonisation must be realistic and sequenced fast where possible, compensated where needed.

Practical steps the paper recommends (and why policymakers should care)

Accelerate regulatory alignment with the EU. Aligning rules is the low-hanging fruit that unlocks market coupling and immediate efficiency gains. Market reforms are technical, but the payoff — lower costs and stronger security — is political and strategic.
Reduce real dependence on Russian fuels. Diversification must go beyond headline contracts. It requires investments in LNG connections, alternative import routes, and faster roll-out of domestic renewables to reduce import vulnerability.
Design a just coal phase-out. Pair plant retirement timetables with retraining, economic revitalisation, and clean-energy investment envelopes so communities are not left behind.
Mobilise private capital for renewables and grids. Improve permitting, de-risk projects with public guarantees, and create transparent auction frameworks to attract the investors the region needs.

Political and financial headwinds plus a window of opportunity

The paper is candid about constraints: weak institutions, fragmented markets, and geopolitical tensions complicate reform. But it also notes a narrow window where EU enlargement dynamics, conditional funding instruments (the EU Growth Plan for the Western Balkans) and post-Ukraine energy policy realignments create momentum and conditional financing that can be leveraged if countries move quickly and coherently.

Electricity generation mix in the Western Balkans, 2014 and 2024

What success looks like

A successful pathway would see the Western Balkans converge with EU market rules, complete market coupling, significantly reduce Russian fuel exposure, and scale renewables deployment while phasing out coal with social protections. Practically, that means lower wholesale price volatility, better utilisation of regional transmission assets, and an energy sector that attracts investment rather than fears it.

Conclusion integration first, transition faster

The Bruegel working paper’s central message is straightforward: the Western Balkans has the geographic and resource advantages to be a strategic partner for Europe’s energy security and green goals but only if the political will to align rules, diversify supplies and invest in renewables is found. Fast-tracking market coupling and decarbonisation in parallel, not in sequence will deliver both security and economic opportunity. For policymakers in Tirana, Sarajevo, Pristina, Podgorica, Skopje and Belgrade, the choice is clear: remain a transit corridor vulnerable to outside influence, or become a resilient, integrated bridge to Europe’s clean-energy future.

March 5, 2026

by AEA in News

PPC and Metlen Forge 1.5 GW Regional Battery Storage Alliance

In a major move to solidify their dominance in the Southeast European energy transition, Greece-based PPC Group and Metlen Energy and Metals (formerly Mytilineos) have entered into a strategic joint venture. The agreement aims to develop, construct, and operate a massive portfolio of Battery Energy Storage Systems (BESS) totaling 1.5 GW in power capacity and 3 GWh in energy storage across Romania, Bulgaria, and Italy.

Fast-Tracking Storage Infrastructure

The partnership is designed for rapid deployment, with both companies targeting the completion of 1 GW of capacity within just 12 months. This aggressive timeline underscores the urgency of integrating flexible assets into regional grids to manage the influx of intermittent renewables.

The technical specifications of the portfolio focus on high-efficiency, utility-scale technology:

Total Capacity: 1.5 GW / 3 GWh (representing two-hour duration systems).
Technology: Liquid-cooled Lithium-Iron-Phosphate (LFP) batteries.
Asset Management: The venture will be equally owned (50/50), leveraging PPC’s regional market presence and Metlen’s specialized EPC (Engineering, Procurement, and Construction) expertise.

Synergy Beyond Solar

This deal follows a landmark 2024 agreement between the two entities, which saw them collaborate on a 2 GW solar pipeline across Italy, Romania, Bulgaria, and Croatia. While that previous arrangement focused on an “at-completion” acquisition model by PPC, this new BESS venture creates a deeper operational partnership.

The storage facilities are intended to perform two critical functions:

Renewable Support: Balancing the output of adjacent photovoltaic and wind farms.
Grid Stability: Providing essential ancillary services to national electricity systems to prevent frequency fluctuations.

Strategic Implications for Southeast Europe

For the government-controlled PPC Group, this alliance secures a significant portion of its three-year energy storage targets. For Metlen, the deal represents a pivotal milestone in its broader European strategy, positioning the firm as a leading player in the continent’s storage infrastructure sector.

“This agreement creates value for both parties and further expands our group’s already significant presence in Southeast Europe,” noted Konstantinos Mavros, PPC Group’s Deputy CEO for Renewables.

As the Balkan and Mediterranean markets continue to decarbonize, the rapid commissioning of these 3 GWh of storage capacity is expected to be a cornerstone for regional energy security and market liquidity.