May 18, 2026

by AEA in News

US-Backed LNG Projects Reshape the Western Balkans’ Energy Landscape

The United States is seeking to reshape the energy map of the Western Balkans through a network of bilateral agreements and infrastructure projects centered on liquefied natural gas (LNG). The broader objective is to reduce the region’s dependence on Russian gas while strengthening a strategic energy corridor linking Southern and Central Europe.

A series of projects is being advanced across Croatia, Bosnia and Herzegovina, North Macedonia, Albania, Montenegro, Kosovo and Serbia. These initiatives include new gas pipelines, LNG terminals and gas-fired power plants, supported politically and financially by both Washington and Brussels. Some projects are already under construction or in the contracting stage, while others remain in planning. Together, they signal a gradual shift in the region’s energy mix toward gas supplies from the United States, Azerbaijan and the Mediterranean basin.

Jonathan Stern of the Oxford Institute for Energy Studies notes that Southeast Europe has already developed alternative gas supply routes. These include LNG terminals in Greece and Croatia, the Southern Gas Corridor from Azerbaijan, and Romania’s Neptun Deep offshore field in the Black Sea, whose exploitation is expected to begin next year and whose reserves are estimated at around 100 billion cubic meters.

Bosnia and Herzegovina Seeks to End Dependence on Russian Gas

Bosnia and Herzegovina has recently become a focal point of regional gas diversification efforts through the Southern Gas Interconnection project with Croatia. The pipeline would give the Federation of Bosnia and Herzegovina access to the LNG terminal on the Croatian island of Krk and to alternative gas suppliers. At the same time, Republika Srpska continues to pursue separate gas links with Serbia, including the Eastern Interconnection project from Bijeljina to Banja Luka.

For nearly five decades, Bosnia and Herzegovina has depended almost entirely on Russian gas, delivered through TurkStream and used mainly for heating in Sarajevo. In overall volume terms, the country remains a relatively small gas consumer compared with Serbia.

The intergovernmental agreement between Bosnia and Herzegovina and Croatia on the Southern Gas Interconnection was signed in Dubrovnik in April, in the presence of US Secretary of Energy Chris Wright. The pipeline is planned to extend from Dalmatia toward central Bosnia, with additional branches toward Herzegovina and the country’s northwest. Croatia’s state-owned Plinacro is leading the Croatian section, while the US-based company AAFS Infrastructure and Energy has been designated to manage the project on the Bosnian side.

The project has, however, drawn criticism from the European Commission and the Energy Community. Concerns center on the Federation of Bosnia and Herzegovina’s special-purpose law, or lex specialis, which named a private American company in the project framework, as well as questions over compliance with EU and Energy Community rules.

Bosnia and Herzegovina currently consumes up to 250 million cubic meters of gas annually, while the planned pipeline is expected to have a capacity of around 1.5 billion cubic meters. This has prompted discussion about the possible construction of gas-fired power plants capable of supplying electricity to roughly 400,000 households. At present, about 80% of the country’s electricity is generated by coal-fired thermal power plants, some of them more than half a century old.

The new pipeline would also connect with the existing gas route arriving from Serbia. Still, Stern argues that while the project is important for Bosnia and Herzegovina, its wider regional relevance is less clear. He also questions the commercial viability of an investment estimated at around EUR 1 billion, particularly given the lack of available LNG transit capacity from Croatia and Serbia’s expanding access to gas through Bulgaria.

Serbia Balances Diversification and Russian Gas Dependence

Serbia is expanding its gas infrastructure as it seeks to preserve its position as a regional energy hub while creating room for US LNG and broader Western investment in the sector.

In February this year, Serbian Minister of Mining and Energy Dubravka Đedović Handanović signed a joint statement with the United States and several Central and Eastern European countries during the Transatlantic Gas Security Summit in Washington. The statement focused on strengthening the resilience of regional gas markets and improving supply security.

Following the summit, Srbijagas Director Dušan Bajatović stated that Serbia would eventually need to purchase American gas, although no quantities or formal supply contracts have yet been defined. Serbia’s 2024 strategic energy cooperation agreement with the United States envisages diversification of energy sources, but it does not currently include a binding agreement to buy US LNG.

Potential US LNG deliveries to Serbia could come through the Krk terminal in Croatia or via Greece’s Alexandroupolis terminal, supported by new interconnections through Bulgaria and North Macedonia. Serbia currently operates approximately 2,500 kilometers of gas pipelines, is planning new links, including one toward North Macedonia, and is expanding the Banatski Dvor gas storage facility.

Despite these diversification efforts, more than 80% of Serbia’s gas still comes from Russia through TurkStream. Major energy assets, including the TE-TO Pančevo combined heat and power plant, remain tied to Russian-linked structures involving Gazprom and the Serbian oil company NIS.

Montenegro Explores an LNG Terminal and Gas-Fired Generation

Montenegro, which currently lacks a domestic gas network, is also being drawn into the emerging US-backed LNG framework. Plans include an LNG terminal at the Port of Bar and the possible development of gas-fired power generation.

The country participated in the Transatlantic Gas Security Summit in Washington in February and joined a broader political statement on gas cooperation between the United States and several Central and Southern European countries.

In 2023, the Montenegrin government signed a memorandum of understanding with US companies Enerflex Energy Systems and Wethington Energy Innovation regarding potential LNG and power infrastructure. However, no LNG supply agreement has been finalized, no volumes have been specified, and no binding commercial contracts have been signed.

Montenegro has also supported the Ionian-Adriatic Pipeline (IAP), which would connect the Trans-Adriatic Pipeline (TAP) in Albania with Croatia, although the project remains at the conceptual stage. Separately, gas-fired power plants ranging from 50 MW to 400 MW are being considered in Bar, Podgorica and Pljevlja, including hybrid solutions and possible conversions of existing facilities.

Studies prepared for the Electric Power Company of Montenegro by Japan’s JERA and Switzerland’s SS&A Power Consultancy concluded that the options assessed are technically feasible and economically viable. Depending on the selected plant capacity and fuel supply source, estimated investments range from EUR 233 million to EUR 362 million.

Kosovo Remains Outside the Current Gas Push

Kosovo currently has no gas infrastructure and relies almost entirely on coal-fired power generation. A proposed gas interconnection with North Macedonia had been included in the European Union’s investment plan for the Western Balkans, but the project was suspended, with the government citing high costs and a strategic preference for renewable energy development.

The proposed pipeline would have provided Kosovo with access to gas from Greek LNG terminals in the Aegean Sea, while a separate link to Albania had also been considered. US officials have indicated that they remain open to supporting commercial cooperation if market conditions become more favorable.

Kosovo also declined to direct roughly USD 200 million in Millennium Challenge Corporation funding toward gas infrastructure, instead shifting the investment toward battery energy storage systems.

North Macedonia Emerges as a Strategic Southern Corridor Link

North Macedonia is building new gas infrastructure with support from Washington and Brussels, aiming to reduce its long-standing dependence on Russian gas and position itself as a regional energy transit hub. As a NATO member and EU candidate country, diversification of energy supply has also taken on a clear geopolitical dimension.

The TE-TO Skopje cogeneration plant, which provides heat to the capital and produces electricity, remains dependent on Russian gas and is controlled by interests linked to the Russian group Sintez.

Skopje has signed a memorandum related to the purchase of US LNG, though detailed commercial terms have not been publicly disclosed. The Gevgelija–Negotino gas pipeline is under construction and is expected to connect North Macedonia with Greek LNG terminals. Its initial annual capacity is planned at 1.5 billion cubic meters.

The European Union is financing the project through a combination of loans and grants. At the same time, an interconnection with Serbia is being planned, with construction expected to begin in 2027. North Macedonia’s Ministry of Energy, Mining and Mineral Resources has also stated that the country plans to develop 67 new energy facilities with a combined installed capacity of 4,416 MW, including a cogeneration plant near Negotino.

Albania Positions Vlora as a Future LNG Hub

In April 2026, Albania signed a strategic agreement worth USD 6 billion involving Venture Global and Aktor LNG USA for long-term LNG supply beginning in 2030. The agreement is part of a broader effort to turn Albania into a regional entry point for US LNG in Southeast Europe.

The plan includes the development of an energy hub in Vlora featuring an LNG terminal and a gas-fired power plant with a capacity of approximately 380 MW. The project would also connect with the Trans-Adriatic Pipeline (TAP), which has transported Azerbaijani gas to Italy since 2020.

Vlore, Albania

Washington views Albania as a potential distribution platform for supplying US gas to Kosovo, North Macedonia and other Western Balkan markets. This is particularly significant because Albania does not currently operate a functional internal gas network, while most of the infrastructure inherited from the socialist period is no longer usable.

For Albania, whose electricity system depends overwhelmingly on hydropower, a gas-fired power plant could serve as a strategic reserve during drought periods and times of rising power demand.

Energy expert Stavri Dhima has argued that Albania’s gasification strategy should combine several elements: construction of the Ionian-Adriatic Pipeline, connection to Croatia’s LNG terminal, access to the Trans-Adriatic Pipeline carrying Caspian gas, and development of an LNG terminal and gas storage facility in Dumrea.

If completed, the LNG terminal in Vlora could become a regional gas hub serving Albania, Montenegro, North Macedonia and Kosovo. Through IAP and TAP, gas could potentially also be directed toward Bosnia and Herzegovina and Italy.

Still, experts caution that infrastructure alone does not guarantee energy security. Countries seeking to reduce dependence on Russian gas must also secure reliable, long-term supply contracts with multiple alternative suppliers.

May 7, 2026

by AEA in News

North Macedonia Launches Intraday Electricity Market as Regional Power Trading Evolves

North Macedonia has taken another significant step toward deeper integration with the European electricity market following the launch of its intraday power market by the National Electricity Market Operator (MEMO). The development represents a major advancement in the country’s electricity market liberalization process and strengthens operational flexibility within the regional energy system.

The official launch ceremony gathered senior representatives from the government, energy institutions, market participants, and international partners. The intraday trading platform and clearing infrastructure were delivered by Slovenia’s BSP Energy Exchange, continuing its cooperation with MEMO after supporting the establishment of North Macedonia’s day-ahead market. Intraday trading operates through Deutsche Börse’s M7 trading system, one of Europe’s widely adopted electricity trading platforms.

The introduction of intraday trading comes three years after the launch of the country’s day-ahead market and reflects the increasing sophistication of North Macedonia’s power sector. Intraday markets play a critical role in modern electricity systems by enabling market participants to adjust positions closer to the actual delivery hour. This improves balancing efficiency, reduces imbalance costs, and enhances the integration of variable renewable energy sources such as solar and wind.

Prime Minister Hristijan Mickoski described the launch as evidence of tangible reform progress in the national energy sector. According to him, energy security and resilience have become strategic priorities for all European economies amid accelerating market transformation and geopolitical uncertainty.

“At a time when energy is one of the most critical issues for every country, our obligation is to create a system that is secure, competitive, and resilient to global challenges,” Mickoski stated during the event.

He emphasized that North Macedonia intends to actively participate in European energy flows and policy frameworks rather than remain on the periphery of the continent’s ongoing energy transition.

Minister of Energy, Mining and Mineral Resources Sanja Božinovska underlined that the intraday market is only one phase of a broader market integration strategy. She reiterated the government’s commitment to future market coupling with the European Union and the continued development of regional electricity trading mechanisms.

“This is just the starting point for our full integration into the European energy family,” Božinovska said, adding that authorities will continue advancing regional cooperation and aligning domestic market structures with EU standards.

MEMO Chief Executive Officer Zoran Gjorgjievski highlighted the operational significance of intraday trading in a rapidly changing electricity environment increasingly shaped by renewable generation and real-time balancing requirements.

“From today, our market not only plans for tomorrow – it operates in real time. The intraday market is a direct response to the dynamics of the modern energy sector,” Gjorgjievski noted.

He stressed that transparent and efficient price formation remains essential for optimal resource allocation, prudent investment decisions, and effective risk management across the electricity value chain.

Gjorgjievski also warned that emerging European regulatory frameworks, particularly the Carbon Border Adjustment Mechanism (CBAM), could introduce additional pressure on domestic electricity producers and potentially affect regional market liquidity. While supporting decarbonization objectives, he argued that the energy transition must remain economically sustainable and carefully managed to avoid undermining market competitiveness.

The launch of the intraday market is also viewed as an important preparatory step toward integration into the single European electricity market. Chairman of the Management Board of ADEX Group and CEO of BSP Energy Exchange Anže Predovnik said the project reflects strong institutional cooperation, strategic government support, and MEMO’s operational commitment.

“What lies ahead is integration into the single European market. Together, we will build a more connected and competitive future,” Predovnik stated.

North Macedonia’s intraday market currently includes 21 participants, demonstrating growing interest among regional traders and electricity companies.

According to Martin Martinovski, electricity and statistics expert at the Energy Community Secretariat, the operational intraday market strengthens North Macedonia’s role within the regional balancing framework. As integration with the EU electricity market progresses, the country could increasingly contribute low-carbon flexibility to neighboring systems while benefiting from cross-border balancing support.

Market growth figures indicate a rapid expansion in trading activity since the launch of organized electricity trading in the country. Trading volumes increased from 335 GWh by the end of 2023 to nearly 970 GWh in 2024, before surpassing 1.37 TWh last year. MEMO currently counts forty active market members, while first-quarter 2026 trading volumes were 19% higher compared to the same period a year earlier.

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 20, 2026

by AEA in News

Serbia needs EUR 27 billion to reach decarbonization goals

Serbia faces a substantial financial and structural challenge in its transition toward a low-carbon energy system. According to recent statements from senior management at the state-owned utility EPS, the country will need approximately EUR 27 billion in investment to meet its decarbonization objectives by 2050.

This estimate underscores both the scale of transformation required and the limits of the current energy model, which remains heavily reliant on fossil fuels—particularly coal—while moving toward alignment with European climate and energy policies.

Financing the Transition: Beyond Public Balance Sheets

A central conclusion emerging from the discussion is that Serbia’s decarbonization pathway cannot be financed through internal resources alone. EPS leadership emphasized that achieving a sustainable transition will require a diversified financing structure involving the state, international financial institutions, commercial banks, and capital markets.

In practical terms, this reflects a broader shift in energy policy: decarbonization is no longer only a technical or environmental issue, but fundamentally a question of financial architecture. Access to long-term, low-cost capital—combined with appropriate risk-sharing mechanisms—will be critical to mobilizing the required investment scale.

To that end, EPS is preparing to enter both domestic and international capital markets. A key milestone in this process is the expected acquisition of a credit rating, which would enable the company to issue green bonds and attract institutional investors.
Such instruments are increasingly central to energy transition financing across Europe, particularly in markets where public funding capacity is constrained.

Structural Transformation of the Power Sector

Beyond financing, the transition implies a deep restructuring of Serbia’s generation portfolio. The gradual decommissioning of aging thermal power plants is seen as inevitable, reflecting both environmental requirements and declining economic viability.

At the same time, the development of renewable energy capacity—primarily wind and solar—is expected to accelerate. EPS has indicated a willingness to engage more actively with private investors through joint ventures, power purchase agreements (PPAs), and even the acquisition of completed or late-stage renewable projects.

This signals a notable evolution in the role of the state utility, from a traditional vertically integrated operator toward a more market-oriented and partnership-driven entity.

Importantly, Serbia’s existing asset base—particularly land holdings and grid infrastructure—provides a strategic advantage for scaling renewable deployment. Leveraging these assets efficiently could reduce project development timelines and costs, improving overall investment attractiveness.

Market Integration and Investor Engagement

The transition strategy also highlights the need for stronger integration with private capital and market mechanisms. EPS leadership explicitly stressed the importance of becoming more agile and active in the market, including building relationships with investors and adapting to competitive dynamics.

This reflects a broader regional trend in the Western Balkans, where historically state-dominated energy sectors are gradually opening to private participation. However, this transition requires not only regulatory reform but also improvements in corporate governance, transparency, and financial performance.

Recent financial results from EPS indicate positive momentum, with a significant increase in annual profit, which could strengthen its credibility with investors and lenders.
Nevertheless, maintaining financial discipline while undertaking large-scale capital expenditure will remain a key challenge.

Strategic Implications: A Transition at Scale and Speed

From a policy perspective, the EUR 27 billion investment requirement highlights the magnitude of Serbia’s decarbonization challenge. The country’s energy system is still largely carbon-intensive, with fossil fuels accounting for a dominant share of electricity generation, making the transition both urgent and complex.

Decarbonization will therefore require a coordinated approach that integrates infrastructure investment, market reform, and financial innovation. It will also need to address social and economic implications, particularly in regions dependent on coal production and thermal generation.

Crucially, the success of this transition will depend on Serbia’s ability to align its energy policy framework with EU standards, improve investment conditions, and mobilize both domestic and international capital at scale.

Conclusion

Serbia’s pathway to decarbonization is now clearly defined in terms of scale, direction, and urgency. The estimated EUR 27 billion investment requirement is not merely a financial figure it represents a comprehensive transformation of the country’s energy system.

The coming years will be decisive. Progress will depend on the effectiveness of financing strategies, the pace of structural reform, and the ability of key institutions such as EPS to evolve into modern, market-oriented energy players. Without these elements, the transition risks delays; with them, Serbia has the potential to position itself as a credible participant in Europe’s low-carbon energy future.

February 16, 2026

by AEA in News

Albania’s Energy Sector: Key 2025 Insights and Outlook

Albania’s energy sector in 2025 remains dominated by hydro and oil, but undergoing rapid change. Gross available energy (supply) in 2023 was 2,234 ktoe, against primary production of 1,799 ktoe. Imported oil and electricity cover the gap: the country needs roughly 4–5 TWh of net imports annually. In 2023 final energy consumption was 1,942 ktoe (down 2.8% year-on-year), with industry (~27%), residential (~34%), transport (~22%), services (~11%) and other sectors (~6%) each accounting for a share. Albania’s energy intensity remains fairly low – roughly 0.17 ktoe per million EUR of GDP (–4.0% in 2023) – reflecting both efficiency gains and a modest economic base.

Infrastructure investments are focused on grid upgrades and new pipelines. Two major 400 kV transmission projects are planned or underway: closing the internal 400 kV ring and building a 400 kV Albania–Kosovo* interconnector (both under WBIF support). The long-delayed Elbasan–Bitola 400 kV line (a 2018 Energy Community project of common interest) still awaits completion. On gas, Albania currently has no domestic market – it consumes virtually no pipeline gas today – but this will change. A Fier exit point on the Trans-Adriatic Pipeline (TAP) is under construction (targeted commissioning October 2027), and a planned Fier–Vlora feeder line is in planning. Meanwhile a new Korça gasification scheme (Azerbaijani Azeri gas via TAP) was agreed in November 2024, aiming to extend distribution into eastern Albania. These gas projects could underpin future power and industrial expansion.

2023 Albania Primary Energy Production by Fuel (ktoe) – oil and hydro dominate

Electricity Market: Liberalization and Infrastructure

Since 2023 Albania has made notable strides in power market integration, but wholesale trading remains limited. A day-ahead market was launched in April 2023 and coupled with Kosovo* from January 2024 – the first cross-border market coupling in the Energy Community. Complementary regional intraday auctions (CRIDAs) between Albania and Kosovo* began in December 2024. (Plans for a continuous intraday market are pending.) The Albanian Power Exchange (ALPEX) operates these markets: by 2024 it had 26 registered participants, of which 16 trade intraday, and traded roughly 12% of Albania’s final electricity consumption on the day-ahead market.

However, full liberalization is unfinished. The day-ahead and intraday markets run in parallel with a traditional regulated market. The state-owned utility KESH still supplies universal service customers (low-voltage households) under a public service obligation (PSO) at government-set prices. Regulated tariffs and supply obligations extend to most small businesses and residential clients. Only customers on 10–110 kV networks (large industry) face market prices, with lower-voltage consumers still sheltered under universal service tariffs. Indeed, current regulations keep in place a PSO for KESH (originally a temporary crisis measure) and a supplier-of-last-resort (SoLR) regime for others. Retail prices for low-voltage consumers thus remain controlled (free market entry is limited), and new retail deregulation phases (10 kV by 2025, 6 kV by 2026) are planned. (These interventions still fall short of EU requirements.)

Balancing and ancillary services are developing along European lines. A 15-minute imbalance settlement period was introduced in 2025 (after delays). Balancing energy is procured via a merit-order market operated by OST (the national TSO). Cross-border balancing cooperation is currently minimal: Albania only shares frequency-restoration reserves with Kosovo* under a joint “AK block” agreement. Full participation in European balancing platforms will require transposing the EU Electricity Regulation (2019/943) and Network Code on balancing (2017/2195) – work that has only just begun.

On network infrastructure, the transmission system operator OST is certified (ownership unbundled) and a member of ENTSO-E, but key grid upgrades lag. The TEN-E revision (2022/869) – which would designate new energy corridors – has not been transposed. In the meantime, two grid projects of regional interest are under development: closing Albania’s internal 400 kV loop and a new 400 kV tie to Kosovo*, both backed by EU grants. Investment plans for OST and the DSO (OSSH) are now regularly approved by the regulator ERE; ERE also endorsed the 2025–27 capital plan of OST in 2025, which includes these projects. Distribution network upgrades (smart metering, loss reduction) remain on the agenda but face funding constraints.

[Insert chart: Albania Electricity Market Coupling Timeline (Day-ahead April 2023, coupling Jan 2024, CRIDAs Dec 2024)]

Gas Market: Emerging Supply and Infrastructure

Historically, Albania had no natural gas consumption; electricity and heating ran on oil and biomass. This is changing. Although no domestic gas market exists yet, Albania is transposing EU gas rules in anticipation. The regulator has applied REMIT transparency rules (excluding market rules). Certification under the Third Package is in place: TAP AG (cross-border pipeline) is certified as an exempt TSO, and Albgaz (Albania’s gas TSO) was conditionally certified under ownership unbundling. Albgaz’s remaining unbundling issues have been repeatedly extended (new deadline end-2025), and TAP and Albgaz plan separate network codes once pipelines operate.

Two key pipeline projects will shape Albania’s gas landscape. First, the TAP Fier exit point will link Albania to the Trans-Adriatic Pipeline. Construction is slated to start May 2026 and complete by October 2027. This facility (a pressure-reduction station and meter) will allow Azeri gas from TAP to enter Albanian networks. Second, the Korça Gasification Project – a private initiative by Azerbaijan’s SOCAR – will build a local grid from a new Fier (TAP) connection eastward. A 2024 MoU commits Albgaz and SOCAR to design and build the exit and local pipeline, with a TAP capacity nomination already in place. If realized (final investment decision pending), Korça would for the first time supply gas to industries and possibly power plants in southern Albania by the late 2020s.

Domestic gas demand is expected to grow once these are online (power plants and industry will switch from oil), but there is no wholesale gas trade yet. Secondary legislation to allow retail gas supply exists, but without an existing network to serve, these serve mainly as placeholders. In practice, Albania’s future gas wholesale is effectively TAP-dominated; a functioning national hub or trading platform is still years away.

Renewable Energy and Decarbonisation

Albania’s power system is already very green by global standards, but has room to diversify. In 2024 total renewable electricity capacity reached about 3,005 MW – dominated by small hydropower (<10 MW) at some 2,181 MW and utility-scale hydro (≈375 MW), with 449 MW of solar PV. (Wind and biogas are currently negligible: the report notes only 3 MW of wind.) Renewables supplied most of Albania’s generation in 2023 (hydro plus a modest biomass cogeneration), but exact shares are not broken out in the report. What is clear is that Albania’s 2030 renewables target is ambitious: the adopted National Energy and Climate Plan (NECP) aims for 54.4% of final energy consumption from renewables by 2030, above the 52.0% goal set by the Energy Community Decision. The NECP also envisions sectoral sub-targets (e.g. ~178% for electricity, 34.6% transport, 16.6% heating/cooling) that exceed current EU RED II mandates.

Policy reforms are in motion to boost renewables. The 2023 Renewable Energy Law shifted from fixed feed-in tariffs to competitive auctions (contracts-for-difference/premium) for green power. Two auctions were already held with fixed prices, with plans to transition to pure CfDs once Albania’s day-ahead market achieves liquidity. So far no statistical transfers or joint schemes (EU cooperation mechanisms) have been used. Net metering is enabled (rooftop systems up to 500 kW) and Albania plans to move to net billing (full retail credit) as of 2024. The law also incorporated guarantees-of-origin (GOs) for all renewable generation: an electronic GO registry became operational under ERE in May 2023, laying groundwork for tracking clean energy. However, “renewable energy communities” are still theoretical – no community project has been set up yet.

In the heating sector, Albania is rolling out support for solar thermal collectors and heat pumps. A recent scheme reimburses 70% of solar water heater costs for low-income households (vs. 20–30% for other systems). Draft legislation for broader RES heating/cooling incentives is pending. On bioenergy, Albania has transposed most RED II provisions, but needs secondary rules for verifying sustainability (GHG savings and land-use criteria) for bioliquids and solid biomass used in heat and power.

Overall, the renewables pipeline is robust: capacity grew by +279 MW in 2024 (mostly PV additions). Auctions and net-billing should further drive solar rooftop uptake, especially for homes and businesses now escaping fixed feed-in tariffs. Hydropower will remain the backbone of Albania’s system; future small hydro additions and the potential for wind in the flat coastal plains (not yet tapped) could further diversify output.

Energy Efficiency and Buildings

Improving efficiency is a strategic priority. Albania’s buildings are its largest energy sink, consuming 38% of final energy in 2023. Recognizing this, in June 2025 Albania adopted a new Energy Performance of Buildings law, aligning key provisions with EU directives (including upcoming 2024 requirements). An Energy Performance Certificate (EPC) system is now operational, with ongoing training and software development. Crucially, a long-term renovation strategy (in line with the EU’s Renovation Wave) was approved in February 2025. The government is developing a detailed renovation plan to reduce building energy use, tackle energy poverty, and modernize housing and offices across Albania’s regions.

Albania’s energy consumption is already edging down. Primary energy use fell to 2,141 ktoe in 2023 (–1.5% year-on-year), while final consumption was 1,942 ktoe (–2.8%). For comparison, the 2030 NECP targets are much higher: 2,600 ktoe (primary) and 2,400 ktoe (final). The continuing decline reflects efficiency measures and structural changes. Energy intensity (use per GDP) is among the lowest regionally at ~0.17 ktoe/MEUR. Key upcoming measures include a new Energy Efficiency Law (planned in 2025 to transpose the recast EU EED), full implementation of the energy obligation scheme, and mandatory labelling and standards (a product-labeling law was passed in mid-2024). So far Albania lacks a dedicated EE fund; financing for retrofits has come from budgets and donor programs, with early ESCO activity in the housing sector. Improved access to credit and subsidies for vulnerable households are being discussed as next steps.

Policy, Regulation and EU Alignment

Albania’s legislative framework is being steadily updated to meet EU/EnC requirements, but gaps remain. The Electricity Integration Package (EIP) – the core EU rulebook for electricity markets – is not yet fully transposed. A draft law (May 2025) would implement many EIP provisions (market design, unbundling, RES integration, etc.), but it has not been passed. In the interim, ERE has adopted some CACM rules: a national capacity allocation & congestion management regulation (EUR 543/2013) was approved in April 2025. Albania also uses the SEE Regional Auction Office (SEE CAO) for cross-border capacity. Notably, the EU rule requiring at least 70% of interconnector capacity to be offered to the market is not in force yet.

In gas, Albania’s alignment is behind schedule. The EU’s Gas Security of Supply Regulation (2017/1938) is only partly implemented in law (via amendments to the 2021 Gas Law). A national Risk-Preparedness regulation (EU 2019/941) is due by end-2025; a draft Power Sector Law under discussion could designate the ministry as risk authority and mandate a preparedness plan. On emissions, Albania’s 2021 Law on Climate Change set up GHG inventories and MRV (monitoring/reporting) systems, and a new climate law (expected 2025) will refine MRVA obligations. However, Albania has no 2050 neutrality strategy yet – a critical missing piece. The Energy Community Secretariat notes this as an opportunity: the new climate law is a chance to embed a 2050 net-zero goal aligned with regional climate neutrality. Similarly, the EU’s new targets (at least –55% GHG by 2030 vs 1990) should be written into law; Albania’s NECP-included target of –53.2% by 2030 has yet to be codified.

Installed Renewable Energy Capacity by Type (MW, 2024) – large hydro vs small hydro vs solar

On renewables and energy, many EU directives are in place but not fully enforced. The transposition of RED II’s sustainability criteria for bioenergy remains incomplete (secondary rules are pending). The Energy Efficiency Directive’s Article 5/7 energy savings obligations are being revised (a new Energy Efficiency Law is expected in 2025). ERE, the energy regulator, is largely independent and well-funded (through fees), but it needs more capacity in market integration and surveillance. The Competition Authority and audit agencies are updating rules: notably, Albania’s competition law still lacks a ban on anti-competitive decisions by associations, a gap being addressed.

Challenges and Investment Opportunities

Challenges for Albania’s energy sector are many. The system is highly hydro-dependent, making it vulnerable to droughts (although the report does not quantify this risk, it is implicit). Hydropower output can swing year-to-year; in dry seasons Albania may import costly thermal power. The wholesale market is still tightly regulated: KESH’s PSO obligation and the tariff freeze for households suppress price signals. With only ~12% of demand traded on the exchange, liquidity and competition are low. Energy poverty is acute – in 2023, 34.8% of households fell behind on utility bills – and subsidies for low-income consumers cost the state ~€14.2 million per year (for under-300 kWh relief). Distribution losses remain high (the report’s chart shows ~27% of primary energy lost in losses and transformation). Regulatory delays (EIP, RED II, TEN-E) also pose risks: without quick reforms, Albania could be left out of key EU market frameworks. Finally, the lack of domestic fossil fuel resources (all oil is imported) means geopolitics still loom large.

Yet opportunities abound for investors. Albania’s grid needs modernization: the 400 kV ring and new interconnectors will unlock capacity and relieve bottlenecks. The Western Balkans Investment Framework (WBIF) and EU funds stand ready to de-risk these projects. On renewables, Albania has proven technology potential. Small hydropower already leads capacity, but solar PV has room to grow – rooftop solar in particular is financially attractive given high sunshine hours and net-billing rules. The successful launch of auctions means new wind and solar projects can seek investors. Albania also has significant wind potential along its Adriatic coast and offshore (noted by developers, though not yet realized).

In gas, early movers will find unique first-mover advantage. The imminent TAP exit point and new Korça pipeline will create an Albanian gas market where none exists. Gas-fired power plants (modern CCGTs) could then enter the mix to complement variable renewables and stabilize supply – currently discussions are underway for a planned new gas power plant (with a 2023 EIA completed). Domestic industries (steel, chemicals, cement) will benefit from cheaper and cleaner gas fuel.

The drive toward European integration is another driver. Albania’s commitment to join the EU means it can tap structural funds and grants (as the 400 kV and efficiency projects already do) to lower investment risk. The Regional Electricity Market (REM) in Southeast Europe is expanding; full day-ahead coupling with North Macedonia, Greece, and others is slated for the coming years through the IBWT process. Albanian power can thus access wider markets (raising price realization for producers). New balancing and reserve-sharing arrangements in the synchronous continental Europe grid could also enhance system stability.

Outlook (2025–2035)

Looking ahead 5–10 years, Albania’s energy transition will be shaped by how quickly reforms and investments are realized. If the EIP is transposed and markets liberalized, Albania could see a virtuous cycle: more foreign investment, deeper regional trading, and faster renewables rollout. The TAP exit (online ~2027) will mark a milestone – enabling real gasification of the economy and likely powering a switch away from oil in power and transport. The 400 kV grid projects (current timeline by 2030) will significantly improve domestic reliability and export capacity.

However, several risks remain. Climate variability poses growing uncertainty: reduced rainfall could lower hydropower generation, necessitating backup thermal plants or imports during dry spells. Delays in drafting the 2050 climate-neutrality strategy or failing to meet Energy Community targets could hinder access to green financing. Continued energy poverty and fiscal pressure from subsidies could constrain budgets for infrastructure. Geopolitical shocks (e.g. regional supply disruptions or price spikes) remain possible, underscoring the need for energy diversification.

On balance, Albania’s prospects are positive: an increasingly competitive energy mix is emerging. By 2030 Albania could comfortably meet its 54% renewables share and even push beyond with new solar and pumped hydro. Improved interconnections and market coupling will integrate Albania into the European grid both technically and economically. Enhanced efficiency in buildings and industry will moderate demand growth (the country’s 2030 NECP actually foresees higher consumption targets than today). This combination – rising renewables and efficiency gains – will bolster Albania’s sustainability, reduce emissions, and hedge fossil-fuel price risks.

In conclusion, the 2025 Energy Community Country Report highlights a period of transition for Albania: from a historically state-dominated, hydro-driven system towards a more liberalized, diversified, and EU-aligned energy economy. Achieving this vision will require sustained reform and investment. The payoff – in terms of economic competitiveness, cleaner air, and greater energy security – promises to be substantial for Albania and its regional partners.

Sources: Energy Community Secretariat, Albania – Annual Implementation Report, Nov. 2025