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.
