The Council of European Energy Regulators (CEER) has published its annual report, “Regulatory Frameworks for European Energy Networks 2025.” This CEER report provides a comprehensive overview of the regulatory regimes for electricity and gas networks at transmission (TSO) and distribution (DSO) level and an important basis for assessing investment conditions, regulatory expectations and emerging trends in European energy markets.
It provides general information on the regulatory systems for electricity and gas networks in EU Member States, Northern Ireland, Norway, the United Kingdom, Iceland, and the five Energy Community Regulatory Boards (ECRB). It analyses how these frameworks support the efficient functioning and investment in networks, looking at key elements such as rate of return (RoR) methodologies, regulatory asset base (RAB) determination, asset depreciation and investment incentive mechanisms.
Key findings include:
- Regulatory approaches vary across countries, but many of the tools and principles are common.
- Incentive-based regulation continues to be widely applied, often combining revenue or price caps with a guaranteed RoR.
- WACC is the most commonly used approach for determining RoR, with differences between electricity and gas networks.
- Long-lived assets are consistently included in RAB, with working capital increasingly taken into account depending on national frameworks.
- Straight-line depreciation remains the predominant method for calculating depreciation, with the useful life of assets typically ranging from 20 to 50 years.
- Incentives for smart grids, smart metering, and distributed renewable energy generation are more prevalent in electricity networks, particularly at the distribution system operator (DSO) level.
Although regulatory frameworks differ across jurisdictions, the report finds a high degree of similarity in the use of incentive-based regulation. Electricity networks (particularly DSOs) continue to be subject to broader incentive mechanisms than gas networks. Regulators are increasingly considering adjustments to existing frameworks to reflect technological advances, changing investment needs, and changes in market conditions.
The report is accompanied by:
– compiled and completed tables (Annex 4);
– twelve in-depth national case studies (Annex 5); and
– a general case study (Annex 6) illustrating how different regulatory instruments affect allowed revenues in a hypothetical scenario.
Bulgaria participated for the first time by providing data for the study, although it did not contribute to the general part of the report.
Among the main highlights…
Regulatory systems and methodologies
Across Europe, incentive-based revenue regulation has become the predominant model for network regulation. More than half of the countries surveyed apply revenue cap regulation for both electricity and gas networks at the transmission and distribution levels. Pure cost-plus regimes survive only as transitional measures in exceptional cases in a few jurisdictions.
The typical regulatory period for CEER members ranges from four to five years, regardless of the type of network or energy sector. This standardisation provides stability and predictability for network operators, while giving regulators sufficient time to introduce efficiency improvements and monitor results. The regulatory framework typically sets revenue caps, including uncontrollable and controllable costs, depreciation, return on assets, and various efficiency indicators designed to simulate competitive market pressure.
CEER has documented significant differences in the choice of regulatory model for electricity distribution networks, which have a direct impact on the bankability of DSOs’ investments, particularly in countries with accelerated electrification programs including treatment of inflation and indexation; use of benchmarking and performance factors; timing of capital cost recognition; degree of ex ante versus ex post adjustment, etc.
Efficiency requirements and benchmarking
Efficiency requirements are at the heart of modern regulation. Around 50% of countries apply X-factors for operating expenses (OPEX), with this percentage reaching 79% for electricity distribution system operators. However, efficiency requirements for capital expenditures (CAPEX) are less common, with only about 20% of respondents applying them to electricity operators and about 10% to gas operators.
The benchmarking methodologies used vary significantly across jurisdictions. CEER documents the widespread use of data-driven comparative efficiency analysis (DEA) and econometric methods (e.g., MOLS), which are sometimes combined in composite efficiency assessments. These assessments are having an increasing impact not only on operating expenses (OPEX) but also on the allowable return on capital expenditures (CAPEX). Germany, for example, uses a complex “best of four” approach that combines DEA and stochastic parametric frontier analysis (SFA) with standardized and non-standardized total cost indicators (TOTEX). Austria uses a combination of 50% DEA and 50% modified MOLS, while Norway uses TOTEX as the sole input into DEA models to minimize costs with constant returns to scale.
Calculating the rate of return
The weighted average cost of capital (WACC) methodology dominates the calculation of the rate of return across Europe. Around 50% of national regulatory authorities (NRAs) use nominal pre-tax WACC, while 25% use real pre-tax WACC. The remaining jurisdictions are divided between after-tax approaches and standard WACC. Some countries, such as Belgium, use alternative methodologies that ensure a return on the equity-financed parts of the regulatory asset base.
Risk-free interest rates are mainly assessed on the basis of government bond interest rates, typically using 10-year bonds, although the duration varies. Most NRAs apply historical averages ranging from one to ten years. The average nominal risk-free interest rate among CEER members is 2.33%, ranging from 0.0% to 6.84%. However, these values fluctuate significantly depending on the timing of the assessment and market conditions.
The Capital Asset Pricing Model (CAPM) is widely used to determine the cost of equity, using the following formula: Cost of equity = Risk-free interest rate + β × Market risk premium. Market risk premiums among CEER members range from 3.5% to 8.0%. These values are typically derived from expert analyses, including the widely cited reports by Dimson, Marsh, and Staunton, as well as the Damodaran database.
For DSOs in the electricity sector, regulators are increasingly distinguishing between “old” RABs, which are often remunerated at historically determined or fixed WACC values, and “new” investments, where the WACC is updated more frequently to reflect current capital market conditions. Austria is an example of this dual WACC approach, where the return on new investments is updated annually and the remuneration for old assets is fixed.
Despite methodological similarities, the effective risk borne by DSOs may differ significantly in practice across jurisdictions. In some places, volume risk is largely neutralised through regulatory accounts and ex post adjustments. In others, DSOs remain fully exposed to demand fluctuations, especially where electricity supply is uneven. The CERA therefore notes that the underlying rates of return on investment are not comparable across countries without taking these built-in risk-sharing mechanisms into account.
Components and assessment of the regulatory asset base (RAB)
The regulatory asset base (RAB) serves as the basis for calculating the allowable return on investment. Fixed assets are included in RAB calculations in all countries studied, representing the most significant component in terms of balance sheet value. However, there are significant differences in terms of other components.
Working capital is included in the RAB by only 30-40% of regulators, with the majority excluding it from the calculations. Assets under construction are included by less than half of the regulatory authorities in gas and electricity distribution, while the inclusion rate is higher for electricity transmission.
Contributions from third parties, including connection fees, EU grants, and funding from public institutions, are almost universally deducted from RAB through “cap” practices. This approach reflects the principle that assets not financed by regulated entities should not generate a regulated return. Leased assets are included by 40-50% of CEER members, with their treatment often depending on whether they are classified as operating expenses under national accounting standards.
RAB remains the main signal for investment and DSO in the electricity sector. In different jurisdictions, RAB typically includes tangible fixed assets and assets under construction, and in some cases current assets, less frequently intangible assets. RAB valuation methodologies vary significantly across Europe. Around 30-40% of countries base RAB exclusively on historical costs, with some using indexed values to account for inflation. The revaluation approach is used by 13-25% of countries, typically using a fully or partially revalued asset base. Several jurisdictions, including Luxembourg, Finland, and Spain, use hybrid methodologies combining historical and revalued assets. These methodologies often distinguish between old and new investments with different commissioning dates. These choices have significant implications for capital recovery profiles and the distribution of costs across generations.
With regard to the treatment of new investments, a key trend identified in the report is the shift towards earlier recognition of capital costs, particularly among electricity distribution system operators facing the need for rapid expansion. Several national regulatory authorities have moved from purely recognising historical costs t-2 to pre-approving investment plans with mechanisms for reconciling the plan with actual results and interim updates of the RAB during the regulatory period.
CEER tacitly acknowledges that delayed recognition of capital costs is incompatible with accelerated investment requirements in the electricity network, although it does not recommend a unified model.
Depreciation practices
Depreciation policy favors stability over innovation and shows much less regulatory experimentation than RoR or RAB treatment.
Straight-line depreciation remains the standard approach in almost all jurisdictions, with the life cycle of assets generally in line with technical standards for the relevant networks. Germany is a notable exception, having introduced accelerated depreciation options (with rates of 8–12%) to cope with the expected decommissioning of gas networks by 2045. The life of assets typically ranges from 20 to 50 years, with most regulators applying different depreciation rates for different asset categories.
Several countries have begun to adjust their depreciation practices in response to the challenges posed by the energy transition. For example, Belgium now depreciates certain new gas transmission assets so that they reach zero value by 2050, while France has reduced the useful life of new gas pipelines from 50 to 30 years. These adjustments reflect growing concerns about stranded assets in the context of Europe’s transition away from fossil fuels.
Although depreciation is generally considered a transferable expense, the CEER recognizes that its interaction with inflation and RAB growth can have a significant impact on cash flows, especially in high inflation environments. Some regulators have introduced indexation roll-ups to mitigate the effects of time lag, but this remains uneven.
Quality incentives and regulation
The report documents the widespread use of incentive mechanisms that go beyond basic performance requirements. In particular, incentives for supply quality are widespread in electricity distribution, with many countries applying bonus/malus systems based on reliability indicators such as the System Average Interruption Duration Index (SAIDI) and the system average interruption frequency index (SAIFI).
Investment incentives are also becoming more prominent, particularly to facilitate the integration of renewable energy, the deployment of smart grids, and the development of electric vehicle charging infrastructure. For example, Austria provides WACC premiums of up to 2% for innovative investments in system automation, digitalisation, renewable energy connections and electricity storage facilities. Similar mechanisms exist in Slovakia and several other jurisdictions.
Incentives for innovation are becoming increasingly widespread, with countries such as Finland, France, and Sweden allocating special budgets (typically 0.5–1% of total revenues) for research and development. These mechanisms aim to encourage technological progress and adaptation to the changing requirements of the energy system.
Response to the energy crisis and market transformation
The report documents in detail the regulatory responses to recent energy market shocks and the ongoing energy transformation. Many countries have adjusted their weighted average cost of capital (WACC) calculations to reflect changed financial market conditions, with several applying separate tariffs for old and new investments to balance consumer protection with investment incentives.
The gas sector faces particular challenges as consumption patterns change and hydrogen infrastructure development begins. In Germany, gas transmission network operators are required to develop plans to convert natural gas networks to hydrogen by 2045, and distribution network operators must develop heating strategies to phase out natural gas. Denmark is encouraging households to switch from gas heating to electric heat pumps by covering the costs of disconnecting from the gas grid through state funding.
Several countries have introduced mechanisms to mitigate the impact of demand fluctuations. For example, Hungary has changed its methodology for allowable revenues to allow for faster reflection of changes in energy prices, and Latvia has increased flexibility through more frequent regulatory account revaluations. Austria has allocated research and innovation budgets to gas distribution network operators to explore options for transforming networks, including the integration of renewable gases and hydrogen.
Quality and security of supply
Quality regulation has evolved significantly, with most countries implementing sophisticated frameworks for measuring performance. The Norwegian framework for costs of energy not supplied (CENS) is a sophisticated approach that quantifies the socio-economic costs of outages, creating strong incentives to maintain reliability without prescriptive requirements.
Meanwhile, the Luxembourg framework assesses the quality of information provided to regulators, with the impact ranging from -0.25% to 0.5% of return on capital. This approach recognizes that the effectiveness of regulation depends on the quality and transparency of data, incentivizing operators to maintain reliable reporting systems.
Emerging trends
The report identifies several critical trends shaping the evolution of regulation. Flexibility services and demand response mechanisms are attracting the attention of regulators, with countries such as Sweden introducing specific incentive schemes. The integration of distributed energy resources, energy storage, and electric vehicle charging infrastructure requires new regulatory approaches that balance innovation with consumer protection.
Digitalisation and cybersecurity are emerging as priority areas, with several countries developing specific regulatory frameworks. The roll-out of smart meters continues across Europe, although approaches to cost allocation, deployment schedules and data management responsibilities vary significantly.
Cross-border coordination is strengthening, particularly among transmission system operators. Investments in interconnections receive specific regulatory support in many countries, recognising the importance of integrated European energy markets for efficiency and security of supply.
With regard to electricity distribution companies, the report clearly shows that regulatory models are still under pressure and are catching up. DSOs are expected to ensure rapid network expansion, digitalisation, increased resilience and rapid integration of distributed energy resources. However, regulatory frameworks still reflect the traditional assumption of gradual and predictable investment growth. Where regulators have modernized the treatment of capital costs and the updating of returns on investment, investment signals appear to be stronger.
From a European integration perspective, CEER findings point to continued fragmentation in the regulation of electricity distribution system operators. Although there is formal convergence at the conceptual level (WACC, RAB, incentives), differences in implementation remain significant, complicating cross-border comparative assessment and potentially disrupting investment flows.
The report highlights the dynamic nature of energy regulation, which must adapt ever more rapidly to unprecedented challenges such as climate change mitigation, energy security concerns, technological transformation, and the need for significant infrastructure investment. Regulatory frameworks are becoming increasingly complex, incorporating multiple incentive mechanisms aimed at different policy objectives, while maintaining the core objective of protecting consumer interests by ensuring efficient and reliable energy network services.
