Local flexibility markets: Mechanisms, benefits and regulatory challenges

Overview

Local flexibility markets for electricity represent an evolving concept within the energy infrastructure sector, currently in the stage of development. These markets are designed to enable distributed energy resources (DERs) to provide flexibility in electricity demand or production and feed-in for the system operator or another counterparty at a local level. This mechanism allows for more efficient management of local grid conditions by leveraging the granular capabilities of dispersed energy assets.

Purpose and Market Designs

The primary purpose of local flexibility markets is to address the widespread issue of grid congestion and to enhance fairness in energy distribution. As there are different purposes for the use of this flexibility, there exists a variety of different market designs. These designs comprise different actors and role models, reflecting the diverse needs and characteristics of local energy systems. Several local market models aim to efficiently tackle the challenges posed by grid congestion, ensuring that the integration of distributed resources is both effective and equitable.

The development of these markets is critical for the modernization of electricity systems, particularly in regions like Germany (DE), where the operational status is currently under construction. By enabling DERs to participate actively in local flexibility markets, system operators can better balance supply and demand, reduce the need for extensive grid reinforcements, and improve overall system reliability. The variety of market designs ensures that different stakeholders can find suitable models that align with their specific operational and strategic goals.

Background: Grid congestion and the cost of feed-in management

Local flexibility markets emerge primarily as a response to structural grid congestion, a phenomenon particularly acute in Northern Germany. The region has experienced a rapid expansion of renewable energy sources, notably wind power, which has often outpaced the physical expansion of the transmission grid. This mismatch between generation capacity and grid infrastructure leads to significant bottlenecks, requiring system operators to implement various management strategies to maintain balance and fairness in the electricity system.

Feed-in management and system redispatch

When grid lines reach their thermal limits, system operators utilize feed-in management to curtail the output of generators. This often involves paying renewable producers to reduce their feed-in, effectively turning on the tap less fully. Another critical tool is system redispatch, where generation is shifted between different nodes to relieve pressure on congested lines. These mechanisms ensure that the electricity demand and production remain balanced locally, even when the broader grid structure is under stress.

The economic implications of these measures are substantial. The costs associated with managing this flexibility have risen sharply as renewable penetration increases. In 2016, the costs for feed-in management and redispatch reached €373 million. The following year, in 2017, these costs escalated to €550 million. Projections indicate that without efficient local market mechanisms, these costs could surge to approximately €5 billion by 2025. This financial pressure highlights the need for diverse market designs that can efficiently allocate flexibility resources among different actors.

These costs reflect the premium paid for flexibility when the grid is not fully optimized. Local flexibility markets aim to reduce these expenses by enabling distributed energy resources to offer their flexibility directly to system operators or other counterparties at a local level. By doing so, they seek to tackle the widespread issue of grid congestion more efficiently, ensuring that the economic burden of integration is fairly distributed among all market participants.

How do local flexibility markets work?

The EU H2020 Smartnet project developed a technical market model for local flexibility, designed to enable distributed energy resources to provide demand or production flexibility to system operators at a local level. This model addresses grid congestion and fairness by structuring interactions between key actors: the System Operator, Market Operator, Flexible Resource Owner, and Aggregator.

Key Roles in the Smartnet Model

In this design, the System Operator identifies local grid constraints and issues a call for flexibility. The Market Operator facilitates the auction or bidding process where Aggregators or direct Resource Owners submit offers. The flexibility provided can be quantified as a change in power P over a time interval Δt, resulting in an energy volume E=P×Δt. The market clears based on price or technical merit, allowing the System Operator to procure the most efficient flexibility to alleviate congestion. This structure ensures that distributed resources can monetize their flexibility, while the grid operator maintains reliability without immediate infrastructure upgrades. The Smartnet model emphasizes clear role separation to reduce transaction costs and enhance market liquidity, supporting the integration of variable renewables and decentralized generation.

What are the benefits of local flexibility markets?

Local flexibility markets deliver significant financial advantages for system operators, particularly within the regulatory framework of the Clean Energy Package. By enabling distributed energy resources to provide flexibility in electricity demand or production, these markets allow operators to manage local grid conditions more efficiently. This mechanism helps address widespread grid congestion issues, reducing the need for immediate, capital-intensive infrastructure upgrades. System operators can procure flexibility services from various actors, optimizing their operational costs while maintaining grid stability. The variety of market designs supports different role models, ensuring that operators can select the most cost-effective solutions for their specific network constraints.

Benefits for Flexibility Providers

For flexibility providers, these markets offer a new revenue stream through the remuneration of location-specific flexibility. Distributed energy resources, such as solar panels, wind turbines, and battery storage systems, can sell their ability to adjust output or demand based on local grid needs. This location-specific valuation ensures that providers are compensated not just for the energy they produce or consume, but for the timing and place of their contribution. This approach enhances the economic viability of distributed energy resources, encouraging greater participation from households, businesses, and small-scale generators. Providers can optimize their assets by responding to price signals that reflect local grid conditions, thereby maximizing their returns.

Macro-Economic and Grid Extension Benefits

On a macro-economic level, local flexibility markets contribute to reduced grid extension costs, which are estimated to reach €50bn by 2030. By leveraging existing distributed resources, the need for extensive new transmission and distribution lines is diminished. This cost saving is substantial, benefiting both consumers and investors. Additionally, these markets facilitate more accurate nodal pricing, which reflects the true value of electricity at different points in the grid. Accurate nodal pricing helps in better resource allocation and investment decisions, further enhancing the efficiency of the electricity system. The combination of reduced infrastructure costs and improved pricing mechanisms supports a more sustainable and economically resilient energy transition.

What are the drawbacks and challenges?

Local flexibility markets face significant implementation hurdles, primarily stemming from the heterogeneous nature of grid infrastructure and the complexity of regulatory frameworks. A central challenge is the need to adapt market designs to specific regional circumstances. Grid congestion patterns vary drastically between urban distribution networks and rural transmission lines, meaning a one-size-fits-all approach often fails to address local fairness and efficiency goals. Different actors and role models must be integrated into these varied designs, complicating standardization efforts across broader energy systems.

Pricing Mechanisms: Nodal vs. Zonal

The debate between nodal and zonal pricing remains a critical technical and economic consideration in market design. Nodal pricing, which assigns specific prices to individual nodes on the grid, offers high granularity and precision in reflecting local congestion costs. However, this level of detail can introduce significant complexity for distributed energy resources and smaller market participants. In contrast, zonal pricing aggregates nodes into broader regions, simplifying the market structure but potentially obscuring localized price signals. The choice between these models impacts how effectively flexibility is procured and how costs are allocated among system operators and end-users. This trade-off between precision and simplicity is central to determining the efficiency of local markets.

Regulatory Hurdles and Incentive Structures

Current regulatory frameworks often lag behind the technical capabilities of distributed energy resources, creating substantial barriers to market entry. A primary issue is the lack of clear incentives for system operators to actively engage in local flexibility markets. Under many existing laws, system operators may not fully capture the economic benefits of procuring local flexibility, leading to potential underinvestment or conservative procurement strategies. These regulatory gaps can result in suboptimal utilization of available resources, such as battery storage or demand response, thereby reducing the overall efficiency of the grid. Addressing these incentive misalignments requires coordinated policy updates that clearly define the roles and rewards for all market participants.

Regulatory framework and policy changes

Local flexibility markets in Germany operate within a layered regulatory architecture, anchored by European Union directives and implemented through specific national statutes. The primary EU-level driver is the Clean Energy Package 4 (CEP 4), which entered into force in 2020. This legislative framework established the foundational rules for integrating distributed energy resources into the broader electricity system, mandating mechanisms for local flexibility to address grid congestion and enhance system efficiency.

National Legislative Implementation

Germany has transposed these EU-level requirements and established domestic rules through three key pieces of legislation. The Energiewirtschaftsgesetz (Energy Industry Law) serves as the overarching statutory framework for the energy sector, defining the roles of market actors and the structural organization of the grid. Complementing this, the Anreizregulierungsgesetz (Incentive Regulation Act) specifically addresses the remuneration of grid operators, creating financial incentives for them to procure local flexibility services to manage capacity constraints. Furthermore, the Strommarktgesetz (Electricity Market Law) details the operational mechanisms of the electricity market, including the specific procedures for local flexibility trading and the interaction between distribution system operators and flexibility providers.

These legal instruments collectively enable distributed energy resources to provide flexibility in electricity demand or production for system operators or other counterparties at a local level. The regulatory design aims to tackle widespread grid congestion and ensure fairness among market participants, supporting the ongoing development of these markets which remain in the stage of development.

Current research projects and pilots

Research into local flexibility markets is actively advancing through various European and national initiatives. At the European level, the CoordiNet project operated until 2022, contributing to the development of market designs that address grid congestion and fairness. These efforts aim to enable distributed energy resources to provide flexibility in electricity demand or production for system operators and other counterparties at a local level.

German National Pilots

In Germany, the SINTEG program has facilitated several national projects. One notable initiative involves enera, which collaborates with key industry players including EWE Netz, Avacon Netz, TenneT, and EPEX SPOT. These partnerships explore different actors and role models within local market designs to efficiently tackle widespread grid issues. The involvement of major network operators and spot exchanges highlights the integration of technical infrastructure with market mechanisms.

Swedish Initiatives

Sweden has also contributed to the field through pilots such as sthlmflex. These projects test practical applications of local flexibility markets, providing insights into how distributed resources can manage local grid constraints. The diversity of approaches across different countries reflects the variety of market designs emerging to suit specific regional needs and grid characteristics.

See also

• Bergkamen Power Station: Coal-Fired Generation and District Heating in Germany
• Gundremmingen Nuclear Power Plant: Technical Profile and Decommissioning
• Chemnitz Nord: Combined Heat and Power Station Profile
• Siemens Energy: Corporate Structure, Wind Turbine Crisis and Market Recovery
• Walsum Power Plant: Technical Profile and Operational Context