Europe’s Grid Modernisation Challenge: How Smart Metering Improves Distribution Visibility

Introduction: Grid Expansion Takes Time, Visibility Cannot Wait

Europe is accelerating the modernisation and expansion of its energy infrastructure.

On 26 June 2026, the Council of the European Union agreed its negotiating position on the European Grids Package. The package addresses cross-border infrastructure planning, permitting, network resilience and measures intended to reduce congestion.

The Council position forms part of the EU legislative process and should not be treated as the final adopted legislation.

Europe is also continuing to expand physical interconnection capacity. On 2 July 2026, a new Spain–Portugal electricity interconnection was inaugurated and commissioned, adding 1,000 MW of cross-border capacity between northern Portugal and Galicia in north-western Spain.

However, new transmission lines, substations, transformers and feeders can take years to plan, permit and construct. During that period, Distribution System Operators (DSOs) still need better information about how existing networks are being used.

This creates an important question:

What can smart meters, feeder telemetry and behind-the-meter sub-metering each reveal about distribution-grid conditions?

Smart metering does not create physical network capacity. It provides data that can support planning, operations and customer-side energy management.

1. Why Europe’s Distribution Grids Need Better Visibility

European distribution networks are being affected by several changes at the same time:

• Distributed solar generation
• Electric-vehicle charging
• Heat pumps
• Commercial and industrial electrification
• Battery energy storage
• Bidirectional electricity flows
• New large electrical loads
• Connection queues
• Local network constraints

A national electricity system may have sufficient generation while a specific transformer or feeder is approaching its thermal or voltage limits, or while the local network faces protection-related constraints.

Grid congestion may therefore occur locally even when the wider power system has adequate generation.

Better distribution visibility can help answer practical questions:

• Which transformers experience the highest utilisation?
• When do local peaks occur?
• Where is customer export increasing?
• Which feeders have phase imbalance?
• Where are voltage conditions becoming more difficult to manage?
• Which areas may require reinforcement?
• Where is additional monitoring needed before new connections are approved?

2. Transmission Expansion Is Not the Same as Distribution Visibility

Transmission expansion and distribution visibility solve different problems.

The European Grids Package is intended to improve infrastructure planning and delivery. These measures are important, but they do not automatically provide a DSO with detailed visibility into every low- or medium-voltage network.

Distribution visibility requires a separate measurement, communications and data-governance architecture.

3. The Three Layers of Distribution-Grid Visibility

A practical visibility architecture can be divided into three layers.

Layer 1: AMI and Customer-Boundary Visibility

Advanced Metering Infrastructure (AMI) and customer-boundary smart meters may provide:

• Interval energy consumption
• Demand patterns
• Import and export energy
• Outage or communication indications where supported
• Customer-level load trends
• Aggregated neighbourhood demand
• Customer-level export that may contribute to reverse power flow on the local network

Customer export does not automatically prove reverse power flow at the feeder or transformer boundary. Other customers may absorb the exported energy before it reaches the upstream network asset.

Network-level reverse power flow should therefore be confirmed through measurements at the relevant transformer or feeder boundary.

Layer 2: Transformer and Feeder Telemetry

Network-level measurements may provide:

• Transformer loading
• Feeder loading
• Local peak demand
• Voltage conditions
• Phase imbalance
• Reverse power flow
• Power factor
• Congestion indicators
• Measurement inputs for connection- and hosting-capacity assessment

Hosting capacity refers to the amount of additional generation, storage or load that a network area may accommodate without violating defined technical limits or requiring specified reinforcement.

This layer shows how aggregated customer behaviour affects shared network assets.

Layer 3: Behind-the-Meter Sub-Metering

Commercial and industrial sub-metering may separate:

• PV generation
• Battery charging and discharging
• EV charging
• HVAC
• Production equipment
• Tenant loads
• Critical circuits
• Flexible loads

This layer explains what is happening inside the customer site.

AMI provides customer-boundary visibility, feeder telemetry provides network visibility, and sub-metering provides asset-level visibility.

No single layer replaces the other two.

4. What AMI Data Can Tell a DSO

Depending on the selected meter functions, communications architecture, Head-End System configuration, Meter Data Management configuration and regulatory framework, smart-meter and AMI data may support:

• Customer load profiling
• Peak-demand analysis
• Import and export monitoring
• Outage detection where supported
• Consumption forecasting
• Aggregated demand analysis
• Identification of areas with increasing distributed generation
• Investigation of persistent voltage concerns where suitable measurements are available

AMI data only becomes useful for transformer- or feeder-level analysis when metering points are correctly mapped to the relevant network assets and, where required, to the correct electrical phase.

The DSO may need to maintain associations between:

• Customer meter
• Service connection
• Low-voltage feeder
• Distribution transformer
• Medium-voltage feeder
• Electrical phase
• Network area

Outdated topology records, customer transfers, phase-mapping errors or inconsistent timestamps can distort aggregated loading, phase-balance and reverse-flow analysis.

AMI data should not automatically be treated as continuous real-time telemetry. Capabilities depend on:

• Meter measurement functions
• Internal refresh rate
• Stored interval length
• Communications latency
• Event-reporting capability
• HES and MDM configuration
• Data-validation status

Near-real-time meter data may be unvalidated and should be distinguished from validated historical, billing or settlement data.

5. What AMI Cannot Tell a DSO

Customer-boundary data has important limitations.

A smart meter normally cannot independently identify:

• Which internal circuit caused a peak
• Whether an EV charger, heat pump or industrial machine was operating
• The exact contribution of PV or BESS behind a shared connection
• Transformer internal condition
• Instantaneous feeder loading at another network point
• Protection actions
• High-speed disturbances
• Harmonic or transient behaviour beyond supported functions

A site may show low net import because PV output is high, a battery is discharging or underlying demand has fallen. The customer-boundary meter alone may not distinguish those causes.

Smart-meter data improves visibility, but it does not replace feeder sensors, protection devices, SCADA or power-quality instruments.

6. Why Feeder and Transformer Metering Matter

Transformer and feeder measurements connect customer data with physical network conditions.

Depending on the architecture, relevant measurements may include:

• Three-phase voltage and current
• Active and reactive power
• Import and reverse-flow energy
• Transformer or feeder demand
• Phase imbalance
• Power factor
• Frequency
• Maximum demand
• Loading trends

This information can support:

• Transformer-utilisation analysis
• Local peak identification
• Feeder-capacity planning
• Connection assessments
• Phase-balancing studies
• Reverse-flow monitoring
• Targeted reinforcement
• Investigation of recurring overloads or voltage concerns

Transformer and feeder telemetry can provide operational inputs for connection- and hosting-capacity assessments.

However, metering data alone does not determine final hosting capacity.

A formal assessment may also depend on:

• Network topology
• Conductor and transformer thermal limits
• Voltage criteria
• Protection requirements
• Fault-current levels
• Diversity and coincidence assumptions
• Operating scenarios
• Reliability conditions
• The DSO’s approved planning methodology

Capacitypedia, launched by ENTSO-E and the EU DSO Entity, helps users find publicly available hosting-capacity information from participating network operators. It does not independently calculate, certify or harmonise the hosting capacity of every network area.

7. Why Behind-the-Meter Sub-Metering Is Still Needed

A utility meter records the net exchange at the customer boundary. It does not normally explain how that net value was created.

A commercial or industrial site may combine:

• Production load
• Cooling
• PV generation
• BESS operation
• EV charging
• Tenant demand
• Office equipment
• Flexible or interruptible circuits

Behind-the-meter sub-metering may support:

• Internal energy management
• Cost allocation
• Equipment-level benchmarking
• Peak-load management
• PV and storage monitoring
• EV-charging analysis
• Tenant billing where legally and technically permitted
• Site EMS integration

Customer sub-meters do not automatically become utility revenue or settlement meters. Meter role, legal-metrology requirements, accuracy class, certification and contractual acceptance must be confirmed for the intended use.

Data Access, Privacy and Cybersecurity

Behind-the-meter data is not automatically available to the DSO or other external platforms.

Access may depend on:

• Applicable legal basis and regulatory mandate
• Customer authorisation where required
• Contractual arrangements
• National data-management rules
• The intended purpose of the data use

Projects should define:

• Data-governance responsibilities and access rights
• Data-controller and data-processor roles where personal data is involved
• Authorised users
• Permitted purposes
• Data granularity
• Retention period
• Anonymisation or aggregation requirements
• Cybersecurity controls
• Authentication and access management
• Data-sharing and revocation procedures

Higher-resolution data can reveal customer behaviour, occupancy patterns, production schedules and equipment operation. Data access should therefore be proportionate to the stated purpose and based on an applicable lawful basis.

8. Interval Data, Telemetry, Billing Data, Settlement Data and Event Data

Different data types serve different purposes.

These categories should not be mixed.

A gateway polling a meter every second does not necessarily mean the meter refreshes all values every second. Similarly, a value available through Modbus is not automatically suitable for billing or settlement.

Projects should distinguish:

• Internal measurement refresh rate
• Gateway polling interval
• Stored interval length
• Transmission latency
• Platform-processing delay
• Timestamp source
• Missing-data treatment
• Validation status
• Intended data use

9. Reverse Power Flow from PV, BESS and EV Infrastructure

Distribution networks were historically designed mainly for one-way electricity flow from the grid toward customers.

That pattern is changing.

Distributed PV may export energy into the local network. A BESS may alternate between charging and discharging. EV-charging clusters may create sharp local demand increases, while bidirectional EV systems may also introduce export.

These resources can affect:

• Transformer loading
• Feeder peak timing
• Voltage conditions
• Reverse power flow
• Phase balance
• Local hosting capacity

Bidirectional metering can show the direction and quantity of energy crossing a defined customer or asset boundary.

It does not, by itself, identify which internal asset caused every change or prove that reverse flow reached an upstream transformer or feeder.

For that reason, distribution analysis may require a combination of:

• Customer-boundary meters
• Transformer measurements
• Feeder telemetry
• Site-level sub-metering
• Correct network-topology mapping

10. Roles of AMI, HES, MDM and Network Platforms

The same numerical value may appear in several systems, but each platform may use different:

• Measurement boundaries
• Intervals
• Scaling
• Validation rules
• Correction processes
• Timestamps
• Retention policies

A clear source-of-truth definition is therefore essential.

11. Can Smart Meters Solve Grid Congestion?

No. Smart meters do not create physical grid capacity.

They cannot replace:

• New transformers
• Larger conductors
• New feeders
• Substation upgrades
• Cross-border interconnections
• Protection-system changes

However, smart metering can support better decisions by helping utilities and customers:

• Improve load forecasting
• Identify local demand peaks
• Detect import and export trends
• Provide inputs to connection studies
• Locate areas requiring more monitoring
• Target flexibility programmes
• Improve customer communication
• Verify selected operational measures where the data is suitable

Smart meters are therefore an information layer within grid modernisation, not a substitute for engineering studies or network investment.

12. Metering Checklist for Distribution and C&I Projects

13. How YTL Can Support Initial Meter Evaluation

Zhejiang Yongtailong Electronic Co., Ltd. (YTL) can support the initial evaluation of selected smart meters, data concentrators, CT-operated meters, multifunction meters, DIN-rail meters, panel meters and communication-enabled metering products for distribution and commercial or industrial applications.

Depending on the selected model and project requirements, YTL can support:

• Initial meter-model selection
• Voltage and current-range review
• Direct-connected or CT-operated configuration discussion
• Import/export measurement review
• Parameter and interval requirement review
• RS485 and Modbus option confirmation
• Register-map, unit and scaling review
• Sample-level meter-to-gateway interface evaluation
• Initial discussion of customer-proposed meter-side interfaces and data requirements for AMI, EMS or data-concentrator integration

Data-concentrator suitability should be confirmed according to:

• Selected model
• Communication architecture
• Number of connected devices
• Polling requirements
• Buffering requirements
• Register-map configuration
• Upstream platform interface

Communication options, interval functions, protocol implementation, accuracy and certification scope must be confirmed according to the selected model, target market, meter role and project architecture.

YTL does not define:

• The utility’s network-topology model
• Hosting-capacity methodology
• Customer-data access rules
• Privacy or data-sharing policy
• HES or MDM architecture
• SCADA control strategy
• Legal-metrology acceptance
• Final system integration

These matters remain the responsibility of utilities, DSOs, engineering providers, platform suppliers, system integrators and relevant regulatory or contractual parties.

YTL supports the field-level electrical-measurement and data-output layer.

Conclusion

Europe needs new transmission lines, substations, feeders and transformers. Physical network investment remains essential.

At the same time, better visibility can help network operators and customers understand how existing assets are being used while larger grid projects are planned and delivered.

The three visibility layers serve different purposes:

1. AMI provides customer-boundary visibility.
2. Transformer and feeder telemetry provide network visibility.
3. Behind-the-meter sub-metering provides asset-level visibility.

For those layers to create useful insight, the data must also be:

• Correctly mapped to network topology
• Time-aligned
• Validated
• Reconciled across boundaries
• Accessed under clear governance rules
• Protected through appropriate cybersecurity controls

Europe’s grid modernisation will depend not only on building more infrastructure, but also on understanding how electricity moves through the distribution system from the feeder to the final asset.

Frequently Asked Questions

What is distribution-grid visibility?

Distribution-grid visibility is the ability to understand loading, voltage, power direction and capacity conditions across customer connections, transformers, feeders and other network assets.

What can AMI data show?

Depending on the system configuration, AMI can show customer-boundary interval consumption, import and export energy, demand trends and selected status information.

Is AMI the same as SCADA?

No. AMI supports customer-meter communications and data collection. SCADA and feeder telemetry generally support network operations and higher-frequency asset monitoring.

Does customer export prove reverse power flow on the feeder?

No. Customer export may be absorbed by nearby loads. Reverse flow should be confirmed at the relevant transformer or feeder boundary.

Can meter data determine hosting capacity?

Not by itself. Metering provides operational inputs, but hosting-capacity studies also depend on network models, thermal limits, voltage criteria, protection requirements and planning assumptions.

Can DSOs automatically access behind-the-meter data?

Not necessarily. Access requires an applicable legal basis and may also depend on customer authorisation, contracts, national rules and the intended use.

References

1. Council of the European Union, European Grids Package: Council Backs Modernised Energy Network for Decarbonisation, 26 June 2026.
2. European Commission, Energy Union: New Spain–Portugal Electricity Interconnection Inaugurated, 2 July 2026.
3. ENTSO-E, Managing Grid Congestion in the Energy Transition: Position Paper on Market Design Options, 10 June 2026.
4. EU DSO Entity and ENTSO-E, Capacitypedia Launched to Improve Access to Grid Hosting Capacity Information Across Europe, 22 May 2026.
5. Directive (EU) 2019/944, particularly Articles 19–24 and Annex II, concerning smart metering systems, near-real-time and validated data, cybersecurity, data protection, data management and interoperability.
6. Regulation (EU) 2016/679, General Data Protection Regulation, concerning lawful processing, purpose limitation, data minimisation, storage limitation, security and controller/processor responsibilities.