C&I monitoring refers to the systematic collection, storage, and visualization of energy and operational data at commercial and industrial sites. C&I stands for Commercial & Industrial. Its purpose is to provide transparency regarding energy flows, consumption patterns, and asset conditions without actively intervening in production processes or plant operation.

C&I Monitoring at a Glance

• C&I monitoring combines energy and operational data from different consumers, generators, and technical assets.
• Main meters and submeters allow energy consumption to be allocated to individual machines, production areas, buildings, cost centers, or sites.
• Dashboards, load profiles, energy balances, reports, and alerts provide a data basis for technical and economic analyses.
• Monitoring can reveal deviations and optimization potential but does not independently implement control measures.

How Does C&I Monitoring Work?

Meters, sensors, and plant control systems collect relevant values continuously, at defined intervals, or in response to specific events. These values can include active power, energy consumption, voltage, current, power factor, operating hours, temperatures, status information, and fault messages. The required data depends on the equipment, operational processes, and objectives of the monitoring project.

Typical monitored components include energy meters, machines, production lines, building systems, photovoltaic systems (PV), battery energy storage systems (BESS), charging infrastructure, heat pumps, and generators. In addition to electrical measurements, process and environmental data can be included if they are relevant to assessing energy use.

Depending on the device, data is provided via communication protocols such as Modbus TCP/RTU, MQTT, or M-Bus, through digital or analog signals, or via manufacturer-specific application programming interfaces (APIs). A local controller or gateway can collect and combine these different data sources.

The data can then be standardized, assigned clear device identifiers, and synchronized in time. Local buffering can limit data loss during an internet connection failure. If the system supports subsequent data transmission, the locally stored values can be transferred to the higher-level platform once the connection has been restored.

The processed information is subsequently available for dashboards, historical load profiles, energy balances, reports, and alerts. A suitable structure of main meters and submeters can, for example, reveal which production area causes a demand peak or how much energy is consumed outside regular operating hours.

Where Is C&I Monitoring Used?

C&I monitoring supports a range of operational tasks:

• Consumption analysis: Companies can examine baseloads, demand peaks, and time-dependent consumption patterns in individual areas.
• Allocation of energy costs: Measurements can be assigned to machines, buildings, cost centers, or different sites.
• Assessment of energy efficiency: Indicators such as energy use per unit of production enable comparisons between periods, production lines, or operating conditions.
• Technical operational monitoring: Status information, fault messages, and deviations from reference values can provide early indications of faults or unusual plant behavior.

Benefits, Limitations, and Technical Requirements

Continuous and structured data collection provides a reliable basis for energy audits, efficiency measures, investment decisions, and technical operations management. It can also reduce the manual effort required to compile consumption data and reveal previously unidentified energy use.

However, the value of monitoring depends directly on measurement and data quality. Measurement points must be positioned correctly and clearly assigned to the relevant consumers or assets. Synchronized timestamps, consistent sign conventions, and a transparent device and meter structure are also essential. Incorrectly installed current transformers, reversed current transformer directions, unsuitable measurement intervals, or data gaps can significantly distort load profiles and energy balances.

Monitoring alone does not reduce energy consumption. It identifies deviations and optimization potential but does not automatically initiate corrective measures. Meaningful efficiency comparisons must account for influencing factors such as production volumes, utilization, operating hours, or outdoor temperature. The compared datasets also require consistent system boundaries and suitable measurement intervals.

Data protection, IT security, and network architecture must also be considered in industrial projects. In particular, the separation of corporate, production, and plant networks, as well as controlled external data access, must be planned according to the requirements of the individual project.

C&I Monitoring with EcoPhi

EcoPhi can locally collect, standardize, and combine energy and operational data from devices and systems supplied by different manufacturers. The information can be made available through dashboards, historical analyses, reports, and alerts. In the configuration described here, the focus is exclusively on monitoring, and plant operation is not actively influenced.

The installed solution can later be expanded into an actively controlling energy management system (EMS), provided that the hardware, interfaces, and system architecture are designed accordingly. An EMS can, for example, calculate setpoints, control PV systems, BESS, or flexible loads, and implement applications such as peak shaving or self-consumption optimization. Depending on the device and project, additional integration, configuration, or engineering services may be required.

C&I Monitoring in Summary

C&I monitoring creates a structured data basis for analyzing energy consumption and asset conditions. Meaningful results require a suitable measurement-point structure and reliable data quality. If designed accordingly, the monitoring system can later be expanded to include active EMS functions.

Frequently Asked Questions About C&I Monitoring

What Is the Difference Between C&I Monitoring and an EMS?

C&I monitoring provides measurement and operational data for analysis. An EMS can additionally process this data, derive setpoints from it, and actively control connected assets.

Why Are Main Meters and Submeters Required?

A main meter records the total consumption of a site or area. Submeters allow consumption to be allocated in greater detail to individual consumers, production areas, buildings, or cost centers.

Can an Existing Monitoring System Be Expanded Later?

Active EMS functions can be added if the controller, system architecture, and device interfaces are suitable. The required control logic must be adapted to the specific application and the operating limits of the connected assets.

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Inverters at a Glance

• PV inverters convert the direct current generated by PV modules into grid-compliant alternating current and regulate the operating point of the PV array using Maximum Power Point Tracking (MPPT).
• BESS inverters generally operate bidirectionally, enabling both charging and discharging of the battery.
• Grid-following inverters normally require an existing grid signal. For island or backup power operation, at least one suitable component must establish voltage and frequency.
• Inverters can provide reactive power in addition to active power. The possible combination of both quantities is limited by the inverter’s permissible apparent power.

How Does an Inverter Work?

An inverter uses power electronic switching components to generate an alternating voltage from a DC voltage. Control and filter stages ensure that the output parameters comply with the technical requirements of the connected utility grid or island grid. In grid-connected systems, the inverter synchronizes with the existing grid voltage and feeds in alternating current with the appropriate frequency and phase angle.

PV inverters also regulate the electrical operating point of the PV array. MPPT adjusts this operating point so that the connected PV modules provide as much power as possible under the current irradiance and temperature conditions. Voltage and current are determined by the current-voltage characteristic of the PV array. At the same time, the inverter monitors permissible voltage, current, temperature and insulation limits, among other parameters.

In a BESS, the inverter controls the flow of energy between the battery and the AC system. During charging, it converts alternating current into direct current; during discharging, it converts direct current into alternating current. In larger battery storage systems, the term Power Conversion System (PCS) is also frequently used for bidirectional power electronics. Depending on the system architecture, however, a PCS may include additional electrical components and functions.

State of charge, battery temperature and current, voltage and power limits are generally taken into account through coordination between the inverter, the battery management system and the higher-level controller.

Grid-following inverters rely on an existing voltage and frequency. If this grid signal is lost, they normally stop operating. Island and backup power systems therefore require at least one grid-forming component. This component establishes the local AC system and defines its voltage and frequency, allowing suitable inverters and loads to operate within that system.

What Types of Inverters Are Available?

String inverters connect one or more PV strings and are commonly used in PV systems with a decentralized architecture. Multiple independent MPPT trackers can regulate groups of modules with different orientations or operating conditions separately.

Central inverters combine the output of many PV strings in a single device. They are primarily used in larger PV installations where high power levels are converted centrally.

Hybrid inverters can connect a PV system and a BESS within a shared system. Depending on the device architecture, the battery may be connected on the DC side. However, a hybrid inverter is not automatically suitable for island or backup power operation. The required grid-forming functions must be explicitly supported.

Module inverters, also known as microinverters, are assigned to individual PV modules or small groups of modules. They enable decentralized power conversion and individual operating-point control but increase the number of electronic components within the PV system.

Typical Applications of Inverters

Inverters perform essential functions in different energy systems:

• In PV systems, they convert the generated DC power into usable or grid-exportable AC power.
• In a BESS, bidirectional inverters control the charging and discharging of the battery.
• In hybrid systems, suitable devices coordinate power conversion between PV, BESS, loads and the utility grid.
• In grid-connected systems, inverters can provide active and reactive power in accordance with local requirements or external setpoints.

Important Parameters and Technical Limits

Relevant monitoring values may include DC and AC power, voltage, current, grid frequency, energy yield, temperature, insulation values, operating status, warnings and fault messages, depending on the device. These data can help identify yield losses, shutdowns, excessive temperatures, communication failures and other deviations.

The rating in kilowatts (kW) describes the active power of an inverter. Kilovolt-amperes (kVA), by contrast, indicate its apparent power limit. Active power and reactive power jointly determine the required apparent power. In simplified form:

S = √(P² + Q²)

Here, S represents apparent power, P active power and Q reactive power. If an inverter must provide more reactive power, the available active power may be restricted by its apparent power limit. Temperature, DC voltage, grid conditions and device-specific operating limits can also reduce the power that is actually available.

Monitoring or external control requires suitable communication interfaces, a supported device protocol and a reliable data connection. The available measurements, setpoints and fault codes differ between manufacturers and device types. Not every inverter provides all relevant values or supports external setpoint control.

Monitoring and Controlling Inverters with EcoPhi

EcoPhi can integrate inverters from different manufacturers into a common monitoring environment through available interfaces. Depending on the product, device integration and project scope, measurements and operating states can be recorded, visualized, evaluated historically and used for alarms or reports.

If the inverter provides a compatible and approved control interface, EcoPhi can also transmit active and reactive power setpoints and integrate the device into higher-level operating strategies for PV, BESS or hybrid systems. The specific functionality depends on the inverter, communication protocol and available control options. EcoPhi does not replace the inverter’s internal protection functions or any certified plant or grid controller required under the applicable grid code.

Inverters Summarized

An inverter connects DC-based energy sources and storage systems to an AC system. Its functions range from power conversion and MPPT to the provision of active and reactive power. Monitoring and external control require suitable device interfaces and clearly defined operating limits.

Frequently Asked Questions About Inverters

What Is the Difference Between a PV Inverter and a BESS Inverter?

A PV inverter primarily converts the direct current from PV modules into alternating current. A BESS inverter usually operates bidirectionally so that the battery can be both charged and discharged.

Can Every Inverter Continue Operating During a Power Outage?

No. To operate without the utility grid, the local system must include a suitable grid-forming component.

What Do kW and kVA Mean for an Inverter?

Kilowatts describe active power, while kilovolt-amperes indicate apparent power. The apparent power limit determines which combination of active and reactive power the inverter can provide.

Can an EMS Control Every Inverter?

No. Active control through an EMS requires a compatible and approved interface as well as supported setpoint functions. Some devices only allow measurements and status information to be read.

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Heat Pumps at a Glance

• The efficiency of a heat pump depends particularly on the temperature of the heat source and the required supply temperature.
• The coefficient of performance (COP) describes efficiency at a specific operating point, while the seasonal performance factor (SPF) evaluates performance over a longer period under real operating conditions.
• Thermal storage systems and the thermal storage capacity of a building enable heat pump operation to be shifted within certain limits.
• An EMS can coordinate the operation of a controllable heat pump with PV generation, electricity prices and electrical load limits.

How Does a Heat Pump Work?

Most heat pumps operate using a closed refrigerant circuit. A refrigerant absorbs heat from the environment in the evaporator and evaporates. An electrically driven compressor then increases the pressure and, consequently, the temperature of the refrigerant. In the condenser, the heat is transferred to the heating system or a thermal storage system. An expansion valve subsequently reduces the pressure before the cycle begins again.

The smaller the temperature difference between the heat source and the required output temperature, the more efficiently the heat pump can operate. Low supply temperatures, such as those used in underfloor heating systems, are therefore generally beneficial. At low outdoor temperatures or when high supply temperatures are required, efficiency usually decreases, meaning that more electrical energy is needed to provide the same amount of heat.

The coefficient of performance (COP) describes the ratio of heat output to electrical input at a defined operating point. In simplified terms, a COP of 4 means that under these conditions, approximately 4 kWh of heat can be provided using 1 kWh of electrical energy.

The seasonal performance factor describes the ratio between the amount of heat provided over a full year or heating season and the electrical energy consumed for this purpose. Its significance depends strongly on whether components such as circulation pumps, control systems and electric backup heaters are included within the defined system boundary.

Typical Heat Pump Applications

Heat pumps are used in residential, commercial and industrial buildings for space heating and domestic hot water production. In suitable applications, they can also provide process heat at a technically achievable temperature level.

Air-to-water heat pumps use ambient air as their heat source. Ground-source brine-to-water heat pumps extract energy from the ground through horizontal collectors or boreholes. Water-to-water heat pumps usually obtain heat from groundwater. The appropriate design depends on factors such as the location, required temperature level, available space and applicable permitting requirements.

In combination with a PV system, part of the heat pump’s operation can be shifted to periods of high on-site electricity generation. A domestic hot water tank or buffer tank stores thermal energy and partially separates heat generation from immediate heat demand.

When combined with a battery energy storage system (BESS), a heat pump can also use electrical energy that was stored previously. Whether this is economically beneficial depends on factors such as electricity prices, storage losses, available battery capacity and alternative uses of the BESS.

Benefits, Limitations and Technical Requirements

Heat pumps can make environmental heat usable and therefore provide more thermal energy than the electrical energy they consume. However, their actual efficiency depends strongly on the building, heat source, system sizing, required temperatures and control quality.

Frequent cycling, unsuitable system sizing and high supply temperatures can reduce efficiency. Intensive use of an electric backup heater also increases electricity consumption. Air-source heat pumps may additionally require energy-intensive defrost cycles.

Flexible operation must account for heat demand, comfort limits, minimum operating times, lockout periods and permitted switching frequencies. Operation can only be shifted if the building or a thermal storage system provides sufficient thermal flexibility.

Integration into an EMS also requires a suitable communication or control interface, such as Modbus, EEBus, an approved manufacturer API or a dedicated control contact. The availability of measurement data alone does not automatically mean that the interface also permits control commands or write access.

How Can EcoPhi Integrate a Heat Pump?

EcoPhi can record a heat pump’s electrical consumption and display it together with data from PV systems, BESS, electricity meters and other loads. Temperatures, operating states and internal measurements can only be integrated if they are available through the device interface or additional sensors.

If a suitable and approved interface is available, the EMS can coordinate operating permissions or setpoints based on PV surplus, electricity prices, load limits and defined comfort conditions. The specific functionality depends on the supported data points, available write access and project requirements.

Control commands are transmitted through the interfaces provided by the manufacturer and within the permitted operating limits. Directly switching the electrical supply off and on is not a standard form of EMS control and may bypass technical protection functions or required run-on periods. The heat pump’s internal controller remains responsible for the refrigerant circuit, compressor operation and safety functions.

Heat Pumps Summarized

A heat pump uses electrical energy to raise environmental heat to a usable temperature level. Its efficiency is significantly influenced by temperature conditions, the heating system and its control strategy. With suitable interfaces and sufficient thermal flexibility, an EMS can coordinate its operation with PV generation, electricity prices and other energy assets.

Frequently Asked Questions About Heat Pumps

What Is the Difference Between COP and SPF?

The COP describes the efficiency of a heat pump at a defined operating point. The SPF evaluates the ratio between the heat provided and the electrical energy consumed over a full year or heating season.

Why Does a Heat Pump Operate More Efficiently at Lower Supply Temperatures?

A low supply temperature reduces the required temperature lift between the heat source and the heating system. As a result, the compressor generally requires less electrical energy per unit of heat provided.

Can a Heat Pump Operate Only When PV Surplus Is Available?

Usually not entirely, because space heating and domestic hot water are also required outside periods of PV generation. However, an EMS can shift flexible operating periods to times with PV surplus, provided that comfort limits and technical requirements are observed.

Can Every Heat Pump Be Controlled by an EMS?

No. The available functions depend on the installed interfaces and the control commands approved by the manufacturer. An interface may provide read-only measurement data without permitting control commands or write access.

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Full Feed-In at a Glance

• The generated PV energy—after deducting technical auxiliary consumption and any losses or curtailment—is intended entirely for export at the designated grid connection point.
• The system operator receives compensation for the exported energy or revenue from market-based electricity sales.
• A revenue-grade metering device records the exported energy at the defined settlement metering point.
• Unlike surplus feed-in, the PV system is not primarily used to supply local loads.

How Does Full Feed-In Work?

The PV modules generate direct current, which the inverter converts into grid-compliant alternating current. The electrical energy is then transferred to the public grid through a defined grid connection point. A revenue-grade metering device records the exported energy at the specified settlement metering point.

Electricity consumed by the building or business is supplied separately from the grid and measured at the designated import metering point. The precise arrangement of meters and electrical connection points depends on the applicable metering concept, the grid operator’s requirements, and the selected compensation or market-based sales model.

A full feed-in system may also temporarily import electrical energy from the grid. Inverters, data loggers, monitoring systems, transformers, and other auxiliary equipment may require energy when the PV system produces little or no power. This technical auxiliary consumption must be distinguished from the electricity consumed by other loads at the site and must be considered in the metering concept.

The exported energy recorded at the settlement metering point may differ from the generation measured directly at the inverters. Possible reasons include cable and conversion losses, technical auxiliary consumption, curtailment, and differences between the measuring devices used.

Where Is Full Feed-In Used?

Full feed-in is commonly used for PV systems whose primary purpose is to generate and sell solar electricity. Examples include ground-mounted PV plants, large rooftop systems without significant local consumption, and installations where generation and consumption are treated separately for technical or contractual purposes.

Full feed-in may also be selected at sites with their own electricity consumption. The decisive factor is whether exporting all generated energy is more suitable than surplus feed-in with self-consumption under the applicable technical, economic, and contractual conditions.

Benefits, Limitations, and Technical Requirements

Full feed-in enables the exported energy to be clearly allocated for metering and commercial settlement. The PV system’s operating strategy does not have to be aligned with the local load profile. However, whether the model is economically advantageous depends on factors including compensation or market revenues, grid electricity prices, the load profile, system size, and the applicable tax framework.

The main technical requirements include a suitable grid connection, an agreed metering concept, and revenue-grade metering. Depending on the market, grid operator, system size, and sales model, additional technical functions may be required.

Monitoring is used to supervise generation, export, availability, and system conditions. A plant controller, by contrast, implements technical requirements at the grid connection point. An interface to an electricity trader, aggregator, or market representative transfers market, power, or dispatch signals between the plant and the relevant market participant. These functions perform different tasks and are not generally interchangeable. An EMS or monitoring system therefore does not automatically replace a plant controller required under the applicable grid connection rules.

Implementation with EcoPhi

EcoPhi can collect and visualize PV generation, grid export, system availability, and relevant operating conditions. Comparing inverter data, meter readings, and, where available, solar irradiance data can help identify yield deviations and investigate potential technical losses. Alarms can be triggered in response to outages, communication failures, or unusually low export power.

Active self-consumption optimization is normally unnecessary for a pure full feed-in system. Depending on the project, EcoPhi can also exchange data with external systems or market participants. The specific implementation depends on the available device interfaces, the metering concept, and the technical requirements. EcoPhi should not be considered a general replacement for a required plant controller or an electricity trader, aggregator, or other market participant.

Conclusion: When Is Full Feed-In Suitable?

With full feed-in, PV generation is intended for export to the public grid. The model enables the exported energy to be clearly allocated but requires an appropriate metering concept. Its economic viability depends on compensation and market conditions as well as the potential benefits of using the electricity for self-consumption instead.

Frequently Asked Questions About Full Feed-In

What is the difference between full feed-in and surplus feed-in?

With full feed-in, all PV generation—apart from the system’s technical auxiliary consumption—is intended for export to the public grid. With surplus feed-in, the PV system first supplies local loads. Only the remaining energy is exported.

Does a full feed-in system have technical auxiliary consumption?

Yes. Inverters, monitoring devices, and auxiliary equipment may require electrical energy for their own operation. This technical auxiliary consumption is not the same as the general electricity consumption of the site.

Is full feed-in more economical than self-consumption?

There is no universal answer. Relevant factors include compensation or market revenues, grid electricity prices, the load profile, system size, and the applicable tax framework.

Does a full feed-in system require an EMS?

An EMS is not normally required for self-consumption optimization in a pure full feed-in system. Monitoring, export control, or technical communication with external systems may nevertheless be necessary or useful.

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Single sign-on (SSO) allows users to access multiple connected applications using one centrally managed digital identity. Multi-factor authentication (MFA) requires at least two different authentication factors. The two methods can be combined but perform different functions.

SSO and MFA at a Glance

• SSO centralises access to connected applications through an identity provider.
• MFA requires authentication factors from at least two different categories.
• An identity provider can perform the MFA check centrally.
• Roles and permissions determine which sites, data and functions users can access after authentication.

How Do SSO and MFA Work?

With SSO, an identity provider (IdP) verifies the user’s digital identity. Examples of identity providers include Microsoft Entra ID and Okta. The target application trusts the secured identity confirmation provided by the IdP and therefore does not need to manage the login credentials itself.

Protocols such as SAML 2.0 and OpenID Connect are commonly used to exchange identity information. The application typically receives a signed assertion or token. Depending on the protocol and configuration, this information may include the user’s identity, selected user attributes and details about the authentication method.

A typical login process begins when a user opens the energy platform. The platform redirects the authentication request to the IdP. After verifying the user, the IdP provides a secured identity confirmation that allows the platform to establish an authenticated session.

MFA combines factors from different categories:

• Knowledge: for example, a password or PIN
• Possession: for example, a registered smartphone with an authenticator app, a hardware token or a security key
• Biometric characteristic: for example, a fingerprint or facial recognition, typically used with a registered device

Two passwords, or a password combined with a PIN, do not constitute MFA because both factors are based on knowledge. Phishing-resistant authentication based on FIDO2 or WebAuthn, including security keys and passkeys, can provide stronger protection than password- or one-time-password-based methods. Depending on the implementation, passkeys can also enable passwordless authentication and should not automatically be treated as a conventional second factor.

SSO and MFA can be used together or independently. In a combined architecture, the IdP can perform the MFA check centrally and then provide the connected applications with a secured identity confirmation. This confirmation may include information about the authentication method used.

Typical Applications in Energy Platforms

SSO is particularly relevant for energy platforms used by multiple users, sites or organisations. Operators can centrally create or revoke access, while service providers and asset managers can use their existing corporate identities.

MFA becomes especially important when users can do more than view measurement data. This includes configuring alarms, changing operating parameters or remotely controlling energy assets. The greater the potential impact of unauthorised access, the stronger the authentication method should be.

Benefits, Limitations and Technical Requirements

SSO can reduce administrative effort and simplify the removal of access when users leave an organisation. MFA reduces the risk that a stolen or guessed password alone will provide access to the platform.

However, a central identity provider also creates a critical dependency. If the IdP is unavailable or incorrectly configured, users may be unable to access several connected applications at the same time. Availability, session duration, logging, recovery procedures and controlled emergency access must therefore be considered.

Authentication and authorisation must be treated separately. Authentication verifies the identity of a user. Roles and permissions then determine which tenants, sites, data and functions that user can access. Shared user accounts should be avoided because changes and control commands cannot otherwise be reliably attributed to an individual.

For SSO integration, the identity provider and the energy platform must support a compatible authentication protocol. Clear user mappings, suitable role models and defined rules for sessions, account deactivation and emergency access are also required.

User Access in the EcoPhi Monitoring & Control Cloud

The EcoPhi Monitoring & Control Cloud supports role-based access control and the separate management of users, systems and tenants. Access can therefore be restricted to the energy assets and information relevant to each user.

Whether SSO or MFA is available for a specific platform package should be assessed for the individual project. Relevant factors include the required identity provider, supported authentication protocols, user structure and applicable security policies. SSO and MFA should therefore not be presented as general standard features without prior technical confirmation.

Importance for Secure Platform Operation

SSO and MFA can improve the management and security of user access. For energy platforms, however, a robust access concept also requires individual user accounts, appropriate permissions, traceable logging and defined operational and recovery procedures.

Frequently Asked Questions About SSO and MFA

Can MFA Be Used Without SSO?

Yes. An application can require MFA for its own user accounts without being connected to a central identity provider.

What Happens If the Identity Provider Is Unavailable?

New SSO logins may be temporarily unavailable. Depending on the session configuration, users who are already logged in may be able to continue working. Critical applications should have defined emergency access and recovery procedures.

Does MFA Replace Role-Based Access Control?

No. MFA strengthens the verification of a user’s identity. Role-based access control determines which data, sites and functions that user may access after authentication.

Are Passkeys Automatically a Form of MFA?

Not necessarily. Passkeys can enable passwordless and phishing-resistant authentication. Whether multiple factors are involved depends on the implementation and how the passkey is activated.

Der Beitrag SSO and MFA erschien zuerst auf EcoPhi Energy IoT.

Programmable Logic Controllers at a Glance

• A PLC processes measurements, switch positions, operating states and fault signals according to stored program logic.
• Cyclic or prioritized program routines enable definable and largely predictable response times.
• A PLC typically performs local and plant-level control, regulation, interlocking and sequencing tasks.
• It can operate independently or together with an EMS, but it does not replace dedicated protection devices.

How Does a PLC Work?

A PLC is connected to sensors, actuators and other systems through digital and analog inputs and outputs or industrial communication interfaces. Depending on the equipment and project, protocols such as Modbus TCP, Modbus RTU, PROFINET or OPC UA may be used. Not every PLC automatically supports all of these protocols.

In conventional cyclic processing, the PLC first transfers the input signals to an input process image. It then executes the stored program and writes the calculated states to the output process image. The physical outputs are subsequently updated. This sequence repeats continuously. Depending on the PLC system, time-controlled, event-driven or prioritized program routines and direct access to inputs and outputs may also be possible.

The program logic can include simple switching conditions as well as control loops, interlocks, sequences and more complex algorithms. The response time that can actually be achieved depends on factors such as the hardware, cycle time, program structure, communication paths and distributed inputs and outputs.

Where Are PLCs Used in Energy Systems?

In PV, BESS, charging and hybrid systems, a PLC can perform various local tasks. Typical examples include:

• It coordinates the starting, stopping or switching sequences of generators, pumps, ventilation systems and controllable loads.
• It processes states from energy meters, PV inverters and battery energy storage systems and derives defined control commands from them.
• It checks enable signals and interlocks before forwarding an external setpoint to a plant component.

A PLC can operate entirely without an EMS if the required control logic is programmed locally and no higher-level coordination is needed.

Difference Between a PLC and an EMS

The main difference lies less in their fundamental computing capabilities and more in their intended system roles. A PLC typically performs deterministic, local and plant-level tasks. An EMS, by contrast, coordinates energy flows and available flexibility across systems based on energy-related, operational or economic objectives.

For example, an EMS can calculate setpoints based on self-consumption, load peaks, forecasts, electricity prices or operating reserves. A connected PLC can then check whether local enable conditions and operating requirements are met and generate specific commands. However, this division of responsibilities is not mandatory and depends on the respective system architecture.

Benefits, Limitations and Technical Requirements

A PLC enables reproducible local processes and can continue to perform defined functions if its connection to higher-level systems is interrupted. Appropriate inputs and outputs or communication interfaces, clearly defined signals and an agreed allocation of responsibilities are required.

Clearly defined fallback strategies for communication and device failures are particularly important. Maintaining the last setpoint should only be permitted if this is technically acceptable and safe for the specific process. Depending on the application, the system may instead need to enter a safe operating state or activate a local fallback control strategy.

A conventional PLC does not replace electrical protection devices. Grid protection, overcurrent protection and other protective functions require suitable components. Safety-related control tasks may only be implemented using appropriately designed hardware, suitable programming and the required verification.

Connecting a PLC to EcoPhi

Depending on the project architecture and available device interfaces, EcoPhi can exchange measurements, operating states, fault messages, enable signals and setpoints. For example, an EcoPhi EMS can calculate a power setpoint, while the PLC controls its local implementation based on programmed enable conditions, interlocks and operating requirements.

Whether communication takes place directly or through another system must be determined for each project. The supported protocols, data points, response times and fallback functions must be verified for the specific PLC and plant. Additional integration or engineering services may be required.

PLCs in Summary

A PLC is an industrial control computer for local and plant-level control, regulation and sequencing tasks. In an energy system, it can operate independently or complement an EMS by implementing its setpoints while considering local enable conditions, interlocks and operating requirements.

Frequently Asked Questions About PLCs

What Does PLC Stand For?

PLC stands for programmable logic controller.

Can a PLC Replace an EMS?

It can execute complex algorithms if it has been programmed accordingly. However, an EMS is typically designed for the system-wide coordination and optimization of energy flows and flexibility.

Does a PLC Always Need a Connection to an EMS?

No. A PLC can operate entirely independently. A connection to an EMS is only required if the two systems are intended to work together within the respective system architecture.

What Happens During a Communication Failure?

The required response must be defined and assessed for operational safety in each project. Depending on the process, the PLC can establish a safe state, activate a local fallback control strategy or maintain a setpoint if explicitly permitted.

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Spot Market Prices at a Glance

• Auction prices, individual trade prices, and price indices must be distinguished.
• The usual unit is €/MWh: 100 €/MWh equals 10 ct/kWh.
• Price differences can create economic opportunities for battery storage systems and flexible loads.

How Are Spot Market Prices Formed?

Prices are determined by supply and demand. Auctions establish a common market-clearing price per delivery interval and bidding zone from buy and sell bids; in continuous trading, prices arise from individual transactions.

Electricity consumption, photovoltaic and wind generation, power plant availability, and cross-border transmission capacity influence price levels.

Spot market prices differ from retail electricity prices, contractual feed-in remuneration, and balancing reserve and imbalance prices. Negative spot market prices do not automatically mean free electricity for consumers.

How Do Energy Management Systems Use Prices?

An energy management system (EMS) can use price time series to schedule battery charging during cheaper periods, discharge later, or shift flexible loads. This requires controllable equipment, suitable interfaces, and compliance with operating limits such as state of charge and grid connection capacity.

Whether this generates savings or trading revenue depends on the electricity supply or marketing contract. A fixed electricity tariff generally does not directly pass through short-term wholesale price fluctuations. The relevant factors are the actual electricity purchase costs and export revenues, including applicable price components, storage losses, and degradation costs.

How Can This Be Implemented with EcoPhi?

For implementation with EcoPhi, each project must establish which price time series or external schedules can be integrated and used for local asset control. Price visualisation in monitoring and connections to specific electricity marketing partners also require confirmation.

Displaying prices and energy flows alone does not constitute active optimisation. This additionally requires suitable control interfaces and configured EMS logic. Technical integration does not automatically provide direct power exchange access or include trading and settlement services.

Frequently Asked Questions on Spot Market Prices

How Does an EMS Use Changing Electricity Prices?

An EMS can charge a battery during lower-cost periods, discharge it when electricity costs are higher, or shift flexible loads to more favourable times. This requires suitable price data, controllable assets, compatible interfaces, and configured control logic.

Does Price-Based Optimisation Automatically Generate Savings?

No. The economic result depends on the applicable purchase and export prices, contractual price components, storage losses, battery degradation costs, and the flexibility of the connected assets. A fixed electricity tariff generally does not directly reflect short-term wholesale price fluctuations.

Does an EcoPhi Integration Include Electricity Trading?

No. EcoPhi can integrate suitable price signals or external schedules for local asset control on a project-specific basis. However, technical integration does not automatically include market access, electricity trading, billing, or settlement services.

Der Beitrag Spot Market Price: Electricity Prices in Short-Term Trading erschien zuerst auf EcoPhi Energy IoT.

Smart Grid Readiness describes the technical ability of a device or energy system to provide relevant measurements and available flexibility through digital interfaces and to respond to external signals. These signals may include power setpoints, operating schedules, price signals or charging permissions. The term does not refer to a uniform technical standard or universally recognised certification.

Smart Grid Readiness at a Glance

• Smart-grid-ready assets can provide operating data digitally and implement external commands within their technical limits.
• Integration requires compatible interfaces, clearly defined commands and verifiable feedback on the actual system response.
• The required functionality depends on the specific application and the systems involved.
• Smart Grid Readiness provides a technical foundation for flexible operation but does not replace project-specific qualification or approval processes.

How Does a Smart-Grid-Ready Energy System Work?

A smart-grid-ready system connects physical energy assets to a digital communication and control layer. Connected assets may include PV systems, battery energy storage systems (BESS), heat pumps, EV charging infrastructure, generators and flexible industrial loads.

The connected devices provide measurements such as current power, energy, operating status, state of charge and available flexibility. For a BESS, flexibility may be described by available charging and discharging power, usable energy, possible activation duration, ramp rates and operating limits. For controllable loads, minimum operating times, required recovery periods and production requirements may also be relevant.

External signals may originate from a grid operator, aggregator, energy market participant or local EMS. Prices and operating schedules are often processed by a higher-level system before being translated into specific setpoints. These commands may define a maximum export power, a charging or discharging power setpoint or an operating permission for a controllable load.

Feedback from the system is essential. Receiving a setpoint does not confirm that it has actually been implemented. Measurements and device status information must therefore indicate whether the requested response occurred or was limited by operating constraints, faults or local safety functions.

Because there are no universal requirements, Smart Grid Readiness must be assessed for each application. Relevant criteria include available data points, update rates, communication latency, writable setpoints, feedback signals, technical response times and behaviour during communication failures. The required values depend on the specific monitoring and control task.

Where Is Smart Grid Readiness Used?

• Grid-supportive operation: PV systems, BESS and controllable loads can respond to external power limits and grid signals.
• Flexibility management: Available charging, discharging and load-shifting potential can be measured and provided to higher-level systems.
• Price-based operation: Loads and storage systems can be operated according to electricity prices or predefined schedules.
• Coordination of local energy systems: An EMS can coordinate generation, storage and consumption using shared measurements and operating objectives.

Benefits, Limitations and Technical Requirements

Smart Grid Readiness enables energy assets to be integrated into higher-level monitoring and control systems. This allows distributed generation, storage systems and flexible loads to be coordinated and adapted to operational or external requirements.

Suitable measurement infrastructure is a fundamental requirement. Power, energy, operating status and flexibility parameters must be available at an update rate appropriate for the application. Controllable assets also require clearly defined setpoints, write access and verifiable feedback.

Devices and higher-level systems need compatible communication protocols and data models. The unit, direction, priority and validity period of each command must be clearly defined. Remote access and external control also require authentication, access permissions, encrypted data transmission and traceable logging of changes.

Local operating and safety limits remain binding when external commands are received. These may include power limits, state-of-charge limits, temperature thresholds, minimum operating times or restrictions at the grid connection point. Communication failures require defined fallback strategies, such as switching to a safe local operating mode.

A lack of native device interfaces can limit integration. Measurements can sometimes be collected using external meters, while existing signals may be integrated through gateways or protocol converters. Active control, however, requires an appropriate and secure control path to be available or technically retrofittable.

How Can EcoPhi Implement Smart Grid Readiness?

EcoPhi can act as a manufacturer-independent communication and EMS layer that collects and consolidates measurements from different energy assets. Depending on the available interfaces and project configuration, external power commands, operating schedules or price data can be integrated and translated into permissible setpoints for PV systems, BESS or flexible loads.

The system response can be monitored through measurements and status information and communicated to external systems. Existing flexibility parameters can be obtained from device data. More advanced calculation of available flexibility requires project-specific logic and suitable input data.

The exact functionality depends on the device and system interfaces as well as the requirements of the individual project. EcoPhi provides the technical integration and control layer but does not automatically provide certification, market qualification or approval by a grid operator or other external party.

Smart Grid Readiness in Summary

Smart Grid Readiness enables the digital integration and flexible control of energy assets. The main requirements are suitable measurement data, compatible communication paths, accessible control interfaces, verifiable system responses and safe fallback strategies. The required functionality must be defined individually for each application.

Frequently Asked Questions About Smart Grid Readiness

Is Smart Grid Readiness a Technical Standard?

No. The term describes a technical capability. The specific requirements depend on the application and the systems involved.

Which Assets Can Be Smart-Grid-Ready?

Examples include PV systems, BESS, heat pumps, EV charging infrastructure, generators and controllable industrial loads.

Is a Communication Interface Sufficient?

No. Data and commands must also be clearly defined, setpoints must be implemented safely and the actual system response must be verifiable.

Does Smart Grid Readiness Automatically Enable Participation in Flexibility Markets?

No. Additional technical evidence, metering concepts, contractual arrangements, qualification procedures or suitable market partners may be required.

Der Beitrag Smart Grid Readiness erschien zuerst auf EcoPhi Energy IoT.

Repowering and Revamping at a Glance

• Revamping generally refers to the modernization or refurbishment of an existing PV system without comprehensively replacing it with a new system.
• Repowering involves replacing major system components, particularly PV modules, with new components.
• The treatment of additional capacity depends on the system type, applicable support scheme and regulatory framework.
• Before implementation, the grid connection, support or remuneration status, metering concept and registration requirements must be assessed for the specific project.

What Is the Difference Between Revamping and Repowering?

Revamping focuses on modernizing an existing PV system and maintaining its continued operation. Typical measures include:

• Replacing or repairing inverters
• Renewing communication equipment and data loggers
• Retrofitting sensors or power optimizers
• Renewing cabling and protection equipment
• Adapting monitoring, plant control or the metering concept

Unchanged installed capacity is not a mandatory criterion for distinguishing revamping from repowering. The decisive factors are which components are replaced and whether the technical or regulatory system configuration changes. Replacing an inverter, for example, does not automatically change the commissioning date or support status of the existing PV modules.

Repowering involves replacing significant parts of a PV system. Older modules are often replaced with modern models to make better use of the available area, reduce failure risks or extend the operational life of the site. Inverters, mounting structures, cabling, protection equipment and plant communication systems may also form part of the project.

The terms revamping and repowering therefore primarily describe the scope and purpose of a modernization project. They do not constitute universally defined regulatory categories.

How Is Repowering Treated Under Support Schemes?

The simplified statement that “the existing capacity retains its previous remuneration and the additional capacity receives the current remuneration” does not apply universally to all PV systems.

Up to the amount of the replaced installed capacity, replacement components may retain the previous commissioning date or support status if the applicable legal requirements are met. The treatment of any capacity exceeding the replaced capacity depends on the system type, support mechanism, market rules and applicable jurisdiction.

In some support schemes, the electricity generated after a capacity increase is allocated proportionally between the replaced capacity and the additional capacity. The additional share may not qualify for support payments. Under other frameworks, the additional capacity may be eligible for a separate payment or support entitlement under the rules in force at the time of replacement.

Some regulatory changes may also depend on approval by national authorities, regional institutions or other competent bodies. Until such approval becomes effective, previous rules or statutory transitional provisions may continue to apply.

The specific allocation of support must therefore be assessed based on the system type, support model, original commissioning date, applicable jurisdiction and scope of the replacement. Describing a project technically as repowering is not sufficient to determine its regulatory or financial treatment.

Typical Measures for Existing PV Systems

Revamping and repowering are particularly relevant when obsolete or unsupported inverters, data loggers and communication devices need to be replaced. Other reasons include frequent failures, module damage, declining yields or the intention to make better use of the available roof or ground area.

As part of a modernization project, a PV system may also be expanded with an EMS, a battery energy storage system or additional consumers. These functional extensions are not automatically classified as revamping or repowering, but they can be combined with corresponding modernization measures.

Benefits, Limitations and Technical Requirements

Revamping can improve the availability, data acquisition and maintainability of an existing system without replacing all components. Repowering can additionally increase the energy yield per unit of area and enable the continued use of existing site and grid connection infrastructure.

A technical assessment of the existing system is required before implementation. This includes the installed module capacity, electrical limits of the inverters, cabling, protection and grid connection equipment, meter arrangement, device interfaces and available system and registration data.

Depending on the modifications, a new grid connection assessment, updated certificates, an adapted metering concept or an update to the information held in applicable energy-system registries may be required. Not every repair or maintenance measure automatically triggers the same obligations.

For systems covered by support or remuneration schemes, the allocation of existing and additional capacity should be assessed specifically for the project before work begins. Technical coordination or information provided by the grid operator may not always constitute a final legal assessment. For systems whose original support period has ended, retaining a previous tariff is less relevant, but technical, metering and regulatory requirements still apply.

How Does EcoPhi Support Modernization?

EcoPhi can integrate existing and renewed inverters, energy meters and sensors into a common monitoring system. Existing data loggers can be replaced by an EcoPhi component if the relevant devices provide supported or integrable interfaces.

Measurements from before and after modernization can be compared if the required historical data is available from the previous system and can be exported in a usable format. Whether historical data can be imported directly and evaluated together with new data depends on the respective data format and project-specific integration.

Additional EMS functions can also be implemented, and new components such as battery energy storage systems or controllable loads can be integrated. However, EcoPhi does not provide the legal assessment or regulatory allocation of existing and additional capacity.

Repowering and Revamping Summarized

Revamping and repowering describe different scopes of modernization for existing PV systems, but they are not universally defined legal categories. The actual modifications determine the technical and regulatory classification. Module replacement and capacity increases require particular attention to the support scheme, payment entitlement and applicable approval requirements.

Frequently Asked Questions About Repowering and Revamping

Does a New Inverter Change the Commissioning Date?

Replacing an inverter does not generally result in a new commissioning date for the existing PV modules. Additional obligations may nevertheless arise if the capacity, grid connection or overall system configuration changes.

Does Existing Support Remain in Place When PV Modules Are Replaced?

This depends on the applicable support scheme, system type and circumstances of the replacement. The allocation of support should therefore be assessed for the specific project before the modules are replaced.

Does Additional Capacity Automatically Receive New Support?

No. Under some regulatory frameworks, the additional share does not qualify for support payments. In other cases, a separate entitlement may be available, subject to the applicable regulations and approval requirements.

Does a Modernization Project Need to Be Registered?

System data must generally be updated if the project changes information that is subject to registration requirements. Whether a particular repair, modernization measure or capacity expansion requires an update depends on the applicable market and the modifications made.

Der Beitrag Repowering and Revamping erschien zuerst auf EcoPhi Energy IoT.