This report contains the latest developments and good practices to develop grid connection codes for power systems with high shares of variable renewable energy (VRE) – solar photovoltaic (PV) and wind. The analysis is an update of the 2016 International Renewable Energy Agency (IRENA) report Scaling up variable renewable power: The role of grid codes and elaborates on the latest developments and experiences related to technical requirements for connecting VRE generators and enabling technologies such as storage, electric vehicles (EVs) or flexible demand and their incorporation in grid connection codes.

An imperfect grid code is, in many cases, better than no grid code at all
Formulating grid codes starts with a consensus-building process including all possible stakeholders. This process uses technical studies to determine the technical limitations in the system. For technological improvements and newer trends and services to be put in place, grid codes must be continuously updated and improved, aiming for system-friendly behaviour. Establishing a grid code is an important step in opening up the power sector to private developers or new plant operators and enabling efficient integration of distributed VRE generators. The development of grid codes may be based on international experience. An imperfect grid code is, in many cases, better than no grid code at all, especially when economic conditions allow for renewable energy development to pick up pace. In this situation, the development of grid codes is needed quickly. Even if the initial grid codes are not perfectly suited to the needs of the system, they ensure a certain minimum functionality of new generators. Furthermore, it is usually easier and cheaper to re-parametrise functionality to better reflect the needs of the system later. Special care should be taken not to ask for excessive requirements that would turn into higher costs that could restrain VRE development. On the other hand, requirements that
are too loose put the system at risk.

Grid codes should be technology-neutral and should evolve to meet system needs
Grid codes should specify the requirements in a technology-neutral manner as far as possible to help avoid the introduction of technical barriers for individual technologies and to allow users to adopt the most economically efficient technical solution to suit their needs and business cases. In case the requirements of a system change over time and grid codes are updated, the cost of upgrades should not fall entirely on existing grid users, and a compromise should be reached on the burden of the cost. If the connection requirements applying to existing assets never change while the rules for new assets become stricter, the result could be a delay in the replacement of old with newer, more advanced technology. On the other hand, if connection requirements evolve constantly for existing assets, huge investment uncertainty is created. A balance needs to be struck between the two extremes. Existing assets should be treated differently from new assets to some extent. However, existing assets that are significantly
refurbished can be considered new. Alternatively, in exceptional circumstances, existing assets can also be forced to comply with new rules.

Grid connection codes in a transforming power system
One of the oldest grid codes requirement for conventional generation units is the frequency and voltage ranges that should be maintained during normal operation and during contingencies. Over the years they have evolved to define the behaviour of the VRE plants during faults and contingencies. Some of the recent modifications to grid codes involve addressing the loss of inertia, available usually from synchronous generator rotors and rate of change of frequency (RoCoF). The introduction of VRE reduces the inertia and increases RoCoF, which is the rate at which frequency changes post-event and a measure that can activate protection devices in the system. Therefore, newer limits and operational constraints, operational measures, and innovative mechanisms to counter the constraints on inertia and non-synchronous penetration limits should be looked into. For systems looking to achieve near 100% of renewables in the long run, the use and role of grid-forming inverters and participation of VRE in black start needs to be emphasised through grid codes.

Ancillary services, which are services from the different active assets in the grid to keep the system going, are described in grid codes. In some power systems, VREs participate to provide ancillary services such as fast frequency response (FFR) and provide reactive power and frequency regulation support with adequate control in place. The type of VRE units that should adhere to controls and the power reduction and power restoration ramps for these units to participate in can also be specified by grid codes. Real-time Internet-based communication is becoming necessary for power system operation, control and monitoring. As a result, cybersecurity is also becoming critical. There is increased reliance on dynamic data communication and the use of technologies like artificial intelligence and machine learning to provide better operational capabilities. This leaves the communication channels vulnerable to cyberattacks, which can destabilise power system operation, energy market operations and grid reliability. Grid codes are evolving towards recommending standards and improving cybersecurity in power systems while ensuring harmonisation and interoperability. Ongoing development for the network code on energy cybersecurity framework (Electricity Regulation [Regulation (EU) 2019/943]) is being done in Europe. In the United States, the North American Electric Reliability Corporation (NERC) Critical Infrastructure Protection (CIP) standards applicable to bulk systems cover the different aspects of network security, such as asset classification, vulnerability assessments, etc.

Grid codes regulate different aspects of the power system, and they can take different names accordingly. For example, the European (European Union [EU] level) grid codes include network connection codes, operating codes and market codes. Because grid codes are the result of the stakeholders’ landscape and the power system organisation structure that is in place, each jurisdiction can have a different grid code structure. For example, in vertically integrated systems, planning codes might not be defined, as the long-term actions of a vertically integrated utility are regulated. Similarly, metering code is needed when multiple players need access to the meter data, which may not be applicable in vertically integrated systems.

For example, the Mexican grid code includes a planning code besides the connection and operation codes (Comisión Reguladora de Energía, 2016). The Western Australia power system includes a metering code as well (Western Australia Government, 2012). The Electric Reliability Council of Texas (ERCOT) has a Nodal Protocol, which is like an overarching grid and market code, planning guide and operating guide, and other binding documents. A prominent example for illustrating a system of grid code documents complementing each other are the European Union Network Codes, a collection of eight documents that are classified as market codes, operation codes and connection codes (Figure 1).

This report focuses on grid connection codes and, in particular, on the provisions relevant to the connection of generators based on variable renewable energy (VRE) and the provisions for the connection of other generators and assets that can enable the integration of VRE in the system. Ancillary service market considerations and harmonisation and standardisation efforts are also discussed briefly.
Wind and solar photovoltaic (PV) are the most dominant VRE technologies. Grid connection codes specify the minimum technical requirements all such power plants need to meet to be granted grid access. Therefore, these requirements must be designed to ensure system safety and stability with increasing shares of the corresponding generator technologies. Inappropriately designed or incomplete requirements will either increase the risk of unplanned consumer supply interruptions (blackouts) and other grid incidents, causing unnecessary expenditures for grid and generator owners (and consequently for consumers) or prevent the system from reaching its VRE penetration targets by impeding the necessary investment. By providing appropriate rules for VRE generators, VRE grid codes support the effectiveness of national and regional energy policies for renewables integration.


The technical connection requirements specified in grid codes can be divided according to the issues addressed. These high-level requirements (or requirement categories) are the essential components of any grid connection code. While the basic requirement specifications are also often similar, there are significant variations in the chosen parameters and in the range of grid user facilities where they apply based on country and site specifications. This is illustrated in Figure 3. Identifying the appropriate parameters parameters for suitable user facility classes, according to the system needs, is a crucial part of grid code design.

Operating ranges for generators are specified in the frequency and voltage domain in most grid codes, with the objective of avoiding unpredictable tripping behaviour during contingencies. Generators are typically required to be capable of continuous operation within certain voltage and frequency ranges (example: 0.95 to 1.05 per unit voltage and ± 1 Hz in 50 Hz frequency) and to remain connected at least for a defined time within a larger range (to account for temporary disturbances). Voltage ranges may vary by area or connection voltage level, but frequency ranges should be aligned for all generators connected to the same synchronous area.

Voltage and frequency operating ranges go back to international standards applied by manufacturers of synchronous machines (Figure 7), with generators always designed to operate within a certain voltage and frequency range, limited by capabilities of the prime mover and the generator and exciter windings. In this regard, providing operation across a larger range is much less problematic for inverter-based generators, as the inverter current rating is the main limiting factor, together with the protection of semiconductor hardware against voltages that are too high.


Grid code requirements worldwide have been continuously refined and extended over the past years, and new requirements have been developed and introduced. This chapter discusses development trends observed across leading grid codes to adapt to further increasing VRE penetration, and to the accompanying transformative trends of decentralisation, digitalisation and electrification of the end-use sector. The most significant changes encompass the requirements for DER and demand response. Also, grid codes start addressing the gridforming capability of inverters, which can be the key to achieving 100% VRE systems as they can operate in stand-alone mode. The evolution of grid code requirements can be divided into three extension dimensions, as illustrated in Figure 12: i) extending requirements, previously only applicable to larger users, to smaller users as well; ii) enabling new user types to connect by specifying corresponding requirements for them; and iii) adapting to the state of technological development and system needs by requiring newly developed functionality.

Controllability requirements are increasingly being extended towards applying to rooftop solar PV and other small DER. There are two main facets of active power controllability for power plants: the first is the capability to reduce power output; the second is the capability of increasing power output upon request. VRE generation must be capable of both, to the extent possible without mandating the addition of energy storage. Grid code requirements therefore specify power reduction capabilities and minimum power restoration ramps for VRE generation. In practice power system operators can impose an upper limit for power injection on a VRE generation facility, and the facility will adhere to this limit as quickly and accurately as required. When power output has been reduced during a disturbance without an externally signalled limit, units must return to the pre-fault operating points quickly to avoid undue impact on the system’s frequency regulation. This ability to reduce VRE power output and eventually also control ramping rates is critical to congestion management and to maintaining frequency stability.


In the bulk power systems of the past, system operators procured ancillary services from transmission-connected conventional power plants to manage system stability. In modern and sustainable power systems, the same services can also be provided by VRE generation, storage and other grid users. The design of ancillary service markets has evolved as well to help system operators integrate VRE by addressing the variability and uncertainty introduced. One set of innovative ancillary services addresses flexibility issues, remunerating those services related to rapid ramping requirements, frequency regulation and so on. Another set of innovative ancillary products allows new market participants to offer such services: wind turbines can be utilised to provide inertial response, solar PV can offer reactive power support and other DER can help increase market liquidity across different trading time frames (IRENA, 2019d). The grid codes and their requirements not only ensure appropriate behaviour of grid users during normal operation and during disturbances, but can also define the technical capabilities required as the basis for contributing such remunerated services procured by the system operator. This
distinction of capabilities and behaviour from system services is illustrated in Figure 15.

This chapter briefly discusses ancillary service markets and looks into specific services around
frequency control: inertia management and FFR. Grid-forming services from inverters are on
the horizon as a new service, and these are expected to also impact the black-start service.
The chapter finishes with a look on the solutions that allow contributions from small-scale grid
users (DER).

Inertia management is becoming increasingly important in high VRE power systems, as inertia in the system decreases with rising penetration of non-synchronous generation, shown in Figure 17. This figure shows the comparison between the responses to a frequency excursion of two systems: a low and a high inertia system. System operators hence have to either ensure that a certain minimum amount of inertia is always present in the system or provide alternative means to limit frequency deviation during low-inertia situations, like adding primary frequency response (PFR) or adding inertia, as shown in Figure 17. With some notable exceptions, this issue is currently generally not subject to grid code requirements, but almost entirely addressed through operational constraints and/or ancillary services.

The inertia issue has been known and discussed since the first introduction of inverter-based generation decades ago. Initial concerns about power systems becoming unstable already at, by today’s standards, relatively low non-synchronous penetration levels have largely been dispersed after the successful large-scale VRE rollout. Between 5% and 30% of non-synchronous penetration continue to circulate as the “stability limit” for a synchronous system, especially in areas and countries with little VRE experience. However, VRE integration in systems in South and West Australia, Ireland and Texas has shown that system stability can be ensured at higher instantaneous penetration levels of 50-70%, and various small island systems have even gone up to 80-90% of non-synchronous penetration without encountering severe stability issues.


Successful compliance enforcement implies compliance verification, which in turn relies on testing. Where and how can compliance tests be conducted? The answer is that tests should be made wherever reasonable in the planning, development, implementation and operation phases of each asset type and each facility (see Figure 21).

Type tests are important for any mass-produced equipment. Equipment manufacturers that provide consistent quality in their production processes only need to prove grid code compliance for an individual specimen of each product type. If the tested specimen passes the test successfully, then the manufacturer can guarantee that all products of the same type meet the corresponding technical requirements and issue a corresponding declaration. Type tests can also be performed by independent testing bodies to achieve higher confidence and verifiability. Such independent entities should apply standardised and transparent processes. Product certification according to a given set of standards and rules follows this transparent third-party verification scheme.


The shift towards open electricity markets along with the introduction of increasing shares of VRE generation introduced a greater need for cross-border trading and inter-TSO co-ordination, which gave rise to the introduction of regional grid codes in some cases. One of the earlier examples of a regional grid code is the Nordic grid code, published in 2004 (Nordel, 2004, 2007). The Nordic grid code is a collection of national rules and agreements between the TSOs of Denmark, Finland, Norway and Sweden, which had introduced the world’s first international electric power exchange, Nord Pool, in 1996. Inter-TSO co-ordination in the region was governed by the association of Nordic transmission grid operators, Nordel, from 1998 The Nordic grid code focused on collecting and harmonising the technical requirements and operational procedures of the Nordel TSOs.

This gives TSOs a lot of freedom to choose the parameters that work best in their system but does not achieve a full harmonisation of requirements (see Table 9). For example, manufacturers of wind turbines know, by way of the RfG, that all wind power plants above the Type B threshold have to be FRT capable, but the actual FRT envelopes may still be different in each country or for each TSO.

This may not be the full harmonisation desired by the manufacturers and project developers, but it is already a major step forward from the pre-EU Network Codes era, when requirements varied even more wildly. Further harmonisation is on the agenda in European Stakeholder Committee discussions that are working on the second iteration of the EU Network Codes. National implementation has been successfully executed (ENTSO-E, 2020a).17 However, different countries have chosen different approaches of implementation, a degree of freedom that was explicitly granted under the codes and the corresponding law. The Connection Codes define the requirements for grid users non-exhaustively, giving each legislation and TSO the freedom to define additional requirements, and leaving considerable freedom in the exact choice of requirement parameters. The structure of national or TSO-specific grid code documents is also not prescribed. Most European TSOs opted for a revision of their respective grid codes to align them with the requirements set out in the European codes. Some (such as the Kingdom of the Netherlands), however, have chosen to directly use the Connection Codes as nationally applicable documents (which would have been the default prescribed by the European Union in case of no action) and only specify additional requirements and parameter clarifications where needed (Ministerie van Binnenlandse Zaken en Koninkrijksrelaties (Kingdom of the Netherlands), 2021; ENTSO-E, 2020a).

Transmission systems in Canada and the United States are operated by a variety of different independent system operators (ISO) or regional transmission operators (RTO), which usually fulfil the role of both a power system operator and a market operator but may not actually own the grids (there may therefore be separate transmission companies focusing on maintenance and asset management). Subtransmission and distribution grids are operated by a variety of different grid operators and utility companies. Market and ownership structures vary widely for the same historic reasons that can be observed in Europe. In this regard, the power system structure and the grid code landscape related to it are as fractured and uneven in North America as they are in Europe, despite the fact that only two (albeit heavily federalised) countries are involved here.

The first regional effort in Latin America and the Caribbean is the interconnection of six countries of Central America through the Regional Transmission Grid (Red de Transmisión Regional, RTR). Along with the physical interconnection of the individual power systems, a regional market (Mercado Eléctrico Regional, MER) was established, governed by CRIE (Comisión Regional de Interconexion Eléctrica) as the regional regulator. The operation of each electric system and the corresponding market is performed by each national system operator, respectively (system operator and market operator) (Montecinos et al., 2021). Each of the six countries is a balancing area. However, the regional operator entity is in charge of supervising and co-ordinating all of the operators in the region and establishing minimum technical requirements to be fulfilled (Ente Operador Regional, 2021).

Furthermore, the regional operator entity is in charge of overviewing any exchanges among the systems such as those for power plants that sell to consumers in different systems and verifying that each country has enough reserves to comply with regional performance indices. Technical and market rules are set out in the RMER (Reglamento del Mercado Eléctrico Regional), published by CRIE (CRIE, 2020). This document is maintained and regularly updated based on proposals from the regional operator entity and/or consultation with the national utilities system operator and market operators and other stakeholders. It has over time evolved from a set of purely market-oriented set of rules into a full and legally binding regional grid code, governing market transactions, inter-operator co-ordination and technical requirements for market actors, including generators.


This section provides an overview of which kinds of connection requirements are appropriate in power systems at different stages of the VRE integration process. Where possible and applicable, the requirements themselves should be drawn from international standards such as the latest editions of EN 50549 or IEEE 1547. When looking at regulation, the European grid codes are probably the best developed. Leading stakeholders from any country should join the corresponding standardisation efforts to ensure that their particular needs are adequately addressed.

Achieving significant levels of VRE is a challenge in any power system, because VRE technology
has become competitive only recently. In many countries the capacities are ramped up quickly. Examples from several countries illustrate that high shares of VRE are already possible with the
technology available today.

Given the wide variety of country power systems, how should their grid codes be designed to facilitate VRE adoption? What requirements and parameters are important, and which aspects could be neglected in a given situation? We discuss these questions based on three different power system archetypes and look at them at three different stages of their VRE integration process. Considering that many countries operate multiple power systems to supply geographically separate areas, we also add further country-level advice to account for the need to design grid codes that cover more than a single system.

An overview of the main characteristics of the three selected archetypical power systems is given in Table 16. Since the discussion first focuses on power systems, we can assume that each of the selected cases has no or only weak interconnectivity to neighbour systems. In comparison to systems with strong interconnection ties, this represents the more challenging situation because fewer resources can be shared with neighbours. The assumed grid structures of the archetypes are related to the predominant existing generation resources – fossil fuelbased generators are commonly located close to the demand centres. This is less the case with hydropower. Therefore, the archetype with a share of hydropower generation features a grid with long-distance transmission between the hydropower resources and the demand centres. The archetypes have not been designed to match any existing systems. However, they aim to capture the most common typical cases in developing countries, where more guidance on designing grid codes for scaling up VRE is usually needed. Systems with very high shares of hydropower are not covered, because their VRE adoption process is less challenging – they do not have major shares of fossil-fuel-based power plants to replace, and hydropower often provides the needed flexibility to accommodate VRE fluctuations. However, hydropower plants have relatively low inertia and relatively slower PFR, often leading to low inertia issues.

Large and Medium systems
Countries with minimal VRE capacity within their power system that intend to kick off the capacity build-up process should not make the mistake of imposing lax connection requirements in the beginning. As in all other phases of VRE integration, the requirements should be oriented towards state-of-the-art VRE industry standards and rules in the countries that have already achieved significant VRE integration. These countries’ standards and rules incorporate experiences from past successes and failures and have been developed over the course of many years with input from all relevant stakeholders.


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