Grid codes are the key for the technical performance of any new installed generating plant. In order to successfully manage the transition towards a more sustainable power system (PS), the technical rules applied to all kinds of generation must be suitable still in years and decades from now. The challenge is to estimate today which technical feature will be crucial for the stable operation of the PS, in light of a generation mix that changes from centralised, relatively large power plants using synchronous generators connected to the transmission grid, towards a decentralised, mainly inverter-based generation mix, that uses volatile renewable sources. This study is based on experiences in central Europe and several countries overseas. It does not refer to one specific market but attempts to learn from the past and give qualitative ideas how the technical system needs of today and the future should be addressed in any PS. A quantitative analysis of future PS needs is what the authors wish to encourage as a next step.

The drive towards renewable energy sources (RES) is dramatically changing the dynamic electrical characteristics of Generators, which are traditionally the dominant dynamic component in Power Systems. Non-synchronous generation (NSG) approaching or even exceeding control area demand is now happening on a rapidly expanding scale. The study identifies from National Grid's perspective as Great Britain transmission system operator, the key challenges during periods of operation with high proportion of RES relative to demand. It raises some major questions. What determines system strength in an HVAC system largely without synchronous generators and what is adequate for stability? What levels of %NSG can be expected in the future energy scenarios? What are the financial consequences of constraining RES production if the technical capabilities create an upper limit of %NSG which the system can be operated at? The study finally proposes closer collaboration across the industry to find the optimal missing solutions.

The need for European Network Codes (NCs) was identified during the course of developing the third legislative package for an internal EU gas and electricity market. The first NC that was initiated by the European Commission covers ‘Requirements for Generators’ (NC RfG) (ENTSO-E, 2013). After an extensive debate and drafting process across TSOs, DSOs, manufacturers, generation owners, industrial consumers, NRAs and policy makers, ENTSO-E finalised drafting the NC RfG in March 2013 (Further changes, especially with respect to the fault-current injection by wind power plant (WPP) were introduced during the process of transferring NC RfG to a EU Regulation as result of the ongoing discussions between the European Commission and relevant stakeholders. See the remark in Section 3 ‘Outlook and Conclusion’.). European wind turbine manufacturers represented by EWEA participated strongly in the dialog with ENTSO-E and the stakeholder consultation. A delicate exercise in developing the NC RfG was the appropriate balance between those aspects that need to be defined exhaustively at European level, and the non-exhaustive connection requirements where further specifications are needed at regional level to cover local system needs. Although improvements were seen, significant concerns still remain with the current document, largely focused on the uncertainty from the many non-exhaustive requirements and therefore having to wait for the national Grid Code processes for many parameters. This study explores the need for fault-ride-through capability from a power system security point of view. The requirements stated in the NC RfG, capabilities of WPPs and challenges related to the non-exhaustive requirements of the NC RfG are presented and discussed with the intention to provide technical background information, which may support the national implementation of these requirements.

This study investigates the impact of the injection of additional reactive current and of active current reduction during fault-ride-through (FRT) of generating units connected to the grid via fully rated voltage-sourced converter (VSC generating units) on the behaviour and stability of the power system. The primary focus is on voltage support, transient stability and frequency stability. The investigation is carried out via computer simulations using a fictitious transmission system, based on German grid code requirements. The K-factor of the dependence of additional reactive current with voltage deviation, the method of active current limitation during FRT and the rate of active power recovery after fault clearance are varied. Results and influences are illustrated and discussed. They show that with an increasing number of converter-connected generating units in power systems, a careful selection of the parameters becomes very important. Insufficient grid code requirements may increase the risk of system instability. Conclusions are drawn and recommendations for optimal settings with respect to future development of grid codes are provided. The mechanism of loss of synchronism of VSC generating units because of inadequate current injection (current angle instability) is explained.

This paper reviews the economics of solar power as a source of grid-connected electricity generation. It is widely acknowledged that costs of solar power have declined, but there is disagreement how its economic value should be calculated. ‘Grid parity’, comparing generation costs to the retail price, is an often used yet flawed metric for economic assessment, as it ignores grid fees, levies, and taxes. It also fails to account for the fact that electricity is more valuable at some points in time and at some locations than that at others. A better yardstick than the retail price is solar power's ‘market value’. This paper explains why, and provides empirical estimates of the solar market value from a literature review, German spot market analysis, and the numerical electricity market model EMMA. At low penetration rates (<2–5%) solar power's market value turns out to be higher than the average wholesale electricity price – mainly, because the sun tends to shine when electricity demand is high. With increasing penetration, the market value declines – the solar premium turns into a solar penalty. In Germany, the value of solar power has fallen from 133% of the average electricity price to 98% as solar penetration increased from zero to 4.7%. This value drop is steeper than wind power's value drop, because solar generation is more concentrated in time. As a consequence, large-scale solar deployment without subsidies will be more difficult to accomplish than many observers have anticipated.

Historically, solar photovoltaic (PV) generation has been able to claim a significant ‘premium’ in revenues over other generation types because of its correlation in operation with peak demand (and therefore high priced) periods. However, similar to many international markets, recent conditions in the Australian National Electricity Market, including low demand, high levels of rooftop PV generation and oversupply of capacity, are found to have eliminated the revenue premium for solar. Half-hourly modelling to 2030 illustrates that historical premiums are unlikely to resurface. Storage is shown to increase solar revenues at high penetrations, but can have a detrimental effect on solar revenues at lower solar penetration levels. Therefore at high solar penetration levels, solar generators will be incentivised to develop storage assets, since they can capture additional portfolio market benefits by minimising the decline in solar premiums because of the merit order effect. In contrast, most other market participants will find storage detrimental to revenues because of increasing competition during high priced periods, and will therefore have less incentive to include storage in their portfolios.

The need for long-distance power transfers in the electricity system is being driven by both deeper market integration and the increasing share of renewables in generation. The best renewables resources are often located far from load centres, while variable renewables, such as wind and solar, benefit from smoothing effects when aggregated over large areas. However, the increased usage of transmission infrastructure raises the question of how the associated costs should be distributed. The authors present here the application of an existing algorithm called marginal participation (MP) which can be used to allocate the power flowing through each network asset (lines and transformers) to particular network users. They consider two new methods to extend the MP algorithm to high voltage direct current lines that operate parallel to alternating current networks. They then apply the allocation algorithm to a future scenario with high renewables penetration in Europe in 2050, developed as part of the Smooth PV project. They see a significant increase in network usage, including a rise in the proportion of cross-border flows. The increase in network usage is driven disproportionately by offshore wind, because of its geographical concentration away from load centres.

The Republic of Ireland and Northern Ireland have ambitious targets for 40% of electricity to be supplied by renewables by 2020, with the majority expected to be supplied by wind power. There is, however, already a significant amount of wind power being turned down, or ‘curtailed’, and this is expected to grow as wind penetrations increase. A model-based approach is taken to estimate curtailment using high-resolution wind speed and demand data covering four years, with a particular focus on the temporal characteristics of curtailment and factors that affect it. The model is validated using actual wind output and curtailment data from 2011. The results for 2020 are consistent with previously published estimates, and indicate curtailment levels ranging from 5.6 to 8.5% depending on assumptions examined in this study. Curtailment is found to occur predominantly at night, and to exhibit stochastic variability related to wind output. To accommodate high penetrations of wind power, the findings highlight the value of flexible demand over relatively long time-periods. The model's output data have been made publicly available for free for further investigation.

The design of control circuit for a solar fed cascaded multilevel inverter to reduce the number of semiconductor switches is presented in this study. The design includes ‘binary’, ‘trinary’ and ‘modified multilevel connection’ (MMC)-based topologies suitable for varying input sources from solar photovoltaic's (PV). In binary mode, 2 ^{N _s +1} − 1 output voltage levels are obtained where N_s is the number of individual inverters. This is achieved by digital logic functions which includes counters, flip-flops and logic gates. In trinary mode, 3 ^Ns levels are achieved by corresponding look-up table. MMC intends design in both control and power circuits to provide corresponding output voltage levels by appropriate switching sequences. Hence to obtain a 15-level inverter, the conventional method requires 28 switches and in binary mode 12 switches are needed. In trinary mode with the same 12 switches, 27 levels can be obtained whereas in MMC only 7 switches are employed to achieve 15 levels. The advantage of these three designs is in the reduction of total harmonic distortion by increasing the levels. Simulations are carried out in MATLAB/Simulink and comparisons were made. All the three topologies are experimentally investigated for a 3 kWp solar PV plant and power quality indices were measured.