Incorporating a Market-based Rate of Change of Frequency Control Ancillary Service in Nodal Electricity Markets

Having a market-based incentive to provide RCS is expected to encourage more facilities to provide inertia to ensure that the system operates in a secure and stable manner. The RCS and the price signal it generates provides an opportunity for innovation, in both market design and operations.

A test system is developed with detailed characteristics of a power system, including network topology, generator parameters, and load parameters. A bespoke nodal SCED optimisation engine is used to conduct security analysis and incorporate RCS requirements and constraints to the optimisation model.

The results of the case simulations provide evidence of the expected interplay between energy, contingency raise, and RCS within a SCED nodal market formulation. For example, a marketbased RCS enables efficient trade-offs between energy concentration, contingency raise, and

RCS. When inertia is fixed administratively, the system is prevented from exploiting cheaper energy schedules even when it would be economically efficient to compensate through additional security services. Co-optimising RCS helps achieve frequency security at lower overall system cost than administratively fixed inertia requirements.

Overall, the resulting behaviour demonstrated that a market-based RCS and DFCM modelling approach is not inherently limited to purely zonal markets and can be applied to a nodal market framework. The findings support the feasibility of future nodal market designs that incorporate frequency security and inertia pricing mechanisms.