Jenny Riesz

The Evolution of the Market: Designing a Market for High Levels of Variable Generation

Renewable energy was not the initial justification for electricity markets, but it is rapidly becoming a driver for new markets and market design changes. Starting in 1982 with market reforms in Chile, competition has been introduced into wholesale electricity markets around the world. This trend is likely to accelerate with countries such as China planning a major restructuring of power systems that could result in electricity markets.

Examining the viability of energy-only markets with high renewable penetrations

An illustrative energy-only electricity market model was used to explore possible market outcomes in scenarios with 100% renewable energy, including high penetrations of low operating cost variable technologies such as wind. Results indicate that even in scenarios with wholesale market prices at

Assessment of minimum inertia requirement for system frequency stability

0/MWh in the majority of periods, all technology types can precisely recover their costs via energy-only wholesale market revenues, if the generation mix is least cost optimized. Importantly, this includes the variable generation technologies. Furthermore, it is illustrated that exercise of market power is not essential for the modelled energy-only market; generators recover costs based upon short run marginal cost (SRMC) pricing alone (representing a highly competitive market), as long as the Market Price Cap (MPC) is set appropriately to reach the desired level of unserved energy. The appropriate setting for the MPC depends upon the cost parameters for the highest SRMC plant (often open cycle gas turbines).

Impact of high variable renewable generation on future market prices and generator revenue

The reduced amount of rotational kinetic energy in power systems has significant detrimental impacts on system frequency behaviour. To ensure system security, this issue must be addressed in a systematic way. Given this, we consider three different metrics, namely i) minimum power penetration from synchronous generators, ii) minimum rated power of synchronous generators, and iii) minimum synchronous kinetic energy, as frequency control constraints in the market dispatch model, and assess frequency behaviour of the system for these metrics. The results show that each metric has a different impact on market dispatch, and, accordingly, on the system frequency behaviour. It is shown that with high penetration of converter-based generation, we need to consider a minimum kinetic energy requirement as a frequency control security constraint in the market dispatch model to guarantee the frequency stability of power systems.

Future high renewable electricity scenarios — Insights from mapping the diversity of near least cost portfolios

This study assesses the potential impact of high renewable generation on the spot electricity prices, generator revenue and profits in an energy-only electricity market. In particular, it presents modelling outcomes for the Australian National Electricity Market (NEM) with a range of possible renewable penetrations in 2030. It is assumed that the current reliability standard is maintained and participants deploy short run marginal cost bidding. The study found that increasing the share of wind and PV generation would likely result in lower average spot prices and subsequently revenue and profit of generators. The revenue impact on large-scale PV was found to be very severe and could lead to insufficient revenue to cover the costs, particularly at higher renewable penetrations. Changes in market mechanisms, such as increasing the Market Price, may be required to ensure revenue sufficiency and long-term resource adequacy in an energy-only market with high renewables.

What cost for more renewables? The incremental cost of renewable generation – An Australian National Electricity Market case study

This paper reports on future electricity generation scenarios modelled using NEMO, a model that applies a genetic algorithm to optimise a mix of simulated generators to meet hourly demand profiles, to the required reliability standard, at lowest overall industry cost. The modelling examined the least and near least cost technology portfolios for a scenario that limited emissions to approximately one quarter of those from the Australian National Electricity Market (NEM) at present. It was found that all the near least cost solutions (within 15% of the least cost solution) involved wind capacity in the range of 31-51 GW, with 98.8% of these near least cost portfolios having at least 35 GW of wind installed. In contrast, the near least cost solutions consistently involved much lower quantities of PV, with 90% of the near least cost portfolios having less than 4.9 GW of installed PV capacity. This suggests that policies to promote high levels of wind deployment and grid integration are likely to be important for achieving low cost, low emissions outcomes, while policies to promote significant PV deployment may be less warranted in the absence of cost effective supporting technologies, such as battery storage or significant demand side participation.