COVID-19 Implications on Electric Grid Operation
By Asma Aziz, Aman Than OO
Worldwide electricity markets work diligently to maintain balance between generation and demand in real time. Energy markets daily operations are based on the current and forecasted demand of electricity and distribution of this demand amongst the pool of scheduled and nonscheduled electricity generators. Generally, electricity is consumed by three major sectors, namely industrial, residential, and services. The real time electricity demand profile is constructed from the residential, commercial, and industrial needs throughout the day. The energy market coordinates the dispatch of generators and their payment on the basis of supply-demand conditions. Generator bids are influenced by a number of factors such as fuel costs, minimum and maximum demand, contract volumes and the capital costs. Generators bid the price at which they are willing to supply a certain volume of electricity and that will be dispatched on the basis of lowest price.
COVID-19 pandemic is having major impacts on every aspect of life including the electrical grid and their operations. The short-term impacts of collective mitigation actions worldwide are visible in terms of the affected regions' demand. With the majority of the population working from home, there is a shift in energy usage patterns. Electricity demand worldwide is significantly reduced from the previous year during the same time period and the demand curve has also taken a new shape in the affected regions. Many countries and jurisdictions have witnessed a reduction of 3% - 10% demand in the past month. From the predictable camel curve shape with two prominent humps before noon and in the evening, the new demand camel curve is much flatter, without the same hump usually shown by the morning and evening peaks and valleys. With commercial loads shifted to the residential load, various governments are providing tax relief or change in the payment plans to mitigate the increase in the domestic bills. However, Governments will need to relook at their policies and ponder over the far reaching effects of this pandemic impact on the energy systems over the longer term.
Although this is not a great concern at the moment, a decline in minimum demand over a sustained period may raise power system security and financial implications for utilities in the future. Grid operators are interested in short term demand forecasting while electricity traders and system planners require medium to long term demand forecasting for generator scheduling and system planning. In the longer term, there may be adverse economic and technical implications of declining demand on the power system operation. Some of these issues are described below.
Generator curtailment and spot market operation:
Spot market matches real time instantaneous demand with power supply through a centralized dispatch process. A specified amount of electricity at specified prices is offered by generators to be supplied to the market for agreed time periods. The market operator scrutinizes all the bids and decides the deployment of the specific generators to produce electricity according to cost-efficient methodology with dispatching of the cheapest generator. Spare generating capacity is kept as the reserve after matching electricity consumption with power generation. In countries like Australia, every 5-minute target is applied to determine a dispatch price based on the highest or the marginal bid for electricity delivery. A spot price is then determined for each region by averaging dispatch prices over every half hour period. The Australian system was set to be changed to a 5-minutes basis by 2021, but now it will be postponed due to the post pandemic impacts.
Utility revenue projections are typically closely tied to the region’s load forecast. Generators must be able to earn enough revenue from the selling of energy to provide incentives for future investment, thereby ensuring market equilibrium. Lower demand means there will be less space to operate larger conventional generators due to low electricity prices and low earnings for generators to recover their fixed costs. Such an outcome can lead to insufficient levels of investment due to uncertainty around future revenue streams, or even premature generator exit. Italy has already started witnessing a change in the generation mix with reduced thermal based generation.
Ancillary Service Operation:
Frequency regulation ancillary service cost is highly dependent upon the generation technologies, demand predictability, and specific regulation of the respective jurisdiction. In the aftermath of the COVID-19 pandemic, if commercial business loads fail to recover and work from home policies become more common, there will be surplus generation. Some of the generators will need to be curtailed. Synchronous generation reduction will further reduce the system inertia leading to an increased rate of change of frequency (ROCOF). ROCOF management is critical to the grid frequency regulation up to the frequency operating standard. Lower inertia leads to a higher ROCOF than the higher inertia system. This means that frequency changes faster following a disturbance in a power system with less synchronous generation, and this could result in loss of additional generation or load to arrest the frequency deviation when it occurs. Reduced system inertia can challenge the effectiveness of existing frequency control mechanisms, which can reduce under high ROCOF. Australia has since introduced a mandatory obligation rule on 26 March 2020 for the generators in the national electricity market to help control system frequency by responding automatically to changes in it. Voltage control can be a major issue for distribution networks in those cities where rooftop solar penetration exceeds 20% of homes. The level of demand for grid power in some feeders can drop close to zero in the middle of the day as demand is met by rooftop solar PV.
Maintenance of power supply reliability standard necessitates availability of a certain amount of reserve power online at all times as a buffer in case of contingency or disruptions. For regions with high concentration of PV in the electrical grid, electric demand will be further reduced, the peak plants and all the intermediate plants will need to shut down, and some of the base load plants will be required to ramped down too. With much of the demand supplied by solar PV, maintaining conventional reserves online will be difficult, thus necessitating PV plant curtailment. Australia has current reliability standard of maintaining the minimum local generation in each region targeting 0.002% unserved energy in any year which is proposed to be increased to 0.0006 per cent in any region in any year. A tighter reliability standard will require more generation and/or demand response available to reduce the duration of wholesale outages from 10½ minutes per year to just over 3 minutes per year. However, this reliability standard will need to be reviewed again in view of the low demand post pandemic.
Utilities should also expect a potential reduction or reallocation of planned capital expenditures over the next several years. Energy projects especially wind projects may be delayed due to lack of workers and funds. Nearly 39% of new electricity generation projects in the US set to come online over the next six months could be stalled. Other possible implications may be in the form of supply chain disruptions, efficient workforce productivity, and increase in operation and maintenance cost. Extended pandemic period for more than 12 months could require significant re-adjustments of markets, which will substantially challenge utility revenues.
This article edited by Hossam Gabber
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