Peaks cause major headaches for system operators, so how can they be countered?
Maintain a diverse generation pool with reliable baseline capacity.
Build stand-by generation, such as peaker plants to meet Peak demand.
Implement demand side management (DSM) mechanisms, such as; Demand Response (DR), Time of Use (TOU) pricing, load shifting, and moving operations to off-peak hours.
Peaks threaten blackouts or brownouts, which can massively disrupt businesses, industry, and residential customers. They also complicate the efforts of system operators to ensure reliable and sufficient supply for all user demands.
Peaks can also increase financial burdens for the grid by creating the need for peaker capacity, raising operating and investment costs. In this article, we’ll be looking at some of the different (and complementary) ways that system operators can tackle Peaks.
First objective – Baseline generation
The main mission for any system operator is to ensure adequate baseline generation – reliable, easily activated generating sources, typically nuclear or fossil fuels.
For example, about 75% of PJM’s generation mix is nuclear and gas, two important baseline options. Ensuring a diversified generation mix is key as it provides grids with flexibility to compensate for changes in variable renewable sources such as solar and wind.
Standby generation – One option for system operators
In order to make sure that enough electricity is available for consumers during Peaks, system operators have several options at hand. The first option is to use standby generation. Some operators choose to build peaker plants – power plants that only come online when necessary (usually a few days or weeks each year), in order to help the grid meet demand.
This option guarantees that enough generating capacity is available, but is very expensive, as new power plants have to be built that only operate for very short periods of time.
The cost of building new infrastructure (including peaker plants) as well as of maintenance can be quite high, so system operators include surcharges on the price of electricity to help pay for these investments. If energy use keeps going up, then the amount of baseline and peak capacity also increases.
This usually means that electricity prices will continue to rise each year as new generation capacity will be required. This is why system operators seek to flatten peaks as much as possible in order to avoid ever mounting standby generation, operation overhead, maintenance, and procurement costs.
Demand side management – Another option for system operators
System operators can try to deal with Peaks by using time-of-use (TOU) pricing.
Basically, this means that the price you pay for electricity changes throughout the day, depending on what time it is. The price is higher during peak times, like during the evening when everyone comes home and turns on appliances.
The idea behind TOU is to make consumers aware of the costs associated with Peaks, and to thereby encourage them to shift when they do energy-intensive activities during off-peak hours.
These higher prices – or the difference between off-peak and peak prices – is called a demand charge.
Traditional electricity rate structures don’t show the real cost of using electricity at different times, so consumers end up using energy indiscriminately. System operators use TOU and demand charges to persuade energy users to change their behaviour and thereby help relieve stress on the grid (i.e. the difference between off-peak and peak pricing in Ontario is almost double, at 10 cents and 17 cents, respectively).
More recently, the impact of TOU has become a key concern for many people forced to work from home due to the COVID-19 pandemic. Awareness of differences in TOU pricing has led to calls from consumers for more extensive off-peak prices during these difficult times.
“Traditional electricity rate structures don’t show the real cost of using electricity at different times, so consumers end up using energy indiscriminately.”
System operators have historically targeted large commercial and industrial consumers, but residential consumers are increasingly becoming familiar with TOU pricing. Since companies and factories use a lot of energy, the potential savings from switching when they do certain activities can be very large.
This is known as load shifting and is one example of demand response, which is a suite of technological and behavioural changes that consumers can implement in order to reduce energy use, save money, and help grid stability.
Encouraging users to shift energy intensive operations to non-peak hours, together with scheduling maintenance to coincide with peaks – thus minimizing downtime – are just two ways that load shifting, and DR, in general, can help system operators combat peaks.
Further options include investments in smart meters and smart thermostats to quickly respond to energy curtailment events.
Promoting the incorporation of on-site energy storage systems, such as electric vehicle batteries or water heaters, can store energy at off-peak prices, and release that energy during peak hours. Ensuring a diverse generation portfolio that incorporates reliable baseline capacity to offset the volatility of renewables like solar and wind also helps reduce the risk of peaks emerging due to seasonal or weather-related factors.
Peaks are also pests at the zonal level
Peaks can also affect systems at the zonal level, where one section or zone of the grid is either producing too much or too little energy, while another has a corresponding deficit/surplus. Part of the fee structure surrounding peaks has to do with transmission charges, namely the fees paid by the system operator to transmission line owners to shift energy to where it is needed.
System operators also have to pay generators the difference in energy prices that may exist between zones, as each zone’s generating costs and capacity profile may be different. These fees are then passed along to the bills of consumers.
“Energy users can play their part by researching their local DR programs and other regional energy initiatives.”
To illustrate this point, let’s set up an example. For instance, as part of the North East Power Coordinating Council (NPCC), the IESO can aid other system operators like PJM or NYISO by providing energy to these systems in cases of generation loss.
Say PJM suffers a 600MW capacity loss, other NPCC members will offer to provide 50% of said loss, with the affected system operator responsible for the other half (i.e. IESO, NYISO, and ISO-NE each provide 100MW).
A second element to consider is the price of electricity in both zones. If electricity costs $25MW/h in Zone A but $30MW/h in Zone B, then the Zone A generators generating the 200MW being transferred to Zone B need to be paid the difference.
The Zone A generators have a contract that guarantees them a certain price, but if the generation is being transmitted elsewhere then it is unfair if they are not paid the same rate as if they generated the electricity in Zone B.
Peaks are complicated beasts – they can rear their heads at a system as well as a zonal level, and require a rapid response from system operators. Managing peaks is one of the key obligations of any system operator, who needs to balance their responsibility to customers with ensuring stable prices and adequate supply.
Energy users can play their part by researching their local DR programs and other regional energy initiatives. We here at EnPowered are more than happy to chat with you about your business’ needs, energy profile, and how we can help you start tackling Peaks properly.