If you haven’t already read the previous Power Markets 101 posts, catch up.
Now that we’ve covered some grid basics and the history of the existing Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs), we’re ready to discuss how competitive, deregulated energy markets operate.
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In competitive energy markets, the ISOs or RTOs must ensure that power is available as consumers demand it. They do this by:
It is important to remember that energy supply and demand must always match. If people used the same amount of energy at the same time every day, balancing these would be easy. However, many factors impact energy load, which is the term for cumulative energy demand at any given point in time. These include weather, time of day, economic activity, and current events.
Since one of the ISOs' main goals is to provide reliable electricity, ISOs make educated energy forecasts for the next day. However, it’s impossible to predict the next day’s load exactly. For this reason, they operate a dual-settlement market design also called a two-stage market, which consists of the day-ahead market and the real-time market.
In the day-ahead (DA) market, once the ISO has forecasted the next day’s load, it has to schedule generation. Each generator tells the ISO how much power it is willing and able to produce the next day and what it will charge for each megawatt-hour (MWh).
In addition to ensuring that the supply of electricity is reliable, the ISOs' other main function is to minimize the cost of electricity. They do this by using the cheapest feasible generation providers first, only taking the more expensive generators' offers when necessary to meet the forecasted load.
The last generator scheduled, with the most expensive price, sets the clearing price for every MWh provided by all the generators. This is the system of economic dispatch, where the system operator determines which generators they need at which times of the day.
The real-time (RT) market is the market where the ISO meets the actual demand, in real-time, by bringing generators on and offline. The changes to the day-ahead forecast and generation schedule can be made anywhere from an hour to five minutes before when the change in the generation is required. Because the demand for electricity varies, the real-time market can be significantly more volatile than the day-ahead market.
In principle, generation in the real-time market is scheduled in the same way as the day-ahead market. Market participants continually update unit offers based on the weather and necessary maintenance, and the ISO accepts the lowest offers first until demand is met.
In practice, the real-time market is slightly more complicated. Some types of generators have faster ramp rates than others (meaning they can start up faster), and renewable generators’ energy production can't be scheduled. (We’ll discuss the nuances of these different generators in our next post).
Another problem is that transmission lines can only transport so much power at one time. If there's too much power flowing across a transmission line, it can burn out. Obviously, the ISO and other market participants don’t want this to happen, so there are controls to make sure that it doesn’t. These include directing power to other transmission lines and using different generators than might be used otherwise.
When there is the risk of too much power flowing across a transmission line, it is called a transmission constraint.
The ISO controls real-time generation through pricing signals to mitigate this constraint risk. ISOs send pricing signals to different pricing nodes. Pricing nodes are specific locations on the grid linked to a component, like generation, load, or transmission.
If the ISO needs a generator to start producing more power, it will increase the price at that pricing node. If the ISO needs a generator to produce less power, it will decrease the price at that pricing node.
The result of economic dispatch and pricing signals is locational marginal pricing (LMP). There are different prices for each node on the grid, based on the clearing price at each specific node on the grid and the cost of producing the next MW of energy. The cost of producing the next MW of energy depends on the actual cost of generating that MW but also on the losses that occur on the transmission line and the impact of congestion on transmission lines.
Lastly, since one of the ISOs' main goals is to provide reliable electricity, they plan backup generation for times when the load is significantly greater than forecasted or transmission lines are particularly congested.
They ensure this reliability through the ancillary service and capacity markets.
In the ancillary service market, generators can offer to hold back X MW of power for a certain price, to use if necessary. These reserves are normally spinning reserves or reserves that can ramp up (or down) quickly.
Capacity markets help make sure that there will be enough generation available for the coming years. In a capacity auction, generators offer to remain operational for a set period of time for a fee. This fee is called a capacity payment.
We explained how ISOs function using the DA, RT, ancillary service, and capacity markets! Next, read our blog post about the basic principles of electricity generation.
For more information on the terms in this blog on deregulated energy markets, check out the Yes Energy Glossary.
Resources we found helpful when putting together Power Markets 101 are available.
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