In the first part of this series “How electricity grew up? A brief history of the electrical grid…”, we covered from the inception of the modern electrical grid from the first centralized power plant in 1882 to 1978. Well, technically, we only covered to about 1935. But, no significant material changes occurred to the grid, or how it operated, between 1935 and 1978. The electrical grew and grew during that time, and a great many centralized power plants came on-line. And, more and more people came to be served by electricity. Here’s the grid in 1935:
And here’s the grid in 1978:
If you compare the image of the grid from 1935 to 1978, they look very much the same there are a few upgrades in the technology, but it’s the same basic set-up. In fact, if you look at grid today, it looks very similar to the grid that exists today.
The Birth of Wholesale Electricity Markets
Now, let’s talk about the big changed that occurred in 1978, and ushered in competition in the electrical industry. Let’s talk PURPA! PURPA is the Public Utility Regulatory Policies Act. The passage of PURPA in 1978 required one significant changed in how regulated utilities bought electricity. It required that regulated utilities buy power from producers that could produce electricity at a cost that was less than the utility’s “avoided cost”. (“Avoided cost” is typically understood as the cost the utility avoids by not having to generate the electricity itself, whether by operating one of its existing power plants, or building a new power plant.) This regulation gave rise to a competitive market where IPPs (Independent Power Producers) could build, operate, and compete with existing utility power plants. This free market approach has helped in diversifying our electricity generation capacity, and given rise to an increase use of renewable energy.
The requirement of utilities to purchase less expensive electricity from IPPs did create somewhat of a free market in the 1980s, but it did not grow nearly as quickly as most expected. Part of the problem was that regulated utilities still owned the transmission lines that delivered the electricity to the market. Utilities gave preferential treatments to their own generating plants for the use of the transmission lines, which unduly burdened the IPPs with higher costs, and therefore made them higher cost than the utility’s own generation. FERC (Federal Energy Regulatory Commission) passed several directives in the late 1980s and early 1990s to alleviate this issue.
The PURPA legislation and the directives from FERC helped to create the wholesale electricity markets we know today. I say “markets” because since electricity is regulated at a state level, the implementation of both the PURPA legislation, and these new directives varied widely among states. In the southeastern United States, the entire electrical grid and the wholesale electricity markets looks very much like it did prior to 1978. The New England states took a different approach, and required that all regulated utilities are not allowed to own any generating capacity. (This remained the case until recently, when the utilities were given the ability to own up to 50 MW of solar generation to support the solar Renewable Portfolio Standard. New England rarely uses less than 10,000 MW at any given time.) In the Mid-West, and most other states, the parents of regulated utilities were allowed to own generation, but this generation could not be directly owned by a regulated utility. (This is Exelon Generation as compared to ComEd for all you Chicago folks.)
The Rise of the ISOs
This seems like it would all work fairly well, especially given my simplistic grid diagram above. In practice, it’s a little more complicated than it first appears. In reality, my “power plant” in the diagram represents dozens, upon dozens, of generators, and there are hundreds of transmission lines, all connecting different points on the map, and all having different capacities. How do you coordinate all of these generators, and all of this transmission capacity, and investments in both? When a single utility controlled the entire grid, it was fairly straight forward. How do you create a mechanism so that competition can be maintained, but you still achieve a stable grid?
Now is the time of the ISO – the Independent System Operator. The ISO has a couple has a very important function in the delivery of electricity. Firstly, it is a regulated entity that owns, operates, and maintains the transmission grid between the generation power plants and the distribution grid or utility. Second, it operates the wholesale electricity market that sends the market signals to the individual generators. An ISO can also sometimes be referred to as an RTO – a Regional Transmission Operator. In practice, RTOs are nearly identical to ISOs. Here’s how an ISO looks in our electrical grid diagram, which has been up-date to reflect the grid from the 1990s:
Operation of the Wholesale Electricity Markets
So, how exactly do wholesale electricity markets operate? The elegance of the ISO is that wholesale markets operate almost exactly how they did in your Econ 101 class – the point at which supply meets demand is exactly what determines the price.
Let me take one small sidebar to explain a few fundamentals about electricity that should make the following explanation a little clearer.
Firstly, electricity cannot be stored. Electricity that is produced now needs to be used now. If more electricity than is demanded is produced, it can cause fluctuations in the voltage and increased heat in grid components can cause the grid to fail. If less electricity than is demanded is produced, voltage across the system can drop leading to brown-outs. This is what happens on hot days in the summer when there just isn’t enough generation to supply all the demand on the grid. There is some effective storage in certain parts of the grid – such as pumped-hydro, but it’s of such a small amount that it’s easier to assume that it doesn’t exist.
Secondly, different types of power plants have different energy profiles – they produce electricity at different costs, ramp at different rates, and have different peak capacities. Let’s take a nuclear power plant compared to a natural gas plant. A nuclear power plant is very expensive to build, but has a very low cost of producing electricity overall. The cost of fuel per unit of electricity is very, very low, and a unit of fuel is able to produce a lot of electricity. Also, it’s very expensive and it takes a long time to turn off a nuclear reactor and to turn it back on. For this reason, they tend to operate nuclear reactors for months or weeks on end without interruption. On the other end of the spectrum, are natural gas plants power plants. The cost of electricity for a natural gas power is almost exclusively tied into the cost of the natural gas used to power the plant. If natural gas prices are low, this electricity will be very inexpensive, and vice versa. Also, natural gas power plants can be ramped up or ramped down very quickly. This means that they can go from idle – producing no electricity, to full capacity in a matter of hours. (I’ll discuss renewable energy plants, and their various costs and complexities, in a separate entry.)
It’s time to get back to the wholesale electricity market. Since electricity can’t be stored, the ISO has to closely match the amount of electricity to the supply of electricity as demand changes throughout the day. How does it to that? It runs a real-time auction for all electricity that is needed, and it runs this auction every hour of the day. It tells every generator how much electricity it needs to fulfill the demand in the market. For example purposes, let’s say this auction is for 100 MW of power. Each generator then has to decide how much electricity it wants to deliver, and at what price. Let’s assume 4 generators – one nuclear, one natural gas, one coal, and one ambitious cyclist who’s bike is hooked up to a generator – for simplicities sake. So, the nuclear knows that it’s very expensive for him to produce electricity, so he’ll bid his 50 MW at 3 c/kWh. Natural gas is currently inexpensive, so the natural gas plant will bid in its 40 MW of electricity at 5 c/kWh. The price of coal is a little more expense, so she bids in her 50 MW of capacity at 8 c/kWh. The cyclist bids in his 5 MW of electricity at 20 c/kWh – they’re replaying the Tour de France, so he’s got better things to do.
So what’s the price of electricity for that hour? It’s actually run as a reverse auction, so the ISO ranks all the bids from lowest to highest price. The ISO then chooses all the capacity bids that added up equals the demand for electricity that hour. The price of electricity for that hour then becomes the last bid selected to reach that level of capacity. The final bid that fits underneath the demand is the 8 c/kWh from the coal plant so 8 c/kWh is the price of electricity for that hour. However, the coal plant is only asked to produce 10 MW of its 50 MW, since that is all the electricity that is demanded. The cyclist is asked to produce no electricity, since his price was too high, and there is no demand for that much electricity.
In practice, it’s a little more complicated than that. The ISO does run these types of auctions every hour of the day for the next hour. But, here’s where the complexity comes in. Each ISO is made up of multiple electricity delivery points, or nodes. An ISO can be made up of dozens of these nodes. Every hour, an auction is run for every node. The prices differ between the nodes because of the distances between the nodes and the generators, and because of the limits on the amount of electricity that can be carried by the transmission lines coming into that particular node. And, not only are auctions held every hour for the next hour (the resulting prices are call RT LMP – real-time locational marginal price), but they’re also held this hour for tomorrow’s hourly market price (the resulting prices are call DA LMP – day-ahead locational marginal price).
All this complexity can get your head swimming pretty quickly. Luckily, it’s not necessary to really understand the nuances of how this works unless you’re going to be trading electricity on the wholesale markets. For normal electricity customers like us, we just need to understand it at a high level. If you can grasp the idea of real-time hour pricing (RT LMP or DA LMP), you’ll be able to understand even the most complex electricity tariff a utility can offer you.
For more info about hourly ISO prices, check out the following:
PJM ISO http://isoexpress.iso-ne.com/guest-hub;jsessionid=CABD0A3611A38F98B987D77C8830AEEA
NY ISO http://www.nyiso.com/public/markets_operations/market_data/maps/index.jsp
NE ISO https://edata.pjm.com/eContour/#app=ecca&e929-selectedIndex=2
Prices are … Negative!
As one of my professors once said, “if you really want to make sure you understand something, do it backwards”. Well this isn’t quite backwards, but let’s see if you can follow the logic behind how and why wholesale electricity prices can sometimes go negative. Yes! Electricity prices sometimes go NEGATIVE! Turn on all the lights, and leave the fridge door open; I’m getting paid to use electricity! …That type of negative.
Think back to the way electricity prices are set in the hourly auctions. I’ll use the same 4 generators – one nuclear, one natural gas, one coal, and one ambitious cyclist who’s bike is hooked up to a generator. But, let’s greatly reduce the amount of electricity that’s demanded. Think about one of those really nice spring nights when you just open the windows before you go to bed – too warm for the heater, but too cool for the AC. The demand for electricity at 3am on one of those nights is really low. For our example, let’s say its 20 MW. So, the nuclear guy’s thinking about bidding in, but he sees how little demand there is. He also knows that if he has shut down his reactor, it’s going to be in the millions of dollars. But, if he can somehow stay on-line and just turn it down a little bit, it will be much less expensive. So, he bids in his entire 50 MW of capacity at -3 c/kWh (yes, negative). I could run through the thought process for the other generators, but I think you’ll be able to follow the logic that the nuclear guy is awarded the bid of 20 MW at -3 c/kWh. And so, the price for that hour is -3 c/kWh.
(It does cost millions to shut down a reactor, and you have to leave it down for a long period of time before you can restart it. It’s less expensive to sell the electricity at a loss for a short period of time than it does to shut down the reactor.)
That’s the basic story of wholesale power markets, how they came to be, and how they operate. As far as the history of electricity markets goes this takes us up to 1997. Next week’s article will cover the birth of the retail electricity market.