 PJM, they used a different model, a different market model, which is sometimes called a pool. And the way that the PJM or pool market works is that individual generators commit their capacity to the market, or the pool. And the pool decides which generators are going to run at which hours. And so the generators don't decide this on an hour to hour basis. The pool actually decides this on an hour to hour basis. And the way that generators are allowed to structure supply offers is much more limited in the pool than it was in the power exchange. In the pool, the supply offers from generators basically just reflected variable cost. And so capital cost recovery and other things were made up through separate payments or separate markets. So the pool type market has really become the dominant market model used in the US today. And the pool type market was more or less what first standard market design looked like. And so the markets that are run by regional transmission organizations are all run as what we call uniform price auctions. And so the way that a uniform price auction works is that suppliers submit supply offers to the RTO. And then these offers are aggregated to form a system supply curve. Originally, demand was assumed to be perfectly inelastic, which is the same thing as saying a vertical demand curve. So whatever demand happened to be, that's what it was. And they would pay whatever price the market happened to produce. And then at the point where this vertical demand curve crossed the offer curve or the supply curve was the market clearing price or what we call the system marginal price for that particular time. So I'll show you a couple of different pictures of this. This is approximately what the supply curve looks like for the PJM market. And a couple of things about this supply curve is that, first of all, it has this kind of hockey stick sort of shape. There's over a large range of electricity demand, the market price would not vary all that much. Or the cost of generation would not vary all that much. And so in the example that I have here, if demand is 100,000 megawatt hours, then, which is this vertical line about here, the point where that vertical line crosses the supply curve is what sets the market price for that particular time period. And so in this particular time period, at a demand of 100,000 megawatt hours, the price would be $80 per megawatt hour. And if the price was a little bit lower or a little bit higher than that, so if it was, say, $80,000, instead of $100,000, the market clearing price would not change all that much. But as demand increases, in this case, past 100,000 or 120,000 megawatt hours, then the cost of the capacity you would have to use in order to satisfy that demand starts to rise very sharply. And so this point, the part of the supply curve over here, where the price starts to rise very steeply, I sometimes called the devil's elbow. And so if we have demand of 140,000 megawatt hours, then all of a sudden, the price would jump to $160 per megawatt hour. So we have increased demand by 40%, and we have doubled the price. So at high levels of electricity demand, the small changes in demand can produce much larger than proportional changes in price, in the market price. So the last generator that is dispatched to meet electricity demand is the generator that basically sets the market price or the system marginal price. And the way that these uniform price options work is that that system marginal price or that market price is paid to every generator whose supply offer was lower than the market price. And so if you're a generator, your profit during any time period is equal to whatever the market price is minus your marginal cost. And so sometimes you'll hear this profit referred to as a scarcity rent. So the way that these uniform price options work, if any of you have taken like Intro Econ or Econ 101 where you have a demand curve and a supply curve and that sets the market price, this uniform price auction works very similarly. And so the way that these markets work is not dissimilar to just about any other market in the world. There is a variation on the uniform price auction called the pay is bid auction. And this is used in the United Kingdom but not in the United States. And the idea behind the pay is bid auction is that there's still a system marginal price that is produced through the market. But rather than each generator earning the system marginal price, each generator who is accepted into the auction, each generator that bids below what the system marginal price turns out to be is paid whatever their bid was. So as I said, this is used in the UK, not in the US. The belief in the US is that if you switch to a pay is bid system, this would simply give generators incentives to manipulate their bids. So if you're a generator that has a marginal cost of $5 a megawatt hour, and you believe that the market price or the system marginal price will be $50 a megawatt hour, in the uniform clearing price auction, you would earn $50 minus 5 equals $45 per megawatt hour in profit. Whereas in a pay is bid auction, if you actually submitted a bid that was equal to your marginal cost, then you would earn $5 per megawatt hour. And so the thought in the US is that this would give this particular supplier an incentive to inflate their bid up to whatever they thought the market clearing price would be. So the pay is bid system is not really used in the US. So basically all of the centralized wholesale markets run by RTOs follow this uniform price auction format.