The links below provide an outline of the material for this lesson. Be sure to carefully read through the entire lesson before returning to Canvas to submit your assignments.
The regulated electric utility model that we studied in Lesson 5 served the industry and consumers well for nearly a century. Costs and prices fell nearly continuously, and service expanded to nearly every corner of the U.S. While other countries experimented with their own regulatory systems, for the most part, these involved national electric utilities, not the regulated private enterprises found in the United States.
Beginning in the 1970s, the trend of falling prices suddenly reversed, and the decades of technological progress in power generation slowed. The rapid pace of technological advance had masked some fundamental problems with the way in which electric utilities were regulated. Dissatisfaction among electricity consumers grew, paving the way for the grand experiments in electricity deregulation and restructuring that continue to this day. This lesson and the following lesson will provide an in-depth discussion of how these new markets are structured and will describe some fundamental changes in how the price of electricity is determined. The basic market concepts will be discussed in this lesson, while the next lesson will examine how these markets are changing in response to the emergence of large-scale renewable power generation.
By the end of this lesson, you should be able to:
This lesson will take us one week to complete. Please refer to the Course Calendar for specific due dates. See specific directions for the assignment below.
If you have any questions, please post them to our Questions about EME 801? discussion forum (not email), located in the Start Here! module. I will check that discussion forum daily to respond. While you are there, feel free to post your own responses if you, too, are able to help out a classmate.
Technology improvements and economies of scale caused electric rates to fall until 1970, which made industry and residential customers happy. In 2002 dollars, price fell from about $5.15 per kWh in 1892 to about 9.7 cents per kWh in 1970. The highly regulated structure of the electric utility business created a stable environment for expansion of access to electric power. Beginning in 1970, however, prices for electric power began to rise sharply: 320% in current dollars from 1970 to 1985 (28% in inflation adjusted prices), as shown in Figure 6.1.
The oil embargo of 1973-74 affected both the production and consumption of electricity. Petroleum fueled 17% of US electricity generation at that time, and so, the curtailment in supply reduced the ability to generate needed electricity. (Today, petroleum supplies only 2%). The uncertain supply and much higher prices (which jumped from $3 in September 1973 to $12 a barrel in January 1974) had a devastating effect on the economy directly and the demand for electricity indirectly. Electric power generation in the United States in the period 1949 through 1973 increased exponentially (at the compounded rate of 7 ¾ % per year), and linearly since 1973 (with annual increases of 70 billion kilowatt-hours per year, the equivalent of roughly 15 new large generation plants per year), as shown in Figure 6.2. The transition from exponential to linear growth was unanticipated, and led to the decade-long over-capacity of generation discussed above. The industry went through a difficult time after 1973 adjusting to the slower rate of growth utilities had in startup, construction, or planning a doubling of generation capacity. No one knew how long the decreased demand would last and, given the penalties of delaying or canceling construction, much of this capacity was built. If the industry had continued to grow exponentially, it would be almost twice as large today as it actually is.
Price increases were driven by higher petroleum, coal, and natural gas prices, rate increases to cover the cost of over-capacity, particularly in generation, reduced rates of technology improvement, and by investments in coal and nuclear generation plants of a size which stretched available technology beyond cost effectiveness. In the 1970s, nuclear power plants promised low cost, environmentally benign power. Many utilities started construction of new nuclear plants. Unfortunately, the utilities learned that building and operating nuclear plants was much more difficult than operating dams and fossil fuel plants. As a result, there were vast cost overruns in construction, e.g., Diablo Canyon and the Washington Public Power System, and poor plant operation, e.g., the fuel rod meltdown at Three Mile Island.
Building excess capacity, eliminating some plants that were in planning or early stages of construction, and having nuclear plants that turned out to be much more expensive than estimated and which didn’t operate well generated tremendously high costs. Public Utility Commissions and consumers resisted putting these costs into the rate base, since they raised costs (and prices) markedly. However, since the PUCs had generally approved the investments, there was little alternative to reimbursing the utilities for the majority of these costs.
The electricity price increases came at a time when deregulation of the airlines (1978), railroads and the trucking industry (1980) were reducing prices substantially. The price increases upset consumers and generated intense political pressure to hold down electricity rates. One proposed answer was deregulating electricity, fostering competition and lower prices
As a reaction to the 1973 energy crisis, Congress passed the 1978 Public Utilities Regulatory Policies Act (PURPA), eliminating, at least in principle, protected monopolies for electric generation. The success of early non-utility generation facilities and of deregulation in other industries led to provisions in the 1992 Energy Policy Act encouraging wholesale and retail choice in electricity. Over the next decade, nineteen states and the District of Columbia enacted some form of electric restructuring legislation.
As shown in Figure 6.1, the price of electricity rose 50% from 1970 to 1975. The “minor” issues in the Rate of Return Regulation (RORR) structure that had been ignored now became major problems. The defects had been hidden by rapidly evolving generation technology that continually lowered generation costs.
Clearly, there were problems with RORR. One alternative would have been to reform the regulatory process, as was originally tried in the United Kingdom. The other alternative, which was embraced first within Chile and the United Kingdom before spreading to the United States, was a package of reforms that would change the way that some parts of the industry were regulated, and loosen regulations in other parts of the industry.
Both of the terms “deregulation” and “restructuring” are sometimes used interchangeably to describe the changed in the electric power industry starting in the 1990s. While the terms are not interchangeable, both in fact are correct. The generation segment of the electricity supply chain has been progressively deregulated, with power plants competing with one another in many areas of the world to provide service to a regional grid operator. Electric transmission has largely been restructured, not deregulated, with transmission regulation shifting from a local to regional scale. In the U.S., this has meant that the regulation of electric transmission has shifted from state to federal authorities. Electric distribution has, with few exceptions, retained the same regulated structure that it has always had. This “last mile” of wires service is provided by a public utility that is granted a local monopoly in exchange for rate of return regulation by the state. In states that have undertaken deregulation and/or restructuring, the “electric utility” is in many cases just a distribution company.
Please read the first two sections from Blumsack, “Measuring the Costs and Benefits of Regional Electric Grid Integration [2],” which describes in more detail the process of deregulation/restructuring and some of the important U.S. federal policy initiatives that have pushed the industry towards its new state. It is important to realize that some aspects of restructuring have essentially arisen from federal initiatives and some from state initiatives. The most important aspects of electricity restructuring are:
Not all areas of the U.S. have adopted deregulation or restructuring. Figures 6.3 and 6.4 show the areas of the U.S. that have adopted competitive wholesale markets for electric energy generation and those individual states that have taken on power-sector reforms at the retail level.
Regional Transmission Organizations (RTOs) are non-profit, public-benefit corporations that were created as a part of electricity restructuring in the United States, beginning in the 1990s. Some RTOs, such as PJM in the Mid-Atlantic states, were created from existing “power pools” dating back many decades (PJM was first organized in the 1920s). The history of the RTO dates back to FERC Orders 888 and 889, which suggested the concept of the “Independent System Operator” (ISO) to ensure non-discriminatory access to transmission systems. FERC Order 2000 encouraged, but did not quite require, all transmission-owning entities to form or join a Regional Transmission Organization to promote the regional administration of high-voltage transmission systems. The difference between RTO and ISO is, at this point, largely semantic. Order 2000 contains a set of technical requirements for any system operator to be considered a FERC-approved RTO.
RTOs are regulated by FERC, not by the states (i.e., RTO rules are determined by a FERC-approved tariff and not by state Public Utility Commissions) and membership in a RTO by any entity is voluntary. Including Texas (which is technically outside of FERC’s jurisdiction), there are seven RTOs in the U.S., covering about half of the states and roughly two-thirds of total U.S. annual electricity demand. Each RTO establishes its own rules and market structures, but there are many commonalities. Broadly, the RTO performs the following functions:
In many ways, RTOs perform the same functions as the vertically-integrated utilities that were supplanted by electricity restructuring. There are, however, a number of important distinctions between RTOs and utilities.
The set of NETL power market primers zipped file [5] contains more information on specific differences between the various RTO markets.
The separation of ownership from control in RTO markets raises some interesting complications for planning. RTOs have responsibility for ensuring reliability and adequacy of the power grid. They must perform regional planning, meaning that they determine where additional power lines and generators are required in order to maintain system reliability. But RTOs generally cannot require that member companies make any investments. They generally rely on a variety of market mechanisms to create financial incentives for member firms to invest in generation. Many transmission investments needed for reliability are eligible for fixed rates of return set by FERC.
Operating a power system requires making decisions on time scales covering fifteen orders of magnitude prior to real-time dispatch, as shown in Figure 6.5.
Since the RTO does not own any physical assets, it must effectively sign contracts with generation suppliers to provide needed services. The market mechanisms run by the RTO are used to procure generation supplies needed to maintain reliability. Once generation supplies are procured by the RTO, it can dispatch generation as needed to meet demand.
RTOs run three types of markets that enable them to manage the power grid over time scales ranging from cycles (one cycle = 1/60th of one second) to several years in advance of real-time dispatch, as shown in Figure 6.6.
Capacity Markets are meant to provide financial incentives for suppliers to keep generation assets online and to induce new investment in generation. Capacity markets are generally forward markets to have generation capacity online and ready to produce electricity at least one year ahead of time. PJM’s capacity market is run three years ahead of time. For example, a generator that participates in the PJM capacity market in 2012 is effectively making a promise to have generation capacity online and ready to produce in 2015. Capacity markets are thought to be necessary because prices in other RTO markets are not always sufficiently high to keep existing generation from shutting down or to entice new generators to enter the market. Not all RTOs have forward capacity markets. Texas, for example, does not operate a capacity market. We will discuss capacity markets in more detail in Lesson 7.
Energy Markets are perhaps the most well-known of all market constructs run by RTOs. Like capacity markets, energy markets are forward markets but are used by the RTO to ensure that enough generation capacity is online and able to produce energy on a day-ahead (24-hour ahead) to one-hour-ahead basis. RTOs run two types of energy markets. The first, the “day-ahead market” is used to determine which generators are scheduled to operate during each hour of the following day (and at what level of output), based on a projection of electricity demand the following day. The second, the “real-time market” is somewhat poorly named; this market is used by the RTO to adjust which generators are scheduled to run on an hour-ahead basis. A better term for the real-time market (which is used in some cases) would be “adjustment market” or “balancing market” since supplies for this so-called real-time market are actually procured one day in advance (but after supplied are procured through the day-ahead market). The prices prevailing in the day-ahead and real-time markets are the most commonly referenced and quoted of all markets run by the RTOs.
Ancillary Services Markets allow the RTO to maintain a portfolio of backup generation in case of unexpectedly high demand or if contingencies, such as generator outages, arise on the system. There are many different types of ancillary services, corresponding to the speed with which the backup generation needs to be dispatched. “Reserves” represent capacity that can be synchronized with the grid and brought to some operating level within 60, 30, or 15 minutes. “Regulation” represents capacity that can change its level of output within a few seconds in response to fluctuations in the system frequency. Ancillary services are increasingly important for renewable energy integration, so we will discuss those markets in Lesson 7.
Suppliers may participate in multiple markets. For example, a 100 MW generator could offer 80 MW to the day-ahead market, 10 MW to the real-time market, and 5 MW each to the regulation and reserves markets. The generator would earn different payments for each type of service provided to the grid. Thus, while the day-ahead or real-time price is often referred to as “the” market price of electricity, in reality there are many different prices in the RTO market at any given time, each representing a different type of service offered to the RTO.
Because the RTO operates its entire system in an integrated way, even though its footprint may encompass many different utility territories and transmission owners, RTO type markets are sometimes referred to as “power pools” or simply “pools.” The following video contains more information about how the pool-type markets are structured, using the largest pool type model (PJM, in the Mid-Atlantic U.S.).
PJM - ah, they used a different model, a different market model, which is sometimes called a pool. And the way the PJM, or pool market, works is that individual generators commit their capacity to the market, or the pool. The pool decides which generators are going to run at which hours. 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. The pool-type market was, more or less, what FERC's standard market design looked like. The markets that are run by regional transmission organizations are all run as what we call uniform price auctions. They 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. 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. I'll show you a couple of different pictures of this.
This is approximately what the supply curve looks like for the PJM market. A couple of things about this supply curve are that, first of all, it has this hockey stick sort of shape. 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. In the example that I have here, if demand is a hundred thousand megawatt hours, which is this vertical line about here, then the point where that 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 a hundred thousand megawatt hours, the price would be eighty dollars per megawatt hour. And if the price were a little bit lower or a little bit higher than that, say eighty thousand instead of a hundred thousand, the market clearing price would not change all that much. But as demand increases, in this case past a hundred and or a hundred and twenty thousand megawatt hours, then the cost of the capacity you'd have to use in order to satisfy that demand starts to rise very sharply. So, this point, the part of the supply curve over here where the price starts to rise very steeply is sometimes called the "devil's elbow."
If we have demand of a hundred and forty thousand 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. At high levels of electricity demand, the small changes in demand can produce much larger than proportional changes in the market price.
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 these uniform price auctions 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. So, if you're a generator, your profit during any time period is equal to whatever the market the price is minus your marginal cost. Sometimes, you'll hear this market referred to as a scarcity rent. The way that these uniform price auctions work, if you've take Econ 101, is not dissimilar to just about any other market in the world.
There is a variation on the uniform price auction called the pay as bid auction. This is used in the UK but not in the United States. The idea behind the pay as 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 payed whatever their bid was. As I said, this is used in the UK but not in the US. The belief in the US is that if you switched to a pay as bid system, this would simply give generators incentives to manipulate their bids. So, if you're a generator that has a marginal cost of five dollars per megawatt hour and you believe that the market price, or the system marginal price, will be fifty dollars per megawatt hour, in the uniform clearing price option, you would earn fifty minus five equals forty-five dollars per megawatt hour in profit. In the pay as bid auction, if you actually submitted a bid that was equal to your marginal cost, then you would earn five dollars per megawatt hour. The thought is, 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 as bid is not really used in the US.
So, basically, all of the centralized wholesale markets run by RTOs follow this uniform price option format.
If you are interested, the following two videos discuss electricity market structures that are alternatives to the pool:
Areas of the US that do not have these centralized electricity markets do have wholesale trade of electricity between generators and buyers, between utilities and so on and so forth. These are what we call bilateral markets, and these bilateral markets actually existed long before electricity deregulation, long before the PJM electricity market and so on and so forth. The first of these was actually set up in the western US in the late 1980s. It was called the Western Systems Power Pool. It's actually still in place - so, the market structure that was set up in the 1980s in the western states is actually still used there today.
The way that bilateral markets work is that large volumes of electricity, sometimes called bulk power, is traded between utilities, between buyers and sellers, at whatever price the two counter parties agree upon. And how these trades actually occur is that potential counter parties actually call each other up on the phone. So, I might be, like, Bonneville Power Administration and I could call somebody at SMUD (The Sacramento Municipal Utility District) and say, "I've got spare electricity to sell; do you want to buy any?" This is basically how the bilateral markets work. And sometimes, the energy that's purchased through these bilateral markets is coupled with access to the transmission grid so that you could actually deliver the electricity. This is sometimes called "firm" energy, as opposed to non-"firm" energy, which is sold without access to the transmission grid. These bilateral markets still exist today. Now, a lot of the bilateral trading takes place over electronic trading platforms. People don't call each other up on the phone as much; instead they might log in to some electronic trading platform, kind of like e-Bay or something like that. When we talk about centralized electricity markets, just keep in mind that places in the US that do not have centralized electricity markets still have trading of electricity through these bilateral markets.
In the mid-1990s, California and a handful of Mid-Atlantic states (the "PJM" market, which stands for Pennsylvania, New Jersey, and Maryland), as part of a broader electricity market restructuring effort, set up much more coordinated, much more formal mechanisms for trading electricity. The California model was a little bit different from the PJM model, but the big similarity that they shared was that rather than people calling each other up on the phone, there would be a centralized exchange setup, kind of like something analogous to the New York Stock Exchange or the New York Mercantile Exchange, where crude oil futures are traded. And rather than buyers and sellers trying to find each other by calling each other up on the phone, everybody would go to this centralized market, or this centralized exchange
For these centralized electricity markets….I'd said that starting in the 1990s there were two competing models for setting up electricity markets: one in California and one in the PJM states. What California did was it tried most directly to replicate a financial exchange, like the New York Stock Exchange, for buying and selling electricity. And so, it opened The California Power Exchange. So, California's biggest utilities, they all agreed to go along with this, and they agreed to buy all of their power from the power exchange. So, how the power exchange worked was this:
First, individual generators decided whether or not they wanted to enter their supplies into the power exchange. This is called decentralized unit commitment. It was up to the generators whether or not they wanted to make their capacity available to the exchange. The bids from the generators, there was an overall cap, so a maximum amount, that the generators could bid, but beyond that, the generators could more or less do whatever they wanted. They could submit whatever type of supply offer they wanted to. And then, just as generators had to submit supply offers, the three large California utilities, they also had to submit demand bids. So, the idea was that you would have so many suppliers rushing into this market to serve so much electricity demand that there would be sort of this vigorous competition that would ensue, sort of like in an auction.
So, the way that the power exchange market worked was that every hour, suppliers would submit supply offers, which is the blue curve here, and the supply offer indicated how much generating capacity the supplier was willing to make available to the power exchange at what price. So, when you put all of these together you got what we call a supply curve or an offer curve. And that's in the blue. On the demand side, the utilities had to submit the amount of electricity that they were willing to buy from the exchange at some price. And so, that's the pink curve right over here. And when these purchase offers were aggregated together you got kind of a California system demand curve. And where the supply and demand curve met determined the price and quantity at which the electricity market would clear. So, in this example, and this is a picture from the late 1990s, the point where supply equals demand, the market cleared for this particular hour at about 32,500 megawatts of generation capacity would be utilized to serve 32,500 megawatt hours of energy demand, and the market clearing price would be $190 per megawatt hour. So, this was repeated every single hour of every single day. And in the event that there wasn't enough electricity purchased in through the power exchange to serve all of California's electricity demand, there was a secondary balancing market that would ultimately equate demand and supply on a sub-hourly basis. So, this was basically how the power exchange model worked, and the California power exchange lasted for about two and a half years, and after the California power crisis, as California's sort of screeching halt to electricity deregulation, the power exchange was shut down. Partially because of California's sort of dismal failure, the power exchange model has not really been replicated anywhere else except in Alberta, up in Canada, where they actually have had a power exchange type market for well over a decade. They seem to like it, but in California, it didn't work so well.
Virtually all RTO markets are operated as “uniform price auctions.” Under the uniform price auction, generators submit supply offers to the RTO, and the RTO chooses the lowest-cost supply offers until supply is equal to the RTO’s demand. This process is called “clearing the market.” The last generator dispatched is called the “marginal unit” and sets the market price. Any generator whose supply offer is below the market-clearing price is said to have “cleared the market,” and is paid the market-clearing price for the amount of supply that cleared the market. Generators with marginal operating costs below the market-clearing price will earn profits. In general, if the market is competitive (all suppliers offer at marginal operating cost) the marginal unit does not earn any profit.
The uniform price auction is illustrated in Figure 6.7. There are five suppliers, each of which offers its capacity to the market at a different price. These supply offers are shown in Table 6.1. Here we will assume that supply offers are equal to the marginal costs of each generator, but in the deregulated generation market suppliers are not really obligated to submit offers that are equal to costs. The RTO aggregates these supply offers to form a single market-wide “dispatch stack” or supply curve. Demand is represented by a vertical line (the RTO assumes that demand is fixed, or “perfectly inelastic” with respect to price). In this case, demand is 55 MWh. Generators A, B, C and D clear the market. Generator E does not clear the market since its supply offer is too high. The market-clearing price, known as the “system marginal price (SMP)” would be $40 per MWh. Generators A, B, C, and D would each be paid $40 per MWh. Generators A, B and C would earn profit. Generator D is the marginal unit so it earns zero profit.
Supplier | Capacity (MW) |
Marginal Cost ($/MWh) |
---|---|---|
A | 10 | $10 |
B | 15 | $15 |
C | 20 | $30 |
D | 25 | $40 |
E | 10 | $70 |
Let’s calculate the profits for each of our generators. Remember that each generator that clears the market (in this case, it would be A, B, C, and D; E does not clear the market) earns the SMP for each unit of electricity they sell. Total profits are thus calculated as:
Profit = Output × (SMP – Marginal Cost).
Since the SMP in our example is equal to $40, profits are calculated as:
Firm A profit = 10 × (40 – 10) = $300
Firm B profit = 15 × (40 – 15) = $375
Firm C profit = 20 × (40 – 30) = $200
Firm D profit = 10 × (40 – 40) = $0
Firm E profit = 0 × (40 – 70) = $0.
Note in particular that Firm D, which is the “marginal unit” setting the SMP of $40/MWh, clears the market but does not earn any profits. We will come back to this case when we discuss capacity markets in Lesson 7.
Unlike petroleum pipelines or natural gas pipelines, which in most cases require compression to maintain sufficient pressure to move product from the wellhead to the sales point, the cost of moving additional electrons through a network of conductors is essentially zero, since there is no fuel cost for “compression” in electrical networks.
(Actually, this isn’t quite true for a couple of reasons. First, transmission lines aren’t perfect conductors, so there is some resistance in the network. Because of this resistance, some of the electricity injected into the transmission grid by power generators is lost as heat between the power plant and the customer. The magnitude of these “resistive losses” is around 10% in a modern power grid like North America’s. What this means is that the system has to generate more power than is actually demanded, to account for these losses. For example, if demand in a system with 10% losses is 100 MW, then the system will need to generate around 111 MW. Second, the transmission grid needs to maintain a certain voltage level, and maintaining this level sometimes involves output adjustments at the power plant location, which does impose an economic cost on the system. In the discussion here, we will ignore these two costs to focus on the effects of transmission congestion.)
In the market-clearing example that we just went through, all suppliers were paid the market-clearing “system marginal price,” and the problem did not really say anything about where the generators or customers were located, or what the transmission network looked like. We just assumed that power produced at any one plant could be delivered to a customer at any location in the transmission network. Thus, electricity markets should exhibit the law of one price, just as we saw in natural gas networks.
While electricity markets should exhibit the law of one price, the reality is that they often do not. Figure 6.8 shows a contour map of electricity prices in the PJM electricity grid on a warm, but not terribly hot day in June 2005. You can find more up-to-date maps [6] on the PJM website [7]. You can also find a really nifty animation of LMPs [8] from the MISO market [9]. If you look carefully at the MISO animation, you may see some negative prices, meaning that someone using electricity gets paid to use it, and someone producing electricity actually pays to generate power! While this may seem strange, it is actually a natural economic outcome of a market with fluctuating supply and demand, and no storage. We'll get to the negative-price phenomenon later in the course.
Getting back to our picture of prices in the PJM system, you can see that prices in the western portion of PJM’s grid are an order of magnitude lower than prices in the eastern portion of the grid. This means that a power plant located in, say, Pittsburgh could make a lot of money by selling electricity to customers in Washington, DC. The demand from Washington should bid up the price in Pittsburgh as more generation in Pittsburgh comes online to serve the Washington market. This is just what we saw in our study of natural gas markets. But this doesn’t happen in electricity. Why?
The basic answer is “transmission congestion.” Conductors cannot hold an infinite number of electrons. At some point the resistive heat would just cause the conductor to melt. (Remember that materials expand when they get hot. When you hear about power lines “sagging” into trees, that is what’s going on.) So, power system engineers place limits on the amount of power that a transmission line can carry at any point in time. When a line’s loading hits its rated capacity, we say that the line is “congested” and it can’t transfer any additional power. So, the system has to find another way to meet demand, without additionally loading congested lines. Usually this involves reducing output at low-cost generators and increasing output at higher-cost generators. This process, known as “out of merit dispatch,” imposes an economic cost on the system.
After correcting for transmission congestion by adjusting the dispatch of power plants, the cost of meeting demand in one location (e.g., Washington) may be substantially higher than the cost of meeting demand in another location (e.g., Pittsburgh). The locational marginal price (LMP) at some particular point in the grid measures the marginal cost of delivering an additional unit of electric energy (i.e., a marginal MWh) to that location.
We will illustrate the concept of LMP using the two-node network shown in Figure 6.9. Node 1 has 100 MWh of demand, while node 2 has 800 MWh of demand. There are two generators in the system – one at node 1 with a marginal cost of $20/MWh and one at node 2 with a marginal cost of $40/MWh. A transmission line connects the two nodes. For the purposes of this example, assume that either of the generators could produce 1,000 MWh, and we will ignore any issues with transmission losses. Both generators submit supply offers to the electricity market that are equal to their marginal costs.
Suppose that the transmission line could carry an infinite amount of electricity. How should the system operator dispatch the generators to meet demand? Either generator by itself could meet all 900 MWh of demand in the system, so the system operator would dispatch generator 1 at 900 MWh and generator 2 would not be dispatched. The SMP would be equal to $20/MWh.
Now, suppose that the transmission line could carry only 500 MWh. In this case, the system operator could supply all of the demand at node 1 with generator 1, but only 500 MWh of demand at node 2 with generator 1. The remaining demand at node 2 would need to be met by dispatching generator 2. Since there is plenty of generation capacity left at generator 1, if demand at node 1 were to increase by 1 MWh, it could be met using generator 1 and thus the LMP at node 1 is $20 per MWh. If demand at node 2 were to increase, that demand would need to be met by increasing output at generator 2. Thus, the LMP at node 2 would be $40 per MWh.
Next we'll look at how much the Generators are paid and how much the Customers pay. Customers at Node 1 are charged $20 per MWh, while customers at Node 2 are charged $40 per MWh for all energy consumed. Generator 1 is paid $20 per MWh, while Generator 2 is paid $40 per MWh for all energy produced. You may notice here that while customers at Node 2 pay $40 per MWh for all 800 MWh that they consume, some of that energy was imported from Node 1 at a much lower cost. This is not a mistake - it's how the LMP pricing system works in the US.
The RTO collects revenue from the customers as follows:
From Node 1: 100 MWh × $20 per MWh = $2,000
From Node 2: 800 MWh × $40 per MWh = $32,000
Total Collections = $34,000
The RTO pays the generators as follows:
To Node 1: 600 MWh × $20 per MWh = $12,000
From Node 2: 300 MWh × $40 per MWh = $12,000
Total Collections = $24,000
The RTO collects excess revenue in the amount of $34,000 - $24,000 = $10,000. It collects this excess revenue because customers at Node 2 pay $40/MWh for all energy consumed, while some of those megawatt-hours only cost $20/MWh to produce.
This excess revenue is called "congestion revenue." In general, when there is congestion in the network and LMPs differ, then there will be some congestion revenue. We will discuss later in the course what the RTO does with this extra revenue. For now, just remember that whenever there is transmission congestion and LMPs at different nodes of the network aren't equal, the RTO will usually wind up with some congestion revenue.
As an exercise for yourself, calculate the LMPs and congestion revenue under a second two-node example. Demand at Node 1 is 5 MWh, while demand at Node 2 is 10 MWh. The transmission line connecting Nodes 1 and 2 has a capacity of 5 MWh. The marginal cost of Generator 1 is $10/MWh while the marginal cost of Generator 2 is $15/MWh.
You should find that the LMP at Node 1 is $10/MWh; the LMP at Node 2 is $15/MWh; and that 5 MW of power is exported from Node 1 to Node 2 on the transmission line.
You should also find that congestion revenue is equal to $25.
While rate of return regulation served the electricity industry and consumers well for many decades, it had embedded in it a number of incentive problems that made for inefficient operation of electric utilities and some behavior by regulators that was not always in the public interest. In particular, rate of return regulation gave electric utilities incentives to over-invest in capital - the so-called "Averch Johnson" effect. Regulators, in turn, labored under incomplete information regarding the state of the utilities that they were supposed to regulate. Even on their best day, the utilities knew more about the power grid than their regulators, so utilities could more easily get regulators to approve investments. Public utility commissioners are aided by large technical staffs, but at the end of the day, these staff members had expert knowledge but still had less data and system information than the utilities.
Recognizing that generation could be competitive over large regional areas, and that transmission and distribution needed to retain some form of regulation, the restructuring of the electricity industry consisted of the following fundamental changes:
In the United States in particular, restructuring has proceeded unevenly. Around half of U.S. states now have a power sector that has been restructured in some way. The other half still operate following the regulated utility structure that we discussed in Lesson 5.
You have reached the end of Lesson 6! Double check the What is Due for Lesson 6? list on the first page of this lesson to make sure you have completed all of the activities listed there before you begin Lesson 7. Note: The Lesson 7 material will open Monday after we finish Lesson 6.
Links
[1] http://economics.mit.edu/files/2093
[2] http://www.eba-net.org/assets/1/6/10-147-184.pdf
[3] https://www.ferc.gov/industries-data/natural-gas/overview/lng
[4] http://www.eia.gov/electricity/policies/restructuring/
[5] https://www.e-education.psu.edu/eme801/sites/www.e-education.psu.edu.eme801/files/NETL_primers.zip
[6] http://www.pjm.com/markets-and-operations/interregional-map.aspx
[7] http://www.pjm.com
[8] https://www.misoenergy.org/markets-and-operations/real-time--market-data/real-time-displays/
[9] http://www.misoenergy.org