EXPLAINING THE GRID PART FOUR
RTO Energy Markets
The first markets I am going to discuss are the energy markets run by Regional Transmission Organizations (RTOs). As in all aspects of RTOs, this is a somewhat simplified account. There are a number of complicated details that I won’t go into now—maybe later—but this description provides a general picture. I have discussed RTOs and RTO markets in previous posts, but will go over some of that ground again for those of you who have not read all my posts, or do not remember everything from those posts.
I think that most people believe that their electricity is provided to them by generation plants owned and operated by their local utility; transmitted to them over that utility’s transmission lines; at rates regulated by their local public utility commission. For decades that was how the electric industry worked, and for some people it is still somewhat true, but in most of the country that no longer is the case. Instead, in two-thirds of the US, electricity is bought and sold in large regional wholesale auctions operated by RTOs. Thousands of generation facilities submit offers to sell in these auctions, and the electricity sold in these auctions is purchased by utilities serving tens of millions of retail customers. That electricity is then transmitted by the RTOs for hundreds of miles of transmission lines that are owned by multiple utilities. Public utility commissions continue to regulate the retail rates consumers pay for this electricity, but the cost of the electricity and transmission service included in those rates is regulated by the Federal Energy Regulatory Commission (FERC) and cannot be revisited by state public utility commissions.
This map, which is taken from the FERC web site (Electric Power Markets | Federal Energy Regulatory Commission) gives an idea of where the RTOs are located.
This map requires some explanation. The areas marked “Southwest,” “Northwest,” and “Southeast” on the map are not part of RTOs, but rather indicate the regions where RTOs do not operate. But the rest of the US is served by different RTOs, as shown on the map. If you are interested in more details about the individual RTOs, you can find a description of them on the FERC website at the above link.
All of the RTOs operate energy markets and, although there are some regional differences, each of these energy markets operates in essentially the same manner. Each of these markets is a competitive market in which generators offer their energy for sale at unregulated rates. Some people assert that the markets are not truly competitive because they are subject to complex rules approved by FERC. This is not correct, however, as I explain in my post “In Defense of RTOs, Part Three.” There are certain limits on the prices at which energy may be offered—which are imposed primarily to prevent the exercise of market power—but no regulatory agency reviews the generators’ offers or sets the prices established in the auctions.
Further, all RTOs require each generator making sales of energy in the RTO to make those sales by offering its energy into the RTO energy market, and each utility or other entity making retail sales of electricity (such as a marketer, co-op, etc.) to purchase its energy from the RTO market. These obligations apply even to utilities that use their own generation to serve their own customers. These utilities must offer the energy produced by their own generation for sale into the RTO market and then purchase energy from the RTO market to serve their own customers.
Why do RTOs impose these mandatory purchase and sale obligations? The short answer is the obligations ensure that competition in the markets provides for the lowest price for consumers. If generators were permitted to withhold their generation from the markets and instead directly supply energy to retail providers, they would be able to shield their generation from competition, with the inevitable result being higher rates to consumers.
All RTO energy markets use the same method to establish the price of energy. To help explain this, I am copying the same illustrative stack graphic that I used in my last post.
Consistent with the way grid operators dispatch generation to run, which I described in my last post, RTOs stack the offers received in their auctions based on the offer price, with the lowest price offer at the bottom and the highest cost offer at the top. The auction accepts the offer in the stack that is necessary to serve the last increment of customer load, in this case the $50 offer, and all lower cost offers.
It is important to keep in mind that the amount of consumer load in an electric system is constantly changing as devices are turned on and off (discussed in more detail in my post “Explaining the Grid Part One”). Because the amount of consumer load is always changing, the amount of energy required to serve that load likewise is changing. As a result, RTOs constantly run energy auctions in real time, and each auction results in different awards, with corresponding changes in price. In some RTOs, the auctions are run and prices change as frequently as every five minutes.
One aspect of RTO energy markets that surprises most people—it certainly surprised me—is that the auctions are used to set a single price paid to all generators who are given awards in the auction, regardless of their offer price. And this price is set equal to the highest offer that receives an award, which is called the “market-clearing offer,” or the “marginal offer.” In my graphic, the marginal offer was $50, and all generators receiving an award are paid $50 for their energy, including the generator offering at $20 and the generator offering at $30.
When I first heard about this feature of RTO energy markets I asked—as many people continue to ask even today—why everyone should get the highest accepted price. If a generator is willing to offer its energy at $20 or $30, why should it be paid more? The theoretical answer is that, under classic economic theory, competitive prices are set at the marginal cost of production. Competitors whose costs are lower than the marginal cost can increase the price at which they sell their goods up to the price charged by the marginal cost producer. Setting the RTO energy price at the price of the marginal offer replicates the price that will result from a competitive market.
Of course, in the theoretical competitive world, all producers are charging the price charged by the marginal cost producer. No one is charging $20 or $30 but being paid $50, which is what happens in RTO energy markets. Paying our generators more than they are offering does not really replicate the classic economic model. So why do all RTOs do this?
The reason is that the $20 and $30 generators would not offer at that price if they were paid only what they offered. These $20 and $30 offers reflect the fact that these generators can operate at a lower cost than the other generators in the stack. And if they operated under a pay as offered mechanism, they would act like low cost producers in other industries. They would attempt to identify the costs of the generator submitting the marginal cost offer and would attempt to offer at or just below the price of that offer. And if the $20 and $30 generators correctly predict the price of the marginal offer, they will offer their energy into the auction at the same price—$50 in my graphic—that they would have received if all generators receiving awards are paid the marginal price offer.
The next question is, if a pay as offered mechanism would yield the same price as the market-clearing price mechanism employed by RTOs, why not employ a pay as offered mechanism? The answer is that generators do not have perfect market information; generation cost data is considered highly confidential, competitively data. As a result, a low cost generator potentially could misjudge the price of the marginal cost offer, and submit an offer that is too high and end up not receiving an award at all. Due to the unique nature of the electric industry, the consequences of such a mistake are different than in other competitive industries.
In most competitive industries, the consequences of a low cost producer charging more than the market will bear are not catastrophic. The producer can simply reduce its price and try again. Eventually, it will arrive at a price close to that charged by the marginal cost producer, and sell its products at that price. But in the electric industry, where electricity is consumed the instant it is generated, if a generator does not get an award it cannot continue to generate electricity and try to sell it later. Rather it must shut down. Not only does it lose revenues but, depending on the type of generation involved, the operational consequences can be significant. Many generation facilities take long periods of time and incur significant costs to shut down and then later return to service. They cannot quickly cycle on and off if their offers are accepted and rejected several times a day.
Paying every generator the marginal offer price resolves this problem. Low cost producers are not required to guess the marginal cost offer and suffer the consequences of an incorrect guess. Instead are able to offer in at or slightly above their variable cost, secure in the knowledge that they will be paid the price of that offer if they receive an award. This results in the most efficient dispatch of generation, ensuring that customers are being charged the competitive marginal cost rate while giving awards to generators whose costs are below the marginal cost of generation in the RTO.
RTOs also operate what are known as “day-ahead” energy market auctions. These auctions are not run in real time, but rather are run the previous day, i.e. the day ahead of the real time energy market auctions. The day-ahead auctions set prices for each hour of the following day, based on the RTO’s projection of load for each hour. The awards process is essentially the same, where offers for each hour are stacked by price and all generators getting awards in an hour receive the market-clearing price for that hour.
The following day, the real time auctions are run to establish the price of energy for deviations from the amount of energy purchased under the day-ahead auction the previous day. The deviations can occur either because a generator produces more or less energy than identified in the day-ahead auction, or because the load is greater or lower than projected in the day-ahead auction for the previous day. This means that receipt of a day-ahead award does not obligate a generator to supply energy the following day. If the generator does supply energy in accordance with the award, it is paid its day-ahead price, but if it does not, it can meet its obligation by essentially buying the required energy in the real time market. And if the generator wants to generate more electricity than it was awarded in the day-ahead auction, it can submit offers to sell that electricity in the real time auctions.
I recognize I have provided a hard to follow and incomplete description of the somewhat complex day-ahead energy markets. Don’t worry if you don’t completely follow what happens in these markets. The main point I want to make for purposes of this post is that the day-ahead markets allow generators to plan their operations for the following day, rather than having to rely on a series of 5 minute auctions conducted in real time. Getting an operating schedule the day ahead, which generators are able to adjust in real time, eliminates much of the operational risk of potentially not receiving an award in the real time auctions.
For the first 15 years or so of RTO market operations, the energy markets provided significant benefits to large baseload units, primarily nuclear but also coal. These units have relatively low variable costs, and so were able to offer into the energy markets at prices that, in many hours, were well below the market-clearing price of energy. This allowed these baseload units to earn revenues significantly in excess of their variable costs. This was important, because large baseload units are much more expensive to construct and can be subject to the requirement to incur capital-intensive improvements to remain in service. The high revenues that the owners of these units received from the RTO energy markets allowed them to earn a good return on their considerable capital investment and to fund necessary capital improvements.
More recently, energy revenues for these types of plants have declined significantly. Energy prices in the RTOs have declined as more wind and solar units have been placed in service and offered their energy into the auctions. Wind and solar units have very low variable costs because they do not have to purchase fuel, which is the primary variable cost for most types of generation facilities. Because of these very low variable costs, wind and solar generators are able to offer into energy markets at very low prices. Indeed, with the tax benefits and subsidies that wind and solar units receive, these units can sell their energy at a loss and still make a profit.
At times, the submittal of offers by wind and solar facilities at negative prices causes RTO energy market prices to go negative, which means that a generator has to pay the RTO to accept its energy. Nuclear units need to stay on line for operational purposes, so they end up having to likewise offer their energy at the very low or negative prices that are becoming more common, even though the nuclear units incur variable costs that are higher than the market-clearing price. (This phenomenon is explained in more detail in my post “A Race to the Bottom”).
As a result, energy markets provide less support for the continued operation of large baseload nuclear and coal units than they once did. This means that the RTO capacity markets have become much more important for these units to operate profitably and remain in service rather than being retired. I will discuss these capacity markets in my next post.
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