Industry 101 | Market Settlements: Settlement Process

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Day-Ahead Market

Electricity is continuously generated and consumed on a 24-hour clock, but settlement periods are defined as distinct half-hour time frames. Electricity suppliers (retailers) assess the demand of their customers in advance for a given settlement period. Once this demand is calculated, they enter into contracts with one or more generation resources in advance to cover this basic minimum expected demand, known as base load. These contracts are essentially OTC – over-the-counter contracts. If deviations from this base load are expected on a certain day—due to weather or other changing factors—the supplier may also buy electricity from power exchanges to shape the base load. These exchange transactions are generally done closer to the period in question, with the cut-off time being an hour before the period’s start; this cut-off is known as the gate closure for the settlement period.

The base load and exchange transactions are the expected standards in the market, but generators can offer to place additional capacity on the grid and set the price they would like to receive for it or request their normal capacity be reduced and set the price they would like to pay for that option. Similarly, suppliers can set a price to be paid for reduced demand or offer a price they would pay for increased demand. These contracts must also close before the gate closure.

Energy Settlement Process Key StepsAt or before the gate closure time, generators must notify the ISO of their contracted generation volumes, including base load, exchanges, and increased or reduced capacity for the given settlement period. Suppliers must do the same for contracted demand volumes. These notifications are known as final physical notifications (FPN).

Between the gate closure time and the beginning of the settlement period, the ISO compares forecasted demand and the FPNs for generation; if there is a discrepancy, it allows for offers and bids from generators and/or suppliers, depending on the need, to rectify. If the market is working as desired, at the beginning of the settlement period, expected generation should exactly meet expected demand.

Market Day

Electricity generators are expected to generate electricity matched with the contracted volume, and the retailer’s customers are expected to consume all the generated electricity that is matched by the contracted volume. However, in reality the generators may generate more or less electricity while the retailer’s customers may consume more or less electricity than contracted. Balancing the market to the day-ahead (DA) is the real-time (RT) market, in which participants can buy and sell energy throughout the operating day. Differences between the scheduled demand from the day-ahead market and the actual demand necessary on the day of trade are balanced through the demand and supply of the RT market.

Day After

The imbalances mentioned before are the basis from which the ISO generates invoices to generators and suppliers. FPNs and bid acceptance data define the contracted volumes, and these expectations are compared against actual half-hourly interval consumption reads from the meter data management agents (MDMA) that give the actual volumes.

Electricity Imbalance Volume = (Electricity Volumes Consumed or Generated – (Bid / Offers Accepted + Total Contracted Volume)

Suppliers who overconsume or generators who underproduce are required to buy the deficit from the system at the set system buy price (SBP). On the other hand, suppliers who underconsume or generators who overproduce have to sell the excess power at the system sell price (SSP). The ISO uses the SBP and SSP to generate invoices and sends these to the generators and suppliers.

To balance the grid, retailer’s customers who consume less electricity than contracted and generators who generate more electricity than contracted need to sell the excess amount  to the system operator at system sell price – SSP.

Electricity Imbalance Amount = Electricity Imbalance Volume * Electricity Imbalance Price (SBP or SSP)

Generally, an ISO will generate market settlement invoices daily, based on the 48 settlement periods in a defined operating day. However, missing or estimated meter data may later be replaced by real reads, or market participants can dispute the charge. Either of these occurrences could cause the ISO to create altered or “trued-up” invoices based on the new information.



Hourly Prices From Demand SchedulesIndependent system operators implement day-ahead (DA) and real-time (RT) energy markets for trading energy. The day-ahead market is an energy market in which participants can buy and sell electric energy at a set price for each hour of the following day. This market is driven by planning through supply offers and demand bids establishing financially binding prices for the following day. A buyer, such as a utility, evaluates how much energy it needs to be able to supply in order to meet demand for the following day, as well as how much it is willing to pay for it. A seller, such as a power plant, decides how much energy to provide and at what hourly price. This information is then developed into a standard supply and demand balance from which each hourly price is derived. The standard market design (SMD) issued by the Federal Energy Regulatory Commission (FERC) places ISOs in a position of power to receive energy and price bids, then responsibly sort and select these with a given motive. An ISO’s motive can range from lowest cost to aiming for the lowest amount of changes to the original schedules.

Some ISOs have full network models that analyze the availability and cost of producing and delivering energy and integrate these costs into the hourly prices called locational marginal prices (LMPs). The main impact of the day-ahead market is the ability for buyers and sellers to evade price volatility through an enforced price.

Locational marginal price is the cost to serve the next unit of load at a specific location with the lowest production cost while still evaluating transmission limit costs.

Locational Marginal Price = Generation Marginal Cost + Transmission Congestion Cost + Cost of Marginal Losses

On the other hand, market clearing price (MCP) is the cost to fulfill the energy demand without considering the transmission limitations. LMP reflects the MCP at each location.



Balancing the day-ahead market is the real-time market, in which participants can buy and sell energy throughout the operating day. Differences between the scheduled demand from the day-ahead market and the actual demand necessary on the day of trade are balanced through the demand and supply of the real-time market. Utilities can buy power that covers the gaps in demand not originally planned for in their day-ahead schedule. These deviations can be caused by plenty of reasons including deviations from load and generation schedules and network model inaccuracies.

Discrepancies in consumption schedules are not always unintentional. If a buyer predicts the real-time market prices to be lower than day-ahead market prices, they may deliberately submit a schedule with underestimated loads. Conversely, if a buyer expects real-time prices to be higher than day-ahead market prices, they may submit an overestimated schedule and sell the excess energy back to the ISO at the real-time market prices. The ability to balance or shift demand necessities between the day-ahead and real-time markets provides a source of demand elasticity in the day-ahead market. This also causes price volatility because of the chance of having price increases in the real-time market while keeping day-ahead prices fairly average.

Deviations in generation schedules can happen for many reasons. Unexpected outages can easily cause the delivered energy to be less than what was expected. Also, energy generators have constraints including start-up time, shut-down time, minimum uptime, and minimum downtime. If a generator falls behind on any of these, they will depend on the real-time market to be able to make up the difference.



While the day-ahead and real-time markets are the most prominent through ISOs, these are not necessarily the only trading opportunities present, and some ISOs do not have both. The figure shown here compares four major northeastern ISOs. PJM and the New England ISO are the most common, with both real-time and day-ahead markets, and the New York ISO has both of these as well as an hour-ahead market.

Having and maintaining multiple markets can cause nuances for an ISO. For instance, the NYISO used their security-constrained unit commitment (SCUC) to predict the physically available flows as well as the MCPs. Their balancing market evaluation (BME) generated hour-ahead prices. They also have a security-constrained dispatch (SCD) to perform a least-cost analysis of the available units every five minutes. While the SCUC and the BME used the same algorithm and were in sync, the SCD has a different model which can result in significantly differing day-ahead and real-time prices, mostly during shortages. The inconsistencies in the BME and SCD also caused discrepancies in the treatment of reserves. The BME sets aside capability to entirely fulfill the energy demand for all reserves while the SCD can use reserves in real-time. In turn, real-time prices can be lower than what was originally forecasted by BME.

The California ISO (CAISO) also faced issues when implementing technology in order to balance and maintain their markets. They implemented the BEEP System, balancing energy and ex-post pricing, which dispatches non-automatic generation control units in ten-minute intervals. Prior to starting market operation in 1998, CAISO enforced a cap on energy bids of $125/MWh in the real-time market, which became known as the BEEP cap. The purpose of this cap was an interim solution to prevent predicted rises in the MCPs due to issues with the BEEP system. The cap was then raised to $250/MWh. Other issues with the BEEP system have occurred, which have made the cap stay in effect. The bid cap predictions are currently linked with the implementation of new systems.

Another issue frequently faced by ISOs is the lack of demand elasticity, referring to the ability for customers to respond to prices by adjusting their demand. This is the most important way for customers to be protected against market power. CAISO has recognized additional sources of demand elasticity as the bridge to increase competitiveness as well as eventually eliminate price caps.

While having multiple energy markets gives an ISO further trading options, responsibly maintaining and regulating these can be an extensive burden. Each ISO must constantly monitor their market in order to come up with the necessary rules and regulations that affect every energy market price.



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