In this post, we are going to focus on ISO-NE capacity charges. Most Regional Transmission Organizations (RTOs) have some type of capacity market, the exceptions being Alberta and Texas, who rely on what's called an energy only market structure. In deregulated electricity markets, there are two main products: electricity; and capacity. Capacity can be viewed as a call option on electricity where a peaking resource is paid just to be on standby in the event that it's needed. In a grid with peaky load characteristics, capacity markets are crucial to keeping the lights on during spikes in demand. The graphic below shows the daily peak demands for the ISO-NE system during the summer of 2012.
In the graphic, you can see that excursions over 23,000 MW in demand are infrequent. Despite their infrequency, there must be enough capacity available to meet demand on hot days when the load spikes. Although the graph above just shows 2012, most ISO-NE summers in the last decade have exhibited load patterns that look just like this.
In capacity markets, if capacity resources get paid to provide capacity then someone else has to pay. As Milton Friedman said, "There is no free lunch" and in capacity markets end use customers ultimately pay for the capacity required to serve their loads. Determining how much end use customers should pay and how to calculate it is a tricky task. PJM, ISO-NE, NYISO, California, and Ontario all allocate costs to load using different methodologies. Over the next few months, we'll walk through each, but ISO-NE is a good place to start since its a pretty straightforward system. In the graphic below, you can see a simple illustration of how monies are collected from load and distributed to capacity resources.
Any customer with an interval meter is assigned an Installed Capacity Tag (ICAP) based on their demand during the ISO-NE annual system peak hour. This is called the customer's coincident demand. There are some exceptions to this in New England for clients in Vermont and those served by municipal utilities. Ultimately, those customers pay for capacity too, but the costs are socialized by the utility. For residential and small commercial customers, the ICAP tag is developed based on a formula. The graphic below shows how the ICAP tag is determined for two interval metered customers. One customer is flexible and can drop their load when they think a system peak is likely. The other customer can't because they are inflexible.
Each customer will get an ICAP Tag based on their coincident peak with the ISO-NE system, but there is a lag between setting an ICAP tag and actually paying for it. The graphic below shows the schedule for ICAP tag assignment and cost allocation.
For many end use customers buying energy competitively in New England, treating capacity charges as a "pass through" item in the contract could lead to a significant cost savings opportunity. Capacity prices are set during the ISO-NE Forward Capacity Market (FCM) auction, but they change slightly from month to month based on the reserve margin and other factors that determine ultimate charges to load. The graph below shows historical capacity charges in the ISO-NE market.
End use customers can take control of this charge by reducing their afternoon demands on the hottest days of the year or by working with an energy service company that warns customers when peak load hours are likely to occur so they can initiate demand response procedures. Presently, Constellation and EnerNOC both offer such services in ISO-NE although there are some significant differences in how they bill customers for the service. If you want to talk more about this stuff, give us a call.