Energy 101: Typical Cost Components of Electricity Supply
In our latest Energy 101 piece, we’re diving in with a closer look at electricity supply cost components, more specifically, capacity and transmission. Energy is of course the main component of your electricity supply, but capacity and transmission are large slices of the pie as well.
The typical cost components of energy include the following:
- With ancillary and ‘other’ rounding out that mix
Transmission refers to the costs associated with the movement of electricity over long distances through what is referred to most commonly as the grid, or the interconnected lines that form a network
- Diving Deeper: Transmission is regulated by the Federal Energy Regulatory Commission (FERC) and operated by either an ISO (independent system operator) or an RTO (regional system operator). Common examples of an ISO or RTO are ERCOT, in Texas, or MISO, which manages electricity across 15 states.
- These organizations assist with planning and operational functions of the power grid and ensure all customers have access to a reliable supply. They also facilitate competition among wholesale suppliers and protect consumers from market manipulation.
How Are Transmission Costs Calculated?
The ISOs or RTOs work with transmission owners to plan and manage the operation, maintenance and expansion of transmission resources. Typically the transmission owners are the utilities. This is the case in most of PJM for example. They provide their annual costs of the transmission systems to the ISO or RTO.
The annual dollars are then spread over the demand value across the zone, known as the network service peak load (NSPL). The NSPL is calculated using a zone’s five peak hours of the past year. The peak hours vary by zone. In recent years, several utilities have used peak hours from the most recent winter as well as summer months. Once a zone’s peak hours are defined, the utilities calculate an NSPL for each customer based on their usage in these hours.
Many markets across the country use a construct called a ‘Capacity Market’. The ‘Capacity Market’ is designed to to help system operators ensure that there is enough electricity supply available on the grid at all times to meet potential demand on the hottest and coldest days of the year – at the lowest possible cost.
Why Capacity Costs Matter to Electric Customers
Capacity is typically the second largest component of a customer’s electricity supply cost, which is why the charges are important for customers to understand. In PJM for example, the capacity planning year runs from June 1st to May 31st each year, and a customer’s Peak Load Contribution (PLC) changes annually, based on PJM’s five coincident peak days and five highest peak hours of system demand each year. A customer’s capacity cost per MW-day is usually driven by high PLCs relative to the average demand. The ratio of the average demand to capacity PLC is known as capacity load factor.
Energy suppliers (ESCOs) charge their customers based on the approved capacity rate. This charge may be in a separate line item on the bill or incorporated into a line item with other charges. The supplier then pays the ISO/RTO for the capacity required to cover the MWs they are contracted to serve and the ISO/RTO in turn pays the participating generators and demand response suppliers.
Regional Capacity Charges
Capacity obligations in many markets are generally determined by an end-user’s peak load contribution (PLC), Installed Capacity (ICAP) or peak monthly demand during a specific timeframe. When the end-user takes supply from an LSE, the local utility provides the PLC to suppliers. Here are some examples of how end-users’ PLCs and ICAPs are determined.
In New York and New England (NYISO & ISO-NE) markets, an end-user’s ICAP is determined by their usage during the “peak hour from the previous year.” The peak hour is the hour during which the usage was the highest across the ISO, as published by the ISO. Once a customer’s ICAP is established, it is set for the planning year. The planning year is May 1-April 30 in NYISO and June 1-May 31 in ISO-NE.
Across the 13 states (Mid Atlantic, Ohio & Northern Illinois) and Washington DC that comprise the PJM territory, an end user’s PLC is determined by their usage during the “five coincident peak hours” (totaled and averaged) from the previous year. The five coincident peak hours are the hours during which the usage was the highest across the RTO, as published by the RTO. Once a customer’s PLC is established, it is set for the planning year, which is June 1-May 31.
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