Guide to Understanding Capacity and Transmission Costs
4 min readUnderstanding the significant impact of capacity and transmission costs is essential for businesses, as these costs can sometimes account for a large portion of your electricity bill, depending on your location. By establishing a solid foundation of knowledge on how these costs are determined, you can better manage your overall energy budget. Additionally, it can empower you to make informed decisions that can lead to significant savings and enhanced operational efficiency.
Supporting Grid Reliability Through Capacity Markets
Balancing energy demand with supply is crucial for grid reliability and resiliency. If there’s not enough energy being generated, the grid can experience brownouts or blackouts. A tool that can be used to incent sufficient supply is called a ‘Capacity Market’. Capacity markets reward resources for being available to meet demand and penalize resources for not showing up when they are needed.
Electricity capacity resources include power plants (nuclear, gas and coal) and renewable resources (wind, solar and hydro). Additionally, customers can reduce electricity demand through programs like demand response, which rewards end-users for cutting back on consumption during peak demand periods to help maintain grid reliability.
Impact of Regional Electricity Grids
Regional differences significantly impact energy prices and capacity. For example, the Northeast relies heavily on natural gas for electricity, but the limited infrastructure for gas pipelines and transmission lines can affect supply reliability during peak times. As a result, power prices in the Northeast are more susceptible to price volatility. In contrast, the Midwest experiences less power price volatility due to more supply availability and lower influence of natural gas prices.
There are seven regional ‘grids’ that play a critical role in ensuring safe and reliable electricity delivery. Some of these grids, known as Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs), pay power generators and demand response customers for their ‘capacity’ to guarantee enough supply to meet their future peak energy demand.
Understanding Capacity Auctions
To facilitate payments to generators, some ISOs and RTOs set capacity rates through competitive auctions. Before each auction, they provide peak electric usage estimates for their region. Bidders then submit offers for power plants, imports, demand response and energy efficiency. The auction procures enough capacity to meet peak usage plus a reserve margin. An accepted bid becomes a commitment, and if a capacity resource isn’t available when needed, the resource owner can face a financial penalty.
Capacity auctions differ among ISOs and RTOs. For example, PJM sets capacity rates 3 years in advance, whereas MISO sets theirs for only one year ahead. However, recent market reforms have caused delays in these auctions. PJM’s December 2024 auction for the 2026/2027 planning year was delayed to July 2025, causing prolonged uncertainty for customers regarding future capacity rates and planning.
Ultimately, consumers pay to have the necessary electricity generating capacity available. Energy suppliers, also known as Load Serving Entities (LSEs), charge customers for capacity, which may appear as a separate line item on the bill or be incorporated with other charges. The supplier then pays the ISO/RTO for the capacity required to cover the megawatts they are contracted to serve, and the ISO/RTO pays the participating generators and demand response suppliers.
Determining Capacity Obligations
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 an end-user receives supply from an LSE, the local utility provides the PLC information to the 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 based on their usage during the peak hour from the previous year’s peak-setting day. This is the hour within each ISO’s given peak setting parameters (e.g.: June – Sept) when usage was highest across the ISO. Once established, the ICAP is set for the planning year, which is May 1 through April 30 in NYISO and June 1 through May 31 in ISO-NE.
- In the PJM territory, which includes all or part of 13 states in the Mid-Atlantic, Ohio and Northern Illinois regions, and Washington, D.C., an end user’s Capacity PLC is determined by their usage during the “five coincident peak hours” from the previous year. These are typically weekday summer hours when usage was highest across the RTO. Once established, the PLC is set for the planning year, which is June 1 through May 31. Similar to Capacity, PJM customers also have a Transmission PLC or NSPL, which is determined based on each customer’s usage during the corresponding NSPL-setting period for their zone.
Strategies for Managing Peak Load Contributions
Since annual capacity and transmission rates are based on consumption during peak-setting events, many businesses actively curtail (reduce) their demand at those times to reduce costs. At Constellation, our Peak Load Management program notifies end users on a day-ahead and/or day-of basis of a potential capacity peak setting event. Consumers who choose to reduce their consumption may lower their capacity obligation for the following year.
Take Control of Your Energy Future
Understanding and managing both capacity and transmission costs are crucial for optimizing your overall energy budget. Constellation offers a range of solutions to help customers manage their electricity costs — identifying opportunities to optimize or reduce consumption during key times, which can lower costs and enhance grid reliability.
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