Capacity Costs – What Factors Make Up Your Total Cost?

Many of our customers experience benefits by participating in AEP Energy programs that help them manage their capacity. In recent editions of Customer Insights, we’ve explained that passing through capacity charges can be beneficial to customers looking to lower overall capacity costs by paying the true cost for capacity minus risk premiums. When considering capacity management, it’s important to understand what factors influence these costs and what to expect in the supply portion of your bill. In this edition of Customer Insights, our experts go a step further by exploring the factors attributing to your final capacity costs. Understanding the mechanics and potential pitfalls will help you get the most out of your energy supply contracts in the future.

What is the Capacity Market?

Regional Transmission Organization (RTO), as PJM and MISO, administer wholesale power markets and set reliability rules in your state. Reliability is accounted for as a component of your supply cost called capacity. The RTOs ensure year-round, reliable power supplies by securing commitments from power plants to generate electricity to meet customer demand during peak periods. To accomplish this, the RTOs incentivize power plants offering capacity with a guaranteed revenue stream in the form of capacity payments. The amount of payments the power plant receives is determined by annual capacity auctions managed by the RTO.  You could think of capacity like an insurance policy, ensuring power plants will react when called upon to generate electricity.

Each year PJM and MISO hold competitive auctions to secure future capacity requirements at the lowest reasonable price for Load Serving Entities (LSE), such as AEP Energy. PJM conducts four capacity auctions leading up to the delivery year. The first auction is called the Base Residual Auction (BRA) and is conducted four years prior to the year the energy will be delivered. Annual Incremental Auctions (IA) occur each year after the BRA up to the delivery year. The IAs are held to better match supply and demand as load forecasts are improved. PJM auctions are governed by what is known as the Reliability Pricing Model (RPM), which establishes the price for capacity subject to generation constraints and other marketing conditions. The RPM rates vary by Locational Delivery Area (LDA) and are effective each year; June 1 through May 31 of the next year. Below is PJMs 2019 auction schedule.

PJM 2019 Auction Schedule

MISO, on the other hand, conducts only one auction that occurs in April prior to the start of each delivery year. The MISO construct is known as Resource Adequacy. Like PJM’s market, Resource Adequacy ensures enough reliable generating resources are available to fulfill electricity demand. MISO’s auction is called the Planning Reserve Auction (PRA), which sets a price for capacity subject to transmission constraints between capacity zones. The PRA rates can vary by MISOs Local Resource Zone (LRZ) and are effective every year from the June 1 through May 31 of the next year. The public utility, Ameren, located in Illinois, is in LRZ four (4). Below is MISO’s 2019 auction schedule.

MISO 2019 Auction Schedule

Depending on your region and market, capacity can have a multitude of moving pieces that reset on an annual basis. With as much as 16% of your total energy supply cost going toward capacity, it is important to familiarize yourself with the nuances of capacity within your respective market and understand the factors attributing to your overall capacity cost.

Whether your energy contract fixes your capacity costs, or your capacity charges are passed through in the supply portion of your bill, all customers’ capacity costs include the same factors. Below is a description showing the context of the industry standards for billing capacity as a pass-through. We’ll explain each of these components further in this article.


Capacity Cost Factors

There are many factors that lead to your total capacity cost, including:   

Peak Load Contribution (PLC) is unique to each customer. Your PLC is determined by your local utility by averaging your demand during the five highest demand hours for the entire PJM system during the summer months. These demand hours are called Coincident Peak or CP hours. In PJM, your PLC is posted in December by the Electric Distribution Company (EDC), and becomes effective June 1 of the following year.

In MISO, your PLC is established solely on the single coincident peak hour from the previous planning year. MISO PLCs are also inclusive of Planning Reserve Margin (PRM), which is additional margin that covers unforeseen demand or outages on the system.

Used by both PJM and MISO for allocating the total zonal cost of capacity to the Load Serving Entities’ (LSE), your PLC is the main quantity for determining your monthly capacity cost. The PLC tag should be shown on your bill within the capacity calculation and displayed in kilowatts (kW). The PLC tag will remain constant throughout the planning year beginning June 1. You can confirm your PLC with your AEP Energy sales representative or through your EDC. 

Changes to your PLC can impact your year-over-year capacity costs. Unlike capacity prices, you have some control over your PLC. AEP Energy has complimentary programs and services in place to help you control your PLC during periods of high demand to manage the risk associated with annual changes to your PLC. To learn more about our load management strategies and services, click here.

Zonal Capacity Price (ZCP) is the final capacity price as determined by the third incremental auction results within PJM’s Reliability Pricing Model (RPM) construct. In MISO, the ZCP is the Planning Resource Auction (PRA) result as determined by the Resource Adequacy construct. Prices are effective June 1 of each delivery year.

In PJM the final capacity price is inclusive of any Capacity Transfer Rights (CTR) which serve as a credit to the load. When discussing energy contracts, it is important to confirm the benefit from the CTR is included in the zonal capacity price being billed by the supplier. Annual changes to these factors can have a significant impact on your year-over-year capacity costs.

PJM auctions begin well in advance of the delivery year making it possible to offset the impact of fluctuating capacity prices. MISO has only one auction occurring in the spring prior to the delivery year, making it difficult to know in advance what future capacity prices may be. Regardless of the RTO, the ZCP should appear on your bill as a $/kW-day rate remaining consistent with the PLC.   

AEP Energy offers strategies to help you smooth your capacity costs over the long term. Contact your sales representative to learn more.

Forecast Pool Requirements (FPR) is additional margin used to cover unforeseen demand spikes or higher than expected outages on the system, like MISO’s PRM.

FPR is the product of two components. The first is the Installed Reserve Margin (IRM) which is the percentage of installed capacity (ICAP) required above the forecast to ensure reliability. ICAP is the amount of electricity the power plant can produce. The second factor in calculating FPR is the Equivalent Demand Forced Outage Rate (EFORd). EFORd measures the likelihood of a power plant’s unavailability due to a forced outage or a partial reduction in its capability when there is demand on the plant to generate electricity. PJM applies its EFORd rate to ICAP, removing the effects of forced outages, converting the IRM value from ICAP to unforced capacity (UCAP). UCAP is the ICAP value of the plant reduced by EFORd.

PJM’s FPR is published along with the auction results, but as a separate component from the price. MISO’s Planning Reserve Margin (PRM) is also determined in conjunction with the auction, but it’s applied by the utility when establishing the PLC. In both markets, these factors are known in advance of the delivery year and play an important part in the buildup of your total capacity cost. If your account is in PJM’s territory, the FPR will appear in the supply portion of your bill as a multiplier in the billing formula.

Zonal Scaling Factors are used to account for differences between forecasted and purchased capacity vs. actual capacity demanded based on PLCs.

There are two types of zonal scaling factors applied within the capacity calculation: 1) Final Zonal Scaling Factor (FZSF) and; 2) the Daily Zonal Scaling Factor (DZSF). The FZSF is determined in advance of the delivery year and changes with each auction. The FZSF will remain static over the course of the delivery year. The DZSF changes daily and is reported to PJM by the EDC. The DZSF are nominal changes to ensure that the daily aggregate of the LSE PLCs meet the zonal UCAP obligation. This means the DZSF can settle either positive or negative with negative being a credit to the LSE and/or to you. These factors should be transparent in the supply portion of your bill.

MISO does not include additional scaling factors to your capacity formula.

Weather Normalization Factors (WNF) are adjustments to the total capacity obligation of the LSE reported by AEP Ohio to PJM for changes due to weather or load growth. EDC zones outside of AEP Ohio apply the WNF when establishing your PLC. Often, suppliers will combine the WNF into the DZSF for display purposes on your bill.

Businesses in the AEP Ohio utility zone are affected by WNF. Your WNF factor, effective June 1, 2019 through May 31, 2020, is 0.997, down from the current factor of 1.075, which will result in a significant decrease in your monthly capacity spend.

Days; the number of days in your billing cycle is the final piece to the equation. The PLC and ZCP are daily rates. Each day the EDC reports the capacity obligation for the zone by the LSE, which PJM and MISO use to allocate capacity cost. You should always be billed for capacity for the same amount of days within your billing cycle. If you are calculating your estimated capacity charges for an entire year, you should use the number of days within that year (make sure to remember leap year!).

Need Advice?

Over the past several years, industrial and commercial customers have opted to pass-through capacity as part of a strategic plan to lower their overall supply costs. While this can be a good strategy, it is also important to understand the factors within these pass-through calculations that can drive fluctuations in your total capacity costs.

Our AEP Energy experts keep up-to-date with the RTOs to bring you information regarding the most recent capacity prices and factors affecting your energy costs. We can also help you calculate estimated future capacity costs to help you plan for your business. Give your AEP Energy sale representative a call today or connect with us online at

AEP Energy does not guarantee the accuracy, timeliness, suitability, completeness, freedom from error, or value of any information herein. The information presented is provided “as is”, “as available”, and for informational purposes only, speaks only to events or circumstances on or before the date it is presented, and should not be construed as advice, a recommendation, or a guarantee of future results. AEP Energy disclaims any and all liabilities and warranties related hereto, including any obligation to update or correct the information herein. Summaries and website links included herein (collectively, “Links”) are not under AEP Energy’s control and are provided for reference only and not for commercial purposes. AEP Energy does not endorse or approve of the Links or related information and does not provide any warranty of any kind or nature related thereto.

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