Transmission Services Overview

November 2018 Edition:  Transmission Services Overview
Transmission of electricity from power generators to energy end users forms the core of our electric grid. Costs incurred for transmission service and reliability represent a key price component of energy bills for consumers.
In this edition of Customer Insights, our experts will explain how transmission will affect your company’s energy budget. We’ll summarize the significant elements of transmission service for you, and how you might consider budgeting for and managing the costs associated with this service.

Glossary of Terms 
To help you understand transmission services, it is important to understand three key terms and how these costs are established.

  • Transmission: A cost derived from the delivery of energy from generators to consumers in a utility service area. Transmission costs fluctuate by utility and are determined by customer’s Network Service Peak Load (NSPL) and Transmission rate (NITS).
  • Network Service Peak Load (NSPL): NSPL is a value unique to each customer and is determined by their energy demand level during their local utility’s zonal transmission network peak(s).
  • Network Integrated Transmission Service(NITS): NITS rate is based on the Federal Energy Regulatory Commission’s (FERC) formula filing, taking into account all the dollars spent on transmission projects and maintenance. The NITS value is specific to a utility and may or may not change annually.

How are Transmission Rates Determined?
Transmission rates and service schedules are formed by Transmission Owners under the jurisdiction and oversight of the Federal Energy Regulatory Commission (FERC), and are administered by Regional Transmission Organizations (RTO), such as PJM and MISO.
PJM controls the northeastern region of the United States in all or some parts of Delaware, the upper Northeastern section of Illinois, the upper Northeastern section of Indiana, Kentucky, Maryland, the Southwestern tip of Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Virginia, West Virginia, and the District of Columbia.
MISO controls the Midwest region of the United States in all or some parts of Illinois, Indiana, Missouri, Iowa, Wisconsin, Michigan, Minnesota, Southwestern Kentucky, Arkansas, Louisiana, Alabama, Southeastern Texas, and portions of the Dakotas and Montana.
Rates for transmission service are set for each Utility Load Zone through what is termed Network Integration Transmission Service (NITS). NITS provides energy consumers with access to generation supply throughout the entire regional grid. Consumers behind a particular utility pay the same rate for transmission service, regardless of where the energy is generated.
In most utility service areas, NITS rates are adjusted annually through FERC-approved formula rate filings. This is to account for changes in operating costs, system loads, or cost recovery requirements for new transmission projects. Rates are based on several factors:

  • Transmission Owners Cost of Service
  • Cost of Capital on Rate Base, including allowed Return on Equity and Interest costs
  • Depreciation and Amortization
  • Tax
  • Operation and Maintenance

Transmission infrastructure investment has been prioritized and incentivized by the FERC in order to promote grid reliability and the efficient functioning of electricity markets. As a result, many Transmission Owners have invested heavily in grid upgrades and modernization programs, which has driven fairly steady year-over-year rate increases in many utility areas.

How Do Transmission Costs Affect Your Budget?
In most jurisdictions, transmission costs are assessed on retail energy suppliers by the RTOs. These costs are based on the Network Service Peak Load (NSPL) contributions of the retailers’ customers and the effective transmission rates.
Because transmission rates are often adjusted annually, they are difficult to forecast, and are outside of the control of your supplier. Consequently, over the course of long-term fixed all-inclusive contracts, adjustments to your transmission costs are likely to occur. To avoid these adjustments, a true-cost transmission pass-through product may be an option for your business.
Within the utility service areas of Ohio transmission is billed by the local utility as part of its bundled rate tariffs. Here transmission rates are most typically based on your monthly (non-coincident) peak demand, which makes controlling transmission costs more difficult. AEP Ohio, Dayton Power and Light and FirstEnergy Ohio offer limited programs that allow certain customers to elect alternative billing mechanisms that provide customers with enhanced opportunities to manage transmission costs. For more details on these programs and whether you might qualify, please contact your AEP Energy sales representative.

How is Your NSPL Established?
PJMs RTO determines your account’s NSPL during the twelve-month period (beginning November 1 and ending October 31) based on your load at the time of the actual peak demand hours within the utility zone in which your account is located. At the end of this twelve-month period, PJM and your local utility will identify the highest load hours that occurred over the period within the Utility Load Zone. Your local utility will identify your usage during these peak periods in order to establish your NSPL requirement.
Your account’s NSPL will subsequently become effective the following calendar year – starting January 1 and ending December 31.
MISO, on the other hand, calculates the transmission charges each month based on load that is coincident with the zonal utility peak load that month.
To obtain your organization’s NSPL, contact your AEP Energy sales representative.

How Are Your Ultimate Transmission Costs Determined?
Transmission cost to a customer is determined by the following formulas:

  • PJM: NSPL x DZSF x Zonal NITS Rate (x Days) = Cost to Customer
    • NSPL: Network Service Peak Load
    • DZSF: Daily Zonal Scaling Factor
      • Many utilities will apply a Daily Zonal Scaling Factor to ensure the sum of NSPLs is equal to peak load on which rates are based.
    • Zonal NITS Rate: Network Integrated Transmission Service rate by utility zone
    • Days: The number of days in the relevant billing period
  • MISO: TCP x Zonal NITS Rate (x Days) = Cost to Customer
    • TCP: Transmission Coincident Peak (i.e. customer load at time of Ameren system peak load)
    • Zonal NITS Rate: Network Integrated Transmission Service rate by utility zone
    • Days: The number of days in the relevant billing period.

Managing Your Transmission Costs
Where transmission costs are charged directly by PJM to retail suppliers, customers may reduce future transmission costs by reducing load during peak demand periods, thus reducing future NSPL tag.
AEP Energy’s PeakAdvisorySM Service for NSPL Peak Management is designed to inform you of likely coincident peak hours to help manage your transmission obligation for the coming year. With our complimentary service, an advance alert will be emailed to you at least a day ahead of the forecasted peak, followed by a final notice to confirm or cancel the event. You choose to activate your organization’s applicable load curtailment strategies to manage and reduce your transmission costs.
Contact your AEP Energy sales representative for more details.

Market Overview – AEP Energy Trading
Natural Gas

  • During the month of October 2018, bullish themes continued on discussion of historically low natural gas inventories and hype surrounding winter forecasts.
  • The larger gains were isolated more to the front of the curve, as prompt month (December 2018) gapped up $0.253/MMBtu to settle at $3.261/MMBtu.
  • Further out the curve, Calendar 2019 up $0.063/MMBtu to $2.841/MMBtu, while Calendar 2020 was up just $0.034/MMBtu to $2.678/MMBtu.

Power PJM – Ohio

  • Power followed gas higher as December 2018 on peak AEP – Dayton Hub jumped $1.45/MWh to $37.75/MWh.
  • Calendar 2019 was up $0.69/MWh to $37.64/MWh and 2020 rose $0.53/MWh to $35.88MWh.

Power Illinois:

  • PJM ComEd zone October 2018 day-ahead on-peak power lost $3.18/MWh closing the month at $34.51/MWh.
  • MISO Illinois.Hub October 2018 day-ahead on-peak power gained $1.02/MWh closing $39.91/MWh to end the month.

Any references made to prompt month natural gas will normally be associated with a range starting the first day of the month through the final settlement of the respective prompt month natural gas contract. Other references to forward natural gas prices and all power prices will be based on a range starting the first day of the month through the final day of the month.

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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