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Transmission Services: How Does This Affect You?

September 10, 2016

September 2016 Edition: Transmission is one of the many electric service components affecting energy prices for consumers, contributing to roughly 8% of your overall energy costs and in some regions of the United States it has reached as high as 30%. Most alarming, transmission costs throughout the country have been doubling and in some cases tripling in areas over the past decade.


Market Overview

Jason Jarecki


September 2016 Natural Gas and Power Updates

Natural Gas

  • During the month of August, natural gas prices were supported by above normal temperatures.
  • Specifically, the shorter term delivery months were strong while longer term natural gas delivery experienced more producer selling (also referred to as forward natural gas hedging activity).
  • The prompt month (September 2016) Henry Hub natural gas contract was up $0.011/mmbtu to $2.887/mmbtu.
  • Calendar year 2017 declined $0.079/mmbtu to $3.106/mmbtu
  • Calendar year 2018 was down $0.060/mmbtu to $2.969/mmbtu

Power: PJM – Ohio

  • Power experienced warm temperatures which pushed prices higher in the front of the price curve.
  • September delivery On-Peak AEP Dayton (AD) Hub rose $0.82/MWh to $33.82/MWh.
  • The remaining balance of 2016 delivery was up $0.57/MWh to $34.00/MWh.
  • Further out the price curve, 2017 delivery AD was marginally higher by $0.04/MWh to $36.67/MWh.
  • 2018 delivery dropped $0.48/MWh to $35.32/MWh on some generator hedging activity.

Power: Illinois

  • While the overall prices of energy remain low, the Illinois power market continues to be very lliquid compared to other markets like PJM and ERCOT-Texas, especially, at the MISO Illinois Hub (please refer to prior monthly updates) which is raising transaction costs.
  • Similar to Ohio, there has been significant legislative discussion in Illinois concerning power purchase agreements from Exelon owned nuclear power plants. Several different stakeholders are involved with these talks including those previously strongly opposed to PPA (Power Purchase Agreements) structures in other states, namely, Dynegy.
  • End users in the commercial and industrial sector should continue to monitor the situation since any type of PPA or restructuring concerning these nuclear plants or other distressed coal plants could result in increased utility distribution costs.
  • Years ago MISO established a 1 year voluntary capacity auctions creating more access for load serving entities to purchase the capacity required to serve their customers. This resulted in ease and more equitable procurement so that capacity wasn’t completely controlled by a few large generators. A major disconnect has been that wholesale and retail contracts typically go out for more than one year and are not based on the capacity planning year period (June-May) used in the auction which forces purchases directly from generators.
  • MISO is in the process of revamping the way capacity is procured in IL on two major fronts: (1) MISO wants to add a 3 year auction (currently it is 1 year Jun-May); (2) MISO is also considering a move to seasonal capacity (separate procurements for winter and summer).
  • Longer term price signals are typically helpful in reducing volatility (making capacity costs more stable for the end user). It also moves capacity procurement more in line with the typical contracting and hedging strategies for commercial and industrial customers that go out multiple years.
  • Seasonal capacity is a new concept that has come up because of the polar vortex in 2014 where coal piles froze at power plants and natural gas was needed to flow for home heating over being used to run power plants. This increased grid costs and created reliability issues. It is unclear what the seasonal structure will look like, but worth monitoring.
  • Additionally, MISO recently took comments on whether to have more stringent import/export limits for the Illinois region which may potentially increase capacity prices for customers. Large generators would like to see this take affect sooner starting in the June 1, 2017 planning year. Depending on the comments this measure could be pushed further out to start in June 1, 2018, but it is inevitable.
  • In a separate but related matter, the Coalition of MISO Transmission Customers (CMTC) has filed a FERC compliant alleging that MISO used incorrect import limits to the MISO North region which includes Illinois. They contend this resulted in much higher Capacity auction prices in previous years. Import/export limits are very important to auctions and the capacity costs you pay.
  • Please speak with your AEP Energy representative with any questions on this or any other topics.

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.


Transmission Services: How Does This Affect You? 

Transmission is one of the many electric service components affecting energy prices for consumers, contributing to roughly 8% of your overall energy costs and in some regions of the United States it has reached as high as 30%. Most alarming, transmission costs throughout the country have been doubling and in some cases tripling in areas over the past decade. Transmission developers and owners have demonstrated a need for investment in grid infrastructure and the Regional Transmission Organizations (RTOs) and regulators have approved a significant number of projects to upgrade the grid after years of little investment. In the midst of a natural gas revolution, there may be debate in coming years over the merits of this size investment in interstate electric infrastructure, especially, with meager electricity demand growth and significant technology gains in distributed generation. Regardless, transmission rates will continue to increase for customers for several more years as projects continue to be built so it is crucial that you consult with your AEP Energy trusted advisor to look at ways to actively reduce this line item.

Various PJM Historical Network Transmission Rates
PJM
Zone
AEP
ATSI >=
138KV
ComEd
Duke
Duquesne
PPL
6/1/12
$28,625
$9,235
$18,730
$14,170
$37,479
$24,119
7/1/12
$27,431
$9,235
$18,730
$14,170
$37,479
$24,119
6/1/13
$27,431
$9,921
$21,732
$11,200
$35,781
$36,688
7/1/13
$32,035
$9,921
$21,732
$11,200
$35,781
$36,688
6/1/14
$32,035
$14,895
$24,025
$15,882
$39,053
$38,729
7/1/14
$37,597
$14,895
$24,025
$15,882
$39,053
$38729
10/1/14
$37,597
$19,145
$24,025
$15,882
$39,053
$38,729
1/1/15
$37,597
$37,014
$24,025
$15,882
$39,053
$38,729
4/1/15
$37,597
$37,014
$31,761
$15,882
$39,053
$38,729
6/1/15
$37,597
$37,014
$31,470
$17,039
$38,880
$34,595
7/1/15
- 8/1/15
$41,438
$37,014
$31,532
$17,039
$38,880
$34,595
1/1/16
$41,438
$43,391
$31,532
$17,039
$38,880
$34,595
6/1/16
$41,438
$43,391
$35,543
$19,881
$50,695
$41,952
7/1/16
$45,545
$43,391
$35,543
$19,881
$50,695
$41,952
Total Net
% Change
59%
370%
90%
40%
35%
74%

transmission-rates-graph

Most customers are billed for transmission charges by your competitive retail energy supplier. There are, however, some utilities, such as those in Ohio, who directly bill customers for transmission service and transmission related ancillary charges. To understand how transmission will affect your company’s energy budget, AEP Energy would like to outline some important aspects.

First, what is Transmission?

Electricity, once generated, must be transmitted to your local utility before it is delivered to you. Transmission is the cost associated with the movement (or transfer) of electric energy over an interconnected group of electric wires, conductors, and other equipment (known as the transmission network). This network is used to move large quantities of power at high voltage, usually over long distances starting from a generating plant (receiving point) to major substations near your load (delivery points).

Transmission is under the jurisdiction of RTOs such as PJM and MISO, who coordinate the movement of wholesale electricity, but transmission is ultimately regulated at the FERC (Federal Energy Regulatory Commission) level. PJM controls a large portion of the northeastern region of the United States including 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, Tennessee, Virginia, West Virginia, and the District of Columbia. MISO controls the Midwest region of the United States in all or parts of Illinois, Indiana, Missouri, Iowa, Wisconsin, Michigan, Minnesota, Southwestern Kentucky, Arkansas, Louisiana, Alabama, Southeastern Texas, and portions of the Dakotas and Montana.

What factors define Transmission?
Transmission is a cost derived from the delivery of energy from generators to consumers in a utility service area. Transmission owners are allowed a rate of return on their investment which is collected through a transmission rate that all retail and wholesale load pays. Transmission costs fluctuate by zone (utility) and are determined by your Network Service Peak Load (NSPL) and zonal transmission rate Network Integrated Transmission Service (Zonal NITS) for your utility service area.

Zonal NITS rates are based on FERC (Federal Energy Regulatory Commission) formula filing that takes account for all dollars spent on transmission projects and maintenance. The Zonal NITS value is specific to your respective utility and is often adjusted annually to account for changes in operating costs, system loads, or cost recovery requirements for new transmission projects. Zonal NITS rates are based on several factors:

  • Transmission Owners Cost of Service
  • Cost of Capital on Rate Base
  • Depreciation and Amortization
  • Tax
  • Operation and Maintenance

What is your Network Service Peak Load (NSPL), and how is this established?
A customer’s Network Service Peak Load (NSPL) is determined in accordance with PJM and the local utility rules. Typically, at the end of a 12-month period, PJM and the local utility will identify the highest unrestricted load hour(s) that occurred on different days during the period. Your local utility will reconcile the different hours back when your energy demand was at its greatest to the highest unrestricted peak load hour that PJM has determined to be your local utility’s zonal peak load obligation. The customer’s transmission NSPL will be updated and billed for the next calendar year starting January 1, ending December 31.

MISO, similarly, calculates the transmission charges each month based on load this is coincident with the zonal utility peak load that month.
To obtain your organization’s NSPL and to look at ways to reduce it, contact your AEP Energy Sales Representative.

What components impact your Transmission cost?
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 sum of NSPLs is equal to peak load on which rates are based.
    • Zonal NITS Rate = Network Integrated Transmission Service rate by zone (utility).
    • Number of days: The number of days in the calendar year when calculating your annual capacity cost.
  • 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 zone (utility).
    • Number of days: The number of days in the calendar year when calculating your annual capacity cost.

AEP Energy makes every reasonable effort to present accurate and reliable information. Certain data, however, may be provided by a third party. As such, AEP Energy cannot guarantee the accuracy of the information provided herein.

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