Disclaimer

• This training presentation is provided as a reference for preparing for the PJM Certification Exam.

• Note that the following information may not reflect current PJM rules and operating procedures.

• For current training material, please visit: http://pjm.com/training/training-material.aspx

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PJM ©2011 www.pjm.com 1

Interconnection Training Program

Load Scheduling

Incremental Loading Tables

LS2

Clement Lovasik

State & Member Training

Winter, 2011

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LS 2 Objectives

• Describe how incremental loading tables are derived

and used for “least cost” dispatch of generating units

to match load demand.

– Describe the two modes of submitting bids for

generating resources cost based and price based

– Describe how a cost based incremental loading curve

for a generating unit is developed, given the unit’s

incremental heat rate and fuel cost

– Develop and use an incremental loading table for a

sample system given unit data

– Describe the “least cost” method for dispatching

generating units for a sample system given an

incremental loading table for the system

Cost Based Bids

• Generation offers to the PJM market are capped at the

unit’s production cost plus a 10% adder

• Start up and no load costs can be updated daily

• Offer developed using guidelines of the Cost Development

Task Force (CDTF)

• CDTF Rules laid out in PJM Manual 15

• Cost based bids are used to cost cap the unit should the

units used to control for a contingency fail the “Three Pivotal

Supplier Test”

• All generators must have a cost based bid on file in eMKT

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Historic LMP-Capped / Negotiated Offers

Historic LMP-Capped Offers

• Generation offers using historic LMPs at the generation

bus where energy is injected

• Value is determined by calculating the average LMP at the

generation bus during all hours over the past six months in

which the resource was dispatched above minimum.

Negotiated Offers

• Offer is based on a negotiated value with the PJM Market

Monitor

• Case-by-case basis

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Price Based Offers

• Offer is based on what the generation owner believes the

market will bear

• Start-up and no-load costs can be updated every 6 months

• Prior to March 31 for period April 1 to September 30

• Prior to September 30 for period October 1 to March 31

• Units may file with MMU for cost-based start-up and no-loads

which may be updated daily

• When switching to Priced Based offers a unit may not

switch back to another type of offer

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Parameter-Limited Schedules

What are Parameter-Limited Schedules?

Parameter-Limited Schedules are limitations that could

be imposed on the parameters that generators submit as

part of their offer.

• All cost based offers are PLS

• Price based schedules can be PLS or non-PLS

These pre-determined limits are used when

certain operational circumstances exist.

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Parameter Limited Schedules

• For each unit class, minimum acceptable operating

parameters include:

– Turn Down Ratio (Ratio of Eco Max MW to Eco Min MW)

– Minimum Down Time

– Minimum Run Time

– Maximum Daily Starts

– Maximum Weekly Starts

Future parameters MAY include: Hot Start Notification Time, Warm Start Notification Time, Cold Start Notification Time

Some parameters will be set based

on operating history of the unit

compared to % of PJM-defined unit

class

The initial Minimum Down Time for each unit is based on

the minimum of the Minimum Down Times submitted over

the prior 24 months, if the resultant minimum down time is

less than or equal to 110 percent of the PJM-defined unit

class Minimum Down Time. If Minimum Down Time

submitted for a unit is more than 110 percent of the PJM-

defined unit class Minimum Down Time, then the unit’s

Minimum Down Time will be set equal to 110 percent of

the PJM defined unit class Minimum Down Time.

i.e.

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Heat Rate

• Measure of efficiency of a unit in converting heat energy to electrical energy.

• Ratio of heat supplied by fuel (MBTU) to MWhr of electrical energy delivered by a unit. – MBTU stands for one million BTUs, which can also be

expressed as one decatherm.

– BTU stands for British Thermal Units

• As heat rate increases, efficiency decreases.

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Heat Rate

Heat Rate = MBTU = Heat Input (MBTU)

MWhr MW Output (MWhr)

Heat Rate = 312 MBTU/hr = 10.4 MBTU

30 MW MWhr

EXAMPLE:

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Heat Rate

• Optimum efficiency is normally at about 80% of full

load.

• Efficiency is less at lower loads due to heat required

to keep boiler hot an turbine spinning.

• At higher loads, losses in the turbine reduce

efficiency.

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Incremental Heat Rate

• IHR = Incremental Heat Rate

• IHR is significant to economic power system

operation.

• IHR is the change in heat input to a unit needed to

produce a given change in generation.

• IHR of a unit increases steadily with generation.

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Incremental Heat Rate

IHR = Increment of heat input (MBTU)

Increment of Power Output (MWhr)

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Incremental Heat Rate

• Increment of heat input =

392 MBTU/hr - 312MBTU/hr = 80 MBTU/hr

• Increment of power output =

40 MW - 30 MW = 10 MW

IHR = Increment of heat input (MBTU)

Increment of Power Output (MWhr)

IHR = 80 MBTU/hr = 8.0 MBTU

10 MW MWhr

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Incremental Cost

• Incremental cost for a unit at a given level of generation

is the cost per MW to produce the next increment of

power output.

• Is calculated by taking the product of the incremental

heat rate and the fuel cost.

INCREMENTAL COST (LAMBDA)

POWER OUTPUT IHR INC. COST

(MW) (MBTU/MWhr) ($/MWhr)

20

30 7.6 (7.6*2.3) = 17.5

40 8.0 (8.0*2.3) = 18.4

50 8.4 (8.4*2.3) = 19.3

60 8.8 (8.8*2.3) = 20.2

70 9.2 (9.2*2.3) = 21.2

80 10.2 (10.2*2.3) = 23.5

90 11.6 (11.6*2.3) = 26.7

100 12.7 (12.7*2.3) = 29.2

Inc. Cost = IHR * Fuel Cost

$/MWhr = MBTU/MWhr * $/MBTU

Fuel Cost = $2.30 / MBTUKEY

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Incremental Cost

Incremental Cost = MBTU x Fuel Cost

MWhr

Incremental Cost = 8.0 MBTU x 2.3 = 18.4 $/MWhr

MWhr

MBTU P

POWER MBTU

Relationship between Incremental Cost and Incremental Heat Rate

Cost for an Increment of Power P = Increase in MBTU needed to produce P Incremental Cost = IHR X Fuel Cost

($)

MWhr (MBTU) MWhr

X ($)

MBTU

Fuel Generating Unit Electrical Energy

$ X MBTU

MBTU MWhr

$ MWhr

=

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For Economic operation of a power system all generating units should be dispatched

at equal incremental cost.

Rate 1 Unit 1 Unit 2 Unit 3 Total 14.0 100 100 100 300 15.0 200 200 200 600 16.0 250 250 250 750 17.0 300 300 300 900

18.0 350 350 350 1050

PRINCIPLE OF ECONOMIC DISPATCH

Principle of Economic Dispatch

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Load (MW x 1000)

1 3 5 7 9 11 13 15 17 19 21 23

50

46

42

38

34

30

22

26

$5

$10

$15

$20

$25

$30

$35

$40

$45

Hour of Day

Dispatching Generation to Meet Load

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Exercise GT-2.1

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Questions

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