heat rate

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

PJM2014

PJM 2011 www.pjm.com 1

Interconnection Training Program

Load Scheduling

Incremental Loading Tables

LS2

Clement Lovasik

State & Member Training

Winter, 2011

PJM2011 www.pjm.com 2

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 units 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

units 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


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


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

PJM2011 www.pjm.com 6 www.pjm.com

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 units Minimum Down Time will be set equal to 110 percent of

the PJM defined unit class Minimum Down Time.

i.e.


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.


Heat Rate

Heat Rate = MBTU = Heat Input (MBTU)

MWhr MW Output (MWhr)

Heat Rate = 312 MBTU/hr = 10.4 MBTU

30 MW MWhr

EXAMPLE:


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.


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.



IHR = Increment of heat input (MBTU)

Increment of Power Output (MWhr)



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


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


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

=


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


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


Exercise GT-2.1


Questions

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heat rate

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