Simulating Power System Operations

GRIDSCHOOL 2010MARCH 8-12, 2010 RICHMOND, VIRGINIA

INSTITUTE OF PUBLIC UTILITIESARGONNE NATIONAL LABORATORY

Thomas D. VeselkaCenter for Energy, Economic, and Environmental Systems Analysis

Decision and Information Sciences DivisionARGONNE NATIONAL LABORATORY

tdveselka@anl.gov 630.252.6711

Do not cite or distribute without permission

MICHIGAN STATE UNIVERSITY

Veselka - 02

GridSchool 2010

Power System OperatorsBalance Supply and Demand

GenerationSupply

TransmissionDistribution Consumer

Demand

Real Time DispatchH1H1 H5H5 H10H10 H15H15 H20H20 H25H25

Day Ahead Planning

D1D1 D8D8

Week Ahead Planning

W1W1 W5W5 W9W9 W13W13

Long-Term Planning

Multi-Year Planning

Year Ahead Planning

Yr1Yr1 Yr2Yr2 Yr3Yr3 Yr4Yr4 Yr5Yr5 Yr6Yr6

Month Ahead Planning

M1M1 M3M3 M5M5 M7M7 M9M9 M11M11 M13M13 M15M15

Real Time DispatchH1H1 H5H5 H10H10 H15H15 H20H20 H25H25

Day Ahead Planning

D1D1 D8D8

Week Ahead Planning

W1W1 W5W5 W9W9 W13W13

Long-Term Planning

Multi-Year Planning

Year Ahead Planning

Yr1Yr1 Yr2Yr2 Yr3Yr3 Yr4Yr4 Yr5Yr5 Yr6Yr6

Month Ahead Planning

M1M1 M3M3 M5M5 M7M7 M9M9 M11M11 M13M13 M15M15

Supply Demand

Veselka - 03

GridSchool 2010

Operations Are Balanced Over Time and Space

Time

Lo

ad

Time

Lo

ad

Time

Lo

ad

Veselka - 04

GridSchool 2010

Resource Stack and Least Cost DispatchUnits Are Loaded into the Grid Based on Electricity Production Cost

Nuclear8 $/MWh

Coal Steam

25 $/MWh

NG Steam40 $/MWh

Diesel120 $/MWh

Gas Turbines80 $/MWh

Oil Steam60 $/MWh

MarginalCost

1,200 MW

40$/MWh800 MW

25$/MWh

1,600 MW

80$/MWh

2,000 MW

120$/MWh

2,400 MW

Cost ???Energy

Not Served

Nuclear500 MW

8 $/MWh

Diesel150 MW120 $/MWh

Coal Steam500 MW25 $/MWh

NG Steam250 MW40 $/MWh

Oil Steam250 MW60 $/MWh

Gas Turbine250 MW80 $/MWh

0

250

500

750

1,000

1,250

1,500

1,750

2,500

2,250

2,000

Supply

Cu

mu

lati

ve S

up

ply

an

d L

oa

d (

MW

)

Minimum

Demand

Maximum Load

FutureGrowth

Minimum Load

Veselka - 05

GridSchool 2010

Production Costs ($/MWh) Are a Function of Fuel CostsUnit Conversion Efficiency and Variable O&M Costs

0 10 20 30 40 50 60 70 80 90

Fossil Steam

Hydroelectric

Combined Cycle

Gas Turbine

Diesel Generator

Nuclear Steam

Efficiency (%)

0 2 4 6 8 10 12 14

Fossil Steam

Hydroelectric

Combined Cycle

Gas Turbine

Diesel Generator

Nuclear Steam

Variable O&M ($/MWh)

Very Low Fuel Cost

High Fuel Cost

Range: Low to High Fuel Cost

High Fuel CostVery High Fuel Cost

No Fuel Cost

Veselka - 06

GridSchool 2010

0 5 10 15 20 25 30 35 40

Fossil Steam

Hydroelectric

Combined Cycle

Gas Turbine

Diesel Generator

Nuclear Steam

Fixed O&M Costs ($/kW-yr)

Capital Expenses and Fixed O&M Costs Do not Factor into the Least-Cost Dispatch (Sunk Investments)

0 200 400 600 800 1000 1200 1400 1600 1800

Fossil Steam

Hydroelectric

Combined Cycle

Gas Turbine

Diesel Generator

Nuclear Steam

Construction Cost ($/kW)

Veselka - 07

GridSchool 2010

Nuclear8 $/MWh

Steam Coal

25 $/MWh

NG Steam40 $/MWh

Diesel120 $/MWh

Gas Turbines80 $/MWh

Oil Steam60 $/MWh

0

250

500

750

1,000

1,250

1,500

1,750

> 2,500

2,250

2,000

Supply

Su

pp

ly (

MW

)

Not Supplied500 $/MWh

0

50

100

150

200

250

300

350

500

450

400P

rod

uc

tio

n C

os

t ($

/MW

h)

0 250 500 750 1,000 1,250 1,500 1,750 2,500 2,2502,000

Cumulative Supply (MW)

NGCCNG

Steam

DieselGas TurbineOil

SteamNuclear

The Least-Cost Resource Stack Can Be Used to Create a Supply Curve

40 $/MWh

1,200 MW Demand

Veselka - 08

GridSchool 2010

0 5 10 15 20 25 30

Fossil Steam

Hydroelectric

Combined Cycle

Gas Turbine

Diesel Generator

Nuclear Steam

Scheduled Maintenance (days)

Real Time DispatchH1H1 H5H5 H10H10 H15H15 H20H20 H25H25

Day Ahead Planning

D1D1 D8D8

Week Ahead Planning

W1W1 W5W5 W9W9 W13W13

Long-Term Planning

Multi-Year Planning

Year Ahead Planning

Yr1Yr1 Yr2Yr2 Yr3Yr3 Yr4Yr4 Yr5Yr5 Yr6Yr6

Month Ahead Planning

M1M1 M3M3 M5M5 M7M7 M9M9 M11M11 M13M13 M15M15

Real Time DispatchH1H1 H5H5 H10H10 H15H15 H20H20 H25H25

Day Ahead Planning

D1D1 D8D8

Week Ahead Planning

W1W1 W5W5 W9W9 W13W13

Long-Term Planning

Multi-Year Planning

Year Ahead Planning

Yr1Yr1 Yr2Yr2 Yr3Yr3 Yr4Yr4 Yr5Yr5 Yr6Yr6

Month Ahead Planning

M1M1 M3M3 M5M5 M7M7 M9M9 M11M11 M13M13 M15M15

Generating Units Are Taken Off-Line for Maintenance and Brought Back Into Service at a Later Time

GenerationSupply

Veselka - 09

GridSchool 2010

Maintenance Outages Are Scheduled During Periods of Low Electricity Demand

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

On-Line Capacity (MW)

Total System Capacity without Outages

ReserveCapacity

PlannedOutages

Capacity with Outages

Lo

ad/C

apac

ity

(MW

)

Demand

Maximize the Smallest Reserve Capacity During the Year

Veselka - 010

GridSchool 2010

Nuclear8 $/MWh

NGCC25 $/MWh

NG Steam40 $/MWh

Diesel120 $/MWh

Gas Turbines80 $/MWh

Oil Steam60 $/MWh

0

250

500

750

1,000

1,250

1,500

1,750

2,500

2,250

2,000

Supply MarginalCost

1,200 MW

40$/MWh

800 MW

25$/MWh

1,600 MW

80$/MWh

2,000 MW

120$/MWh

2,400 MW

Cost 500EnergyNot Served

Su

pp

ly S

tac

k w

ith

ou

t M

ain

ten

an

ce

(M

W)

NGCC25 $/MWh

NG Steam40 $/MWh

Diesel120 $/MWh

Gas Turbines80 $/MWh

Oil Steam60 $/MWh

MarginalCost

0

250

500

750

1,000

1,250

1,500

1,750

2,500

2,250

2,000

Supply

Su

pp

ly S

tac

k w

ith

Ma

inte

na

nc

e (

MW

)

1,600 MW

120$/MWh

1,200 MW

80$/MWh

800 MW

60$/MWh

2,000 MW

500$/MWh400MW not supplied

at 2000 MW Load

2,400 MW

500$/MWh800MW not supplied

at 2400 MW Load

Planned Transition

Scheduled Maintenance Alters the Supply Stack

Nuclear Unit Scheduled Out of Service

Veselka - 011

GridSchool 2010

0

50

100

150

200

250

300

350

500

450

400

Pro

du

cti

on

Co

st

($/M

Wh

)

0 250 500 750 1,000 1,250 1,500 1,750 2,500 2,2502,000

Cumulative Supply (MW)

80 $/MWh

40 $/MWh

Curve with Maintenance

Curve without Maintenance

1,200 MW

The Supply Curve Shifts When Units Are Either Taken Off-Line or Brought Back Into Service

1,800 MW

500 $/MWh

Since the Supply Curve Is Typically Steeper at High Loads the Increase in Generation Cost Attributed to a Scheduled Outage is Less Expensive when Loads Are Low

Veselka - 012

GridSchool 2010

0 1 2 3 4 5 6 7 8 9

Fossil Steam

Hydroelectric

Combined Cycle

Gas Turbine

Diesel Generator

Nuclear Steam

Forced Outage Rate (%)

Generating Units Unexpectedly Breakdown (Randomly Forced out of Service)

There are hundreds of causes for outages. The North American Electric Reliability Council (NERC) categorizes these into the following groups: Boiler Balance of plant Steam turbine Generator Pollution control equipment External Regulatory Personnel errors Performance

Generating Unit Forced Outages Add to System Uncertainty

Grid Operations Must Be Prepared to Immediately Fill the Generation Void when a Generator Suddenly Is Taken Off Line

Good Source: Generation Availability Dataset (GADS)

Veselka - 013

GridSchool 2010

It Is Very Unlikely that ALL Generating Units Will Be On-Line at any Point in Time when there Are Many Units in the System

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Planned & Maintenance Outages Forced Outages On-Line Capacity Load

Total System Capacity

Random Forced Outages

Lo

ad/C

apac

ity

(MW

)

Veselka - 014

GridSchool 2010

Mathematical Techniques that Use Probabilistic Methods Help Quantify System Risks and Help Planners and Operators Manage Outage Risks

Operational?Operational?

Operational?Operational?

Operational?Operational?

Dow

nU

nit

Up

DownDown

UnitUnit

UpUp

Unit Up

Down

Unit Up

Unit Up

Unit Up

16

16X6

16X6X6

0102030405060708090100

0 100 200 300 400 500 600 700 800 900 1000

90.00

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 10.00Pro

babi

lity

(per

cent

)

Energy Not Served (MW)

Random Forced Outages & Probability that all Demand Will not Be Served

Example 1Number Plants = 1Plant Size = 1200 MWForced Outage Rate = 0.1Load = 1000 MW Possible Combinations

Plant A Operates

This occurs 90 percent of the time

90 = 0.9 X 100

Plant A Is Out of Service

This occurs 10 percent of the time

10 = (1.0 – 0.9) X 100

Expected Energy not Served (MW) = 100 MWh

Random Forced Outages & Probability that all Demand Will not Be Served

Example 2Load = 1000 MWNumber Plants = 2Plant Size = 600 MW eachForced Outage Rate = 0.1

Possible CombinationsPlant A Plant B

Occurrence Frequency Plant A Plant B

81 Percent0.9 X 0.9 = 0.81

9 Percent(1.0- 0.9) X 0.9 = 0.09

9 Percent0.9 X (1.0- 0.9) = 0.09

1 Percent(1.0- 0.9) X (1.0- 0.9) = 0.01

18 Percent

600 MW Served400 MW Not Served

0102030405060708090100

0 100 200 300 400 500 600 700 800 900 1000

81.00

0.00 0.00 0.0018.00

0.00 0.00 0.00 0.00 0.00 1.00

Pro

ba

bili

ty

(pe

rce

nt)

Expected Energy not Served = 82 MWh

Random Forced Outages & Probability that all Demand Will not Be Served

Engineering Guideline: Largest unit should be no larger than 10 percent of the peak load

0102030405060708090100

0 100 200 300 400 500 600 700 800 900 1000

72.90

0.0024.30

0.00 0.00 0.00 2.70 0.00 0.00 0.00 0.10

Example 3Load = 1000 MWNumber Plants = 3Combinations = 8Plant Size = 400 MW eachForced Outage Rate = 0.1

Pro

babi

lity

(per

cent

)

Expected Energy not Served = 65.8 MWh

0102030405060708090100

0 100 200 300 400 500 600 700 800 900 1000

65.61

29.16

0.00 0.00 4.86 0.00 0.00 0.36 0.00 0.00 0.01

Example 4Load = 1000 MWNumber Plants = 4Combinations = 16Plant Size = 300 MW eachForced Outage Rate = 0.1

Pro

babi

lity

(per

cent

)

Expected Energy not Served = 51.2 MWh

0102030405060708090100

0 100 200 300 400 500 600 700 800 900 1000

88.91

8.52 2.13 0.38 0.05 0.00 0.00 0.00 0.00 0.00 0.00

Example 5Load = 1000 MWNumber Plants = 12Combinations = 4096Plant Size = 100 MW eachForced Outage Rate = 0.1

Pro

babi

lity

(per

cent

)

Expected Energy not Served = 2.1 MWh

2 Units: Expected Energy not Served = 82.0 MWh

1 Unit: Expected Energy not Served = 100.0 MWh

3 Units:

4 Units:

12 Units:

All Examples Have the Same Total Capacity

Veselka - 018

GridSchool 2010

System Reliability Increases as a Function of Higher Capacity, but Higher Reliability Becomes Increasingly more Expensive

Reserve Margin

Rel

iab

ilit

yK

ee

p L

igh

ts o

n

ReliabilityKeep Lights on

Ca

pit

al E

xpe

nse

s a

nd

F

ixe

d O

&M

Co

sts

More On-line Capacity

Veselka - 019

GridSchool 2010

System Reliability Increases as a Function of the Number of Units in the System, but it Becomes Increasingly more Expensive

Number of Units

Rel

iab

ilit

yK

ee

p L

igh

ts o

n

ReliabilityKeep Lights on

Ca

pit

al E

xpe

nse

s a

nd

F

ixe

d O

&M

Co

sts

More Units (Identical Capacity)

Veselka - 020

GridSchool 2010

Operators Reserve (Do not Fully Load) Some of a Unit’s Capacity so the Generating System Can Rapidly Respond to a Forced Outage

Gen

erat

ing

Cap

acit

y (M

W)

ow

ing

Scheduled Output

SpinningReserves

Ou

tpu

t D

isp

atch

ed (

MW

) Reserves AreUsed to Fill

Outage Voids

Nuclear8 $/MWh

NGCC25 $/MWh

NG Steam40 $/MWh

Diesel120 $/MWh

Gas Turbines80 $/MWh

Oil Steam60 $/MWh

0

250

500

750

1,000

1,250

1,500

1,750

2,500

2,250

2,000

No Spinning

With Spinning

Su

pp

ly S

tac

k (

MW

)

Nuclear8 $/MWh

NGCC25 $/MWh

NG Steam40 $/MWh

Diesel120 $/MWh

Gas Turbines80 $/MWhOil Steam60 $/MWh

Reserves

Production Costs Are More Expensive

Load

Veselka - 021

GridSchool 2010

Spinning Reserves

Rel

iab

ilit

yK

ee

p L

igh

ts o

n

ReliabilityKeep Lights on

Pro

du

cti

on

Co

sts

($

/MW

h)

Operate More Expensive Units at Lower Efficiency

Reliability Increases as More Spinning Reserves Are Added, but it Is Increasingly More Expensive

Veselka - 022

GridSchool 2010

Random Outages Affect Electricity Prices Depending on the Type and Amount of Capacity that Is Off-Line

Lowest Load

0.00

30.40

0.00

10.50

40.52

16.51

1.110.00

0.830.07 0.07

0

5

10

15

20

25

30

35

40

45

13.0 13.1 13.2 13.3 13.4 13.5 13.6 13.7 13.8 13.9 > 13.9

Market Price ($/MWh)

Per

cen

t o

f T

ime

Typically, Low Loads Have Relatively Inexpensive Prices & Low Volatility

Average Load

0.00

16.09

0.00

7.90

0.00 0.00 0.00

56.26

17.53

0.27 0.001.68

0.00 0.00 0.05 0.09 0.00 0.06 0.00 0.00 0.01 0.02 0.00 0.02 0.01 0.010

10

20

30

40

50

60

<14.2 14.2 14.3 14.4 14.5 14.6 14.7 14.8 14.9 15.0 15.1 15.2 15.3 15.4 15.5 15.6 15.7 15.8 15.9 16.0 16.1 16.2 16.3 16.4 16.5 >15.8

Market Price ($/MWh)

Per

cen

t o

f T

ime

When Loads Increase Prices Are Higher and the Price Spread Increases

High Loads Are Associated with Expensive Prices and High Volatility

Veselka - 023

GridSchool 2010

Probabilistic Techniques Can Be Used to Estimate Market Prices and Price Volatility as a Function of Load

0

4

8

12

16

20

24

28

32

36

40

0 10 20 30 40 50 60 70 80 90 100

Load and Market Price Exceedance Probability (Percent of Time)

Lo

ad (

GW

)

0

10

20

30

40

50

60

70

80

90

100

Un

con

gested

Market P

rice ($/MW

h)

Min-Max Price Range

Load

Average Price

HighVolatility

LowVolatility

Veselka - 024

GridSchool 2010

Probabilistic Techniques Can also Be Used to Estimate Operating Profits (Payments to Capital)

0

10

20

30

40

50

60

70

80

90

100

110

0 9 18 27 36 45 54 63 72 81 90 99Unit Capacity Factor

Mark

et

Pri

ce (

$/M

Wh

)

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

13,000

14,000

15,000

An

nu

al P

rofit ($

/MW

of C

ap

acity

)

Average Price Over All Hours Dispatched ($/MWh)

Market Price ($/MWh)

Annual Profit ($/MW of Capacity)

New Unit Production

Cost

Projected Capacity Factor

Average Price When Dispatched

Annual Profits (Based On No Outages)

0

10

20

30

40

50

60

70

80

90

100

110

0 9 18 27 36 45 54 63 72 81 90 99Unit Capacity Factor

Mark

et

Pri

ce (

$/M

Wh

)

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

13,000

14,000

15,000

An

nu

al P

rofit ($

/MW

of C

ap

acity

)

Average Price Over All Hours Dispatched ($/MWh)

Market Price ($/MWh)

Annual Profit ($/MW of Capacity)

New Unit Production

Cost

Projected Capacity Factor

Average Price When Dispatched

Annual Profits (Based On No Outages)

Op

era

ting

Pro

fit ($/M

W o

f Cap

ac

ity)

Ma

rke

t P

ric

e (

$/M

Wh

)

Unit Production

Cost

Running Average

Price

Capacity Factor

Operating Profit(without outage)

Veselka - 025

GridSchool 2010

Hydroelectric Power Plants Are an Important Component of Grid Operations in Some Systems

Very flexible operation Change operations quickly Large range of operations Good resource for ancillary services

No fuel required Very low production costs Zero air emissions

High fixed costs Expensive to build Maintain dam, reservoir, & plant

Environmental concerns Effect operations and economics

Limited energy source Cannot always operate at full capacity Uncertainty

Veselka - 026

GridSchool 2010

Reservoirs Are Multi-Purpose Resources Operations Consider Many Factors

Reservoir water storage and management Flood control Irrigation Environmental management Fish and wildlife (endangered species) Municipal and industry water supply Supply for generating units with steam

turbines Recreation Navigation Soil erosion Hydroelectric power generation

In Addition to Power Plant Equipment Limits,Operations Are also Constrained by Reservoir Limits

S t = S t-1 + I t - O t - D t - L t

t is current time,S is reservoir storage or content, I is reservoir inflow,O is reservoir outflow,D is reservoir diversion,L is reservoir loss (e.g., evaporation)

Turbine

Reservoir ElevationHead

Tail

Dam

PowerPlant

WaterIntake

Reservoir Volume

ReleaseFlow

SideFlows

Upstream Releases Elevation

LimitsMax

Min

Reservoir Storage Capacity Range from a Few Hours or Less to Multiple Years of Water Release

Run-of-River Hydro Has no Storage (cannot dispatch)

Minimum Release Rate

Peak Shaved

Remaining Loads

Peaking Capability(100 MW)

Mandatory Water Release Pattern

(1,200 MWh)

DiscretionaryRelease Pattern

(710 MWh)

Lo

ads

(MW

)G

eneratio

n (M

Wh

)

Capability: 150 MWMinimum Release: 50 MWGeneration: 1,910 MWh No Other Restrictions

Traditional Hydropower Plant Dispatch Focused on Displacing High Cost Thermal Generation

Market Driven Operations Yield a Very Different Generation Pattern

30

Hydropower Plants Are Often Cascaded, Adding to the Complexity of Operations

ToMontrose

ToRiffle

CurecantiSubstation

Blue Mesa

CrystalMorrow Point

ToFourCorners

BlackCanyon

The Aspinall Cascade Is a Tightly Coupled System with a High Level of Operational Interdependencies

BlackCanyon

Recent Aspinall Cascade Dispatch Simulation Results

Reality Versus Theory

Hydropower Plant Operations Carry Financial Risks Due to Natural Reservoir Inflow Variability

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

Exceedance Fraction

Mo

nth

ly R

ev

en

ue

(1

00

0's

$)

0

100

200

300

400

500

600

Revenue

Nu

mb

er

of

Occ

ura

nces

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

Exc

eed

an

ce F

req

uen

cy

Zero Occurances

Occurances

MonthAverage of All

TracesCRSS Average

HydrologyOver

EstimateJan 20,039.7 20,050.8 11.1Feb 16,936.9 16,935.1 -1.8Mar 14,476.2 14,477.7 1.6Apr 15,905.8 15,912.3 6.5May 18,042.7 18,021.3 -21.5Jun 20,624.8 20,787.2 162.3Jul 39,740.6 39,938.6 198.1Aug 33,145.3 33,294.6 149.3Sep 15,333.4 15,418.4 85.0Oct 13,794.6 13,781.7 -12.9Nov 16,547.5 16,534.9 -12.6Dec 24,733.0 24,752.7 19.7

Annual 249,320.6 249,905.4 48.7

Monthly Revenue (1000's $)

Veselka - 034

GridSchool 2010

ReservoirsInitial reservoir elevationMaximum reservoir elevationMinimum reservoir elevationElevation change per water releasePower conversion efficiency (upper) Generation capability (upper)

Pump

Energy is ProducedWhen Generating

Energy is ConsumedWhen Pumping

Substation

Upper Reservoir

LowerReservoir

Pumped Storage Plants Both Consume and Produce Power

Pump Maximum pumping rate Pumping efficiency

Veselka - 035

GridSchool 2010

Economics of Pump Storage Are Good when there Are Wide Price Spreads Between Off-Peak (Low Demand) and On-Peak (High Demand) Periods

Buy Electricityat Low Prices

Sell Electricityat High Prices

Price Difference ShouldCover Pumping Losses

Veselka - 036

GridSchool 2010

In the Absence of Transmission Congestion, Lower Cost Generators Are Used First

The Marginal Cost of Serving Load or

Locational Marginal Price (LMP)

Is the Same Throughout the System

Mid cost generator

Highest cost generator

Lowest cost generator

Load

Load

Load

Veselka - 037

GridSchool 2010

Congestion Results in a Re-dispacth of Some Units Resulting in Range of LMPs Across the Grid

A Spread in LMPs Across the Network Is an Indicator of Transmission Congestion

Higher LMP

Congested Line

Mid cost generator

Highest cost generator

Lowest cost generator

Load

Load

Load

Lower LMP

Veselka - 038

GridSchool 2010

Dispatch with Loads of 250 MW without Congestion Radial Network

100 MW30 $/MWh

100 MW75 $/MWh

Demand 100 MWh

100 MW10 $/MWh

Demand 150 MWh

LMP = 75 $/MWh @ all locations

Price setter

50

100

50

50 100 MWh Production

50 MWh Production

100

100 MWh Production

Assumes Bid Price = Marginal Production Cost

Economic/production cost $7,750

Consumer cost GenCo revenue

$18,750

GenCo Profit

$11,000

Note: Above example assumes that production and load levels are constant over a one-hour time period

Veselka - 039

GridSchool 2010

Dispatch with Loads of 250 MW with Congestion Radial Network

100 MW75 $/MWh

Load 100 MW

100 MW10 $/MWh

Load 150 MW

LMP = 30 $/MWh

Price setter

100 MW30 $/MWh

LMP = 75 $/MWh

Price setter

25 MW transfer

limitCongestion Charge

75 $/MWh-30 $/MWh 45 $/MWh

75

25

5075 MWh

Production

75

75 MWh Production

100

100 MWh Production

Assumes Bid Price = Marginal Production Cost

Economic/production cost was $7,750

w/congestion $8,875

Consumer cost was $18,750

w/cong $12,000

GenCo Profit

Was $11,000w/cong $2,000

Consumers save $6,750 with congestion

Amount re-dispatched (MWh) 25 Congestion charge ($/MWh) 45

Congestion payment ($) 1,125

Congestion Charge

Note: Above example assumes that production and load levels are constant over a one-hour time period

Economic Cost $1,125

Transmission CongestionAffect the Choice of Generators to Dispatch

0

40

60

80

100

120

140

160

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000

Cumulative MW

Pro

du

ctio

n C

ost

or

Gen

erat

or

Gen

co B

id P

rice

($/M

Wh

)

Generation Bid

Curve

Price Responsive

Demand Curve(Load)

Generators Dispatched

Generators Off-line

For 1 hour Independent System Operator

Units Dispatched Out-of-Merit

In Many Situations More Expensive Bids Are Dispatched Because of Transmission Congestion

Veselka - 041

GridSchool 2010

Source: T. Overbye, UIUC

Red indicates high LMPs or load pockets where lower cost

power cannot be delivered

Blue indicates low LMPs or generator pockets where lower cost power cannot be sent out

The Eastern Interconnect Contains Thousands of Busses and a Very Complex Transmission System

LMPs are the result of the transmission congestion

Veselka - 042

GridSchool 2010

Power Flows Down Path of Least Resistance(Power Transfer Distributions Factor – Pathway)

.0446

.569

2

.189

4 .0670

.1744

.714

0

.2860

.0007.0069

.28

80 .2819 .1

88

7

.18

13

.0601

.1001

.3881.3705

.241

5

Power Injection(Generation)

Power Sink (Load)

Veselka - 043

GridSchool 2010

The System Operator Can Relieve Transmission Congestion by Opening Circuits (Once Opened, a Lower Cost Dispatch May Be Implemented)

Cap. 600 MWPC $20/MWh

Cap. 250 MWPC $100/MWh

Cap. 200 MWPC $50/MWh

Demand 450 MW

Cap. 600 MWPC $20/MWh

Cap. 250 MWPC $100/MWh

Cap. 200 MWPC $50/MWh

Demand 450 MW

Congested Line

Veselka - 044

GridSchool 2010

Balancing Authority (BA) Maintain Load-Interchange-Generation Balance within an Area and Supports Interconnection Frequency in Real-Time

Tie-line Flows

Tie-line Flows

Tie-

line

Flow

sTie-Line Flows Are Scheduled to Take Advantage of Economic Power Transfers while at the Same Time Inadvertent Power Travels Down the Path of Least Resistance

Veselka - 045

GridSchool 2010

In Addition to Spinning Reserves, Regulation Service Is Needed to Maintain Frequency

Reg

ulatio

n D

ow

n

Time

Load

Reg

ula

tio

n U

p

Time (minutes)

Reg

ula

tio

n S

ervi

ce (

MW

)

0

40

0 60-40

Veselka - 046

GridSchool 2010

Units that Provide Ancillary Service Have a Reduced Range of Scheduled Operation

Spinning reserves (SR)Affects maximum generation

Regulation services (RS)Affects minimum & maximum

generation Minimum Generation

When generation is off-line the unit cannot provide either spinning reserves or regulation services

Min

imu

mL

oad

Fo

llow

ing

Min

imu

mL

oad

Fo

llo

win

g

Increase Minimum

Decrease Maximum R

egu

lation

Service

SpinningReserves

Ca

pab

ility

(M

W)

Up

Down

Veselka - 047

GridSchool 2010

Area Control Error (ACE) Is a Measure ofSystem Error in BA Interchange and Time Error

ACE = (Ta - Ts) – 10Bf (Fa - Fs) +/- Bt Te

Actual Versus Scheduled Net Interchanges (MW)

Over BA Tie-Lines

Actual Versus Target Frequency (Hz)

Area Bias per 0.1 Hz (MW/Hz)

Time Error(seconds)

Time Error Bias (MW/second)

slow

fast

clock

Reg

ulatio

n D

ow

n

Reg

ula

tio

n

Up

Time (minutes)

Re

gu

lati

on

Se

rvic

e (

MW

)

0

40

0 60-40 M

inim

um

Lo

ad

Fo

llo

win

g

Min

imu

mL

oad

Fo

llow

ing

Increase Minimum

Decrease Maximum

Reg

ula

tion

Serv

ice

Spinning Reserves

Cap

abili

ty (

MW

)

Up

Down

Veselka - 048

GridSchool 2010

Summary: Power System Operators Balance Supply & Demand

Dispatch generating units to meet load

Have a least-cost operating objective

Adjust grid topology to help relieve congestion

Maintain operating reserves to keep the lights on when there is an outage

Regulate power quality Keep the clocks on time

Thank you for your attention

Source: BOR