efficiency and home energy use clean, green coal

9/13/2011

1

Efficiency and Home Energy Use• Whole-house energy efficiency approach –

find out which parts consume the most energy

Energy Systems Research Laboratory, FIU

http://www1.eere.energy.gov/consumer/tips/home_energy.html

Clean, Green Coal• “Clean coal” is a vague term that refers to a number of

processes by which coal can be used to make electricity with less “pollution.”

• These technologies include

– Electrostatic precipitators, which remove particles from the flue gases. Precipitators are uniformly used.


g p y

– Scrubbers are used to remove sulfur dioxide, which was implicated in creating acid rain.

– Low NOx burners are used to remove nitrogen oxides (Nox).

– CO2 removal is more difficult, with sequestration an option

Growth in Coal Generation: US and China

Energy Systems Research Laboratory, FIUSource http://www.netl.doe.gov/coal/refshelf/ncp.pdf

Background on the Electric Utility Industry

• First real practical uses of electricity began with the telegraph (around the civil war) and then arc lighting in the 1870’s (Broadway, the “Great White Way”).

• Central stations for lighting began with Edison in 1882, using a dc system (safety was key) but transitioned to ac


using a dc system (safety was key), but transitioned to ac within several years. Chicago World’s fair in 1893 was key demonstration of electricity

• High voltage ac started being used in the 1890’s with the Niagara power plant transferring electricity to Buffalo; also 30kV line in Germany

• Frequency standardized in the 1930’s

Regulation and Large Utilities

• Electric usage spread rapidly, particularly in urban areas. Samuel Insull (originally Edison’s secretary, but later from Chicago) played a major role in the development of large electric utilities and their holding companies

– Insull was also instrumental in start of state regulation in 1890’s


• Public Utilities Holding Company Act (PUHCA) of 1935 essentially broke up inter-state holding companies

– This gave rise to electric utilities that only operated in one state

– PUHCA was repealed in 2005

• For most of the last century electric utilities operated as vertical monopolies

Vertical Monopolies

• Within a particular geographic market, the electric utility had an exclusive franchise

Generation In return for this exclusivefranchise, the utility had the


Transmission

Distribution

Customer Service

yobligation to serve all existing and future customersat rates determined jointlyby utility and regulators

It was a “cost plus” business

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Vertical Monopolies

• Within its service territory each utility was the only game in town

• Neighboring utilities functioned more as colleagues than competitors


• Utilities gradually interconnected their systems so by 1970 transmission lines crisscrossed North America, with voltages up to 765 kV

• Economies of scale keep resulted in decreasing rates, so most every one was happy

History, cont’d -- 1970’s

• 1970’s brought inflation, increased fossil-fuel prices, calls for conservation and growing environmental concerns

• Increasing rates replaced decreasing ones

• As a result U S Congress passed Public Utilities


• As a result, U.S. Congress passed Public Utilities Regulator Policies Act (PURPA) in 1978, which mandated utilities must purchase power from independent generators located in their service territory (modified 2005)

• PURPA introduced some competition, but its implementation varied greatly by state

PURPA and Renewable Energy

• PURPA, through favorable contracts, caused the growth of a large amount of renewable energy in the 1980’s (about 12,000 MW of wind, geothermal, small scale hydro, biomass, and solar thermal)

Th k “ lif i f iliti ” (QF )


– These were known as “qualifying facilities” (QFs)

– California added about 6000 MW of QF capacity during the 1980’s, including 1600 MW of wind, 2700 MW of geothermal, and 1200 MW of biomass

– By the 1990’s the ten-year QFs contracts written at rates of $60/MWh in 1980’s, and they were no longer profitable at the $30/MWh 1990 values so many sites were retired or abandoned

Electricity Prices, 1990-2007

Source: EIA, annual energy review, 2007


Total USA solar/pv energy production was essentially flat from 1990 to 2005 (0.06 quad vs. 0.065)

Total wind generation stayed flat during 1990’s (around 0.03) but is now growing (0.32 in 2007; solar/pv is 0.08 in 2007)

History, cont’d – 1990’s & 2000’s• Major opening of industry to competition occurred

as a result of National Energy Policy Act of 1992

• This act mandated that utilities provide “nondiscriminatory” access to the high voltage transmission


• Goal was to set up true competition in generation

• Result over the last few years has been a dramatic restructuring of electric utility industry (for better or worse!)

• Energy Bill 2005 repealed PUHCA; modified PURPA

State Variation in Electric Rates


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Historical Electricity Use


Source: EIA, annual energy review, 2008

• Total USA solar/pv energy production was essentially flat from 1990 to 2005 (0.06 quad vs. 0.065)

• Total wind generation stayed flat during 1990’s (around 0.03) but is now growing (0.32 in 2007; solar/pv is 0.08 in 2007)

• In 2008, largest sources of renewable energy in descending order: hydroelectric, wood, biofuels, wind, waste, geothermal, solar/PV

http://www.eia.doe.gov/aer/pdf/aer.pdf

Historical Electricity Generation


• In 2008, fossil fuels (coal, petroleum, and natural gas) accounted for 71% of all net generation

• Nuclear contributed 20%• Renewable energy resources contributed 9% • In 2008, 67% of the renewable energy came from conventional

hydroelectric powerSource: EIA, annual energy review, 2008

The California-Enron Effect

RI

WA

OR

NV

CA

ID

MT

WY

UT CO KS

NE

SD

NDMN

IA

WI

MO

IL IN OH

KY

WVA VA

PA

NY

VT ME

MI

NHMA

CTNJ

DEMD

DC


Source : http://www.eia.doe.gov/cneaf/electricity/chg_str/regmap.html

AK

electricityrestructuring

delayedrestructurin

g

no activity suspendedrestructuring

CA

AZNM

TX

OK

MO KYTN

MS

LA

AL GA

FL

SCNC

AR

HI

August 14th, 2003 Blackout


https://reports.energy.gov/

Read the blackout report:

Renewable Portfolio Standards (September 2009)

WA: 15% by 2020*

CA: 20% by 2010

☼ NV: 25% by 2025*

UT: 20% by 2025*

☼ CO: 20% by 2020 (IOUs)10% by 2020 (co-ops & large munis)*

MT: 15% by 2015

ND: 10% by 2015

SD: 10% by 2015

IA: 105 MW

MN: 25% by 2025(Xcel: 30% by 2020)

☼ MO: 15% b 2021

WI: Varies by utility; 10% by 2015 goal

MI: 10% + 1,100 MW by 2015*

☼ OH: 25% by 2025†

ME: 30% by 2000New RE: 10% by 2017

☼ NH: 23.8% by 2025

☼ MA: 15% by 2020+ 1% annual increase(Class I Renewables)

RI: 16% by 2020

CT: 23% by 2020

☼ NY: 24% by 2013

☼ NJ: 22.5% by 2021

☼ PA: 18% by 2020†

☼ MD: 20% by 2022

VA: 15% by 2025*

VT: (1) RE meets any increase in retail sales by 2012;

(2) 20% RE & CHP by 2017

KS: 20% by 2020

☼ OR: 25% by 2025 (large utilities)*5% - 10% by 2025 (smaller utilities)

☼ IL: 25% by 2025


Source: http://www.dsireusa.org/

State renewable portfolio standard

State renewable portfolio goal

Solar water heating eligible *† Extra credit for solar or customer-sited renewables

Includes separate tier of non-renewable alternative resources

☼ AZ: 15% by 2025

☼ NM: 20% by 2020 (IOUs)10% by 2020 (co-ops)

HI: 40% by 2030

☼ Minimum solar or customer-sited requirement

TX: 5,880 MW by 2015

☼ MO: 15% by 2021☼ y

☼ DE: 20% by 2019*

☼ DC: 20% by 2020☼ NC: 12.5% by 2021 (IOUs)

10% by 2018 (co-ops & munis)

29 states & DChave an RPS

5 states have goals

Impact of 2009 Stimulus Bill on Renewable Energy

• American Recovery and Reinvestment Act (ARRA)

• The 2009 stimulus bill contained several provisions related to renewable energy– $32 billion to enhance the electric power grid


– A three year extension to renewable production tax credits

– About $40 billion for energy efficiency in various forms

– $2 billion for advanced battery manufacturing

• Also a lot of synchrophasor-related ARRA projects– http://www.naspi.org/meetings/workgroup/workgroup.stm

– Synchrophasors and renewable energy integration are related

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Power System Structure

• All power systems have three major components: Load, Generation, and Transmission/Distribution.

• Load: Consumes electric power

• Generation: Creates electric power.


• Transmission/Distribution: Transmits electric power from generation to load.

• A key constraint is since electricity can’t be effectively stored, at any moment in time the net generation must equal the net load plus losses

2007 USA Electric Energy FlowNote, Electricity is “Refined” Energy


Source: EIA 2007 Annual Energy Review

2008 USA Electric Energy Flow


Source: EIA 2008 Annual Energy ReviewNote- this graphic does NOT show losses

LOADS

• Can range in size from less than one watt to 10’s of MW

• Loads are usually aggregated for system analysis

• The aggregate load changes with time, with strong


gg g g gdaily, weekly and seasonal cycles

– Load variation is very location dependent

Loads- Household Consumption

Source: EIA 2008 Annual Energy Review


Example: Daily Variation for CA


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Example: Weekly Variation


Change in US Electric Demand Growth


Source: EIA Annual Energy Outlook 2010

Example: Annual System Load

15000

20000

25000

W L

oad


0

5000

10000

1

518

1035

1552

2069

2586

3103

3620

4137

4654

5171

5688

6205

6722

7239

7756

8273

Hour of Year

MW

Load Duration Curve

• A very common way of representing the annual load is to sort the one hour values, from highest to lowest. This representation is known as a “load duration curve.”

6000

5000


4000

3000

2000

1000

0

DEM

AN

D (M

W)

0 1000 HRS 7000 8760

Load duration curve tells how much generation is needed

GENERATION

• Large plants predominate, with sizes up to about 1500 MW.

• Coal is most common source (56%), followed by nuclear (21%), hydro (10%) and gas


(10%).

• New construction is mostly natural gas, with economics highly dependent upon the gas price

• Generated at about 20 kV for large plants

New Generation by Fuel Type(USA 1990 to 2030, GW)


Source: EIA Annual Energy Outlook 2007

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Basic Gas Turbine Efficiency

Compressor

Fuel100%

Combustion chamber

Turbine Generator

ACPower 33%

1150 oC


Fresh air

Exhaustgases 67%

550 oC

Brayton Cycle: Working fluid is always a gas

Most common fuel is natural gas

Maximum Efficiency

550 2731 42%

1150 273

Typical efficiency is around 30 to 35%

Gas Turbine


Source: Masters

Combined Heat and Power

Compressor

Fuel100%

Combustion chamber

Turbine

Exhaust gases

Generator

ACPower 33%


Fresh air

Heat recovery steamgenerator (HRSG)

Water pump

Feedwater

Exhaust 14%

Steam 53%

Process heat

Absorption cooling

Space & water heating

Overall Thermal Efficiency = 33% (Electricity) + 53% (Heat) = 86%

Combined Cycle Power Plants


Efficiencies of up to 60% can be achieved, with even higher values when the steam is used for heating

Determining operating costs• In determining whether to build a plant, both the fixed

costs and the operating (variable) costs need to be considered.

• Once a plant is build, then the decision of whether or not to operate the plant depends only upon the variable costs


• Variable costs are often broken down into the fuel costs and the O&M costs (operations and maintenance)

• Fuel costs are usually specified as a fuel cost, in $/Mbtu, times the heat rate, in MBtu/MWh– Heat rate = 3.412 MBtu/MWh/efficiency

– Example, a 33% efficient plant has a heat rate of 10.24

Heat Rate

• Fuel costs are usually specified as a fuel cost, in $/Mbtu, times the heat rate, in MBtu/MWh

– Heat rate = 3.412 MBtu/MWh/efficiency

– Example, a 33% efficient plant has a heat rate of 10 24 Mbtu/MWh


10.24 Mbtu/MWh

– About 1055 Joules = 1 Btu

– 3600 kJ in a kWh

• The heat rate is an average value that can change as the output of a power plant varies.

• Do Example 3.5, material balance

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Historical and Forecasted Heat Rates


http://www.npc.org/Study_Topic_Papers/4-DTG-ElectricEfficiency.pdf

Fixed Charge Rate (FCR)

• The capital costs for a power plant can be annualized by multiplying the total amount by a value known as the fixed charge rate (FCR)

• The FCR accounts for fixed costs such as interest on loans, returns to investors, fixed operation and


, , pmaintenance costs, and taxes.

• The FCR varies with interest rates, and is now below 10%.

• For comparison this value is often expressed as$/yr-kW

Annualized Operating Costs

• The operating costs can also be annualized by including the number of hours a plant is actually operated

• Assuming full output the value is


Variable ($/yr-kW) =

[Fuel($/Btu) * Heat rate (Btu/kWh) +

O&M($/Kwh)]*(operating hours/hours in year)

Coal Plant Example

• Assume capital costs of $4 billion for a 1600 MW coal plant with a FCR of 10% and operation time of 8000 hours per year. Assume a heat rate of 10 Mbtu/MWh, fuel costs of 1.5 $/Mbtu, and variable O&M of $4.3/MWh. What is annualized cost per kWh?


Fixed Cost($/kW) = $4 billion/1.6 million kW=2500 $/kWAnnualized capital cost = $250/kW-yr

Annualized operating cost = (1.5*10+4.3)*8000/1000

= $154.4/kW-yr

Cost = $(250 + 154.4)/kW-yr/(8000h/yr) = $0.051/kWh

Capacity Factor (CF)

• The term capacity factor (CF) is used to provide a measure of how much energy a plant actually produces compared to the amount assuming it ran at rated capacity for the entire year


CF = Actual yearly energy output/(Rated Power * 8760)

• The CF varies widely between generation technologies,

Generator Capacity Factors

Energy Systems Research Laboratory, FIUSource: EIA Electric Power Annual, 2007

The capacity factor for solar is usually less than 25% (sometimes substantially less), while for wind it is usually between 20 to 40%). A lower capacity factor means a higher cost per kWh

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One-line Diagrams

• Most power systems are balanced three phase systems.

• A balanced three phase system can be modeled as a single (or one) line.


• One-lines show the major power system components, such as generators, loads, transmission lines.

• Components join together at a bus.

PowerWorld Simulator Three Bus System

Bus 2 Bus 1

204 MW

102 MVR

150 MW116 MVR

1.00 PU

-20 MW 4 MVR

20 MW -4 MVR

-34 MW10 MVR

-14 MW

4 MVR

1.00 PU

106 MW 0 MVR

100 MWAGC ONAVR ON

Load withgreenarrows indicatingamountof MWflow

Note the


Bus 3Home Area

150 MW 37 MVR

116 MVR

102 MW 51 MVR

34 MW-10 MVR

14 MW -4 MVR

1.00 PU

AVR ON

AGC ONAVR ON

flow

Usedto controloutput ofgenerator Direction of arrow is used to indicate

direction of real power (MW) flow

power balance ateach bus

Power Balance Constraints

• Power flow refers to how the power is moving through the system.

• At all times in the simulation the total power flowing into any bus MUST be zero!


flowing into any bus MUST be zero!

• This is know as Kirchhoff’s law. And it can not be repealed or modified.

• Power is lost in the transmission system.

Basic Power Flow Control

• Opening a circuit breaker causes the power flow to instantaneously (nearly) change.

• No other way to directly control power flow in a transmission line


in a transmission line.

• By changing generation we can indirectly change this flow.

Transmission Line Limits

• Power flow in transmission line is limited by heating considerations.

• Losses (I2 R) can heat up the line, causing it to sag


to sag.

• Each line has a limit; Simulator does not allow you to continually exceed this limit. Many utilities use winter/summer limits.

Overloaded Transmission Line


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Interconnected Operation

• Power systems are interconnected. Most of North America east of the Rockies is one system, with most of Texas and Quebec being exceptions

I i di id d i ll


• Interconnections are divided into smaller portions, called balancing authority areas (previously called control areas)

Balancing Authority (BA) Areas

• Transmission lines that join two areas are known as tie-lines.

• The net power out of an area is the sum of the flow on its tie-lines.


• The flow out of an area is equal to

total gen - total load - total losses

= tie-flow

Area Control Error (ACE)• The area control error is the difference

between the actual flow out of an area, and the scheduled flow.

• Ideally the ACE should always be zero.

B h l d i l h i h


• Because the load is constantly changing, each utility must constantly change its generation to “chase” the ACE.

Automatic Generation Control• BAs use automatic generation control (AGC)

to automatically change their generation to keep their ACE close to zero.

• Usually the BA control center calculates ACE b d ti li fl th th AGC


based upon tie-line flows; then the AGC module sends control signals out to the generators every couple seconds.

Three Bus Case on AGC

Bus 2 Bus 1

266 MW

133 MVR1.00 PU

-40 MW 8 MVR

40 MW -8 MVR

1.00 PU

101 MW5 MVR


Bus 3Home Area

150 MW

250 MW 34 MVR

166 MVR

133 MW 67 MVR

-77 MW 25 MVR

78 MW-21 MVR

39 MW-11 MVR

-39 MW

12 MVR

1.00 PU

5 MVR

100 MWAGC ONAVR ON

AGC ONAVR ON

Generator Costs• There are many fixed and variable costs

associated with power system operation.

• The major variable cost is associated with generation.

C t t t MWh id l


• Cost to generate a MWh can vary widely.

• For some types of units (such as hydro and nuclear) it is difficult to quantify.

• Many markets have moved from cost-based to price-based generator costs

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Economic Dispatch

• Economic dispatch (ED) determines the least cost dispatch of generation for an area.

• For a lossless system, the ED occurs when all the generators have equal marginal costs.


IC1(PG,1) = IC2(PG,2) = … = ICm(PG,m)

Power Transactions

• Power transactions are contracts between areas to do power transactions.

• Contracts can be for any amount of time at any price for any amount of power.


• Scheduled power transactions are implemented by modifying the area ACE:

ACE = Pactual,tie-flow - Psched

100 MW Transaction

Bus 2 Bus 1

225 MW

113 MVR

150 MW

1.00 PU

8 MW -2 MVR

-8 MW 2 MVR

-84 MW -92 MW

1.00 PU

0 MW 32 MVR

AGC ON


Bus 3Home Area

Scheduled Transactions

150 MW

291 MW 8 MVR

138 MVR

113 MW 56 MVR

27 MVR

85 MW-23 MVR

93 MW-25 MVR

30 MVR

1.00 PU

100 MWAGC ONAVR ON

AGC ONAVR ON

100.0 MW

Scheduled 100 MW Transaction from Left to Right

Net tie-line flow is now 100 MW

Security Constrained Economic Dispatch

• Transmission constraints often limit system economics.

• Such limits required a constrained dispatch in order to maintain system security


order to maintain system security.

• In three bus case the generation at bus 3 must be constrained to avoid overloading the line from bus 2 to bus 3.

Security Constrained Dispatch

Bus 2 Bus 1

357 MW

179 MVR

194 MW

1.00 PU

-22 MW 4 MVR

22 MW -4 MVR

-142 MW -122 MW

1.00 PU

0 MW 37 MVR100%

OFF AGC


Bus 3Home Area

Scheduled Transactions

448 MW 19 MVR

232 MVR

179 MW 89 MVR

49 MVR

145 MW-37 MVR

124 MW-33 MVR

41 MVR

1.00 PU

100%

100 MWAVR ON

AGC ONAVR ON

100.0 MW

Dispatch is no longer optimal due to need to keep Line from bus 2 to bus 3 from overloading

Multiple Area Operation

• If Areas have direct interconnections, then they may directly transact up to the capacity of their tie-lines.

• Actual power flows through the entire


• Actual power flows through the entire network according to the impedance of the transmission lines.

• Flow through other areas is known as “parallel path” or “loop flows.”

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Seven Bus Case One-line Diagram

Top Area Cost

1

2

3 4

5

106 MW 110 MW 40 MVR

80 MW 30 MVR

1.00 PU

1.01 PU1.04 PU

0.99 PU1.05 PU

62 MW

-61 MW

44 MW -42 MW -31 MW 31 MW

38 MW

-37 MW

79 MW -77 MW

-32 MW

32 MW-14 MW

94 MW

AGC ON

AGC ONCase Hourly Cost 16933 $/MWH

System hasthree areas

Area top has fivebuses


p

Left Area Cost Right Area Cost

2 5

6 7

168 MW

200 MW 201 MW

130 MW 40 MVR

40 MW 20 MVR

1.04 PU1.04 PU

-39 MW

40 MW-20 MW 20 MW

40 MW

-40 MW

200 MW 0 MVR

200 MW 0 MVR

20 MW -20 MW

AGC ON

AGC ON

AGC ON

8029 $/MWH

4715 $/MWH 4189 $/MWH

Area left has one bus

Area right has one bus

Seven Bus Case: Area ViewArea Losses

Top

-40.1 MW

0.0 MW 0.0 MW 40.1 MW

7.09 MW

Actualflowbetweenareas

System has40 MW f


Area Losses Area Losses

Left Right

0.0 MW 40.1 MW

0.33 MW 0.65 MW

Loop flow can result in higher losses

40 MW of“Loop Flow”

Scheduledflow

Seven Bus System – Loop Flow?Area Losses

Top

-4.8 MW

0.0 MW 0.0 MW 4.8 MW

9.44 MW

Note thatTop’s Losses haveincreasedf

Transaction has actually decreasedthe loop flow


Area Losses Area Losses

Left Right

100.0 MW 104.8 MW

-0.00 MW 4.34 MW

100 MW Transactionbetween Left and Right

from 7.09MW to9.44 MW

Power Transfer Distribution Factors (PTDFs)

• PTDFs are used to show how a particular transaction will affect the system.

• Power transfers through the system according


to the impedances of the lines, without respect to ownership.

• All transmission players in network could be impacted, to a greater or lesser extent.

17%

58% 41%

51% 42%

34%

A B

C

D

400.0 MWMW 400.0 MWMW 300.0 MWMW

250.0 MWMW

PTDF Example: Nine Bus System Actual Flows


45% 6%

54%

29%

32%

G E

I

F

H

250.0 MWMW

200.0 MWMW

250.0 MWMW

150.0 MWMW

50.0 MW

39%

44%

56% 13%

30% 20%

10%

A B

C

D

400.0 MWMW 400.0 MWMW 300.0 MWMW

250.0 MWMW

PTDF Example: PTDFs for Transfer from A to I


35% 2%

34%

34%

32%

G E

I

F

H

250.0 MWMW

200.0 MWMW

250.0 MWMW

150.0 MWMW

50.0 MW

34%

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PTDF Example: PTDFs for Transfer from G to F

6%

6% 12%

18%

61%

12%

6%

A B

C

D

400.0 MWMW 400.0 MWMW 300.0 MWMW

250.0 MWMW


61% 19%

21%

21%

G E

I

F

H

250.0 MWMW

200.0 MWMW

250.0 MWMW

150.0 MWMW

50.0 MW

20%

Role of RTO/ISO and NERC Reliability Coordinators


Photo source: http://www.ferc.gov/industries/electric/indus-act/rto/rto-map.asp

Pricing Electricity

• Cost to supply electricity to bus is called the location marginal price (LMP)

• Presently PJM and MISO post LMPs on the web

• In an ideal electricity market with no transmission limitations the LMPs are equal


limitations the LMPs are equal

• Transmission constraints can segment a market, resulting in differing LMP

• Determination of LMPs requires the solution on an Optimal Power Flow (OPF)

Three Bus Case LMPs: Line Limit NOT Enforced

Bus 2 Bus 1

0 MW 10.00 $/MWh

60 MW 60 MW

120 MW

10.00 $/MWh

180 MW120%

Gen 1’s costis $10 per MWh

Gen 2’s costis $12 per MWh


Bus 3

Total Cost

0 MW

180 MWMW

60 MW

60 MW120 MW

10.00 $/MWh

120%

0 MWMW

1800 $/hr

Line from Bus 1 to Bus 3 is over-loaded; all buses have same marginal cost

Three Bus Case LMPS: Line Limits Enforced

Bus 2 Bus 1

60 MW 12.00 $/MWh

20 MW 20 MW

100 MW

10.00 $/MWh

120 MW100%


Bus 3

Total Cost

0 MW

180 MWMW

80 MW

80 MW100 MW

14.01 $/MWh

80% 100%

80% 100%

0 MWMW

1921 $/hr

Line from 1 to 3 is no longer overloaded, but nowthe marginal cost of electricity at 3 is $14 / MWh

Generation Supply Curve

40

60

80

/ M

Wh)

Base LoadCoal and Nuclear

NaturalGas Generation

As the load goes up so does the price


0

20

40

0 10000 20000 30000 40000

Generation (MW)

Pri

ce ($ Coal and Nuclear

Generation

Renewable Sources Such as Wind Have Low Marginal Cost, but they are Intermittent

9/13/2011

13

MISO LMPs on Sept 21, 2010 (7:50am)


Available on-line at www.midwestmarket.org

MISO LMPs on Sept 21, 2010 (7:50am)


Frequency Control

• Steady-state operation only occurs when the total generation exactly matches the total load plus the total losses– too much generation causes the system frequency


too much generation causes the system frequency to increase

– too little generation causes the system frequency to decrease (e.g., loss of a generator)

• AGC is used to control system frequency

April 23, 2002 Frequency Response Following Loss of 2600 MW


efficiency and home energy use clean, green coal

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