Alstrom IPPs Financial Model

7/28/2019 Alstrom IPPs Financial Model

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Power Plant Economics

Carl BozzutoALSTOM 2006. We reserve all rights in this document and in the information contained therein.

Reproduction, use or disclosure to thirdparties withoutexpress authority is strictlyforbidden


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2

Overview

z Economic Terms

z Economic Methodologies

z Cost Models

z Pitfalls

z Cost Studies

z Results

z Some words about CO2

z Conclusions


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3

Economic Terms

z Return on Sales = Net after tax/Sales revenue

z Asset turnover = Sales revenue/Assets

z Leverage = Assets/Equity

z PE Ratio = Stock Market Price (per share)/Net after tax (per share)

z Market/Book Ratio = Stock Market Price (per share)/Equity (per share)

z Return on Assets = Net/Assets

z

Return on Equity = Net/Equityz Discount Rate = Time value of Money

z Net Present Value = Present Value of Future Returns @ Discount Rate

z Internal Rate of Return = Discount Rate which yields an NPV of zero


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Why do we care?

z ROS x Turnover x Leverage x PE = Market/Book

Listed firms want to increase stock price (shareholder value)

z The Discount Rate considers risk as well interest rates and inflation The discount rate is often a project hurdle rate

z Many firms use IRR for project evaluation

z Return on Equity is a key consideration for any investment


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Economic Methodologies

z A Power Plant is a long lived asset that is capital intensive.

z It also takes a long time to acquire the asset.

Construction times range from 2 years for a combined cycle plant to 3 4years for a coal plant to 10 years for a nuclear plant.

z A key issue is treating the time value of money.

z Depreciation is a key consideration.

z Different entities treat these considerations differently.


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Plant Cost

z Plant Cost is exceptionally site specific.

Labor costs

Shipping and material costs Environmental costs

Site preparation costs

Site impacts on performance Fuel costs

Cooling water type and availability

Connection costs

z Today, we really dont know what the final cost of a plant wil l be.

Raw material escalation

Shipping costs Labor costs


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Plant Cost Terminology

z There are numerous ways to talk about plant cost. Engineered, Procured, and Constructed (EPC cost)

Most commonly used today

Fits best with Merchant Plant model

Does not included Owners Costs Land, A/E costs, Owners Labor, Interconnection, Site Permits, PR, etc.

Can often be obtained as a fixed price contract for proven technology

Equipment Cost Generally the cost to fabricate, deliver, and construct the plant equipment

Overnight Cost

Either the equipment cost or the EPC cost with the NPV of interest during

construction. This was used in the 70s and 80s to compare coal plantswith nuclear plants due to the difference in construction times.

Total Installed Cost (TIC)

The total cost of the equipment and engineering including interest during

construction in present day dollars. This is the cost that a utility wouldrecord on its books without the cost of land and other home office costs.

Total Plant Cost (TPC) includes all costs


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z Simple payback The number of years it takes to pay back the original investment

z Return on Equity

For regulated utilities, the ROE is set by the regulatory body. The equity is determinedby the total plant cost being allowed in the rate base. The equity portion is determined bythe leverage of the company. The ROE is applied to the equity and added to the cost indetermining the cost of electricity and thus the rate to be charged to the customer.

z Capital Charge Rate

This is the rate to be charged on the capital cost of the plant in order to convert capitalcosts (ie investment) into operating costs (or annual costs). This rate can be estimated

in a number of ways. This rate generally includes most of our ignorance about the future(ie interest rates, ROE, inflation, taxes, etc.)

z Discounted Cash Flow Analysis

This method is preferred by economists and developers. A spreadsheet is set up toestimate the cash flows over the life of the project. An IRR can be calculated if anelectricity price is known (or estimated).


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z All of these methods can be made equivalent to one another forany given set of assumptions.

A simple payback time can be selected to give the same cost of electricity

(COE) as the other methods. A return on equity can be selected to give the same COE.

A capital charge rate can be selected to give the same COE.

The Discounted Cash Flow method is considered the most accurate. However,there are still a considerable number of assumptions that go into such a modelsuch as the discount rate, inflation rate, tax rate, interest rates, fuel prices,capacity factors, etc. that the accuracy is typically less in reality.

z The Independent Power Producer pioneered the use of the DCFmodel for smaller power projects.

In this model, the developer attempted to fix as many costs as possible byobtaining fixed price contracts for all of the major cost contributors. These

included the EPC price, the fuel contract, the Operations & MaintenanceContract (O&M), and the Power Purchase Agreement.


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Cost Models

z Capital Charge Rate Model

The goal is to select a capital charge rate that typically covers most of thefuture unknowns. This rate is applied to the EPC cost in order to provide anannual cost that will provide the desired return on equity.

In its simplest form, one can use the following:

Interest rate on debt - 8 - 10% for utility debt

ROE - 10 12 % for most utilities

Inflation rate - 3 4% Depreciation - 2 4%

Taxes and Insurance - 3 5%

Risk - ? (typically 3% for mature technologies, higher for others)

Another approach would be to run a number of DCF cases with differentassumptions and then assess a capital charge rate that is consistent.

A reasonable number for a regulated utility is 20% (one significant figure)


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Discounted Cash Flow Model

z The goal is to estimate the cash flows of the project over the life of theplant. A significant number of variables are involved and must beestimated or assumed in order to make the spread sheet work.

Input variables include net output, capacity factor, availability, net plant heat rate(HHV), degradation, EPC price, construction period, insurance, initialspares/consumables, fixed O&M, variable O&M, fuel price, fuel heating value (HHV),financial closing date, reference date, depreciation, analysis horizon, ownerscontingency, development costs, permitting costs, advisory/legal fees, start up fuel, fuel

storage, inflation rates, interest rates, debt level, taxes, construction cash flow,discount rate, and ROE.

A detailed cash flow analysis is set up for each year of the project. For shorter termprojects, these estimated cash flows are more realistic. For longer term projects, the

accuracy is debatable. Since the cash generation may be variable, it is often desirable to perform some kind of

levelizingfunction to generate an average that is understandable. There are risksassociated with this step.

The most common application is to assume a market price for electricity and then try tomaximize the IRR for the project.


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Discounted Cash Flow Model

z The model assumes that we know a lot about the project and thenumber of variables. What if we dont know very much about the futureproject? For example, what if we dont know where the plant will belocated? What if we dont know which technology we will use for theplant? What if we want to compare technologies on a consistent basis?

z One approach is to run the DCF model backwards . In this approach,we stipulate a required return and calculate an average cost ofelectricity needed to generate that return. We stil l need to make a lot ofassumptions, but at least we can be consistent.

z One advantage of having such spread sheet programs is that a wide

range of scenarios and assumptions can be tested. This approachgives us a little more insight into the decision making process andhelps us understand why some entities might chose one technologyover another.


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Typical Construction Period w/Cash Drawdown

1. Cumulative Drawdown

-600,000

-500,000

-400,000

-300,000

-200,000

-100,000

01 3 5 7 9

1

1

1

3

1

5

1

7

1

9

2

1

2

3

2

5

2

7

2

9

3

1

3

3

3

5

3

7

3

9

4

1

4

3

4

5

4

7


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Typical Levelized Cash Flow

4. Ending Equity Cashflow

(350,000)

(300,000)

(250,000)

(200,000)

(150,000)

(100,000)

(50,000)

0

50,000

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41


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Pitfalls

z The biggest pitfall is thinking that these numbers are real . They areonly indicative. Just because a computer can calculate numbers to thepenny does not mean that the numbers are accurate. There is a lot ofuncertainty due to the number of assumptions that have to be made.

z It is important to understand what the goal and/or objective of theanalysis is. In the following study, the goal was to comparetechnologies that might be used in the future. This goal is different

from looking at a near term project where the site, technology, fuel,customer, and vendors have already been selected.

z There is no substitute for sound management judgement.

z The analysis itself does not identify the risks. The analyzer mustconsider the risks and ask the appropriate what if questions. In thefollowing study, over 3,000 spread sheet runs were made in order to

analyze the comparisons effectively.z Avoid the Swiss Watch mentality.


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Baseline Economic Inputs 1997 400 MW Class

Subcritical Su ercritical P800 PFBC IGCC

Size(MW)

400 400 400 400

Ca ital Cost($/ kW)

1,000 1,050 1,100 1,380

Heat Rat

(Btu/ kWh)

9,374 8,385 8,405 8,700

Availabilit(%)

80 80 80 80

C cle Time(months)

36 36 48 48

Fixed O&M($/ kW)

31.14 32.11 33.69 39.08

Variable O&M(mills/ kWh)

0.7 0.69 1.01 0.42

Source: Market Market ABB GE


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CFB P200 PFBC NGCC

Size(MW) 100 100 270Capital Cost($/ kW)

1,000 1,200 500

Heat Rate

(Btu/ kWh)

10,035 8,815 6,640

Availability(%)

80 80 80

Cycle Time(months)

30 32 24

Fixed O&M($/ kW)

44.13 55. 41 16.92


1.18 1.06 0.01

Source: Market ABB PGT


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Baseline Economic Inputs - 2005 400 MW Class

Subcritical Su ercritical P800 PFBC IGCC

Siz(MW)

400 400 400 400

Ca ital Cost($/ kW)

750 750 750 1,100

Heat Rate

(Btu/ kWh)

8,750 8,125 8,030 7,800

Availabilit(%)

80 80 80 80

C cle Tim(months)

24 24 30 36

Fixed O&M($/ kW)

26.33 26.33 26.95 33.69


0.81 0.75 1.05 0.37

Source: BA Plan BA Plan SECAR GE


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CFB P200 PFBC NGCC

Size(MW) 100 100 270

Capital Cost($/ kW)

725 850 325

Heat Rate

(Btu/ kWh)

9,350 8,530 6195

Availability(%)

80 80 80

Cycle Time(months)

18 22 18

Fixed O&M($/ kW)

38.84 48.67 16.44


1.15 1.12 0.01

Source: BA Plan SECAR PGT


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Financing Scenario Summary

Loan structur Munici al Utilit IPP 1 IPP 2 Industrial

Horizon ( ears) 40 30 15 15 10

Interest rate (%) 5.75 7.75 8.75 8.75 8.25

Loan term ( ears) 40 30 9 9 10

De reciation ears 40 30 15 15 10E uit % 0 50 30 50 75

Debt % 100 50 70 50 25

ROE % n/ 10 20 20 23

Taxes % 0 20 30 30 30


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Comparison of Financing Scenarios400 MW Subcri tical PC Fired Plant

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

Municipal Utility IPP-1 IPP-2 Industrial

Financing Arrangement

Levelized

Tariff,c/kWh

Financial

Fixed O&M

Variable O&M

FuelFinancial

costshave

majorinfluenceonCOE


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Comparison of TechnologiesMunicipal Financing - 1997

(80% CF, $1.20 coal and $3.00 gas)

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

SubcritPC(400 MW)

Super PC(400 MW)

P-800(400 MW)

IGCC(400 MW)

P-200(100 MW)

CFB(100 MW)

NGCC(270 MW)

LevelizedTariff,c/kWh

Financial

Fixed O&M

Variable O&M

Fuel


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Comparison of TechnologiesUtility Financing - 1997

(80% CF, $1.20 coal and $3.00 gas)

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

SubcritPC(400 MW)

Super PC(400 MW)

P-800(400 MW)

IGCC(400 MW)

P-200(100 MW)

CFB(100 MW)

NGCC(270 MW)


Financial

Fixed O&M

Variable O&M

Fuel

Higherfinancialco

st

increasesinfluence

on

COE

NGCClooksbetterontotalCOE,but worseondispatchbasis.


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Comparison of TechnologiesIPP(1) Financing - 1997

(80% CF, $1.20 coal and $3.00 gas)

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

SubcritPC(400 MW)

Super PC(400 MW)

P-800(400 MW)

IGCC(400 MW)

P-200(100 MW)

CFB(100 MW)

NGCC(270 MW)


Financial

Fixed O&M

Variable O&M

Fuel


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Comparison of TechnologiesIPP(2) Financing - 1997

(80% CF, $1.20 coal and $3.00 gas)

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

SubcritPC(400 MW)

Super PC(400 MW)

P-800(400 MW)

IGCC(400 MW)

P-200(100 MW)

CFB(100 MW)

NGCC(270 MW)


Financial

Fixed O&M

Variable O&M

Fuel


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Comparison of TechnologiesIndustrial Financing - 1997

(80% CF, $1.20 coal and $3.00 gas)

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

SubcritPC(400 MW)

Super PC(400 MW)

P-800(400 MW)

IGCC(400 MW)

P-200(100 MW)

CFB(100 MW)

NGCC(270 MW)


Financial

Fixed O&M

Variable O&M

Fuel

Capacity Factor Effect on COE


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Capacity Factor Effect on COE

Municipal Financing - 1997($1.20 coal and $3.00 gas)

2.0

3.0

4.0

5.0

6.0

7.0

8.0

20% 30% 40% 50% 60% 70% 80% 90% 100%

LevelizedT

ariff,

(c/kWh)

Capacity Factor, (%)

SubcritPC

SupercritPC

P-800

IGCC

P-200

CFB

NGCC

Dispatchrateand/orcapacityfactor

havemajorinfluenceonCOE


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Impact of Availability on COEMunicipal Financing - 1997

($1.20 coal)

2.5

2.6

2.7

2.8

2.9

3.0

3.1

3.2

3.3

3.4

3.5

6,500 6,600 6,700 6,800 6,900 7,000 7,100 7,200 7,300 7,400 7,500

Capacity, (hrs/ year)

LevelizedT

ariff,

(c/kWh)

Subcrit PC

Supercrit PC

~5 days

5 days lost availabil ity makes

sub and supercritical equal.


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Sensitivity AnalysisSubcritical PC

1997 IPP1 Financing - $1.20 coal

-20%

-15%

-10%

-5%

0%

5%

10%

15%

20%

-20% -15% -10% -5% 0% 5% 10% 15% 20%

Percent Variable Change

Change

inCOE,

(%)

Availability

EPC pricePlant heat rate

Fixed O&M

Cycle time

Var O&M

In%, changeinav

ailabilityand

EPCpricehavehi

ghestinfluenceon

COE


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Sensitivity AnalysisNGCC

1997 IPP1 Financing - $3.00 gas

-20%

-15%

-10%

-5%

0%

5%

10%

15%

20%

-20% -15% -10% -5% 0% 5% 10% 15% 20%

Percent Variable Change

Change

inCOE,

(%)

Availability

EPC price

Plant heat rate

Fixed O&M

Cycle time

Var O&M

ForNGCC%, chan

geinavailabilitya

nd

efficiencyhavehig

hestinfluenceonC

OE


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Comparison of TechnologiesChina 1997 Municipal Financing Conditions

($1.80 coal and $5.00 LNG)

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

SubcritPC

SupercritPC

P-800 IGCC P-200 CFB NGCC

LevelizedTariff,

(c/kWh)

Financial

Fixed O&M

Variable O&M

Fuel

Firstcostlessimp

ortant

fuelsensitivedue

tohighcost

NGCChigh

duetofuel

cost

C i f T h l i


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Comparison of TechnologiesChina 1997 IPP Financing Condit ions

($1.80 coal and $5.00 LNG)

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

SubcritPC

SupercritPC

P-800 IGCC P-200 CFB NGCC

LevelizedTariff,

(c/kWh)

Financial

Fixed O&M

Variable O&M

Fuel

Comparison of Technologies


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Japan Market Conditions - 1997($2.90 coal and $5.00 LNG)

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

SubcritPC(400 MW)

Super PC(400 MW)

P-800(400 MW)

IGCC(400 MW)

P-200(100 MW)

CFB(100 MW)

NGCC(270 MW)

Levelized

Tariff,c/kWh

Financial

Fixed O&M

Variable O&MFuel

Firstcostlessimp

ortant

fuelsensitive

duetohighcost


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Net Plant Heat Rate Summary

9,3

75

8,3

85

8,4

05

8,7

00

8,8

15

10

,035

6,6

40

8,7

50

8,1

25

8,0

30

7,8

00 8

,530 9

,35

0

6,1

95

7%

3%

4%

10%

3%

7% 7%

0

2,000

4,000

6,000

8,000

10,000

12,000

Subcrit PC

(400 MW)

Super PC

(400 MW)

PFBC-P800

(400 MW)

IGCC

(400 MW)

PFBC-P200

(100 MW)

CFB

(100 MW)

NGCC

(270 MW)

NetPlantH

eatRate(Btu/kW)

0%

2%

4%

6%

8%

10%

12%

NPHRImprove

ment(%)

19972005Improvement


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Summary of EPC Prices

$1

,0

00

$1

,05

0

$1

,100

$1

,38

0

$1

,200

$1

,0

00

$35

0

$75

0

$75

0

$75

0

$1

,100

$85

0

$7

25

$325

25%

29%

32%

20%

29%

28%

7%

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

Subcrit PC

(400 MW)

Super PC

(400 MW)

PFBC-P800

(400 MW)

IGCC

(400 MW)

PFBC-P200

(100 MW)

CFB

(100 MW)

NGCC

(270 MW)

EPCPr

ice($/kW,net)

0%

5%

10%

15%

20%

25%

30%

35%

40%

EPCDecrea

se(%)

19972005

% Decrease


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Coal Technology Cost TrendsExtrapolated to 2005

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

1989 1991 1993 1995 1997 1999 2001 2003 2005

Year

EPCPrice($/kW,net)

Subcritical PCSupercritical PCP800P200

all400MWtechnologies

havethesamemidtermtarget

Market Trends


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Carbon Steel Price Trends

Market Trends

175

150

125

100

IndexBas

e1982

01/02 01/03 01/04 01/05 01/06

Month

Market Trends


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Nickel Trend : 2000 - 2006

1.80

2.202.60

3.00

3.40

3.80

4.20

4.60

5.00

5.40

5.80

6.20

6.60

7.00

7.40

7.80

8.20

8.60

9.00

9.40

9.80

10.20

10.60

11.00

11.40

11.80

12.20

12.60

13.0013.40

13.80

14.20

14.60

15.00

15.40

15.80

16.20

January

February

March

April

May

JuneJuly

August

September

October

November

December

January

February

March

April

May

JuneJuly

August

September

October

November

December

January

February

March

April

May

JuneJuly

August

September

October

November

December

January

February

March

April

May

JuneJuly

August

September

October

November

December

January

February

March

April

May

JuneJuly

August

September

October

November

December

January

February

March

April

May

JuneJuly

August

September

October

November

December

January

February

March

April

May

JuneJuly

August

September

October

November

December

2000 2001 2002 2003 2004 2005 2006

Month / Year

S

potNickel

Low Ni Avg. Spot Ni High Ni

Todays Costs (Estimated)


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40

y ( )

z Todays debate centers around conventional pulverized coal plants(PC) and integrated gasification combined cycle plants (IGCC).

z As we have seen, the current level of development for IGCC makes it

uncompetit ive with PC, which explains why very few have been built.z The claim for the future is that the cost of capture of CO2 to mitigate

greenhouse gas concentrations in the atmosphere wil l be more

expensive for PC than for IGCC. Further, as IGCC develops, its costswil l come down (learning curve).

z As we are in a state of flux with regard to present day costs for plants,the best we can assume (to one significant figure) is that costs haveescalated from their 1997 level to about double. That is, a PC plant isnow about $2000/Kw and an IGCC is about $3000/Kw (EPC). Recallthat the forecast in 1997 was for PC to be $750/Kw and the IGCC to be

$1100/Kw. Unfortunately, that is one of the dangers of forecasting.

Todays Costs (Estimated)


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y ( )

z Fuel costs have also escalated. Recent data for fuel costs delivered tonew plants is about $1.75/MMBTU for coal and $6.50/MMBTU for gas.

z We can input these new costs into the spread sheet model and get an

estimate for the COE for a utili ty trying to make a decision today. Under these conditions, with no CO2 capture, the COE for the PC plant would be 6.55

cents/Kwhr and the IGCC plant would be 9.41 cents/Kwhr.

The natural gas plant would again look competitive at 6.3 cents/Kwhr with an 80%capacity factor. However, at a more typical 40% capacity factor, the COE is 8.30cents/Kwhr.

As a result, we see a lot of utilities considering supercritical pulverized coal plants.

z What about the argument for CO2 capture? This is a subject of intense debate/argument. IGCC costs are expected to increase by

15 - 20% for CO2 capture. The range for PC is considerable. Old technology couldincrease by as much as 50%. Current technology ranges from 20 30%. New

technology is estimated between 10 15%. Whos right?

Efficiency Critical to emissions strategy


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Critical to emissions strategy

Coal w/ 10%

co-firing biomass

100% Coal

Existing US coal

fleet @ avg 33%

CommercialSupercritical/

First of kind IGCC

Net Plant Efficiency (HHV), %

Source: National Coal Counci lFrom EPRI study

Meeting the Goals forCoal Based Power - Efficiency


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0

10

20

30

40

50

POLK/WABASH

IGCC

Target for New

IGCC*

SCPC Today USC Target Next Gen IGCCPlant

Efficiency

%(

HHVB

asis)

Coal Based Power - Efficiency

CO2 Mitigation Options for Coal Based Power


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for Coal Based Power

9Increaseefficiency

Maximize MWs per lb of carbon processed

9Fuel switch with biomass

Partial replacement of fossil fuels =proportional reduction in CO2

9Then, and only then .Capture remaining CO2for EOR/Sequestration

= Logical path to lowest cost of carbon reduction

CO2 Capture Post Combustion


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Technology Status

CO2 Scrubbing options ammonia based

Demonstration in 2006. Advantage of lower costs than Amines.

Applicable for retrofit & new applications

CO2 Frosting Uses Refrigeration Principle to Capture CO2 from Flue Gas.

Process Being Developed by Ecole de Mines de Paris, France, with ALSTOM Support

CO2 Wheel Use Regenerative Air-Heater-Like Device with Solid Absorbent Material to Capture ~ 60% CO2

from Flue Gas.

Being Developed by Toshiba, with Support from ALSTOM

CO2Adsorption with Solids Being Developed by the University of Oslo & SINTEF Materials & Chemistry (Oslo, Norway),in Cooperation with ALSTOM

Advanced Amine Scrubbing Further Improvements in Solvents, Thermal Integration, and Application of MembranesTechnologies Focused on Reducing Cost and Power Usage Multiple suppliers drivinginnovations

Technology Validation & Demonstration

p

Post Combustion CO2 CaptureChilled Ammonia


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Chilled Ammonia

Without CO2Removal

MEA-Fluor Dan.Proc.

NH3

Total power plant cost, M$ 528 652 648

Net power output, MWe 462 329 421

Levelized cost of power, c/KWh 5.15 8.56 6.21

CO2 Emission, lb/kwh 1.71 0.24 0.19

Avoided Cost, $/ton CO2 Base 51.1 19.7

Going Down The Experience Curve forPost Combustion CO2 Capture


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0

500

1000

1500

2000

2500

3000

1990 1995 2000 2005 2010 2015 2020

HeatofReaction(BTU/lb)

Post Combustion CO2 Capture

1995 2000 2005 2010 2015

2001 ParsonsStudy (Fluor)

ABBLumnus

ProcessOptimization

AdvancedAmines

ProcessInnovations

ALSTOMsChilled

AmmoniaProcess

Significant Improvements Are Being Achieved

Values FromCurrent

Projects

1,350 BTU/lb

Multiple Paths to CO2 ReductionInnovations for the Future


48/50

48

0

2

4

6

8

10

SCPC

IGCC

SCPC

w/ME

A

Oxyfiring

wCO2

SCPC

adv

amine

s

IGCC

Fturbin

e

SCPC

NH

3

USCPCadvCO

2

IGCCH

turbinewadvCO

2

Levelized

COEcents/Kw

hr

Innovations for the Future

No CO2 Capture ------------------------------With CO2 Capture---------------------------

Note: Costs include compression , but do not include sequestration equal for all technologies

Technology Choices Reduce Risk and Lower Costs

Hatched Range reflects cost variation from fuels and uncertainty

Economic ComparisonCost of Electricity (common basis)


49/50

49

Cost of Electricity (common basis)

4.00

4.50

5.00

5.50

6.00

6.50

7.00

7.50

8.00

8.50

9.00

0 10 20 30 40 50

CO2 Allowance Price ($/Ton CO2 Emitted)

(Cents

/kWhr)

Ref Air fired CFB w/ocapture

Ref IGCC 7FA w/ capture spare

O2 fired PC w/capture

O2 fired CFB w/ capture

Ammonia scrubbing

Chemical Looping

Conclusions


50/50

50

New coal fired power plants shall be designed for highestefficiency to minimize CO2 and other emissions

Lower cost, higher performance technologies for postcombustion CO2 captureare actively being developed, andmore are emerging

There is no single technology answer to suit all fuels and allapplications

The industry is best served by a portfolio approachto drivedevelopment of competitive coal power with carbon capture

technology

Documents

Alstrom IPPs Financial Model