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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 third parties without express authority is strictly forbidden

2

Overview

Economic TermsEconomic MethodologiesCost ModelsPitfallsCost StudiesResultsSome words about CO2Conclusions

3

Economic Terms

Return on Sales = Net after tax/Sales revenueAsset turnover = Sales revenue/AssetsLeverage = Assets/EquityPE Ratio = Stock Market Price (per share)/Net after tax (per share)Market/Book Ratio = Stock Market Price (per share)/Equity (per share)Return on Assets = Net/AssetsReturn on Equity = Net/EquityDiscount Rate = Time value of MoneyNet Present Value = Present Value of Future Returns @ Discount RateInternal Rate of Return = Discount Rate which yields an NPV of zero

4

Why do we care?

ROS x Turnover x Leverage x PE = Market/Book– Listed firms want to increase stock price (shareholder value)

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

Many firms use IRR for project evaluationReturn on Equity is a key consideration for any investment

5

Economic Methodologies

A Power Plant is a long lived asset that is capital intensive.It also takes a long time to acquire the asset.– Construction times range from 2 years for a combined cycle plant to 3 – 4

years for a coal plant to 10 years for a nuclear plant.

A key issue is treating the time value of money.Depreciation is a key consideration.Different entities treat these considerations differently.

6

Plant Cost

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

Today, we really don’t know what the final cost of a plant will be.– Raw material escalation– Shipping costs– Labor costs

7

Plant Cost Terminology

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 Owner’s Costs

Ø Land, A/E costs, Owner’s 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 plants with 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 would record on its books without the cost of land and other home office costs.

– Total Plant Cost (TPC) – includes all costs

8


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

Return on Equity– For regulated utilities, the ROE is set by the regulatory body. The equity is determined

by the total plant cost being allowed in the rate base. The equity portion is determined by the leverage of the company. The ROE is applied to the equity and added to the cost in determining the cost of electricity and thus the rate to be charged to the customer.

Capital Charge Rate– This is the rate to be charged on the capital cost of the plant in order to convert capital

costs (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.)

Discounted Cash Flow Analysis– This method is preferred by economists and developers. A spread sheet is set up to

estimate the cash flows over the life of the project. An IRR can be calculated if an electricity price is known (or estimated).

9


All of these methods can be made equivalent to one another for any 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 model such as the discount rate, inflation rate, tax rate, interest rates, fuel prices, capacity factors, etc. that the accuracy is typically less in reality.

The Independent Power Producer pioneered the use of the DCF model for smaller power projects.– In this model, the developer attempted to fix as many costs as possible by

obtaining fixed price contracts for all of the major cost contributors. These included the EPC price, the fuel contract, the Operations & Maintenance Contract (O&M), and the Power Purchase Agreement.

10

Cost Models

Capital Charge Rate Model– The goal is to select a capital charge rate that typically covers most of the

future unknowns. This rate is applied to the EPC cost in order to provide an annual 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 different assumptions and then assess a capital charge rate that is consistent.

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

11

Discounted Cash Flow Model

The goal is to estimate the cash flows of the project over the life of the plant. A significant number of variables are involved and must be estimated 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, initial spares/consumables, fixed O&M, variable O&M, fuel price, fuel heating value (HHV), financial closing date, reference date, depreciation, analysis horizon, owner’s contingency, 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 term projects, 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 levelizing function to generate an average that is understandable. There are risks associated with this step.

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

12

Discounted Cash Flow Model

The model assumes that we know a lot about the project and the number of variables. What if we don’t know very much about the future project? For example, what if we don’t know where the plant will be located? What if we don’t know which technology we will use for the plant? What if we want to compare technologies on a consistent basis?One approach is to run the DCF model “backwards”. In this approach, we stipulate a required return and calculate an average cost of electricity needed to generate that return. We still need to make a lot of assumptions, but at least we can be consistent.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 and helps us understand why some entities might chose one technologyover another.

13

Typical Construction Period w/Cash Drawdown

1. Cumulative Drawdown

-600,000

-500,000

-400,000

-300,000

-200,000

-100,000

0

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47

14

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

15

Pitfalls

The biggest pitfall is thinking that these numbers are “real”. They are only indicative. Just because a computer can calculate numbers to the penny does not mean that the numbers are accurate. There is a lot of uncertainty due to the number of assumptions that have to be made.It is important to understand what the goal and/or objective of the analysis is. In the following study, the goal was to compare technologies 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.There is no substitute for sound management judgement.The analysis itself does not identify the risks. The analyzer must consider the risks and ask the appropriate “what if” questions. In the following study, over 3,000 spread sheet runs were made in order to analyze the comparisons effectively.Avoid the “Swiss Watch” mentality.

16

Experience Base

Major Competitors Technology Maturity

Sub-Critical PC 1,200 GW Alstom,MHI, B&W, FW and Several Others

Mature

Super-Critical PC 265 GW Alstom,MHI, B&W Proven PFBC 0.5 GW Demo IGCC 1 GW GE, Shell, Conoco Phillips Demo CFB 20 GW Alstom, FW Proven NGCC 200 GW GT

100 GW ST GE, Siemens, Alstom Mature

Technology Position and Experience

17

Baseline Economic Inputs – 1997 400 MW Class

Subcritical Supercritical P800 PFBC IGCCSize(MW)

400 400 400 400

Capital Cost($/ kW)

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

Heat Rate(Btu/ kWh)

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

Availability(%)

80 80 80 80

Cycle Time(months)

36 36 48 48

Fixed O&M($/ kW)

31.14 32.11 33.69 39.08

Variable O&M(mills/ kWh)

0.77 0.69 1.01 0.42

Source: Market Market ABB GE

18


CFB P200 PFBC NGCC Size (MW)

100 100 270

Capital 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

Variable O&M (mills/ kWh)

1.18 1.06 0.01

Source: Market ABB PGT

19

Baseline Economic Inputs - 2005 400 MW Class

Subcritical Supercritical P800 PFBC IGCCSize(MW)

400 400 400 400

Capital Cost($/ kW)

750 750 750 1,100

Heat Rate(Btu/ kWh)

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

Availability(%)

80 80 80 80

Cycle Time(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

20


CFB P200 PFBC NGCCSize(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

21

Financing Scenario Summary

Loan structure Municipal Utility IPP 1 IPP 2 Industrial

Horizon (years) 40 30 15 15 10

Interest rate (%) 5.75 7.75 8.75 8.75 8.25

Loan term (years) 40 30 9 9 10

Depreciation (years) 40 30 15 15 10

Equity (%) 0 50 30 50 75

Debt (%) 100 50 70 50 25

ROE (%) n/a 10 20 20 23

Taxes (%) 0 20 30 30 30

22

Comparison of Financing Scenarios400 MW Subcritical 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

Leve

lized

Tar

iff, c

/ kW

h

FinancialFixed O&MVariable O&MFuel Financial costs have

major influence on COE

23

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

Subcrit PC(400 MW)

Super PC(400 MW)

P-800(400 MW)

IGCC(400 MW)

P-200(100 MW)

CFB(100 MW)

NGCC(270 MW)

Leve

lized

Tarif

f, c/

kW

h

FinancialFixed O&MVariable O&MFuel

24

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

Subcrit PC(400 MW)

Super PC(400 MW)

P-800(400 MW)

IGCC(400 MW)

P-200(100 MW)

CFB(100 MW)

NGCC(270 MW)

Leve

lized

Tarif

f, c/

kW

h


Higher financial cost

increases influence on

COE

NGCC looks better on total COE,but worse on dispatch basis.

25

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

Subcrit PC(400 MW)

Super PC(400 MW)

P-800(400 MW)

IGCC(400 MW)

P-200(100 MW)

CFB(100 MW)

NGCC(270 MW)

Leve

lized

Tarif

f, c/

kW

h


26

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

Subcrit PC(400 MW)

Super PC(400 MW)

P-800(400 MW)

IGCC(400 MW)

P-200(100 MW)

CFB(100 MW)

NGCC(270 MW)

Leve

lized

Tarif

f, c/

kW

h


27

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

Subcrit PC(400 MW)

Super PC(400 MW)

P-800(400 MW)

IGCC(400 MW)

P-200(100 MW)

CFB(100 MW)

NGCC(270 MW)

Leve

lized

Tarif

f, c/

kW

h


28

Capacity Factor Effect on COEMunicipal 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%

Leve

lized

Tarif

f, (c

/ kW

h)

Capacity Factor, (%)

Subcrit PCSupercrit PCP-800IGCCP-200CFBNGCC

Dispatch rate and/or capacity factor

have major influence on COE

29

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)

Leve

lized

Tar

iff, (

c/ k

Wh)

Subcrit PCSupercrit PC

~5 days

5 days lost availability makessub and supercritical equal.

30

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

Cha

nge

in C

OE,

(%)

AvailabilityEPC pricePlant heat rateFixed O&MCycle timeVar O&M

In %, change in availability and

EPC price have highest influence on COE

31

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

Cha

nge

in C

OE,

(%)

AvailabilityEPC pricePlant heat rateFixed O&MCycle timeVar O&M

For NGCC %, change in availability and

efficiency have highest influence on COE

32

Comparison of Technologies China 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

Leve

lized

Tar

iff, (

c/ k

Wh)


First cost less important

fuel sensitive due to high cost

NGCC high

due to fuel cost

33

Comparison of Technologies China 1997 IPP Financing Conditions

($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

Leve

lized

Tarif

f, (c

/ kW

h)


34

Comparison of TechnologiesJapan 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

Subcrit PC(400 MW)

Super PC(400 MW)

P-800(400 MW)

IGCC(400 MW)

P-200(100 MW)

CFB(100 MW)

NGCC(270 MW)

Leve

lized

Tarif

f, c/

kW

h


First cost less important

fuel sensitive due to high cost

35

Net Plant Heat Rate Summary

9,37

5

8,38

5

8,40

5

8,70

0

8,81

5

10,0

35

6,64

0

8,75

0

8,12

5

8,03

0

7,80

0 8,53

0 9,35

0

6,19

5

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)

Net

Pla

nt H

eat R

ate

(Btu

/kW

)

0%

2%

4%

6%

8%

10%

12%

NPH

R Im

provement (%

)

19972005Improvement

36

Summary of EPC Prices

$1,0

00

$1,0

50

$1,1

00

$1,3

80

$1,2

00

$1,0

00

$350

$750

$750

$750

$1,1

00

$850

$725

$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)

EPC

Pric

e ($

/kW

, net

)

0%

5%

10%

15%

20%

25%

30%

35%

40%

EPC D

ecrease (%)

19972005% Decrease

37

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

EPC

Pric

e ($

/kW

, net

)

Subcritical PCSupercritical PCP800P200

“all 400 MW technologies

have the same mid term target

38

Carbon Steel Price Trends

Market Trends

175

150

125

100

Inde

x B

ase

1982

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

Month

39

Nickel Trend: 2000 - 2006

1.802.202.603.003.403.804.204.605.005.405.806.206.607.007.407.808.208.609.009.409.80

10.2010.6011.0011.4011.8012.2012.6013.0013.4013.8014.2014.6015.0015.4015.8016.20

Janu

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embe

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ecem

ber

2000 2001 2002 2003 2004 2005 2006Month / Year

Spot

Nic

kel

Low Ni Avg. Spot Ni High Ni

Market Trends

40

Today’s Costs (Estimated)

Today’s debate centers around conventional pulverized coal plants (PC) and integrated gasification combined cycle plants (IGCC).As we have seen, the current level of development for IGCC makes it uncompetitive with PC, which explains why very few have been built.The claim for the future is that the cost of capture of CO2 to mitigate greenhouse gas concentrations in the atmosphere will be more expensive for PC than for IGCC. Further, as IGCC develops, its costs will come down (learning curve).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 have escalated from their 1997 level to about double. That is, a PC plant is now about $2000/Kw and an IGCC is about $3000/Kw (EPC). Recall that 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.

41

Today’s Costs (Estimated)

Fuel costs have also escalated. Recent data for fuel costs delivered to new plants is about $1.75/MMBTU for coal and $6.50/MMBTU for gas.We can input these new costs into the spread sheet model and get an estimate for the COE for a utility 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 8.30 cents/Kwhr.

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

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 could increase by as much as 50%. Current technology ranges from 20 – 30%. New technology is estimated between 10 – 15%. Who’s right?

42

Efficiency –Critical to emissions strategy

Coal w/ 10%co-firing biomass

100% Coal

Existing US coal fleet @ avg 33%

Commercial Supercritical/

First of kind IGCC

Net Plant Efficiency (HHV), %

Source: National Coal CouncilFrom EPRI study

43

0

10

20

30

40

50

POLK/WABASHIGCC

Target for NewIGCC*

SCPC Today USC Target Next Gen IGCCPlan

t Effi

cien

cy %

(HH

V B

asis

)Meeting the Goals for Coal Based Power - Efficiency

44

CO2 Mitigation Options –for Coal Based Power

Increase efficiencyMaximize MWs per lb of carbon processed

Fuel switch with biomassPartial replacement of fossil fuels =

proportional reduction in CO2

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

= Logical path to lowest cost of carbon reduction

45

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% CO2from Flue Gas. Being Developed by Toshiba, with Support from ALSTOM

CO2 Adsorption 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 Membranes Technologies Focused on Reducing Cost and Power Usage – Multiple suppliers driving innovations

Technology Validation & Demonstration

CO2 Capture – Post Combustion

46

Post Combustion CO2 CaptureChilled Ammonia

Without CO2 Removal

MEA-Fluor Dan. Proc.

NH3

Total power plant cost, M$ 528 652 648Net power output, MWe 462 329 421

Levelized cost of power, c/KWh 5.15 8.56 6.21CO2 Emission, lb/kwh 1.71 0.24 0.19Avoided Cost, $/ton CO2 Base 51.1 19.7

47

0

500

1000

1500

2000

2500

3000

1990 1995 2000 2005 2010 2015 2020

Hea

t of R

eact

ion

(BTU

/lb)

Going Down The Experience Curve forPost Combustion CO2 Capture

1995 2000 2005 2010 2015

2001 Parsons Study (Fluor)

ABB Lumnus

Process Optimization

AdvancedAmines

Process Innovations

ALSTOM’sChilled

Ammonia Process

Significant Improvements Are Being Achieved

Values From Current Projects

1,350 BTU/lb

48

02468

10

SCPC

IGCC

SCPC w/M

EAOxy

firing w

CO2

SCPC adv a

minesIG

CC F turb

ineSCPC N

H3USCPC ad

v CO2

IGCC H

turb

ine w ad

v CO2

Leve

lized

CO

E ce

nts/

Kw

hrMultiple Paths to CO2 ReductionInnovations 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

49

Economic ComparisonCost 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)

(Cen

ts/k

Whr

)

Ref – Air fired CFB w/o capture

Ref – IGCC 7FA w/ capture spare

O2 fired PC w/ capture

O2 fired CFB w/ capture

Ammonia scrubbing

Chemical Looping

50

Conclusions

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

Lower cost, higher performance technologies for postcombustion CO2 capture are actively being developed, and more are emerging

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

The industry is best served by a portfolio approach to drive development of competitive coal power with carbon capture technology

power plant economics - cmu · 5 economic methodologies za power plant is a long lived asset that...

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