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
Economic Methodologies
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
Economic Methodologies
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
Baseline Economic Inputs – 1997 100 MW Class
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
Variable O&M(mills/ kWh)
0.81 0.75 1.05 0.37
Source: BA Plan BA Plan SECAR GE
20
Baseline Economic Inputs – 2005 100 MW Class
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
Variable O&M(mills/ kWh)
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
FinancialFixed O&MVariable O&MFuel
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
FinancialFixed O&MVariable O&MFuel
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
FinancialFixed O&MVariable O&MFuel
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
FinancialFixed O&MVariable O&MFuel
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)
FinancialFixed O&MVariable O&MFuel
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)
FinancialFixed O&MVariable O&MFuel
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
FinancialFixed O&MVariable O&MFuel
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
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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