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  1. 1. Power Plant Economics Carl Bozzuto ALSTOM © 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. 2. Overview Economic Terms Economic Methodologies Cost Models Pitfalls Cost Studies Results Some words about CO2 Conclusions 2
  3. 3. Economic Terms Return on Sales = Net after tax/Sales revenue Asset turnover = Sales revenue/Assets Leverage = Assets/Equity PE 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/Assets Return on Equity = Net/Equity Discount Rate = Time value of Money Net Present Value = Present Value of Future Returns @ Discount Rate Internal Rate of Return = Discount Rate which yields an NPV of zero 3
  4. 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 evaluation Return on Equity is a key consideration for any investment 4
  5. 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. 5
  6. 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 6
  7. 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. 7 – Total Plant Cost (TPC) – includes all costs
  8. 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). 8
  9. 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. 9
  10. 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) 10
  11. 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. 11
  12. 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 approach gives us a little more insight into the decision making process and helps us understand why some entities might chose one technology over another. 12
  13. 13. Typical Construction Period w/Cash Drawdown 1. C ulativeD dow um raw n 0 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 1 3 5 7 9 -100,000 -200,000 -300,000 -400,000 -500,000 -600,000 13
  14. 14. Typical Levelized Cash Flow 4. EndingEquityCashflow 50,000 0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 (50,000) (100,000) (150,000) (200,000) (250,000) (300,000) (350,000) 14
  15. 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. 15
  16. 16. Technology Position and Experience Experience Major Competitors Technology Base Maturity Sub-Critical PC 1,200 GW Alstom,MHI, B&W, FW Mature and Several Others 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 GE, Siemens, Alstom Mature 100 GW ST 16
  17. 17. Baseline Economic Inputs – 1997 400 MW Class Subcritical Supercritical P800 PFBC IGCC Size 400 400 400 400 (MW) Capital Cost 1,000 1,050 1,100 1,380 ($/ kW) Heat Rate 9,374 8,385 8,405 8,700 (Btu/ kWh) Availability 80 80 80 80 (%) Cycle Time 36 36 48 48 (months) Fixed O&M 31.14 32.11 33.69 39.08 ($/ kW) Variable O&M 0.77 0.69 1.01 0.42 (mills/ kWh) Source: Market Market ABB GE 17
  18. 18. Baseline Economic Inputs – 1997 100 MW Class CFB P200 PFBC NGCC Size 100 100 270 (MW) Capital Cost 1,000 1,200 500 ($/ kW) Heat Rate 10,035 8,815 6,640 (Btu/ kWh) Availability 80 80 80 (%) Cycle Time 30 32 24 (months) Fixed O&M 44.13 55. 41 16.92 ($/ kW) Variable O&M 1.18 1.06 0.01 (mills/ kWh) Source: Market ABB PGT 18
  19. 19. Baseline Economic Inputs - 2005 400 MW Class Subcritical Supercritical P800 PFBC IGCC Size 400 400 400 400 (MW) Capital Cost 750 750 750 1,100 ($/ kW) Heat Rate 8,750 8,125 8,030 7,800 (Btu/ kWh) Availability 80 80 80 80 (%) Cycle Time 24 24 30 36 (months) Fixed O&M 26.33 26.33 26.95 33.69 ($/ kW) Variable O&M 0.81 0.75 1.05 0.37 (mills/ kWh) Source: BA Plan BA Plan SECAR GE 19
  20. 20. Baseline Economic Inputs – 2005 100 MW Class CFB P200 PFBC NGCC Size 100 100 270 (MW) Capital Cost 725 850 325 ($/ kW) Heat Rate 9,350 8,530 6195 (Btu/ kWh) Availability 80 80 80 (%) Cycle Time 18 22 18 (months) Fixed O&M 38.84 48.67 16.44 ($/ kW) Variable O&M 1.15 1.12 0.01 (mills/ kWh) Source: BA Plan SECAR PGT 20
  21. 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 21
  22. 22. Comparison of Financing Scenarios 400 MW Subcritical PC Fired Plant 10.0 9.0 Financial Fixed O&M 8.0 Variable O&M have Fuel Finan cial costs COE e on 7.0 majo r influenc Levelized Tariff, c/ kWh 6.0 5.0 4.0 3.0 2.0 1.0 0.0 Municipal Utility IPP-1 IPP-2 Industrial Financing Arrangement 22
  23. 23. Comparison of Technologies Municipal Financing - 1997 (80% CF, $1.20 coal and $3.00 gas) 4.0 Financial Fixed O&M 3.5 Variable O&M Fuel 3.0 Levelized Tariff, c/ kWh 2.5 2.0 1.5 1.0 0.5 0.0 Subcrit PC Super PC P-800 IGCC P-200 CFB NGCC (400 MW) (400 MW) (400 MW) (400 MW) (100 MW) (100 MW) (270 MW) 23
  24. 24. Comparison of Technologies Utility Financing - 1997 (80% CF, $1.20 coal and $3.00 gas) 5.0 4.5 Financial Fixed O&M 4.0 NGCC lo Variable O&M oks bett but wor er on to Fuel se on di tal COE , Levelized Tariff, c/ kWh 3.5 spatch b asis. ncial cos t 3.0 Hi gher fina ce on increase s influen 2.5 CO E 2.0 1.5 1.0 0.5 0.0 Subcrit PC Super PC P-800 IGCC P-200 CFB NGCC (400 MW) (400 MW) (400 MW) (400 MW) (100 MW) (100 MW) (270 MW) 24
  25. 25. Comparison of Technologies IPP(1) Financing - 1997 (80% CF, $1.20 coal and $3.00 gas) 8.0 Financial Fixed O&M 7.0 Variable O&M Fuel 6.0 Levelized Tariff, c/ kWh 5.0 4.0 3.0 2.0 1.0 0.0 Subcrit PC Super PC P-800 IGCC P-200 CFB NGCC (400 MW) (400 MW) (400 MW) (400 MW) (100 MW) (100 MW) (270 MW) 25
  26. 26. Comparison of Technologies IPP(2) Financing - 1997 (80% CF, $1.20 coal and $3.00 gas) 9.0 Financial Fixed O&M 8.0 Variable O&M Fuel 7.0 Levelized Tariff, c/ kWh 6.0 5.0 4.0 3.0 2.0 1.0 0.0 Subcrit PC Super PC P-800 IGCC P-200 CFB NGCC (400 MW) (400 MW) (400 MW) (400 MW) (100 MW) (100 MW) (270 MW) 26
  27. 27. Comparison of Technologies Industrial Financing - 1997 (80% CF, $1.20 coal and $3.00 gas) 16.0 Financial Fixed O&M 14.0 Variable O&M Fuel 12.0 Levelized Tariff, c/ kWh 10.0 8.0 6.0 4.0 2.0 0.0 Subcrit PC Super PC P-800 IGCC P-200 CFB NGCC (400 MW) (400 MW) (400 MW) (400 MW) (100 MW) (100 MW) (270 MW) 27
  28. 28. Capacity Factor Effect on COE Municipal Financing - 1997 ($1.20 coal and $3.00 gas) 8.0 Subcrit PC Supercrit PC 7.0 P-800 IGCC D is P-200 patc Levelized Tariff, (c/ kWh) CFB 6.0 h ra hav te a NGCC em ajor nd/or c influ apac en c i 5.0 e on ty facto COE r 4.0 3.0 2.0 20% 30% 40% 50% 60% 70% 80% 90% 100% Capacity Factor, (%) 28
  29. 29. Impact of Availability on COE Municipal Financing - 1997 ($1.20 coal) 3.5 3.4 3.3 Subcrit PC 5 days lost availability makes Supercrit PC Levelized Tariff, (c/ kWh) 3.2 sub and supercritical equal. 3.1 3.0 2.9 2.8 ~5 days 2.7 2.6 2.5 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) 29
  30. 30. Sensitivity Analysis Subcritical PC 1997 IPP1 Financing - $1.20 coal 20% a nd e in availability n COE In %, chang est influe nce o 15% e high EPC price hav 10% Change in COE, (%) 5% 0% -5% -10% Availability EPC price Plant heat rate -15% Fixed O&M Cycle time Var O&M -20% -20% -15% -10% -5% 0% 5% 10% 15% 20% Percent Variable Change 30
  31. 31. Sensitivity Analysis NGCC 1997 IPP1 Financing - $3.00 gas 20% and in av ailability 15% NG C C % , change fluence o n COE For e st i n have high 10% efficiency Change in COE, (%) 5% 0% -5% -10% Availability EPC price Plant heat rate Fixed O&M -15% Cycle time Var O&M -20% -20% -15% -10% -5% 0% 5% 10% 15% 20% Percent Variable Change 31
  32. 32. gh NGCC hi Comparison of Technologies China 1997 Municipal Financing Conditions el ($1.80 coal and $5.00 LNG) due to fu 4.0 cost ta nt 3.5 t less impor First cos e to high c os t tive du 3.0 f uel sensi Levelized Tariff, (c/ kWh) 2.5 2.0 1.5 1.0 Financial Fixed O&M Variable O&M 0.5 Fuel 0.0 Subcrit Supercrit P-800 IGCC P-200 CFB NGCC PC PC 32
  33. 33. Comparison of Technologies China 1997 IPP Financing Conditions ($1.80 coal and $5.00 LNG) 7.00 6.00 Levelized Tariff, (c/ kWh) 5.00 4.00 3.00 2.00 Financial Fixed O&M 1.00 Variable O&M Fuel 0.00 Subcrit Supercrit P-800 IGCC P-200 CFB NGCC PC PC 33
  34. 34. Comparison of Technologies Japan Market Conditions - 1997 ($2.90 coal and $5.00 LNG) 5.0 4.5 4.0 Levelized Tariff, c/ kWh 3.5 3.0 2.5 2.0 r ta nt t less impo 1.5 First cos to high c os t Financial e due l sensitiv Fixed O&M 1.0 fue Variable O&M Fuel 0.5 0.0 Subcrit PC Super PC P-800 IGCC P-200 CFB NGCC (400 MW) (400 MW) (400 MW) (400 MW) (100 MW) (100 MW) (270 MW) 34
  35. 35. Net Plant Heat Rate Summary 12,000 12% 10,035 9,375 10% 9,350 10,000 10% 8,815 8,750 8,700 8,530 8,405 8,385 8,125 8,030 Net Plant Heat Rate (Btu/kW) 7,800 NPHR Improvement (%) 8,000 8% 6,640 6,195 7% 7% 7% 6,000 6% 4% 4,000 4% 3% 3% 2,000 1997 2% 2005 Improvement 0 0% Subcrit PC Super PC PFBC-P800 IGCC PFBC-P200 CFB NGCC (400 MW) (400 MW) (400 MW) (400 MW) (100 MW) (100 MW) (270 MW) 35
  36. 36. Summary of EPC Prices $1,600 40% $1,380 1997 2005 $1,400 % Decrease 35% $1,200 32% $1,100 $1,100 $1,050 $1,200 30% 29% $1,000 $1,000 29% 28% EPC Price ($/kW, net) EPC Decrease (%) $1,000 25% 25% $850 $750 $750 $750 $725 $800 20% 20% $600 15% $350 $325 $400 10% 7% $200 5% $0 0% Subcrit PC Super PC PFBC-P800 IGCC PFBC-P200 CFB NGCC (400 MW) (400 MW) (400 MW) (400 MW) (100 MW) (100 MW) (270 MW) 36
  37. 37. Coal Technology Cost Trends Extrapolated to 2005 2,000 1,800 Subcritical PC Supercritical PC 1,600 P800 P200 1,400 EPC Price ($/kW, net) 1,200 1,000 800 600 “all 4 400 have 00 MW t the s echn ame olog 200 mid ies term targ 0 et 1989 1991 1993 1995 1997 1999 2001 2003 2005 Year 37
  38. 38. Market Trends Carbon Steel Price Trends 175 Index Base 1982 150 125 100 01/02 01/03 01/04 01/05 01/06 Month 38
  39. 39. 39 Spot Nickel 1.80 2.20 2.60 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 13.00 13.40 13.80 14.20 14.60 15.00 15.40 15.80 16.20 January February March April May June July 2000 August September October November December January February March April May June Market Trends July 2001 August September October November December January February March April May June July 2002 August September October November December Low Ni January February March April May June July 2003 August September Month / Year Avg. Spot Ni October November December Nickel Trend: 2000 - 2006 January February March April High Ni May June July 2004 August September October November December January February March April May June July 2005 August September October November December January February March April May June July 2006 August September October November December
  40. 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. 40
  41. 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? 41
  42. 42. Efficiency – Critical to emissions strategy Source: National Coal Council From EPRI study 100% Coal Coal w/ 10% co-firingbiomass Commercial Supercritical/ First of kind IGCC Existing US coal fleet @ avg 33% Net Plant Efficiency (HHV), % 42
  43. 43. Meeting the Goals for Plant Efficiency % (HHV Basis) Coal Based Power - Efficiency 50 40 30 20 10 0 POLK/WABASH Target for New SCPC Today USC Target Next Gen IGCC IGCC IGCC* 43
  44. 44. CO2 Mitigation Options – for Coal Based Power Increase efficiency Maximize MWs per lb of carbon processed Fuel switch with biomass Partial replacement of fossil fuels = proportional reduction in CO2 Then, and only then ….Capture remaining CO2 for EOR/Sequestration = Logical path to lowest cost of carbon reduction 44
  45. 45. CO2 Capture – Post Combustion Technology Status CO2 Scrubbing options – Demonstration in 2006. Advantage of lower costs than Amines. ammonia based 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 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 45
  46. 46. Post Combustion CO2 Capture Chilled Ammonia Without CO2 MEA-Fluor Dan. NH3 Removal Proc. 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, $/ton CO2 Base 51.1 19.7 46
  47. 47. Going Down The Experience Curve for Post Combustion CO2 Capture 3000 ABB Lumnus Heat of Reaction (BTU/lb) 2500 Values From Current Projects 2000 1500 1,350 BTU/lb ALSTOM’s Chilled Ammonia 1000 2001 Parsons Process Study (Fluor) 500 Process Advanced Process 0 Optimization Amines Innovations 1990 1995 1995 2000 2000 2005 2005 2010 2010 2015 2015 2020 Significant Improvements Are Being Achieved 47
  48. 48. Multiple Paths to CO2 Reduction Innovations for the Future ‘Hatched’ Range reflects cost variation from fuels and uncertainty Technology Choices Reduce Risk and Lower Costs 10 No CO2 Capture ------------------------------With CO2 Capture--------------------------- Levelized COE cents/Kwhr 8 6 4 2 0 3 PC 2 CC EA e 2 2 es O NH in CO CO SC in C IG /M rb am PC v v w tu w ad ad g SC PC F v in C ad w CC SC fir CP e PC xy IG in US rb O SC tu H CC Note: Costs include compression , but do not include sequestration – equal for all technologies IG 48
  49. 49. Economic Comparison Cost of Electricity (common basis) Ref – Air fired CFB w/o 9.00 capture 8.50 Ref – IGCC 7FA w/ capture spare 8.00 O2 fired PC w/ 7.50 capture (Cents/kWhr) 7.00 O2 fired CFB w/ capture 6.50 6.00 Ammonia scrubbing 5.50 5.00 Chemical Looping 4.50 4.00 0 10 20 30 40 50 CO2 Allowance Price ($/Ton CO2 Emitted) 49
  50. 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 post combustion 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 50

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