### ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

FINAL REPORT

SUBMITTED BY

ALSTOM POWER INC. POWER PLANT LABORATORIES 2000 DAY HILL ROAD WINDSOR, CT 06095 (860) 688-1911

Project Manager: Mark Palkes
Principal Investigators:

Richard E. Waryasz Gregory N. Liljedahl

PREPARED FOR

NETL AAD DOCUMENT CONTROL BLDG. 921 US DEPARTMENT OF ENERGY NATIONAL ENERGY TECHNOLOGY LABORATORY P.O. BOX 10940 PITTSBURGH, PENNSYLVANIA 15236-0940 (COOPERATIVE AGREEMENTT NO. DE-FCP-01NT41222)

REPORT SUBMITTAL DATE: SEPTEMBER 8, 2004 PERFORMANCE PERIOD: OCTOBE R 1, 2001 – FEBRUARY 28, 2004

PPL REPORT NO. PPL-04-CT-03ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 ii 

### DISCLAIMER

This report was prepared as an account of work sponsored by an agency of the United Sates Government. Neither the United States Governm ent nor any agency thereof, nor any of their employees makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not nec essarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not ne cessarily state or refl ect those of the United States Government or any agency thereof.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 iii 

### ACKNOWLEDGMENTS
The authors appreciatively acknowledge the follo wing people for their contributions to the successful performance of the work presented herein:

 

### John Marion, John Ferguson, Roland Tetreault, Ray Chamberland, Mike Rini, Maurus Herzog, Brendon Scarlin, Richard Skowyra, Ra ymond Hickey, Diane Calkin, Glen Jukkola, Srivats Srinivasachar, and Larry Cellilli of ALST OM Power Inc. for their contributions as follows:

• John Marion: For providing overall project leadership.

• John Ferguson: For proving design guidance and cost calculations for the CMB TM 

### Boiler Islands.

• Roland Tetreault: For providing design graphics services.

• Ray Chamberland: For providing economic analyses for all cases.

• Mike Rini: For providing performance and cost information for wet FGD systems and FDA systems used for flue gas sulfur removal.

• Maurus Herzog and Brendon Scarlin: For provid ing performance and cost information for the steam cycles.

• Richard Skowyra: For provid ing general consultation on Circulating Fluidized Bed boilers.

• Raymond Hickey: For providing general consultation on all boiler designs.

• Diane Calkin: For providing cost estimating of Pulverized Coal and Circulating Fluidized Bed Boiler Islands.

• Glen Jukkola: For providing general consultation on Circulating Fluidized Bed and Circulating Moving Bed Boilers.

• Srivats Srinivasachar: For providing in formation on mercury removal from boilers.

• Larry Cellilli: For providin g contract adm inistration.

 

### William McMahon of Parsons Energy and Chemical Group, Inc., of Wyomissing, Pennsylvania: For providing complete design a nd cost information for the material handling systems (Coal, Limestone, and Ash).

 

### Barry Brederstorff of American Electric Power, Inc., of Columbus, Ohio: For providing general project consultation, economic assumptions, an d design and cost information for balance of plant equipment for the Repowering Case.

The financial support of this project by DOE Na tional Energy Technolog y Laboratory (Contract No DE-FCP-01NT41222), and ALSTOM Power Inc. is also appreciatively acknowledged.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 iv 

### PUBLIC ABSTRACT
ALSTOM Power Inc.’s Power Plant Laboratories (ALSTOM) has teamed with the U.S. Department of Energy National Energy Tec hnology Laboratory (DOE NETL), American Electric Company (AEP) and Parsons Ener gy and Chemical Group to co nduct a comprehensive study evaluating coal fired steam power plants, known as Rankine Cycles, equipped with three different combustion systems: Pulverized Coal (PC), Ci rculating Fluidized Bed (CFB), and Circulating Moving Bed (CMB TM 

### ). Five steam cycles utilizing a wide range of steam conditions were used with these combustion systems.
The motivation for this study was to establis h through engineering analysis, the most costeffective performance potential available th rough improvement in the Rankine Cycle steam conditions and combustion systems while at t he same time ensuring that the most stringent emission performance based on CURC (Coal Utiliza tion Research Council) 2010 targets are met.

• > 98% sulfur removal

• < 0.05 lbm/MM-Btu NO x



### • < 0.01 lbm/MM-Btu Particulate Matter

• > 90% Hg removal
The final report discusses the results of a co al fired steam power plant project, which is comprised of two parts. The main part of the study is the analysis of ten (10) Greenfield steam power plants employing three different coal combustion technologies: Pulverized Coal (PC), Circulating Fluidized Bed (CFB), and Circulating Moving Bed (CMB TM 

### ) integrated with five different steam cycles. The st udy explores the technical f easibility, thermal performance, environmental performance, and economic viabilit y of ten power plants that could be deployed currently, in the near, intermediate, and long-term time frame. For the five steam cycles, main steam temperatures vary from 1,000°F to 1,29 2°F and pressures from 2,400 psi to 5,075 psi. Reheat steam temperatures vary from 1,000° F to 1,328°F. The number of feedwater heaters varies from 7 to 9 and the associated feedwater temperature varies from 500°F to 626°F. The main part of the study therefore determines the steam cycle parameters and combustion technology that would yield the lowest cost of electricity (COE) for the next generation of coalfired steam power plants.
The second part of the study (Repowering) expl ores the means of upgrading the efficiency and output of an older existing coal fired steam po wer plant. There are currently more than 1,400 coal-fired units in operation in the United Stat es generating about 54 percent of the electricity consumed. Many of these are modern units are clean and efficient. Additionally, there are many older units in excellent condition and still in se rvice that could benefit from this repowering technology. The study evaluates the technica l feasibility, thermal performance, and economic viability of this repowering concept.
Major conclusions :
Primary results for both parts of the study ar e summarized in terms of thermal efficiency, environmental performance, inve stment costs, and cost of elec tricity (COE). For the ten Greenfield cases, the calculated thermal effici encies (HHV basis) range from 37.02% to 43.55%. The effect of the increasing steam cycle paramet ers (Temperature and Pressure) is to increase plant efficiency. The highest efficiency is achiev ed for the ultra supercritical steam cycle 1,292°F/ 1,1328°F/5075 psi. With respect to thermal effi ciency, for the same steam conditions, there is little difference when comparing among t he combustion systems (PC, CFB, and CMB TM 

### ) as would be expected. In general the thermal efficiency of the PC fired systems are about the same as for the CFB based systems. The CFB and PC system s thermal efficiency are about 0.1 percentage points higher than the CMB TM 

### systems which is due to only partial sulfation in the CMB TM 

### combustor.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 v 

### The specific plant investment cost results fo r the Greenfield cases range from about 1,018 to 1,168 $/kW-net. For the same steam conditions, the CMB TM 

### combustion system plants require the lowest investment costs as compared to PC or CFB plants. This cost advantage increases as steam cycle conditions (Temperat ure and Pressure) are raised. The CFB systems are about 70 $/kW lower in cost than the PC type combustion syst ems. This difference is primarily attributable to the differences in the costs fo r the gas cleanup system equipment.
The levelized cost of electricity (C OE) results for the Greenfield cases range from about 3.4 to 4.0 Cents/kWh. These results indicate that the CMB TM 

### case designed for the ultra supercritical steam conditions is the most economical from a COE basis. Compared to the PC case designed for the same ultra supercritical steam conditions, it require s significantly less weight of very expensive Ni alloy tubing. For the same steam conditions there is very little difference in the COE between CFB and CMB TM 

### designs.

Similar to the investment cost results, the PC cases are about 7% higher than the CFB type combustion systems with respect to COE at t he same steam conditions. The advantage of the CFB systems is attributable to the investment cost savings. Because of the additional reduction in investment cost associated with CMB TM 

### based systems, the CMB TM 

### combustion system offers a COE advantage as compared to PC of about 8-10% (greater advantage at higher steam conditions) and about 1% as compared to CFB type combustion systems.
The cost of electricity is directly related to the cost of fuel. As the cost of fuel increases, the cost of electricity increases also and at the same ti me the economics continue to shift towards the more efficient power plant systems. For example, at a coal price of $1.80 MM-Btu the COE is the lowest for the ultra-supercritical case among the PC power plant cases. The ultra-supercritical CMB case continues to offer the lowest COE among the power plant cycles analyzed.

There is direct correlation of CO 2 

### emissions and plant thermal efficiency. For example, the ultra supercritical PC case is about 18% more effici ent than conventional subcritical PC case and it also emits about 18% less CO 2 

### per kWh of net output.
The study has also investigated the impact of potential taxes placed on CO 2 

### emissions. As expected, the COE increases significantly with the increase in the tax. The tax would become a major driver in utility companies’ selection proc ess of the power plant cycle parameters and the high efficiency plants would beco me the technologies of choice.
For the Repowering Case, CMB combustion tech nology was selected because of its economic advantage for high temperature cycles. The calculated thermal efficiency (HHV basis) is improved from 35.70% for the existing unit to 38. 40%. The investment costs necessary for all the equipment required for this repowering project is 413 $/kW-net and the resulting incremental cost of electricity is calculated to be 0.47 Cents/ kWh (2.76 - 2.29 Cents/kW h). Incremental cost is calculated relative to the unmodified existing unit. This difference may quickly disappear if the price of NO x 

### credits continues to increase and/or a major capital investment is required to refurbish the existing boiler or if there is loss of availability caused by the aging equipment. CO 2 

### emissions are decreased from about 1.94 to 1. 80 lbm/kWh, a reducti on of about 8 percent.
In summary, from the results of the study the evaluated power plan t systems fall either into the near term or long term category with respect to technology implementation. All combustion technologies can achieve low levels of pollutants and comply with the CURC 2010 air pollution targets. Technology is available today to facilitat e construction of all the PC cycles, except for the ultra-supercritical steam conditions, and all the CFB steam cycles. Technology is being developed to enable market introduction of the ultra supercritical and CMB TM 

### cycles in a 10 to 15 year timeframe. The very high steam temperatur es of the ultra-supercritical steam cycle do not appear to be practical for conventional CFB technology where combustion temperature is generally limited to 1,550 o 

### F. CMB TM 

### technology with the combustion temperature of 2000 o 

### FECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 vi 

### allows greater latitude in selecting the range of steam cycle parameters. The ultra-supercritical CMB TM 

### design offers the prospect of the lowest COE.
The CFB power plants are the technology of choice for high sulfur coals. For low sulfur coals the PC power plants that don’t requi re installation of the back end NO x 

### and SO x 

### control technologies would be favored. The supercritical CFB plants have the lowest cost of electricity and its cost continues to improve for higher steam conditions.
Major recommendations:
Building up on these results, the next step in t he development effort of the Rankine power plant cycle is recommended. It should include a CFB design with steam conditions of 4,000 psi to 5000 psi and main and reheat steam te mperatures of approximately 1,200 o 

### F. The potential plant efficiency improvement would be significant and the efficiency should be in the range of 41-42% (HHV basis). These steam conditions may require some CFB process modifications to enable the higher steam temperatures but would represent the upper limit for conventional boiler alloys. Such a design would fulfill the promise of high e fficiency and low cost of the intermediate term (3 to 5 years) power plant cycle.

Based on reliability, investment costs, emission s and cost of electricity a coal fired steam power plant will continue to be a good investment for power plant owners especially compared to other options such as IGCC for coal powered electric power production. The thermal efficiencies of today’s steam power plants with supercritical st eam cycles are higher than today’s IGCC plants. For power plants of the future, studies show that coal fired steam plants with ultra-supercritical steam cycles will maintain this efficiency advan tage over future IGCC plants with advanced gas turbines.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### Table of Contents

1. Introdu ction ................................................................................................................. ................ 1 2. Case Studies; Plant Perfor mance, Design and Equipm ent........................................................ 6 2.1 Plant Design Ba sis and Scope:............................................................................................ 6 2.2 Steam Cycles for t he Greenfield Cases............................................................................. 12 2.2.1 General Steam Cy cle Description .......................................................................... 12 2.2.2 Steam Cycl e Equipment ......................................................................................... 19 2.2.2.1 Steam Turb ine Generators.......................................................................... 19 2.2.2.2 Condensate Systems .................................................................................. 19 2.2.2.3 Feedwate r Systems..................................................................................... 19 2.3 Pulverized Coal (P C) Fired Cases ..................................................................................... 20 2.3.1 Steam Cycles fo r the PC Cases ............................................................................. 21 2.3.2 Steam Generator Designs for the PC Fi red Cases ................................................ 21 2.3.2.1 Heat Transfer Surfaces and Arrangement for t he PC Boilers..................... 21 2.3.2.2 Materials for t he PC Fired Boilers: .............................................................. 25 2.3.2.3 Firing Systems fo r the PC Bo ilers: .............................................................. 26 2.3.2.4 Air Heater System for the PC Boilers.......................................................... 28 2.3.2.5 Start-up System for Supercritical and Ultra-Supercritical PC Boilers:......... 28 2.3.3 Balance of Plant Equipm ent for the PC Cases....................................................... 29 2.3.3.1 Gas Cleanup System s for the PC Cases .................................................... 29 2.3.3.2 Other BOP System s for the PC Cases ....................................................... 33 2.3.4 Overall Plant Performance Co mparison for t he PC Cases .................................... 38 2.4 Circulating Fluidiz ed Bed (CFB) Cases ............................................................................. 40 2.4.1 Steam Cycles fo r the CFB Cases........................................................................... 41 2.4.2 Steam Generator Desi gns for the CF B Cases ....................................................... 41 2.4.2.1 CFB Steam Generator De sign Philosophy and Scale- up: .......................... 41 2.4.2.2 Heat Transfer Surfaces and Arrangement for the CFB Boilers.................. 43 2.4.2.3 Materials fo r the CFB Boilers ...................................................................... 46 2.4.2.4 Firing System for the CFB Boilers............................................................... 46 2.4.2.5 Air Heater System for the CFB Boilers........................................................ 47 2.4.2.6 Start-up System for Supercritical CFB Boilers ............................................ 47 2.4.3 Balance of Plant Equipm ent for the CF B Cases..................................................... 47 2.4.3.1 Gas Clean-up System s for the CF B Cases................................................. 48 2.4.3.2 Other BOP System s for the CF B Cases ..................................................... 49 2.4.4 Overall Plant Performance Co mparison for t he CFB Cases .................................. 50 2.5 Circulating Moving Bed (CMB TM 

### ) Cases ............................................................................ 53 2.5.1 Steam Cycles for the CMB TM 

### Cases....................................................................... 54 2.5.2 Steam Generator Designs for the CMB TM 

### Cases................................................... 54 2.5.2.1 CMB TM 

### Backgr ound..................................................................................... 54 2.5.2.2 Heat Transfer Surfaces and Arrangement for the CMB TM 

### Boilers .............. 56 2.5.2.3 Materials for the CMB TM 

### Boilers .................................................................. 59 2.5.2.4 Firing System for the CMB TM 

### Boilers........................................................... 59 2.5.2.5 Air Heater System for the CMB TM 

### Boilers ................................................... 59 2.5.2.6 Start-up System for Supercrit ical and Ultra-Supercritical CMB TM 

### Boilers ... 59 2.5.3 Balance of Plant Equipment for the CMB TM 

### Cases ................................................ 60 2.5.3.1 Gas Clean-up Systems for the CMB TM 

### Cases ............................................ 60 2.5.3.2 Other BOP Systems for the CMB TM 

### Cases................................................. 60 2.5.4 Overall Plant Performance Comparison for the CMB TM 

### Cases .............................. 62 2.6 Repower ing Case............................................................................................................. .. 65 2.6.1 Steam Cycle for the CMB TM 

### Repowering Case...................................................... 67 2.6.2 Steam Generator Design for the CMB TM 

### Repowering Case .................................. 70 2.6.2.1 Heat Transfer Surfaces and Arrangement for the CMB TM 

### Repowering Boiler ..................................................................................................................... 70 2.6.2.2 Materials for the CMB TM 

### Repowering Boiler................................................ 72ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 viii 

### 2.6.2.3 Firing System for the CMB TM 

### Repowering Boiler ........................................ 73 2.6.2.4 Air Heater System for the CMB TM 

### Repowering Boiler................................. 73 2.6.2.5 Start up System for the CMB TM 

### Repowering Case ..................................... 73 2.6.3 Balance of Plant Equipment for the CMB TM 

### Repowering Case.............................. 73 2.6.3.1 Gas Clean-up Systems for the CMB TM 

### Repowering Case.......................... 73 2.6.3.2 Other BOP Systems for the CMB TM 

### Repowering Case .............................. 73 2.6.4 Existing Sporn Plant Desc ription and Pe rformance................................................ 75 2.6.5 Overall Plant Performance for the CMB TM 

### Repowering Case ................................ 78 2.7 Overall Plant Performance Comparison (a ll Cases) .......................................................... 81 2.7.1 Auxiliary Po wer Basi s: ............................................................................................ 81 2.7.2 Plant Perfor mance Summa ry:................................................................................. 82 2.7.3 The Effect of Steam Cycle Pa rameters on Plant Performance: ............................. 90 2.7.4 The Effect of Combustion System on Plant Performance: ..................................... 91 2.7.5 Comparison of CO 2 

### Emissions for All Cases:......................................................... 92 3. Cost Analysis ................................................................................................................ ............ 93 3.1 Greenfield Cases In vestment Costs .................................................................................. 96 3.1.1 Total Plant In vestment Costs:................................................................................. 96 3.1.2 Boiler Is land Costs:................................................................................................. 98 3.1.3 Turbine Is land Costs:............................................................................................ 100 3.1.4 Other Balance of Pl ant Equipment Costs:............................................................ 102 3.2 Repowering Case In vestment Costs................................................................................ 103 3.3 Operating and Main tenance Co sts .................................................................................. 105 4. Economic Analysis............................................................................................................ ...... 106 4.1 Economic Analysis Assumptions ..................................................................................... 106 4.2 Cost of Electricity Calculation........................................................................................... 10 7 4.3 Economic Analys is Results.............................................................................................. 108 4.3.1 Pulverized Coal Fired Ca ses ................................................................................ 108 4.3.2 CFB and CMB TM 

### Cases ........................................................................................ 108 4.3.3 Repower ing Case ................................................................................................. 109 4.3.4 Economic Sensitiv ity Study Summary .................................................................. 110 4.3.4.1 Case PC-3................................................................................................. 111 4.3.4.2 Case CFB-3............................................................................................... 112 4.3.4.3 High Temperature Nickel Alloy Sensit ivity Study ...................................... 113 4.3.4.4 NO x 

### / SO x 

### Credit Sensitivity Study for Repower ing Case ......................... 115 4.4 Economic Study Summa ry and Conclu sions................................................................... 117 5. Conclusions and Recommendations...................................................................................... 121 6. Bibli ography ................................................................................................................. ........... 124 7. Appendi ces ................................................................................................................... .......... 125 7.1 Appendix I - Plant E quipment Li sts .................................................................................. 126 7.1.1 Boiler Island Equipment for Greenfield Cases...................................................... 127 7.1.1.1 PC Cases Boiler Island Equi pment ........................................................... 127 7.1.1.2 CFB Cases Boiler Island Equi pment......................................................... 130 7.1.1.3 CMB TM 

### Cases Boiler Is land Equi pment ..................................................... 133 7.1.2 Balance of Plant Equipment for Greenfie ld Cases ............................................... 136 7.1.3 Sporn Repowering Ca se Equipment List.............................................................. 152 7.1.3.1 Sporn Repowering Case Boiler Island Equipment.................................... 152 7.1.3.2 Sporn Repowering Case Balance of Plant Equipm ent ............................. 154 7.2 Appendix II - Drawin gs ..................................................................................................... 1 55 7.3 Appendix III – Detailed Investment Costs and Operating and Main tenance Costs......... 170 7.4 Appendix IV - Economic Sens itivity Study Result s .......................................................... 194 7.4.1 Case PC-1 – 1 x 630 MW PC Fired Steam Plant with SCR................................. 194 7.4.2 Case PC-2 – 1 x 650 MW PC Fired Steam Plant with SCR................................. 196 7.4.3 Case PC-3 – 1 x 660 MW PC Fired Steam Plant with SCR................................. 198 7.4.4 Case PC-4 – 1 x 680 MW PC Fired Steam Plant with SCR................................. 200 7.4.5 Case PC-5 $20 Nickel - 1 x 740 MW PC Fired Steam Plant with SCR and $20 per Pound High Temperat ure Alloy........................................................................................ 202ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### 7.4.6 Case PC-5 $28 Nickel - 1 x 740 MW PC Fired Steam Plant with SCR and $28 per Pound High Temperature Alloy Econom ic Sensitivit y Result s......................................... 204 7.4.7 Case PC-5 $32.9 Nickel - 1 x 740 MW PC Fired Steam Plant with SCR and $32.90 per Pound High Temperature Alloy Economic Sensitivity Results .................................. 206 7.4.8 Case CFB-2 - 1 x 650 MW CFB Steam Plant with SNCR Economic Sensitivity Results ........................................................................................................................ ..... 208 7.4.9 Case CFB-3 - 1 x 660 MW CFB Steam Plant with SNCR Economic Sensitivity Results ........................................................................................................................ ..... 210 7.4.10 Case CFB-4 - 1 x 680 MW CFB Steam Plant with SNCR Economic Sensitivity Results ........................................................................................................................ ..... 212 7.4.11 Case CMB-3 - 1 x 670 MW CMB Steam Plant with SNCR Economic Sensitivity Results ........................................................................................................................ ..... 214 7.4.12 Case CMB-5 20 Alloy - 1 x 750 MW CMB Steam Plant with SNCR and $20 per Pound High Temperature Alloy Econom ic Sensitivit y Result s......................................... 216 7.4.13 Case CMB-5 28 Alloy - 1 x 750 MW CMB Steam Plant with SNCR and $28 per Pound High Temperature Alloy Econom ic Sensitivit y Result s......................................... 218 7.4.14 Case CMB-5 32.9 Alloy - 1 x 750 MW CMB Steam Plant with SNCR and $32.90 per Pound High Temperature Alloy Economic Sensitivity Results .................................. 220 7.4.15 Case Base Phillip Sporn Unit 4 – Base Phillip Sporn Unit 4 Economic Sensitivity Results ........................................................................................................................ ..... 222 7.4.16 Case Base Phillip Sporn Unit 4 Purchase NO x 

### Credits – Base Phillip Sporn Unit 4 with Purchase of $5k per Ton NO x 

### Credits Economic Sensitivity Results....................... 224 7.4.17 Case Repowe ring Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with No Emissions Credits Sold and $20 per Pound High Temperature Alloy Economic Sensitivity Results ........................................................................................................................ ..... 226 7.4.18 Case Repowe ring Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with No Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity Results ........................................................................................................................ ..... 228 7.4.19 Case Repowe ring Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with No Emissions Credits Sold and $32.90 per Pound High Temperature Alloy Economic Sensitivity Results ............................................................................................................ 230 7.4.20 Case Repowe ring Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with $2k per Ton NO x 

### and $200 per Ton SO x 

### Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity Results............................................................. 232 7.4.21 Case Repowe ring Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with $5k per Ton NO x 

### and $200 per Ton SO x 

### Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity Results............................................................. 234 7.4.22 Case Repowe ring Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with $8k per Ton NO x 

### and $200 per Ton SO x 

### Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity Results............................................................. 236ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### List of Figures
Figure 1.0. 1: Simplified Diagram of a Rankine Cycle Steam Power Plant................................... 1 Figure 2.2. 1: Steam Cycle #1 Schematic and Pe rformance ...................................................... 14 Figure 2.2. 2: Steam Cycle #2 Schematic and Pe rformance ...................................................... 15 Figure 2.2. 3: Steam Cycle #3 Schematic and Performance 16 Figure 2.2. 4: Steam Cycle #4 Schematic and Pe rformance ...................................................... 17 Figure 2.2. 5: Steam Cycle #5 Schematic and Pe rformance ...................................................... 18 Figure 2.3. 1: Simplified Gas Side Proce ss Flow Diagram for the PC Cases............................. 20 Figure 2.3. 2: Pulverized Co al Fired Sliding Pressure Supercritical Boiler ................................. 23 Figure 2.3. 3: Boiler Water/Steam Flow Diagram for Supercritical Designs ............................... 24 Figure 2.3. 4: Spiral Wound Furnace C onstruction and Support ing Structure............................ 25 Figure 2.3. 5: Start-Up System with Low Load Circulat ion Pump for Supercritical Boilers......... 29 Figure 2.3. 6: SCR Typical Arrangement Diagra m...................................................................... 30 Figure 2.3. 7: Simplified Process Fl ow Diagram for We t FGD System....................................... 31 Figure 2.3. 8: Pilot-Scale and Full Scale ESP Hg Removal Efficiencies as a function of Sorbent Injecti on Rate ................................................................................................................. ........ 32 Figure 2.3. 9: Thermal Efficiency for PC Cases (HHV Basis) ..................................................... 39 Figure 2.4. 1 Simplified Gas Side Proce ss Flow Diagram for the CFB Cases........................... 40 Figure 2.4. 2: Cyclone Ar rangements and Scale Up................................................................... 42 Figure 2.4. 3: Pant Leg Style Comb ustor – Side View Schematic .............................................. 42 Figure 2.4. 4: Side View Elevation of a 700 MW Supercriti cal CFB Boiler ................................. 45 Figure 2.4. 5: Isometric View of Second-Generation Superc ritical CFB Boiler ........................ 46 Figure 2.4. 6: Flash Dryer Absorber (FDA) Process Schematic Diagram................................... 48 Figure 2.4. 7: Thermal Effi ciency for CF B Cases........................................................................ 52 Figure 2.5. 1: Simplified Gas Side Process Flow Diagram for the CMB TM 

### Cases ...................... 53 Figure 2.5. 2: CMB TM 

### Combustion System Schematic................................................................ 55 Figure 2.5. 3: Side Elevation View of a 700MW Supercritical CMB TM 

### Boiler (Case CMB TM 

### -3).. 57 Figure 2.5. 4: Side Elevation of Mo ving Bed Heat Exchanger (Case CMB TM 

### -3)........................ 58 Figure 2.5. 5: Thermal Efficiency Comparison for CMB TM 

### Cases ............................................... 64 Figure 2.6. 1: Simplified Schematic of AEP’ s Philip Sporn Plant Repowered with a High Efficiency St eam Cy cle......................................................................................................... .. 66 Figure 2.6. 2: Simplified Gas Side Process Flow Diagram for the Repowering Case ................ 67 Figure 2.6. 3: Repowering Case Steam Cycle Schem atic Diagram ........................................... 69 Figure 2.6. 4: CMB TM 

### Combustor General Arrangement Drawing (Side Elevation).................... 71 Figure 2.6. 5: CMB TM 

### Combustor General Arrangement Drawi ng (Plan Vi ew)........................... 71 Figure 2.6. 6: CMB TM 

### Moving Bed Heat Exchanger Surface Ar rangement ................................ 72 Figure 2.6. 7: Draft System Schematic Diagram......................................................................... 74 Figure 2.6. 8: Existing Sporn Site Plan........................................................................................ 7 5 Figure 2.6. 9: Simplified Gas Side Process Flow Diagram for the Existing Sporn Unit #4 ......... 76 Figure 2.6.10: Existing Sporn Plant Steam Cycle Schem atic Diagram........................................ 77 Figure 2.6.11: Thermal Efficiency Comparis on for the Repo wered and Exis ting Unit ................. 80 Figure 2.7. 1: Boiler Efficiency Comparison for all Cases........................................................... 85 Figure 2.7. 2: Steam Cycle Thermal Effi ciency Comparison for all Cases ................................. 86 Figure 2.7. 3: Total Auxiliary Po wer Comparison fo r all Ca ses................................................... 87 Figure 2.7. 4: Plant Thermal Effici ency Comparison fo r all Cases.............................................. 88 Figure 2.7. 5: Plant CO 2 

### Emission Comparison for all Ca ses ..................................................... 89 Figure 2.7. 6: Net Plant Heat Rates (HHV ba sis) for Subcritical (2,400 psia) Cycles................. 90 Figure 2.7. 7: Net Plant Heat Rates (HHV basis) for Supercritical Cycles.................................. 91 Figure 2.7. 8: CO 2 

### Emissions (lbm/kWh ) – All Ca ses ................................................................. 92 Figure 3.1. 1: EPC Plant Costs – Summary of all Case s............................................................ 97 Figure 3.1. 2: Specific Boil er Costs (Acc ount 4).......................................................................... 99 Figure 3.1. 3: Specific Boiler Isla nd Costs (Accounts 4, 5 an d 7) ............................................. 100 Figure 3.1. 4: Specific Turb ine Costs (Acc ount 8)..................................................................... 101 Figure 3.1. 5: Specific Tu rbine Island Costs (Acco unts 8, 3, 9, and 11)................................... 102ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### Figure 3.1. 6: Specific Other BOP Equipment Co sts (Accounts 1, 2, 10, 12, 13, and 14)........ 102 Figure 4.3. 1: Levelized Cost of Electricity Comparison for Repowering Versus Base Plant (without Emissions So ld or Purchased) ............................................................................... 109 Figure 4.3. 2: Repowering versus Base Case – With NO x 

### Credi ts ........................................... 110 Figure 4.3. 3: Case PC-3 - Ec onomic Sensitivit y Result s ......................................................... 111 Figure 4.3. 4: Case CFB-3 - Ec onomic Sensitivit y Results....................................................... 112 Figure 4.3. 5: Case PC-5 – High Temperature Alloy Sensitivity Results .................................. 113 Figure 4.3. 6: Case CMB TM 

### -5 – High Temperature Allo y Sensitivity Results........................... 114 Figure 4.3. 7: Case Repowe ring – High Temperature Allo y Sensitivity Results ....................... 114 Figure 4.3. 8: Case Repowering – NO x 

### Credit Sensitiv ity Results............................................ 115 Figure 4.3. 9: Case Repowering – Breakdown of COE from NO x 

### Credit Sensitivity Study ...... 116 Figure 4.4. 1: Levelized Cost of Electr icity Comparison for PC and CFB/ CMB TM 

### Cases ........ 117 Figure 4.4. 2: Levelized Cost of Electricity Co mparison for Repo wering versus Base Plant.... 118 Figure 4.4. 3: Effect of Coal Cost on COE for PC Cases.......................................................... 119 Figure 4.4. 4: Effect of Coal Cost on COE for CFB/ CMB TM 

### Cases .......................................... 119 Figure 4.4. 5: Cost of Electricity for PC Power Plant Cases For Different CO 2 

### Emissions Tax Rate ........................................................................................................................... . 120 Figure 5.0. 1: Cost of Electric ity Comparison (All Cases) ......................................................... 122 Figure 5.0. 2: Cost of Electricity Comparison fo r 1.25 and 1.80 $/MM-Btu Fuel Cost – All Cases. ............................................................................................................................ 122 Figure 7.2. 1 Front Arrange ment of 700MW Supercritical CFB Steam Generator................... 156 Figure 7.2. 2 Side Arrangement of 700MW S upercritical CFB St eam Generator.................... 157 Figure 7.2. 3 Plan Arrangement of 700MW S upercritical CFB St eam Generator.................... 158 Figure 7.2. 4 Front Arrange ment of 700MW Subcritica l CFB Steam Generator...................... 159 Figure 7.2. 5 Side Arrangement of 700MW Subcritical CFB St eam Generator....................... 160 Figure 7.2. 6 Side Arrangement of 700MW Subcritical CFB St eam Generator....................... 161 Figure 7.2. 7 Front Arrange ment of 700MW Supercritical CMB Steam Generator.................. 162 Figure 7.2. 8 Side Arrangement of 700MW S upercritical CMB St eam Generator................... 163 Figure 7.2. 9 Plan Arrangement of 700MW S upercritical CMB St eam Generator................... 164 Figure 7.2.10: Philip Sporn Plant - Plan View of Existing Site ................................................... 165 Figure 7.2.11: Topping Steam Turbine fo r Sporn Unit #4 R epowering Case ............................ 166 Figure 7.2.12: Philip Sporn Sectional Side Elevat ion of Steam Generator Repowering Case . 167 Figure 7.2.13: Philip Sporn Front Elevation of Steam Generator Repowering Case................. 168 Figure 7.2. 14: Philip Sporn Plan View of Steam Generator Repowering Case ......................... 169 Figure 7.4. 1: Case PC-1 - 1 x 630 MW PC Fired Steam Plant with SCR Economic Sensitivity Results ........................................................................................................................ .... 194 Figure 7.4. 2: Case PC-2 – 1 x 650 MW PC Fi red Steam Plant with SCR Sensitivity Analysis Results ........................................................................................................................ .... 196 Figure 7.4. 3: Case PC-3 – 1 x 660 MW PC Fi red Steam Plant with SCR Sensitivity Analysis Results ........................................................................................................................ .... 198 Figure 7.4. 4: Case PC-4 – 1 x 680 MW PC Fi red Steam Plant with SCR Sensitivity Analysis Results ........................................................................................................................ .... 200 Figure 7.4. 5: Case PC-5 20 Nickel - 1 x 740 MW PC Fired Steam Plant with SCR and $20 per Pound High Temperature Alloy Econom ic Sensitivit y Result s............................................. 202 Figure 7.4. 6: Case PC-5 $28 Nickel - 1 x 740 MW PC Fired Steam Plant with SCR and $28 per Pound High Temperature Alloy Economic Sensitivity Results....................................... 204 Figure 7.4. 7: Case PC-5 $3 2.9 Nickel - 1 x 740 MW PC Fired Steam Plant with SCR and $32.90 per Pound High Temperature Allo y Economic Sensit ivity Results .......................... 206 Figure 7.4. 8: Case CFB-2 - 1 x 650 MW CFB St eam Plant with SNCR Economic Sensitivity Results ........................................................................................................................ .... 208 Figure 7.4. 9: Case CFB-3 - 1 x 660 MW CFB St eam Plant with SNCR Economic Sensitivity Results ........................................................................................................................ .... 210 Figure 7.4.10: Case CFB-4 - 1 x 680 MW CFB St eam Plant with SNCR Economic Sensitivity Results ........................................................................................................................ .... 212 Figure 7.4.11: Case CMB-3 - 1 x 670 MW CMB St eam Plant with SNCR Economic Sensitivity Results ........................................................................................................................ .... 214ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 xii 

### Figure 7.4.12: Case CMB-5 20 Alloy - 1 x 670 MW CMB Steam Plant with SNCR and $20 per Pound High Temperature Alloy Econom ic Sensitivit y Result s............................................. 216 Figure 7.4.13: Case CMB-5 28 Alloy - 1 x 750 MW CMB Steam Plant with SNCR and $28 per Pound High Temperature Alloy Econom ic Sensitivit y Result s............................................. 218 Figure 7.4.14: Case CMB-5 32.9 Alloy - 1 x 750 MW CMB Steam Plant with SNCR and $32.90 per Pound High Temperature Alloy Economic Sensitivity Results....................................... 220 Figure 7.4.15: Case Base Phillip Sporn Unit 4 – Base Phillip Spor n Unit 4 Economic Sensitivity Results ........................................................................................................................ .... 222 Figure 7.4.16: Case Base Phillip Sporn Unit 4 Purchase NO x 

### Credits – Base Phillip Sporn Unit 4 with Purchase of $5k per Ton NO x 

### Credits Economic S ensitivity Results ........................... 224 Figure 7.4.17: Case Repo wering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with No Emissions Credits Sold and $20 per Pound Hi gh Temperature Alloy Economic Sensitivity Results ........................................................................................................................ .... 226 Figure 7.4.18: Case Repo wering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with No Emissions Credits Sold and $28 per Pound Hi gh Temperature Alloy Economic Sensitivity Results ........................................................................................................................ .... 228 Figure 7.4.19: Case Repo wering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with No Emissions Credits Sold and $32.90 per Pound Hi gh Temperature Alloy Economic Sensitivity Results ........................................................................................................................ .... 230 Figure 7.4.20: Case Repo wering Phillip Sporn Unit 4 – Repowe ring Phillip Sporn Unit 4 with $2k per Ton NO x 

### and $200 per Ton SO x 

### Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity Results................................................................. 232 Figure 7.4.21: Case Repo wering Phillip Sporn Unit 4 – Repowe ring Phillip Sporn Unit 4 with $5k per Ton NO x 

### and $200 per Ton SO x 

### Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity Results................................................................. 234 Figure 7.4.22: Case Repo wering Phillip Sporn Unit 4 – Repowe ring Phillip Sporn Unit 4 with $8k per Ton NO x 

### and $200 per Ton SO x 

### Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity Results................................................................. 236ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 xiii 

### List of Tables

Table 2.1. 1: Site Characteri stics (Greenfie ld Cases)................................................................. 8 Table 2.1. 2: Design Coal Analysis (Medium Vo latile Bituminous) for Greenfield Cases........... 9 Table 2.1. 3: Design Limestone Anal ysis for Greenfield Cases.................................................. 9 Table 2.1. 4: Design Coal Analysis (High Vo latile Bituminous) for Repowering Case.............. 10 Table 2.2. 1: Steam Cycle Condit ions for Greenfie ld Cases..................................................... 12 Table 2.3. 1: Gas Side Material and En ergy Balance for the PC Cases .................................. 20 Table 2.3. 2: EPA Propos ed Mercury Limits ............................................................................. 31 Table 2.3. 3: Stack Design Para meters .................................................................................... 34 Table 2.3. 4: Coal Rece iving Design Summary ........................................................................ 35 Table 2.3. 5: Overall Plant Performa nce Comparison fo r PC Ca ses........................................ 38 Table 2.4. 1: Gas Side Material and En ergy Balance for the CFB Cases ................................ 41 Table 2.4. 2: Overall Plant Performa nce Comparison fo r CFB Cases...................................... 51 Table 2.5. 1: Gas Side Material and Energy Balance for the CMB TM 

### Cases ............................ 54 Table 2.5. 2: Overall Plant Performance Comparison for CMB TM 

### Cases.................................. 63 Table 2.6. 1: Gas Side Material and Ener gy Balance for the Repowering Case...................... 67 Table 2.6. 2: Gas Side Material and Energy Balance for the Existi ng Sporn Unit #4............... 76 Table 2.6. 3: Overall Plant Performanc e Comparison for Repowering Case ........................... 79 Table 2.7. 1: Overall Plant Perfor mance Comparison (all Cases) ............................................ 84 Table 3.0. 1: Operating Labor Require ments............................................................................ 95 Table 3.1. 1: Total Plant Investment Co st Summary for the Greenfield Cases ........................ 97 Table 3.2. 1: Total Plant Investment Co st Summary for the Repowering Case ..................... 103 Table 3.3. 1: Total Plant Operat ing and Maintenan ce Costs .................................................. 105 Table 4.1. 1: Economic Evaluat ion Study Assumptions.......................................................... 107 Table 4.3. 1: Pulverized Coal Systems (PC-1, PC-2, PC-3, PC -4, PC-5) – Economic Analysis Summa ry ........................................................................................................................ .... 108 Table 4.3. 2: CFB and CMB TM 

### Systems (CFB-2, CFB-3, CMB TM 

### -3, CMB TM 

### -4, CMB TM 

### -5) – Economic Analysis Summary............................................................................................... 108 Table 4.3. 3: Repowering System – Economic Analysis Summary ........................................ 109 Table 7.3. 1: Case PC-1 Investme nt Costs............................................................................. 171 Table 7.3. 2: Case PC-1 Oper ating and Maintena nce Costs.................................................. 172 Table 7.3. 3: Case PC-2 Investment Costs............................................................................. 173 Table 7.3. 4: Case PC-2 Oper ating and Maintena nce Costs.................................................. 174 Table 7.3. 5: Case PC-3 Investment Costs............................................................................. 175 Table 7.3. 6: Case PC-3 Oper ating and Maintena nce Costs.................................................. 176 Table 7.3. 7: Case PC-4 Investment Costs............................................................................. 177 Table 7.3. 8: Case PC-4 Oper ating and Maintena nce Costs.................................................. 178 Table 7.3. 9: Case PC-5 Investment Costs............................................................................. 179 Table 7.3.10: Case PC-5 Operat ing and Maintena nce Costs.................................................. 180 Table 7.3.11: Case CFB-2 Investment Costs........................................................................... 181 Table 7.3.12: Case CFB-2 Operat ing and Maintena nce Costs................................................ 182 Table 7.3.13: Case CFB-3 Investment Costs........................................................................... 183 Table 7.3.14: Case CFB-3 Operat ing and Maintena nce Costs................................................ 184 Table 7.3.15: Case CFB-4 Investment Costs........................................................................... 185 Table 7.3.16: Case CFB-4 Operat ing and Maintena nce Costs................................................ 186 Table 7.3.17: Case CMB-3 Investment Costs.......................................................................... 187 Table 7.3.18: Case CMB-3 Operat ing and Maintena nce Cost s............................................... 188 Table 7.3.19: Case CMB-5 Investment Costs.......................................................................... 189 Table 7.3.20: Case CMB-5 Operat ing and Maintena nce Cost s............................................... 190 Table 7.3.21: Sporn Unit #4 Repowe ring Case Invest ment Costs........................................... 191 Table 7.3.22: Sporn Unit #4 Repowering Case Op erating and Maint enance Costs................ 192 Table 7.3.23: Existing Sporn Unit #4 Operating and Mainte nance Co sts................................ 193ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 xiv 

### Table 7.4. 1: Case PC-1 – 1 x 630 MW PC Fi red Steam Plant with SCR Sensitivity Analysis Results ........................................................................................................................ .... 195 Table 7.4. 2: Case PC-2 – 1 x 650 MW PC Fi red Steam Plant with SCR Sensitivity Analysis Results ........................................................................................................................ .... 197 Table 7.4. 3: Case PC-3 – 1 x 660 MW PC Fi red Steam Plant with SCR Sensitivity Analysis Results ........................................................................................................................ .... 199 Table 7.4. 4: Case PC-4 – 1 x 680 MW PC Fi red Steam Plant with SCR Sensitivity Analysis Results ........................................................................................................................ .... 201 Table 7.4. 5: Case PC-5 20 Nickel - 1 x 740 MW PC Fired Steam Plant with SCR and $20 per Pound High Temperature Alloy Econom ic Sensitivit y Result s............................................. 203 Table 7.4. 6: Case PC-5 $28 Nickel - 1 x 740 MW PC Fired Steam Plant with SCR and $28 per Pound High Temperature Alloy Econom ic Sensitivit y Result s............................................. 205 Table 7.4. 7: Case PC-5 $32.9 Nickel - 1 x 740 MW PC Fired Steam Plant with SCR and $32.90 per Pound High Temperature Allo y Economic Sensit ivity Results .......................... 207 Table 7.4. 8: Case CFB-2 - 1 x 650 MW CFB St eam Plant with SNCR Economic Sensitivity Results ........................................................................................................................ .... 209 Table 7.4. 9: Case CFB-3 - 1 x 660 MW CFB St eam Plant with SNCR Economic Sensitivity Results ........................................................................................................................ .... 211 Table 7.4.10: Case CFB-4 - 1 x 680 MW CFB St eam Plant with SNCR Economic Sensitivity Results ........................................................................................................................ .... 213 Table 7.4.11: Case CMB-3 - 1 x 670 MW CMB Steam Plant with SNCR Economic Sensitivity Results ........................................................................................................................ .... 215 Table 7.4.12: Case CMB-5 20 Alloy - 1 x 670 MW CMB Steam Plant with SNCR and $20 per Pound High Temperature Alloy Econom ic Sensitivit y Result s............................................. 217 Table 7.4.13: Case CMB-5 28 Alloy - 1 x 750 MW CMB Steam Plant with SNCR and $28 per Pound High Temperature Alloy Econom ic Sensitivit y Result s............................................. 219 Table 7.4.14: Case CMB-5 32.9 Alloy - 1 x 750 MW CMB Steam Plant with SNCR and $32.90 per Pound High Temperature Alloy Economic Sensitivity Results....................................... 221 Table 7.4.15: Case Base Phillip Sporn Unit 4 – Base Phillip Sporn Unit 4 Economic Sensitivity Results ........................................................................................................................ .... 223 Table 7.4.16: Case Base Phillip Sporn Unit 4 Purchase NO x 

### Credits – Base Phillip Sporn Unit 4 with Purchase of $5k per Ton NO x 

### Credits Economic Se nsitivity Results ........................... 225 Table 7.4.17: Case Repo wering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with No Emissions Credits Sold and $20 per Pound Hi gh Temperature Alloy Economic Sensitivity Results ........................................................................................................................ .... 227 Table 7.4.18: Case Repo wering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with No Emissions Credits Sold and $28 per Pound Hi gh Temperature Alloy Economic Sensitivity Results ........................................................................................................................ .... 229 Table 7.4.19: Case Repo wering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with No Emissions Credits Sold and $32.90 per Pound Hi gh Temperature Alloy Economic Sensitivity Results ........................................................................................................................ .... 231 Table 7.4.20: Case Repo wering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with $2k per Ton NO x 

### and $200 per Ton SO x 

### Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity Results................................................................. 233 Table 7.4.21: Case Repo wering Phillip Sporn Unit 4 – Repowe ring Phillip Sporn Unit 4 with $5k per Ton NO x 

### and $200 per Ton SO x 

### Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity Results................................................................. 235 Table 7.4.22: Case Repo wering Phillip Sporn Unit 4 – Repowe ring Phillip Sporn Unit 4 with $8k per Ton NO x 

### and $200 per Ton SO x 

### Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity Results................................................................. 237ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 xv 

### acfm A ctual cubic feet per minute A NSI A merican National Standards Institute A SME A merican Society of Mechanical Engineers BI Boiler Island BOP Balance of Plant Btu British Thermal Unit CFB Circulating Fluidized Bed cfm Cubic Feet per Minute CMB Circulating Moving Bed CO 2 

### Carbon Dioxide COE Cost of Electricity CS Carbon Steel dB Decibel DCS Distributed Control System DOE/NETL Department of Energy/National Energy Technology Laboratory EPC Engineered, Procured and Constructed ESP Electrostatic Precipitator FBC Fluidized Bed Combustion FD Forced Draft FDA Flash Dryer Absorber FGD Flue Gas Desulfurization FOM Fixed Operation & Maintenance gpm Gallons per minute HHV Higher Heating Value HP High Pressure hp Horse Power hr Hour HT High Temperature HVAC Heating, Ventilating and Air Conditioning Hz Hertz ID Induced Draft in. H 2 

### O Inches of Water in. Hga Inches of Mercury, Absolute IP Intermediate Pressure ISO International Standards Organization kV Kilovolt kWe Kilowatts electric kWh Kilowatt-hour lbm Pound mass LHV Lower Heating Value LP Low Pressure LT Low Temperature MBHE Moving Bed Heat Exchanger MCR Maximum Continuous Rating MWe Megawatt electric 

# ACRONYMS AND ABBREVIATIONSECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 xvi 

### N 2 

### Nitrogen Gas NPHR Net Plant Heat Rate O&M Operation & Maintenance PA Primary Air PC Pulverized Coal PFD Process Flow Diagram ppm Parts per million psia Pound per square inch, absolute psig Pound per square inch, gauge SA Secondary Air TGA Thermo-Gravimetric Analysis TPD Ton Per Day TPH Ton Per Hour TSA Temperature Swing Adsorption UBC Unburned Carbon VOM Variable Operation & MaintenanceECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 xvii 

### Executive Summary
Due to continued higher cost and scarcity of o il and natural gas, and no growth of nuclear power generation, attention has focused on coal as a major energy resource for the nation’s future. However, in search of higher efficiency and lo wer emission, much of this attention has been directed toward second generation technologies such as coal gasification combined cycle and fuel cell systems that utilize hydr ogen derived from coal gasificati on processes or nat ural gas fuel. Other advanced power plant sy stems that in addition to power generation may also generate chemical products have also been emphasized.
Less consideration has been given to potential im provements in conventional coal fired steam power plants, known as Rankine Cycles, that are also capable of high efficiency and lower emissions. These plants utilize pulverized coal or fluidized bed combustion systems.

In view of the possible near-term benefits, a U.S. Department of E nergy/ALSTOM Power Inc. consortium has funded an assessment of Rank ine Cycle power plants equipped with three different combustion systems: Pulverized Coal (PC), Circulat ing Fluidized Bed (CFB), and Circulating Moving Bed (CMB TM 

### ). Five steam cycles utilizi ng a wide range of steam conditions were used with these combustion systems. The pu rpose of this study is to establish through engineering analysis, the most cost-effectiv e performance potential available through improvement in the Rankine Cycle st eam conditions and combustion systems.
ALSTOM managed and performed the subject study from its US Power Plant Laboratories office in Windsor, Connecticut. Participating, as sub- contractors in this effort are Parsons Energy and Chemical Group, from its offices in Wyomis sing, Pennsylvania and American Electric Power (AEP), from its offices in Columbus, Ohio. Th e US Department of Energy National Energy Technology Laboratory provided consultation and f unding. ALSTOM provided cost share to this project.
This report discusses the results of a coal fir ed steam power plant project, which is comprised of two parts. The main part of the study was the an alysis of ten (10) Greenfield steam power plants employing three different coal combustion te chnologies: Pulverized Coal (PC), Circulating Fluidized Bed (CFB), and Circulating Moving Bed (CMB TM 

### ) integrated with five different steam cycles. The study explores t he technical feasibility, therma l performance, environmental performance, and econo mic viability of ten power plants that could be deployed currently, in the near, intermediate, and long-term time frame. For the five steam cycles, main steam temperatures vary from 1,000°F to 1,292°F and pressures from 2,400psi to 5,075psi. Reheat steam temperatures vary from 1,000°F to 1,328°F. The number of feedwater heaters varies from 7 to 9 and the associated feedwater temperature va ries from 500°F to 626°F. The main part of the study therefore determines the steam cycle parameters and combustion technology that would yield the lowest cost of electricity (COE ) for the next generation of coal-fired steam power plants. With respect to environmental performa nce, the Greenfield plants are designed to meet the following emissions performance based on CURC (Coal Utilization Research Council) 2010 targets.

• > 98% sulfur removal

• < 0.05 lbm/MM-Btu NO x



### • < 0.01 lbm/MM-Btu Particulate Matter

• > 90% Hg removal

Mercury control has not been considered in the in vestment costs or economic analysis for this study to simplify the analysis. New mercury contro l technology is currently being developed. It is believed that the investment and operating cost would be relati vely small and approximately the same for PC, CFB, and CMB TM 

### boiler technologies.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 xviii 

### The second part of the study (Repowering) expl ores one means of upgrading the efficiency and output of an older existing coal fired steam po wer plant. There are currently more than 1,400 coal-fired units in operation in the United Stat es generating about 54 percent of the electricity consumed. Many of these are modern units are clean and efficient. Additionally, there are many older units in excellent condition and still in se rvice that could benefit from this repowering technology. The study evaluates the technica l feasibility, thermal performance, and economic viability of this repowering concept.
Primary results for both parts of the study ar e summarized in terms of thermal efficiency, environmental performance, inve stment costs, and cost of elec tricity (COE). The table shown below defines the case studies in terms of steam cycle parameters and combustion technology and the table and associated figures also summariz e the thermal efficiency, investment cost, and COE results for all the cases.

Primary Results Summary: Thermal Efficiency, In vestment Costs, and Cost of Electricity

PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 Repower Existing
Steam Cycle Parameters Main Steam Pressure (psia) 2408 2408 3625 3915 5075 2408 3625 3915 3625 5075 4242 2015 Main Steam Temperature (Deg F) 1000 1049 1049 1085 1292 1049 1049 1085 1049 1292 1292 1050 Reheat Steam Temperature (Deg F) 1000 1112 1112 1148 1328 1112 1112 1148 1112 1328 1000 1000 Feedwater Temperature (Deg F) 500 500 500 554 626 500 500 554 500 626 460 453 Number of Feedwater Heaters (no.) 777897787988
Efficiency and Output Boiler Efficiency (HHV basis) (fraction) 0.8975 0.8975 0.8975 0.8975 0.8975 0.8975 0.8975 0.8975 0.8926 0.8926 0.8873 0.8816

Steam Cycle Efficiency (fraction) 0.4442 0.4543 0.4650 0.4745 0.5161 0.4543 0.4650 0.4745 0.4650 0.5161 0.4604 0.4269 (Btu/kwhr) 7683 7512 7339 7193 6613 7512 7339 7193 7339 6613 7413 7994

Generator Output (kw) 696316 711278 736148 753937 821374 711278 736148 753937 736148 821374 203807 168604

Net Plant Output (kw) 630526 646080 662936 677479 741615 647588 663823 678366 665552 744230 184887 156518

Fuel Heat Input (HHV basis) (MM-Btu/hr) 5812 5812 5812 5812 5812 5812 5812 5812 5844 5844 1643 1496

Net Plant Heat Rate (HHV basis) (Btu/kwhr) 9218 8997 8768 8580 7838 8976 8756 8568 8781 7853 8889 9561 Thermal Efficiency (HHV basis) (fraction) 0.3702 0.3794 0.3893 0.3978 0.4355 0.3803 0.3898 0.3983 0.3887 0.4346 0.3840 0.3570

Costs and Economics Investment Costs ($/kWe net) 1,139 1,126 1,109 1,098 1,168 1,051 1,038 1,039 1,018 1,039 413 n/a

Levelized Cost of Electricity (Cents/kWh) 3.96 3.89 3.82 3.76 3.77 3.62 3.56 3.53 3.52 3.41 2.76 2.29



### For the ten Greenfield cases, the calculated th ermal efficiencies (HHV basis) range from 37.02% to 43.55%. With respect to thermal efficiency, for the same steam conditions, there is little difference when comparing among the combustion systems (PC, CFB, and CMB TM 

### ) as would be expected. In general the thermal efficiency of the PC fired systems are about the same as for the CFB based systems. The CFB and PC systems thermal efficiency are about 0.1 percentage points higher than the CMB TM 

### systems which is due to only partial sulfation in the CMB TM 

### combustor. The effect of the increasing st eam cycle parameters (Tem perature and Pressure) is also clearly illustrated.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 xix 

### Plant Thermal Efficiencies (HHV Basis) – All Cases

0.3702 0.3794 0.3893 0.3978 0.4355

0.3803 0.3898 0.3983

0.3887 0.4346

0.3840

0.3570

0.30 0.32 0.34 0.36 0.38 0.40 0.42 0.44 0.46

PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 Repower ExistingThermal Efficiency - HHV (fraction)



### The specific investment cost results for the Gr eenfield cases are shown in the table above range from about 1,018 to 1,168 $/kW-net. For the same steam conditions, the CMB TM 

### combustion system plants require the lowest investment co sts as compared to PC or CFB plants. This cost advantage increases as steam cycle conditions (T emperature and Pressure) are raised. The CFB systems are about 70 $/kW lower in cost than t he PC type combustion systems. This difference is primarily attributable to the differences in the costs for the gas cl eanup system equipment.

Plant Investment Costs ($/kW - EPC Basis) – All Cases

1,139 1,126 1,109 1,098 1,168

1,051 1,038 1,039 1,018 1,039

413

0 0 200 400 600 800 1000 1200 1400

PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 Repower ExistingPlant Investment Costs - EPC Basis ($/kW-net )ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 xx 

### The levelized cost of electricity (COE) results fo r the Greenfield cases shown in the table above range from about 3.4 to 4.0 Cents/kWh. These results indicate that Case CMB TM 

### -5 is the most economical from a COE basis. Compared to Case PC-5 it requires significantly less weight of very expensive Ni alloy tubing. The effect of in creased steam conditions on COE is also shown in the graph below with the increased steam cond itions offering a slight advantage. For the same steam conditions there is very little difference in the COE between CFB and CMB TM 

### designs.

Similar to the investment cost results, the PC cases are about 7% higher than the CFB type combustion systems with respect to COE at t he same steam conditions. The advantage of the CFB systems is attributable to the investment co st savings discussed above. Because of the additional reduction in investment cost associated with CMB TM 

### based systems, the CMB TM 

### combustion system offers a COE advantage as compared to PC of about 8-10% (greater advantage at higher steam conditions) and about 1% as compared to CFB type combustion systems.

Cost of Electricity (Cents/kWh) – All Cases

3.96 3.89 3.82 3.76 3.77 3.62 3.56 3.53 3.52 3.41

2.76

2.29

0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 4.50

PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 Repower ExistingCost of Electricity - (Cents/kwhr)



### The cost of electricity is directly related to t he cost of fuel. The above COE’s are calculated for the price of fuel of $1.25/MBtu. As the cost of fuel increases, as shown in the figure below, the cost of electricity increases also and at the same time the economics continue to shift towards the more efficient power plant systems. For example, at a of coal price of $1.80 MM-Btu the COE is the lowest for the ultra-supercritical case PC -5 among the PC power plant cases. The ultrasupercritical CMB-5 continues to offer the lo west COE among the power plant cycles analyzed.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 xxi 

### Cost of Electricity Comparison for 1.25 and 1.80 $/MM-Btu Fuel Cost – All Cases

4.46 4.39 4.30 4.23 4.21 4.12 4.04 4.00 4.00 3.84

3.24

2.80

0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 4.50 5.00PC-1PC-2PC-3PC-4PC-5CFB-2CFB-3CFB-4CMB-3CMB-5RepowerBase $1.25 per MMBtu ($1.27 per MMBtu for Sporn Plant) $1.80 per MMBtu



### The following figure shows a comparison of specific CO 2 

### emissions (lbm/kWh) for all the cases. This figure, in combination with the thermal efficiency results shown above, shows the direct correlation of CO 2 

### emissions and plant thermal efficiency. For example, Case PC-5 is about 18% more efficient than Case PC-1 and it also emits about 18% less CO 2 

### per kWh of net output.

CO 2 

### Emissions (lbm/kWh) – All Cases

1.893

1.847

1.800

1.762

1.609 1.843

1.798

1.759 1.803

1.612 1.803 1.939

1.50 1.55 1.60 1.65 1.70 1.75 1.80 1.85 1.90 1.95 2.00

PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 Repower ExistingCO2Emissions - (lbm/kwhr)



### The study has also investigated the impact of potential taxes placed on CO 2 

### emissions. The figure below illustrates t he changes in the COE as the potenti al tax increases for the PC power plant cases. As expected, the COE increases significantly with the increase in the tax. The figure also shows that the tax would become a major driver in utility companies selection process of the power plant cycle parameters and the high efficiency plants would become the technologies of choice.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 xxii 

### Cost of Electricity for PC Power Plant Cases For Different CO 2 

### Emissions Tax Rate

3.0 4.0 5.0 6.0 7.0 8.0 9.0

0 10 20 30 40 50 CO2 Tax ($/Ton CO2)Cents/kwhr PC-1 (2400/1000/1000)

PC-2 (2400/1049/1112)

PC-3 (3625/1049/1112)

PC-4 (3915/1085/1148)

PC-5 (5075/1292/1328)



### For the Repowering Case, CMB combustion tech nology was selected because of its economic advantage for high temperature cycles. The calculated thermal efficiency (HHV basis) is improved from 35.70% for the existing unit to 38. 40%. The investment costs necessary for all the equipment required for this repowering project is 413 $/kW-net and the resulting incremental cost of electricity is calculated to be 0.47 Cents/ kWh (2.76 - 2.29 Cents/kWh). Incremental cost is calculated relative to the unmodified existing uni t. This difference may quickly disappear if the price of NO x 

### credits continues to increase and/or a major capital investment is required to refurbish the existing boiler or if there is loss of availability caused by the aging equipment. CO 2 

### emissions are decreased from about 1.94 to 1. 80 lbm/kWh, a reducti on of about 8 percent.
In summary, from the results of the study the evaluated power plan t systems fall either into the near term or long term category with respec t to technology implementation. All combustion technologies can achieve low levels of pollutants and comply with the CURC 2010 air pollution targets. Technology is available to day to facilitate constr uction of all the PC cycles, except for the ultra-supercitical steam conditions of Case PC -5, and all the CFB steam cycles. Technology is being developed to enable market introduction of Case PC-5 and both CMB TM 

### cycles in a 10 to 15 year timeframe. The very high steam temperat ures of the ultra-supecritical steam cycle do not appear to be practical for conventional CFB technology where combustion temperature is generally limited to 1,550 0 

### F. CMB TM 

### technology with the combustion temperature of 2000 0 

### F allows greater latitude in selecting the range of steam cycle parameters. The ultra-supecritical CMB TM 

### design offers the prospect of the lowest COE.
The CFB power plants are the technology of choice for high sulfur coals. For low sulfur coals the PC power plants that don’t requi re installation of the back end NO x 

### and SO x 

### control technologies would be favored. The supercritical CFB plants have the lowest cost of electricity and its cost continues to improve for higher steam conditions.

Building up on these results, the next step in t he development effort of the Rankine power plant cycle is recommended. It should include a CFB design with steam conditions of 4,000 psi to 5000 psi and main and reheat steam te mperatures of approximately 1,200 0 

### F. The potential plant efficiency improvement would be significant and the efficiency should be in the range of 41-42% (HHV basis). These steam conditions may require some CFB process modifications to enable the higher steam temperatures but would represent the upper limit for conventional boiler alloys.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 xxiii 

### Such a design would fulfill the promise of high effi ciency and low cost of the intermediate term (3 to 5 years) power plant cycle.

Based on reliability, investment costs, emissions and cost of electricity a coal fired steam power plant will continue to be a good investment for power plant owners especially compared to other options such as IGCC for coal powered electric power production. The thermal efficiencies of today’s steam power plants with supercritical steam cycles are higher than today’s IGCC plants. For power plants of the future, studies show that coal fired steam plants with ultra-supercritical steam cycles will maintain this efficiency advan tage over future IGCC plants with advanced gas turbines. (MARION,10)ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 1 

## 1. Introduction

Because of continued higher cost and scarcity of oil and natural gas, and no growth of nuclear power generation, attention has focused on coal as a major energy resource for the nation’s future. However, in search of higher efficien cy and lower emission, much of this attention has been directed toward second-generation technologies. These technologies include coal gasification combined cycles, fuel cells that utilize hydrogen derived from coal gasification or natural gas fuel, and other advanced power plant systems that in addition to power generation may also generate chemical products.
Less consideration has been given to potential im provements in conventional, pulverized, and fluidized bed coal fired steam power plants, know n as Rankine Cycles, that are also capable of high efficiency and lower emission. A typical Ra nkine Cycle steam power plant configuration is shown in Figure 1.0.1.

IP

COND A LP

A

BFPT HP

Steam Generator Air Heater ESP ID Fan FGD

Steam Coils

Stack

FD Fan Steam Coils

BFP 

### Figure 1.0. 1: Simplified Diagram of a Rankine Cycle Steam Power Plant

In view of the possible near-term benefits, a U.S. Department of E nergy/ALSTOM Power Inc. consortium has funded an economic and technical feasibility assessment of a wide range of Rankine Cycles equipped with three different combustion systems: Pulverized Coal (PC), Circulating Fluidized Bed (CFB), and Circulating Moving Bed (CMB TM 

### ). The purpose of this study is to establish through engineering analysis, the most cost-effectiv e performance potential available through improvements in the steam conditions of the Rankine Cycle.
Specific project objectives are listed below:

• Determine the thermal efficiency, investm ent costs, and economi c improvements of the Rankine Cycle Steam Power Plant as a function of steam conditions.

• Identify state-of-the-art power plant systems, which are available in the market place today, in the near term, and long term future.

• Compare the economics of a nominal 7 00MW Rankine Cycle for the same steam conditions applying PC, CFB, and CMB TM 

### combustion technologies.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 2 

### The results of this study are based on a multi-step process that considers:

• Thermodynamic performance (Plant Thermal Efficiency)

• Equipment design, selection, and pricing (EPC basis)

• Economic Analysis (Cost of Electricity)

Historical Experience: The modern Rankine Power Plant is the produc t of over 100 years of design developments and improvements. In 1900 typical steam conditions were 180 psig and 350°F with heat rates around 35,000 Btu/kWh. Reheat cycles were first used during the 1920’s. During the 1940’s steam conditions reached 1,500psig and 1,000/1,000°F. The 1950’s saw the progress culminate with the introduction of double reheat utilizing 5,000p sig throttle pressure and steam temperatures of 1,200/1,050/1,050°F at the E ddystone 1 unit of the Philadelphia Electric Company.

The throttle conditions at Eddystone 1 have been decreased somewhat due to material creep and coal ash corrosion problems, but the unit still maintains 4,700psig and 1,125°F throttle conditions, higher than any other unit in the US , after about 45 years of operation.
Since the early 1960’s for a variety of reas ons, advanced steam conditions have not been pursued in the domestic market. There was littl e motivation to continue lowering heat rates of fossil-fired plants because of the expected increa se in nuclear power generation for base load application and the availability of re latively inexpensive fossil fuels.

However, due to recent increases in fuel pric es and environmental concerns, plant heat rate is beginning to play a greater role in the utility companies’ decision in selecting the most cost effective and environmentally friendl y steam plant cycle. The corollary of higher efficiency is lower fuel consumption and lower emissions for the same unit of electrical output. It also means that for every pound of coal, which doesn’t hav e to be burned, there is a pound of coal that doesn’t need to be purchased, transported, stored a nd pulverized. If that coal is not burned it is not necessary to collect and dispose of combustion residues. As a direct function of efficiency, CO 2 

### emission, which is believed to be a contributor to global warming, is reduced in proportion to improved efficiency, as are NO x 

### and SO x 

### emissions, which are contributors to acid rain. Particulate matter, VOC, CO, and trace metal emissions are similarly reduced.

Methodology and Design Parameters: This study is based on ALSTOM’s previous work (Palkes, Liljedahl, Kruger, Weirich; 1999), which examined power plant parameters that would produce the lowest cost of electricity (COE) for the next generation pulverized coal-fir ed steam power plants. A total of 25 different design cases, each with 700 MWe nominal capacity were examined in the previous study.
The current study has updated the results of t he previous work and expanded it to include an ultra-high steam conditions power plant cycle. A dditionally, the current study also investigates three different coal combustion systems. The following list shows a comparison of the range of steam conditions and other plant paramete rs for the previous and current study.
Previous Study Current Study

• Live steam pressure: 2,408 - 3,915psi 2,408 – 5,075psi

• Live steam temperatures: 1,000°F - 1,090°F 1,000°F - 1,292°F

• Reheater temperatures: 1, 000°F - 1,153°F 1,000°F - 1,328°F

• Feedwater final temperatures: 482°F - 572°F 500°F - 626°F

• Reheater pressures between 527 - 798psi 703 – 1,054psi

• Number of feedwater preheaters: 7 – 8 7 – 9

• Combustion System: PC PC, CFB, CMB TMECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 3 

### This project represents a coal fired steam power plant project, which is comprised of two main parts. The first part of the study is an analysis of ten (10) Greenfield plants utilizing a wide range of steam cycle parameters and three different comb ustion systems. The second part of the study (Repowering) explores one means of upgrading the efficiency and output of an older existing coal fired steam power plant.
Greenfield Plants Study: The first part of the project, which represents the majority of the effort, is an assessment of ten (10) different Greenfield power plant system s with ~700-820 MWe generator output capacity. Although the generator outputs vary, the heat input to the steam cycles (i.e. boiler heat output) is the same for all cases. These ten plants encomp ass a matrix of plant designs incorporating a wide range of steam cycle parameters and three different combustion systems.
Five steam cycles are used among the ten Greenfie ld cases. Steam turbine design conditions for these five steam cycles (designated Steam Cycle 1-5) are shown below and range from conditions widely used today to conditions envisioned applicable for power plants of the future.
Steam Cycle Design Conditions:

• Steam Cycle #1; 1,000°F/1,000°F/2,408 psia

• Steam Cycle #2: 1,049°F/1,112°F/2,408 psia

• Steam Cycle #3: 1,049°F/1,112°F/3,625 psia

• Steam Cycle #4; 1,085°F/1,148°F/3,915 psia

• Steam Cycle #5; 1,292°F/1,328°F/5,075 psia

Each case selected utilizes one of the five steam cycles, listed above, integrated with one of three coal combustion systems: Pulverized Coal (PC) , Circulating Fluidized Bed (CFB), and Circulating Moving Bed (CMB TM 

### ). The case identification acronym used for all the Greenfield cases is comprised of two or three letters, which identify the type of combustion system (i.e. PC, CFB, or CMB TM 

### ), combined with a single numb er, which identifies the steam cycle used (i.e. 1, 2, 3, 4, or 5). For example, Case PC-3 indicates a pulveriz ed coal combustion system combined with the # 3 steam cycle (i.e. 1,049°F/1,1 12°F/3,625 psia) as listed above.

Five of the ten Greenfield cases selected incl ude pulverized coal (PC) fired steam generators equipped with low NO x 

### tangential firing systems. These five PC cases utilize all five of the above identified steam cycles, which pr ovide discretely different st eam conditions, thermodynamic performance, and equipment design. Additionally three cases are selected with CFB and two cases are selected with CMB TM 

### combustion systems.
The five Greenfield PC cases are listed below showing the design steam conditions.

• PC-1 ; 1,000°F/1,000°F/2,408 psia

• PC-2 : 1,049°F/1,112°F/2,408 psia

• PC-3 : 1,049°F/1,112°F/3,625 psia

• PC-4 ; 1,085°F/1,148°F/3,915 psia

• PC-5 ; 1,292°F/1,328°F/5,075 psia
Additionally, three Greenfield cases were select ed with circulating fluidized bed (CFB) steam generators designed to produce the following steam conditions:

• CFB-2 ; 1,049°F/1,112°F/2,408 psia

• CFB-3 ; 1,049°F/1,112°F/3,625 psia

• CFB-4 ; 1,085°F/1,148°F/3,915 psiaECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 4 

### The final two cases included in the first part of the study are two Greenfield cases with the following steam conditions selected for plant s equipped with advanced circulating moving bed (CMB TM 

### ) steam generators:

• CMB TM 

### -3 ; 1,049°F/1,112°F/3,625 psia

• CMB TM 

### -5 ; 1,292°F/1,328°F/5,075 psia
ALSTOM has been pursuing the development of CMB TM 

### technology for the past few years. Significant progress has been made in understanding combustion and heat transfer processes unique to the CMB TM 

### technology.
All power plant cases examined in the first par t of the study are designed for several common parameters including the same boiler heat outpu t, fuel analysis, limestone analysis, ambient conditions, condenser pressure, etc. These plants produce net plant outputs of about 630-750 MWe. The heat input into the steam turbines (i.e. heat output from the steam generators) is maintained constant for all cycles independent of the steam parameters to simplify thermodynamic and economic analyses. The resulting fuel heat input to the boilers is also nearly equivalent for all the Greenfield cases.
A number of major components and systems requi re design modifications due to changes in steam conditions. They are the steam turbine, generator, steam generator, high-pressure piping and fittings in accordance with pressure and temperature, feedwater pumps, high-pressure feedwater train, condenser and cooling water system, and the accessory electric plant. The designs also reflect differences between subcri tical drum-type and once-through supercritical units, which employ different water treatment systems. A condensate polishing system is required for the supercritical plants.

Depending on the combustion technology employ ed, the steam generator designs and their auxiliary components will be different. The designs account for inherent differences in coal combustion, NO x 

### particulate control, and sulfur control processes.

Environmental concerns are addressed in the designs also. With respect to environmental performance, the Greenfield plants are designed to meet the following emissions performance based on CURC (Coal Utilization Rese arch Council) 2010 targets.

• > 98% sulfur removal

• < 0.05 lbm/MM-Btu NO x



### • < 0.01 lbm/MM-Btu Particulate Matter

• > 90% Hg removal

Mercury control has not been considered in the in vestment costs or economic analysis for this study to simplify the analysis. New mercury contro l technology is currently being developed. It is believed that the investment and operating cost would be relati vely small and approximately the same for PC, CFB, and CMB TM 

### boiler technologies.
Repowering Study: The second part of the study (Repowering) expl ores one means of upgrading the efficiency and output of an older existing coal fired steam powe r plant. In this part of the study, one candidate case, Unit #4 of the Philip Sporn plant (~ 169 MWe gross output) owned and operated by American Electric Power (AEP), is bei ng analyzed for a re powering scenario.
The proposed repowering concept uses a number of new plant components integrated with the existing plant components to the maximum extent pr actical. The repowered plant includes a new CMB TM 

### boiler. It also includes a new topping steam turbine that expands steam from the new CMB TM 

### boiler at 1,292°F/4,337psia to the steam conditions of 1,050°F/2,015psia, which match the throttle conditions of the existing steam turbine.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 5 

### The scope of this second part of the study is to determine the overall thermal performance, investment cost, and incremental cost of electric ity for repowering the plant to operate at these higher steam conditions. The incremental cost of electricity is incremen tal as compared to the unmodified Sporn Unit #4 Plant. For the repowering case, due to the limited framework of this study, it was agreed that no additional emissi on control system would be installed and at a minimum, the current air emission standards would be maintained. However, the CMB TM 

### boiler produces inherently low NO x 

### emissions. It is capable of 0.10 lbm/MM-Btu NO x 

### emission without SNCR as compared to the existing unit emission of 0.57 lbm/MM-Btu. Since NO x 

### emissions are a tradable commodity, particularly during the five-month ozone season when NO x 

### emission is limited to 0.15 lbm/MM-Btu, the economic analysis (Section 4) includes NO x 

### trade allowances.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 6 

## 2. Case Studies; Plant Perfo rmance, Design and Equipment This section of the report provides detailed de scriptions of all the study cases (Greenfield and Repowering), the design basis, and the various processes used for each of the cases analyzed. The equipment used for these pr ocesses is also described. Additionally, the overall plant performance of each case is also presented in terms of performance summary tables.
A total of eleven (11) case studies were analyzed in this two-part evaluation. The first part of the study, which represents the main e ffort of the study, is an evaluati on of ten (10) Greenfield power plants. The second part of the study is a single case that evaluates the viability of repowering an existing coal fired steam plant to higher steam conditions.
The first part of the study evaluates ten (10) Greenfield cases ranging from ~700-820 MWe gross output. These cases are subdivided into three dist inct groups, which utilize different Boiler Island systems for combustion of the coal. The first group includ es five (5) cases, which utilize Pulverized Coal (PC) fired boilers and a wide range of steam conditions. The second group includes three (3) cases, which utilize Circulating Fluidized Bed (CFB) boilers and three of the same steam cycles used in the first group. The third group includes two (2) cases, which utilize advanced Circulating Moving Bed (CMB TM 

### ) boilers and two of the same steam cycles used in the PC group. One of the steam cycles used in the CMB TM 

### group is also common with one of the CFB group steam cycles. All of the steam cycles for these 10 cases require the same heat input from the boiler. To summarize the Greenfield case studies, a total of five steam cycles were used with three combustion systems. All five steam cycles were not used for each combustion system group. The selection of these cases allows a common basis comparison of both coal combustion system and steam cycle parameters.
The second part of the study evaluates a repowering scenario (~205 MWe gross output), which addresses the need for improved perf ormance for the large fleet of existing older coal fired power plants. The Philip Sporn plant, owned by Americ an Electric Power (AEP), is being analyzed to estimate the performance and cost of repowering t he plant to operate at higher steam conditions. The steam conditions for the topping steam turbine are 4,242 psia / 1,292°F inlet and 2,016 psia /1,050°F exhaust. The topping turbine exhausts into the existing steam turbine inlet. The existing steam turbine has conditions of 2,000 psia, 1, 050°F with reheat steam at 500 psia and 1,000°F. Because this case represents a site specific r epowering evaluation, the results are not directly comparable to the ten Greenfield cases in the first part this study.



### 2.1 Plant Design Basis and Scope: All of the plants designed for this conceptual level study, except for the repowering case, are assumed to be located on a common Greenfield site, and are assumed to be operated under common conditions of fuel, limestone, utility and environmental standards. This section is intended to describe the common parameters, the host site conditions, the scope of the cost estimate, and other items, which will be used as a common design basis for all these plants.

Common Parameters: All of the Greenfield plants were designed for t he identical coal and limestone analyses, ambient conditions, site conditions, etc. such that each case study provides results which are directly comparable, on a common basis, to all other cases analyzed within this work. Additionally, all cases (except for the repowering case) were de signed for a constant heat input to the steam cycles (i.e. boiler heat output). The ambient condi tions used for all material and energy balances were based on the standard American Boiler Manufacturers Association (ABMA) atmospheric conditions (i.e. 80 °F, 14.7 psia, 60 percent relative humidity). Many other items were common between cases such as the site, plant services, etc. as described below.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 7 

### Plant Site and Scope: The generic plant site, which is common to all study cases, is assumed to be located in the Gulf Coast region of southeastern Texas. The site consists of approximately 300 usable acres within 15 miles of a medium-sized metropolitan area, with a well-established infrastructure capable of supporting the required construction work force. The area immediately surrounding the site has a mixture of agricultural and light industrial uses. The site is served by a river of adequate quantity for use as makeup cooling water with minimal pretreatment and for the receipt of cooling system blowdown discharges.
A railroad line suitable for unit coal trains passes within 2-1/2 miles of the site boundary. A welldeveloped road network serves the site, capa ble of carrying AASHTO H-20 S-16 loads and with overhead restriction of not less th an 16 feet (Interstate Standard).
The site is on relatively flat land with a maximum difference in elevation within the site of about 30 feet. The topography of the area surrounding t he site is rolling hills, with elevations within 2,000 yards not more than 300 feet above the site el evation. The site is within Seismic Zone 1, as defined by the Uniform Building Code. The following list further describes the assumed site characteristics.

• The site is Greenfield with no existing improvements or facilities.

• The site is relatively clear and level with no characteristics that would cause any unusual construction problems.

• The structural strength of the soil is adequate for spread footings (no piling is required) at this site.

• No rock excavation is required on this site.

• An abundant sub-surface water supply is assumed available on this site.
The boundary limit for these plant s includes the complete plant facility within the “fence line”. It encompasses all equipment from the coal pile to the busbar and includes the coal receiving and water supply systems and terminates at the high -voltage side of the main power transformers. The scope of supply is further defined by the following list.

• Site preparation and site improvements

• Foundations, buildings, and structures required for all plant equipment and facilities

• General support facilities for admi nistration, maintenance, and storage

• Coal and limestone receiving, storage, and handling systems

• Boiler Island from coal feed through gas cleanup system including associated solids handling systems

• Power block, including steam turbine, heat rejection, and makeup water systems

• Plant electrical distribution, lighting, and communication systems

• High-voltage electrical system through step-up transformer

• Instruments and controls

• Miscellaneous power plant equipment
The electrical facilities within the plant scope include all switchgear and control equipment, generator equipment, station service equipment, conduit and cable trays, all wire and cable. It also includes the main power transf ormer, foundations, and standby equipment.
Additionally, the following utilities are assu med to be available at the site boundary.

• Communication lines

• Electrical power for plant construction

• Potable water and sanitary sewer connections

• Electrical transmission facilities and linesECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 8 

### Plant Ambient Design Conditions: Table 2.1.1 lists ambient and other relevant char acteristic assumptions for this site. The ambient conditions used for all material and energy balances were based on the standard American Boiler Manufacturers Association (ABMA) atmospheric conditions (i.e. 80°F, 14.7 psia, and 60 percent relative humidity).
All steam cycles for the Greenfield cases used a condenser pressure of 2.5 inches of mercury (absolute) as shown in Table 2.1.1. The r epowering case used a condenser pressure of 1.6 inches of mercury per actual site operating conditions. For equipment sizing, the maximum dry bulb temperature is 95°F, and the minimum dry bulb temperature for mechanical design is 20°F.

Table 2.1. 1: Site Characteristics (Greenfield Cases) Design Parameter V alue Elevation (ft) 500 Design Atmospheric Pressure (psia) 14.7 Design Temperature, dry bulb ( o 

### F) 80 Design Temperature, wet bulb ( o 

### F) 52 Design Relative Humidity (percent) 60 Design Condenser Pressure (in Hga) 2.5 Ash Disposal Off Site Water Source River



### Consumables: Table 2.1.2 shows the design coal analyses (Ultimate, Proximate and Higher Heating Value) used for all Greenfield cases. The coal is classified as a medium volatile bituminous coal. Table 2.1.3 shows the design limestone analysis used for the PC, CFB, and CMB TM 

### study cases.
Table 2.1.4 shows the design coal analyses (Ultimate, Proximate and Higher Heating Value) used for the Repowering case. The coal is classified as a high volatile bituminous coal. Limestone was not used in the repowering case except as part of a parametric economic analysis included in Section 4. For this case the limestone analysis was assumed as shown in Table 2.1.3.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 9 

### Table 2.1. 2: Design Coal Analysis (Medium Volatile Bituminous) for Greenfield Cases
Ultimate Analysis Constituent (Units)
O2 

### (wt. frac.) 0.0316

N2 

### " 0.0146
H2O 

### " 0.0399

H2 

### " 0.0357
Carbon 

### " 0.6205
Sulfur 

### " 0.0234
Ash 

### " 0.2343 Total 

### " 1.0000

Proximate Analysis Constituent (Units)
Fixed Carbon 

### (wt. frac.) 0.5483
Volatile Matter 

### " 0.1775
Moisture 

### " 0.0399
Ash 

### " 0.2343 Total 

### " 1.0000

HHV Coal 

### (Btu/lbm) 11074



### Table 2.1. 3: Design Limestone Analysis for Greenfield Cases

Constituent (Units) Value CaCO 3 

### (wt. frac.) 83.71
Moisture 

### " 1.00 Impurities 

### " 7.08 MgCO 3 

### " 8.21
Total 

### " 100.00ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 10 

### Table 2.1. 4: Design Coal Analysis (Hi gh Volatile Bituminous) for Repowering Case

Constituent (Units) Value O2 

### (wt. frac.) 7.12
N2 

### " 1.49
H2O 

### " 7.55
H2 

### " 4.58
Carbon 

### " 66.96
Sulfur 

### " 1.00
Ash 

### " 11.30
Total 

### " 100.00

Constituent (Units) Value Fixed Carbon 

### (wt. frac.) 49.15
Volatile Matte r 

### " 32.00
Moisture 

### " 7.55
Ash 

### " 11.30
Total 

### " 100.00

HHV Coal 

### (Btu/lbm) 12100



### Plant Services: The following services and support systems are avail able at the plant as a part of the balance-ofplant systems.
Auxiliary Power Systems:

• 7,200 V system for motors above 3,000 hp.

• 4,160 V system for motors from 250 to 3,000 hp.

• 480 V system for motors from 0 to 250 hp and miscellaneous loads.

• Emergency diesel generator (480 V) to supply loads required for safe and orderly plant shutdown. Instruments and controls and other loads requiring regulated (1-percent) 208/120 Vac power are supplied from this source.

• 250 Vdc system motors and, via static inverter s, uninterruptible ac power for the integrated control and monitoring system, intercommunication.

• 125 Vdc system for dc controls, emergency lighti ng, and critical tripping circuits including the plant shutdown system.
Cooling Water:

• Cooling water (from the cooling towers) is available at between 20 and 30 psig, 90 ° F maximum temperature. The water is periodically chlorinated, and pH is maintained at 6.5 to 7.5. The cooling towers receive makeup water from the river.

• Auxiliary cooling water, which uses de-mineralized water treated for corr osion control, at 60 to 80 psig and 105 ° F, is available for small heat loads (e.g., control oil coolers). The pH is maintained at about 8.5.
Compressed Air:

• Instrument air filtered and dried to -40 ° dew point at 80 to 100 psig and 110 ° F (maximum).

• Service air at 80 -100 psig and 110 ° F (maximum).

Lube Oil:

• Lube oil from the conditioning system, with particulate matter removed to 10 μ m or lower.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 11 

### Hydrogen and Carbon Dioxide:

• H 2 

### and CO 2 

### for generator cooling and purging from storage.

Nitrogen:

• N 2 

### for equipment blanketing against corrosion during shutdown and lay-up.

Raw Water:

• Filtered river water. Additional water treat ment will be included for potable water, etc.

Structures and Foundations: Structures are provided to support and permit ac cess to all plant components requiring support to conform to the site criteria. The structure(s) ar e enclosed if deemed necessary to conform to the environmental conditions.
Foundations are provided for the support struct ures, pumps, tanks, and other plant components. A soil-bearing load of 5,000 lbm/ft 2 

### is used for foundation design.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 12 

### 2.2 Steam Cycles for the Greenfield Cases

Five steam cycles were selected for the ten Gr eenfield cases. These cycles (~700-820 MWe gross output) have discretely different stea m conditions, thermodynamic performance, and equipment design. Steam turbine design conditio ns for these five steam cycles are shown in Table 2.2.1 and range from conditions widely used today to conditions expected for the power plants of the future.

Table 2.2. 1: Steam Cycle Conditions for Greenfield Cases

Superheater Outlet Temperature Reheater Outlet Temperature Main Steam Pressure Feedwater Temperature Number of Feedwater

Heaters (Deg F) (Deg F) (psia) (Deg F) (no.) 1 PC-1 1000 1000 2408 500 7 2 PC-2, CFB-2 1049 1112 2408 500 7 3 PC-3, CFB-3, CMB-3 1049 1112 3625 500 7 4 PC-4, CFB-4 1085 1148 3915 554 8 5 PC-5, CMB-5 1292 1328 5075 626 9 (1)
(1) This steam cycle includes a topping desuperheater in addition to the 9 feedwater heaters Case Identification Acronym Steam Cycle Identification Number



### 2.2.1 General Steam Cycle Description Each steam cycle starts at the condenser hot we ll, which is a receptacle for the condensed steam from the exhaust of the steam turbine. The co ndensate flows to the suction of the condensate pumps, which increase the pressure of the fl uid and transport it through the piping system, and low-pressure feedwater heaters (LPFWH’s) and enable it to enter the open contact heater, or deaerator. The condensate passes through a gland steam condenser (GSC) first, followed in series by four or five (depending on steam cycl e) low-pressure feedwater heaters. Steam Cycle #5 utilizes five LPFWH’s whereas all the other st eam cycles use four. The heaters successively increase the condensate temperature by condens ing and partially sub-cooling steam extracted from the LP steam turbine section. Each heat er receives a separate ex traction steam stream at successively higher pressure and temperature. The condensed steam (now referred to as heater drains) is progressively passed to the next lower pr essure heater, with the drains from the lowest heater draining to the condenser.
The condensate entering the deaerator is heated and stripped of non-condensable gases by contact with the steam entering the unit. The steam is condensed and, along with the heated condensate, flows by gravity to a deaerator storage tank. The boiler feedwater pumps take suction from the storage tank and increase the fluid pressure. Both the condensate pump and boiler feed pump are electric motor driven. The boosted condensate flows through three more high-pressure feedwater heater s, increasing in temperature and then enters the boiler economizer section. Each heater receives a separate extraction steam stream at successively higher pressure and temperature. The condensed steam (drains) is progressively passed to the next lower pressure heater, with the drains from the lowest heater draining to the deaerator.
Within the boiler the feedwater is evaporat ed and finally superheated. The high-pressure superheated steam leaving the finishing supe rheater is expanded through the high-pressure turbine. The exhaust from the high-pressure turbine is reheated and returned to the intermediate pressure turbine. The reheated steam expand s through the intermediate and low-pressure turbines before exhausting to the condenser. The condenser pressure used for all cases in this study was 2.5 in Hga.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### These five steam cycles are shown schematically in Figures 2.2.1 – 2.2.5. All five of these cycles are used for the PC cases. Additionally, four of these steam cycles are also used in either the CFB and/or CMB TM 

### cases as indicated in the table above.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### Figure 2.2. 1: Steam Cycle #1 Schematic and PerformanceECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### Figure 2.2. 2: Steam Cycle #2 Schematic and PerformanceECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### Figure 2.2. 3: Steam Cycle #3 Schematic and PerformanceECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### Figure 2.2. 4: Steam Cycle #4 Schematic and PerformanceECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### Figure 2.2. 5: Steam Cycle #5 Schematic and PerformanceECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### 2.2.2 Steam Cycle Equipment This section provides a brief description of t he major equipment included with the steam cycle, including the steam turbine generator, the c ondensate system, and the feedwater system for these steam cycles.

2.2.2.1 Steam Turbine Generators The turbine consists of a high-pressure (HP) section, a double flow intermediate-pressure (IP) section, and two double-flow low-pressure (LP) sections, all connected to the generator by a common shaft. Main steam from the boiler pa sses through the stop va lves and control valves and enters the turbine. The steam initially enter s the turbine near the middle of the high-pressure span, flows through the turbine, and returns to t he boiler for reheating. The reheated steam flows through the reheat stop valves and intercept va lves and enters the IP sections. After passing through the IP sections, the stea m enters a crossover pipe, which transports the steam to the two LP sections. The steam is divided into two path s that flow through the LP section, exhausting downward into the condenser.

The turbine stop valves, control valves, reheat stop valves, and intercept valves are controlled by an electro-hydraulic control system.
The turbine is designed to operate at variable inlet steam pressure (sliding pressure operation) over the entire load range.

2.2.2.2 Condensate Systems The function of the condensate system is to pump condensate from the condenser hot well to the deaerator, through the gland steam condenser and the low-pressure feedwater heaters. The system consists of one main condenser; tw o 50 percent capacity, motor-driven verticalcondensate pumps; one gland steam condenser; four or five (depending on steam cycle) lowpressure heaters, and one deaerator with a storage tank.
Condensate is delivered to a common discharge header through two separate pump discharge lines, each with a check valve and a gate valve. A common minimum flow recirculation line, discharging to the condenser, is provided to maintain minimum flow requirements for the gland steam condenser and the condensate pumps.

2.2.2.3 Feedwater Systems The function of the feedwater system is to pump feedwater from the deaerator storage tank through the high-pressure feedwater heaters and to the boiler economizer. Two motor-driven boiler feed pumps are provided to pump feedwater through the three high-pressure feedwater heaters. Pneumatic flow control valves control t he recirculation flow. In addition, the suctions of the boiler feed pumps are equipped with startup st rainers, which are utilized during initial startup and following major outages or system maintenance.
The “once through” supercritical plants, compared to the drum type subcritical units, include a condensate polishing system. Subcritical desi gns have a steam drum installed for water steam separation. They also have water recirculation in the boiler waterwalls. For these designs, boiler water chemistry is controlled by chemical treatm ent in the drum and a periodic drum blowdown. Since the supercritical designs are of the once- through flow design and don’t have drums, boiler tubing and the steam turbine must be protected against potential corrosion due to contaminated feedwater that could result from leaking cond ensers. For this reason, once through designs require a condensate polishing system. Steam purity requirements are the same regardless of the type of boiler used.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### 2.3 Pulverized Coal (PC) Fired Cases

Five pulverized coal fired cases (PC-1, PC-2 , PC-3, PC-4, and PC-5) with different steam conditions were analyzed for the Pulverized Coal (PC) fired group. Each case includes a selective catalytic reactor (SCR) for NO x 

### emission control, an electrosta tic precipitator for particulate removal, and a wet flue gas desulfurization (FGD) unit for sulfur capture. The five PC fired steam generators all fire the same amount of fuel and include low NO x 

### tangential firing systems capable of reducing furnace NO x 

### emissions to 0.25 lbm/MM-Btu. All five PC fired cases are identical with respect to the gas side energy and material bal ance. Figure 2.3.1 shows a simplified gas side process flow diagram for the five PC cases and Table 2.3.1 shows the associated inlet and outlet stream conditions.

Tri-Sector

Ash Air Heater

Coal Induced Draft Fan

Secondary Air Fan

Coal Mill System 1 2 ESP Steam Generator Unit FGD System

S t

a
c k

5 4 3

Primary Air Fan SCR Ammonia



### Figure 2.3. 1: Simplified Gas Side Process Flow Diagram for the PC Cases

Table 2.3. 1: Gas Side Material and Energy Balance for the PC Cases



### PC Cases Point 1 Point 2 Point 3 Point 4 Point 5 Coal A sh Cooler ID Fan PA Fan SA Fan Units In Out Out In In Flow lbm/hr 524,875 24,756 6,193,144 1,200,411 4,320,192 Temperature Deg F 80 250 268 80 80 Gas Analysis N2 % weight n/a n/a 70.97 74.55 74.55 CO2 % weight n/a n/a 19.33 0.04 0.04 H2O % weight n/a n/a 4.20 1.30 1.30 O2 % weight n/a n/a 5.00 22.84 22.84 SO2 % weight n/a n/a 0.40 0.00 0.00

Ar % weight n/a n/a 0.09 1.27 1.27



### A brief performance summary for these five PC cases reveals the following information. The Case PC-1 subcritical plant produces a net output of about 631 MWe with a net plant heat rate and thermal efficiency of 9,218 Btu/kWh and 37.02 perc ent respectively. The Case PC-2 subcritical plant produces a net output of about 646 MWe with a net plant heat rate and thermal efficiency of 8,997 Btu/kWh and 37.94 percent respectively. The Case PC-3 supercritical plant produces a net output of about 663 MWe with a net plant heat ra te and thermal efficiency of 8,768 Btu/kWh and 38.93 percent respectively. The Case PC-4 superc ritical plant produces a net output of about 677 MWe with a net plant heat rate and thermal efficiency of 8,580 Bt u/kWh and 39.78 percentECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### respectively. Finally, the Case PC-5 ultra-supercr itical plant produces a net output of about 742 MWe with a net plant heat rate and thermal efficiency of 7,838 Bt u/kWh and 43.55 percent respectively. Detailed plant performance for the five PC cases is shown in Section 2.3.4.

2.3.1 Steam Cycles for the PC Cases The steam generators and steam turbines for the five PC cases are designed for a wide range of steam conditions. Main steam pressure for thes e cases ranges from about 2,400 to 5,075 psia. Main steam temperature for these cases ranges from about 1,000 to 1,300°F while reheat steam temperature ranges from about 1,000 to 1,330°F. The steam conditions for the five PC cases are defined as listed below.

• PC-1 : 1,000°F/1,000°F/2,408 psia

• PC-2 : 1,049°F/1,112°F/2,408 psia

• PC-3 : 1,049°F/1,112°F/3,625 psia

• PC-4 : 1,085°F/1,148°F/3,915 psia

• PC-5 : 1,292°F/1,328°F/5,075 psia
This wide range of steam cycle conditions within th is group allows quantification of differences in performance, investment costs, and economics (c ost of electricity) as a function of steam conditions. Several of these steam cycles are also used in the other combustion system groups (CFB and CMB TM 

### ) which will provide a direct comparison of the effect of coal combustion system changes. For example, the stea m cycle used for Case PC-2 is identical to that used for Case CFB-2 (Refer to Section 2.4). Other steam cy cle commonalties between the three combustion system groups are explained later in Sections 2.4 and 2.5 respectively.

2.3.2 Steam Generator Designs for the PC Fired Cases

Five pulverized coal fired steam generators were designed for this study. Many components within the Boiler Islands were common among the cases since each of the five cases were designed for the same boiler heat input and outpu t. With the same boiler heat output and with all five boilers designed for the same boiler efficiency, the gas side balance of plant equipment (draft system, and gas cleanup system) was identical. Similarly the solids handling equipment (coal, ash, and limestone) is identical for all five cases.

2.3.2.1 Heat Transfer Surfaces and Arrangement for the PC Boilers Heat transfer surfaces were sized for all five cases and metal temperature calculations were performed for most of the heat transfer surfaces. The materials were selected based on allowable stresses and oxidation limits of available alloys. No special provision was made in selecting tubing materials to combat increased potential for exfoliation and corrosion for very high temperature design cases. For each case, in addition to the heat transfer surfaces, estimates were made of the drum length for subcritical designs, header and connecting link sizes and materials, and the back-pass height, required to accommodate variations in back-pass installed heat transfer surfaces. All cases included select ion of the circulation and start up systems. For these cases, detailed selection sheet packages were prepared for cost estimating purposes.
The study used a total pressure loss for the r eheat systems of 10% of the turbine cold reheat pressure. Half of this pressu re loss was made available for the boiler reheat system and the balance for the reheat piping system.
Since the heat input into the cycle is the same fo r all cases, the furnace size is fixed for all five designs. Heat liberated in the furnace is partially absorbed by the waterwall tubes forming the lower and upper chambers of the furnace.

Figure 2.3.2 illustrates a typica l boiler arrangement of a onc e-through supercritical steam generator. It is a two-pass gas design with pendant heating surfaces located in the upper furnaceECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### and the horizontal heat transfer surfaces in the rear pass. (A Tower Type boiler configuration is feasible also but was not used in this study).
Combustion takes place in the lower furnace. A fter leaving the lower furnace, the flue gas enters the upper furnace where wide-spaced superheat di vision panels and superheat platens cool the gases. Downstream of the platen s and above the arch, there is a finishing reheater followed by a finishing superheater pendant. To minimize the effe ct of a high radiant heat flux emitted by the combustion process in the furnace, the final supe rheat section is shielded from the furnace and is installed behind the final reheat section. In the backpass, there is a primary reheater followed by an economizer. The economizer is the last section within the steam generator and is located just ahead of the SCR and Ljungstrom® air heater. The location of the convective and radiant surfaces is determined by considering a proper balance between gas, steam, and tube metal temperatures.
Heat transfer surface arrangement for the ultra- supercritical design is the same except that an extra horizontal low temperature surface section is installed in the back-pass and ahead of the primary reheat section. In general, due to the high steam temperatures of the ultra-supercritical design the superheat and reheat surface quantitie s are significantly larger than for the more conventional steam temperature designs.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 23 1. Separator 15. R.H. Horizontal Assemblies 29. Steam Coal Air Heaters 2. Furnace Lower Ring Header 16. R.H. Low Temp. Pendent Assemblies 30. Cold Primary Air Duct 3. Furnace Hopper Tubes 17. R.H. Finishing Assemblies 31. Hot Primary Air Duct 4. Furnace Spiral Waterwall Tubes 18. R.H. Outlet Header 32. Mixed Air Ducts to Pulverizers 5. Furnace Vertical Waterwall Tubes 19. Tripper Conveyor 33. Economizer Bypass Line 6. Economizer Inlet Header 20. Coal Bunkers 34. SCR Bypass Duct 7. Economizer Assemblies 21. Feeders 35. Flue Gas Duct to SCR 8. Backpass Lower Ring Header 22. Mill Maintenance System 36. SCR 9. Backpass Sidewall Tubes 23. Pulverizers 37. Flue Gas Ducts to Air Heaters 10. S.H. Division Panelettes 24. Pyrites Removal System 38. Air Heaters 11. S.H. Platen Assemblies 25. Coal Nozzles & Windbox 39. Flue Gas Outlet Ducts 12. S.H. Finish Assemblies 26. Separated Overfire Air 40. Precipitators 13. S.H. Outlet Header 27. Primary Air Fans 41. Submerged Scraper Conveyor 14. R.H. Inlet Header 28. Forced Draft Fans



### Figure 2.3. 2: Pulverized Coal Fired Sliding Pressure Supercritical BoilerECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### Figure 2.3.3 shows a simplified high pressure ma in steam and reheat steam flow diagram for the supercritical designs. The feedwater is preheated in the economizer tubes. Vertical outlet tubes from the economizer terminate in an economizer outlet header from which connecting piping transports the water to the furnace wall inlet headers.

Figure 2.3. 3: Boiler Water/Steam Flow Diagram for Supercritical Designs

The fluid that flows up through the furnace tube s is collected at the waterwall outlet headers. From there, it passes through connecting tubes to the separators, and then to roof and rear wall tubes. The supercritical fluid then enters, in sequence, panels, platens and the superheat finishing section. Reheat steam enters the horizontally configured primary reheat section. The reheat steam exits through the rear pendant and continues into the finishing reheat pendant.
Surface arrangement for the two subcritical de signs are configured slightly differently. The primary reheat is preheated in the radiant walls installed in the upper furnace region. The other major difference between the subcritical and superc ritical designs is in the use of a steam drum that is not required for the supercritical units. The supercritical and ultra-supercritical boilers are equipped with start-up separators, which form an in tegral part of the start-up system discussed in the start-up system section of this paper.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### The waterwall construction for subcritical and supercritical designs is similar. Both use a rifled tube, vertical wall configuration. The superc ritical design, however, employs much smaller diameter tubes. The furnace wall construction for the ultra-supercritical design features a spiral wall design as illustrated in Figure 2.3.4. The principle of the spiral wound furnace is to increase the mass flow per tube by reducing the number of tubes required to envelop the furnace. Arranging the tubes at an angle such that t hey form a spiral pattern around the furnace accomplishes this.

Figure 2.3. 4: Spiral Wound Furnace Construction and Supporting Structure

2.3.2.2 Materials for the PC Fired Boilers: Typical materials of construction for steam generator tubing, headers and piping are carbon, ferritic, and austenitic steels. Th ese steels are relatively inexpens ive, have satisfactory strength, are easily fabricated, and are resistant to corros ion and oxidation from steam and furnace gases. For subcritical designs, the waterwalls are cons tructed of carbon steel 210C. The supercritical designs require application of conventional lo w chrome (Cr) ferritic steels T12 (1Cr-1/2Mo) andECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### T23 (2-1/4Cr-1/2Mo) in some critical areas of the upper furnace. Increasing cycle steam parameters depletes the design margin for tubes.
Compared to lower pressure steam conditions, ul tra supercritical steam generation takes place at a higher temperature level. This is due to a number of factors; each one of them has a significant impact on the design of the waterwalls. The first factor is associated with the higher feedwater temperature at the economizer inlet and outlet. Th is leads to higher fluid temperature in the furnace walls. The second one is high operating pressure which requires thicker wall tubes. The third one pertains to reduced cooling flow that is associated with improved cycle efficiency. The effect of higher fluid temperature and pressure on the furnace walls must be mitigated by means of increased mass velocity and/or higher strength alloys for tubes or both.
For the ultra-supercritical case, primary materials of construction are the modified T22 alloy, HCM2S (T23) and a higher chromium steel (9%), T91, which is also used for the construction of the vertical tubes. Other 9-12% chromium st eels such as T92, and HCM12A could be applied also instead of T91. These alloys are not as easy to work with and fabrication of the fusion or finwelded panels requires post weld heat treatment. Therefore it was decided to use the more conventional alloys. The use of these higher st rength materials, however, could enable higher fluid temperatures in the waterwalls. The vertical wall, which is less expensive than the spiral wall construction used may be feasible also.

Materials of construction for the superheat and reheat tubes are conventional steels for all designs except the ultra-supercritical. The use of low and high Cr ferritic alloys (T12, T22, T23, and T91) is maximized as much as it is practi cal. Above outside tube metal temperatures of 1175°F, the materials of choice are austenitic steels. The alloys used are TP304H (18Cr-8Ni), TP347H (18Cr-10NiCb), and Super 304H (18Cr-9NiNb) . The extent of application of each alloy was governed by cost and pressure drop considerat ion. For the ultra-supercritical design, the austenitic alloys provide only a limited solution. As the metal temperatures increase, the limit of these steels is quickly reached and stronger materials are required. The primary materials of construction for the higher temperature superheat tubing are Super 304H, IN 617, Hayness 230, and IN 740. The latter three are nickel-based alloys and are currently being tested in Europe, Japan, and USA. Similarly, the reheat finishing section tubes require application of nickel-based alloys such as Hayness 230 and HR 120. Super 304H was also used for this section.
In the selection of headers and piping the fo llowing five parameters must be considered: (1) pressure drop, (2) flow distribution, (3) design temperature, (4) operating pressure and (5) mode of operation. For the subcritical and supercritical designs, low and high chromium ferritic alloy pipes P22 and P91 are used throughout. For the ul tra-supercritical case, nickel-based alloys are required for the outlet headers and main steam piping. IN 617 is used for this purpose. For the intermediate headers and links, austenitic and high ferritic materials are applied. IN 617 is also employed for the finishing reheat outlet header and piping. The other Ni based alloys could be applied also.
2.3.2.3 Firing Systems for the PC Boilers: The firing system is designed to provide controlle d efficient conversion of the chemical energy of the fuel into heat energy while minimizing pollu tant formation. The heat energy produced is transferred to the heat absorbing surfaces throughout the steam generator. To accomplish this, the firing system introduces fuel and air for comb ustion, mixes the reactants, ignites the mixture, and distributes the flame envelope and the prod ucts of combustion. The firing system is comprised of several components or sub-system s including the windbox, the steam temperature control system, the ignition sy stem, and the pulverizer system.

Windbox: The fuel and air are introduced into the furnace through a device called a windbox. The windbox is a vertical stack of alternating fuel and ai r compartments with dampers associated with each compartment. One windbox is located in each corn er of the rectangular furnace. Both the fuelECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### and air are directed toward the tangent of an imaginary circle in the center of the furnace, thus the name “Tangential Firing”. The concept used for tangential firing is to form a single flame envelope within the furnace, which is controlled by the windbox assemblies. The windboxes are controlled on an elevation basis. For example, the top coal nozzles in each of the four windboxes are geometrically identical and operated as if t hey were one. The fuel piping is arranged such that all four coal nozzles are fed from the same pulverizer. As pulverizers are taken in and out of service, fuel flow to the furnace is increased or decreased from the same elevation within the windboxes. Thus the symmetry of the flam e is maintained regardless of the number of pulverizers in operation needed to support the unit load. Because of the flame pattern symmetry, each furnace wall tube receives a predictable and repeatable heat flux for all loads and combinations of pulverizers in service.
The windbox also includes overfire air compartments for NO x 

### control. The NO x 

### emissions from the boiler are reduced to 0.25 lbm/MM-Btu.
The flame scanners require a separate cooling air source, which is provided by two dedicated booster fans. The booster fans receive air from the forced draft fan discharge.
Steam Temperature Control System: For both the fuel and air, vertically adjustable nozz le tips are provided within the windbox to direct the fuel and air up or down from horizontal. The nozzles are capable of tilting up or down as much as 30 degrees from horizontal through the use of lever arms driven by pneumatic or electric drives. This allows the capabilit y of raising or lowering the flame pattern within the furnace. When tilted down, more radiant heat is absorbed within the furnace and the gas temperature available to the superheater and reheater is redu ced. When tilted up the reverse occurs.
This tilting capability therefor e gives the operator (or control system) t he ability to control superheater or reheater outlet temperature wi th the firing system and to use de-superheating spray for trim which minimizes the amount of de-superheating spray required. Thus the tilt capability allows compensation for the continuous ly changing conditions of the furnace walls due to ash deposition, wall-blower operation, load changes, and variations in ash composition.
Ignition System: The High Energy Arc (HEA) igniter is designed fo r the capability of igniting fuels ranging from No. 2 to No. 6 fuel oil. The system uses an electr ical capacitor discharge device for producing a high intensity spark. There is one elevation of HEA i gniters for each elevation of light oil warm-up guns. The warm-up guns are used to li ght off the adjacent coal elevations.
Pulverizer System: Six volumetric feeders provide the required flow rate of coal to each pulverizer. Each feeder is supplied from a dedicated coal silo. Each pulver izer feeds one windbox elevation of coal nozzles. The pulverizers are of the HP configuration and include Dynamic TM 

### Classifiers and are designed to provide fine grind (85% through 200 mesh) pul verized coal for minimization of combustible losses.
The pulverizer dries and grinds the coal prior to transport to the furnace. The feed coal is discharged onto a revolving bowl. Centrifugal forc e causes the coal to travel to the perimeter of the bowl and through the grinding zone. Primary air is directed upward around the bowl where it entrains the pulverized coal. The coal/air mixt ure then enters the primary classifier where the large heavier particles are separated and returned to the bowl for further grinding. The lighter particles are carried to the dynamic classifi er where secondary classification occurs. The rotational speed of the dynamic classifier determi nes the ultimate fineness. The coal leaving the dynamic classifier through the exhauster then en ters the fuel piping system while oversized particles return to the bowl for additional grinding.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### Any tramp iron or other dense difficult to grind foreign material drops from the bowl edge through the primary air stream to the mill bottom w here it is scraped out of the pulverizer.
During the operation of pulverizers, conditions can arise where the potential for pulverizer fires or explosions exists. A fire extinguishing system is therefore provided on all pulverizers as required by code.

2.3.2.4 Air Heater System for the PC Boilers In all five cases the same high efficiency air heat ers were installed. The air heater system is used for increasing the efficiency of the system by reducing the exit gas temp erature leaving the boiler. Hot air leaving the air heater is used not only to provide oxygen for combustion of the coal but also for drying and transport of the coal. For these designs, two Ljungstrom horizontal tri-sector regenerative air preheaters are used. Air flow to and flue gas flow from the air heaters is provided from the Draft System (refer to Section 2.3.3.2).

The Ljungstrom bi-sector regenerative air preheat er design is a very efficient and cost effective air heating system. The utilization of rotating modu lar elements with highly efficient heat transfer surface makes these air heaters extremely compac t and cost effective for a large amount of heat transferred.

Sootblowers are used to cl ean the air heater heat transfer su rfaces. The sootblower drive unit is located externally and can be serviced while the uni t is in operation. The sootblowing medium (air or steam) pressures and flow rates are selected to achieve an optimum balance between duration of the cleaning cycle, energy consumption and element life.

2.3.2.5 Start-up System for Supercritical and Ultra-Supercritical PC Boilers: The function of the start-up system is to prov ide disturbance-free operat ion of the boiler during the start-up, shutdown, and low load operation in an economical manner. A simplified start-up system, shown in Figure 2.3.5, has essentially the same simplicity as the drum type Controlled Circulation® boilers which rely on circulating pu mps to provide sufficient cooling flow for the furnace tubes. A once-through boiler operates in the normal operating range, as its name indicates, in a pure, once through flow sequence. In this mode, the boiler feed pump forces the water/steam flow through the economizer, furnace walls, and the superheater. The once-through operating mode applies in a load range from full load down to a minimum once-through load that is generally between 25 and 45%, depending on boiler design. Below this load the waterwall flow is kept constant. This is accomplished by wate r recirculation by means of a circulating pump to maintain satisfactory tube cooling. During the start-up, steam generated in the waterwalls must be separated from water at the waterwall outlet and dry saturated steam is piped to the first superheater section. A water separator is used to separate steam from water. This type of the start-up system is featured for a ll supercritical PC, CFB, and CMB TM 

### designs in this study.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### Figure 2.3. 5: Start-Up System with Low Load Circulation Pump for Supercritical Boilers

2.3.3 Balance of Plant Equipment for the PC Cases The balance of plant equipment described in th is section includes the gas cleanup system equipment and other BOP equipment. The equipment in the category of other BOP equipment includes the draft system equipment, the coo ling system equipment, the material handling equipment (coal, limestone, and ash), electrical equipment, and miscellaneous BOP equipment. Refer to Appendix I for equipment lists and Appendix II for drawings.

2.3.3.1 Gas Cleanup Systems for the PC Cases The gas cleanup system for the PC cases, which is the same design for all five cases, includes all equipment necessary for the final stage of NO x 

### reduction, particulate removal, and sulfur removal. Particulate removal is done with an elec trostatic precipitator and sulfur (SO 2 

### ) is removed with a wet flue gas desulfurization (FGD) unit.

The selective catalytic reduction system uses a catalyst and a reductant (ammonia gas, NH 3 

### ) to dissociate NO x 

### to nitrogen gas and water vapor. The SC R catalytic-reactor chamber is typically located between the economizer outlet and air heater flue-gas inlet (see Figure 2.3.6). This location is typical for steam-generating units wi th SCR operating temper atures of 575 to 750°F. Upstream of the SCR chamber are the ammoni a injection pipes, nozzles, and mixing grid. Through orifice openings in the ammonia injection nozzles, a diluted mixture of ammonia gas in air is dispersed into the flue-gas stream. After the mixture diffuses, it is further distributed in the gas stream by a grid of carbon steel piping in the flue-gas duct. The ammonia/flue-gas mixture then enters the reactor where the catalytic reaction is completed.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### Figure 2.3. 6: SCR Typical Arrangement Diagram

Boiler flue gas enters the spray tower and is cont acted by the absorbent slurry where the SO 2 

### is absorbed reducing SO 2 

### emissions by 98%. The spent sorbent dr ains to the scrubber effluent hold tank (reaction tank) where the dissolved sulfur compounds are precipitated as calcium salts. Fresh limestone is added to regenerate the spent absorbent. The rate of additive feed is pH controlled. From the reaction tank the regenerat ed absorbent slurry is pumped back to the spray tower absorber. The slurry typically contains from 5-15% suspended solids consisting of fresh additive, absorption reaction products, and lesser amounts of flyash.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 31 

### Figure 2.3.7 shows a simplified process flow diagram for the wet FGD system (Singer, 1991).

Figure 2.3. 7: Simplified Process Flow Diagram for Wet FGD System

To regulate the amount of solids a bleed str eam is pumped to the clarifier for solid/liquid separation. Liquid is drawn off the top of the clarifier and returned to the scrubber loop. The clarifier underflow, containing from 25-45% solids, is further de-watered in a vacuum filter. The filtrate is returned to the scrubber loop. Ma ke-up water is added to the system to replace evaporated water and water carried with the wast e filter cake stream. The make-up water is added as mist eliminator wash at the top of the spray tower and also as the additive slurrying medium.

Mercury Removal The power industry in the US is faced with m eeting new regulations to reduce the emissions of mercury compounds from coal-fired plants. These regulations are directed at the existing fleet of approximately 1,400 existing boilers as well as additional new boilers. EPA’s December 15, 2003 proposal to regulate mercury emissions from electric utility steam generating units includes several alternatives including prescriptive MACT standards and cap-and-trade options. In all of these versions, the EPA is proposing output-based limits for new units as shown in Table 2.3.2.

Table 2.3. 2: EPA Proposed Mercury Limits Unit Type Hg(10 -6 

### lbm/MWh) Bituminous-fired 6.0 Sub-bituminous-fired 20 Lignite-fired 62 IGCC unit 20 Coal-refuse-fired 1.1ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 32 

### Therefore, the industry needs mercury control tech nologies that can effectively meet regulations on a wide variety of coal characteristics. Rec ent full-scale and emerging pilot-scale testing indicate that activated carbon injection in the flue gas duct upstream of a particulate control device can be effective for mercury control. Howeve r, mercury removal is difficult for lignite and sub-bituminous coals compared to bituminous c oals because of the high proportion of elemental mercury in the flue gas. A fabric filter capt ures mercury to a higher degree compared to an ESP due to enhanced gas-sorbent contact. However, it is capital intensive (~ $30 - 50/kW e 

### ). On the other hand, sorbent consumption is high for an ESP (factor of 5 to 10 vis-à-vis fabric filters). One of the approaches under development at ALST OM (Mer-Cure) does not require installation of an additional fabric filter for mercury control. Capital costs with this approach are expected to be less than $ 5-10/kW e 

### , and sorbent consumption is expected to be comparable to a fabric filter (~ 5 lbm/MM-acf). The Mer-Cure approach empl oys a sorbent preparati on and injection system that enhances sorbent performance by changing t he physical nature of the sorbent. In addition, process chemistry modifications and a unique injection methodology are used to further enhance mercury capture performance. It is anticipated that the long run cost of the enhanced sorbents used in our approach to be only marginally higher than the baseline activated carbon, given the low additive costs and simplicity of the sorbent preparation method.
The potential for mercury capture enhancement with the Mer-Cure technology is provided by recently concluded US-DOE funde d tests at the University of North Dakota – Energy and Environmental Research Center. In these test s, the performance of this technology was compared to current industry standard: Norit Darco FGD TM 

### sorbent injection. Results are presented in Figure 2.3.8 from the firing of a li gnite coal with sorbent injection upstream of an ESP.

Figure 2.3. 8: Pilot-Scale and Full Scale ESP Hg Removal Efficiencies as a function of Sorbent Injection Rate

0 1 2 3 4 5 6 7 8 9 10



### Inlet Outlet Baseline Norit FGD Norit FGD ALS-30 ALS-30 ALS-38B ALS-382Hg (t) Concentration (μg/Nm3)



### Sorbent Feed Rate X 4X X/4 X/2 X/4 X/4 41%

57%

69% 74%

88% 92% Removal % 

### ALSTOM BaselineECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 33 

### Comparison is also provided for standard sorbent in jection in field units firing bituminous and subbituminous coals (Bustard et al., 2002). These data show that up to 90% mercury removal is possible at sorbent injection rates less than 10% of the standard sorbent with ALSTOM’s technology, in contrast to less than 55 % removal with injection rates of the standard sorbent. The Mer-Cure technology is expected to be demonstrated at full-scale in fall 2004.

Mercury control has not been considered in the in vestment costs or economic analysis for this study to simplify the analysis. New technology is cu rrently being developed. It is believed that the investment and operating cost would be small and approximately the same for PC, CFB, and CMB TM 

### boiler technologies.
2.3.3.2 Other BOP Systems for the PC Cases The equipment in the category of other BOP equi pment includes the draft system equipment, the cooling system equipment, the material handling equipment (coal, limestone, and ash), electrical equipment, and miscellaneous BOP equipment. Refer to Appendix I for equipment lists.
Draft System: The flue gas is moved through the boiler, the SC R, precipitator, scrubber, and other Boiler Island equipment with the draft system. The draft system is the same for all five PC cases. The draft system includes the primary and secondary air fans , the induced draft (ID) Fan, the associated ductwork and expansion joints, and the stack, wh ich disperses the flue ga s leaving the system to the atmosphere. The induced draft, primary air, and secondary air fans are driven with electric motors and controlled to operate the unit in a balanced draft mode with the furnace outlet maintained at a slightly negative pressure (typically, -0.5 inwg).
A forced draft primary air (PA) fan provides hot (t emperature controlled) air to the pulverizers for pulverized coal drying and transport of the pulveri zed coal to the furnace. It is preheated in a steam coil air heater (during cold ambient c onditions only) and a regenerative air preheater. Temperature control for the pulverizers is achiev ed by mixing cold air leaving the PA fan (which is bypassed around the air heater) with hot air leaving the air heater.
A forced draft secondary air (SA) fan provides an air stream that is preheated in a steam coil air heater (during cold ambient conditions only) and a regenerative air preheater, and is then introduced into the furnace as secondary air for combustion of the coal.
The flue gas exiting the furnace passes through the convection pass of the unit, flowing through the superheater, reheater, and, economizer sect ions. The flue gas leaving the convection pass flows through the SCR and regenerat ive air pre-heaters and then ex its the unit and flows to the precipitator for particulate capture. The flue gas is drawn through the precipitator with the Induced Draft (ID) Fan and then flows through the sulfur removal system and is finally discharged to atmosphere through the stack.
The following fans are provided with the scope of supply of the steam generator:



## • Primary air fans, which provides forced draft pr imary airflow. These fans are centrifugal type units, supplied with electric motor drives, inlet screens, inlet vanes, and silencers. The total electric power required for the electric motor drives is 1,322 kW for all five cases.



## • Secondary air fans, which provides forced draft secondary airflow. These fans are centrifugal type units supplied with electric motor drives , inlet screens, inlet vanes, and silencers. The total electric power required for the electric motor drives is 1,589 kW for all five cases.



## • Induced draft fans, centrifugal un its supplied with electric motor drives and inlet dampers. The total electric power required for the electric motor drives is 8,950 kW for all five cases.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 34 

### The total power requirement for the PC cases fans is 11,861 kW, which is about 46% of the power required for the CFB cases and about 50% of the power required for the CMB TM 

### cases.

Ducting and Stack: One stack is provided with a single FRP liner. The stack is constructed of reinforced concrete. The stack is sized for adequate dispersion of crit eria pollutants, to assure that ground level concentrations are within regulatory limits. Table 2.3.3 shows the stack design parameters.

Table 2.3. 3: Stack Design Parameters Design Parameter V alue 

### Flue Gas Temperature (F) 280 Flue Gas Flow (lbm/hr) 5,650,000 Flue Gas Flow (acfm) 1,737,000 Particulate Load (gr/scf) nil



### Coal Handling and Preparation: All the cases included in this study, except t he repowering case, use the exact same equipment for coal handling and preparation. This is possib le because the heat output from the boiler is the same for all cases. The function of the coal hand ling and preparation system is to unload, convey, prepare, and store the coal delivered to the plant. The scope of the system is from the trestle bottom dumper and coal receiving hoppers up to the inlets of the prepared fuel silos.

The bituminous coal is delivered to the site by unit trains of 100-ton rail cars. Each unit train consists of 100, 100-ton rail cars. The unlo ading is done by a trestle bottom dumper, which unloads the coal to two receiving hoppers. Coal fr om each hopper is fed directly into a vibratory feeder. The 6" x 0 coal from the feeder is disc harged onto a belt conveyor (No. 1). The coal is then transferred to a conveyor (No. 2) that transfers the coal to the reclaim area. The conveyor passes under a magnetic plate separator to re move tramp iron and then to the reclaim pile.
Coal from the reclaim pile is fed by two vibr atory feeders, located under the pile, onto a belt conveyor (No. 3) that transfers the coal to the coal surge bin located in the crusher tower. The coal is reduced in size to 3" x 0. The coal then enters a second crusher that reduces the coal size to 1/4" x 0. Conveyor No. 4 then transfers the coal to the transfer tower. In the transfer tower the coal is routed to the tripper that loads the coal into one of the three silos.
Technical Requirements and Design Basis

• Coal burn rate:

− Maximum coal burn rate = 524,000 lbm/h = 262 tph plus 10 percent margin = 288 tph (based on the 100 percent MCR rating for the plant, plus 10 percent design margin)

− Average coal burn rate = 446,000 lbm/h = 225 tph (based on MCR rate multiplied by an 85 percent capacity factor)

− Coal delivered to the plant by unit trains:

− Five unit trains per week at maximum burn rate

− Four unit train per week at average burn rate

− Each unit train shall have 10,000 tons (100-ton cars) capacity

− Unloading rate = 30 cars/hour (maximum)

− Total unloading time per unit train = 11 hours (minimum)

− Conveying rate to storage piles = 3,000 tph (maximum)

− Reclaim rate = 1,000 tph

− Storage piles with liners, run-o ff collection, and treatment systems:ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 35 

### − Active storage = 19,000 tons (72 hours at maximum burn rate)

− Dead storage = 160,000 tons ( 30 days at average burn rate)

Table 2.3. 4: Coal Receiving Design Summary Design Parameter V alue 

### Coal Receiving (TPH) 288 Active Storage (Tons) 19,000 Dead Storage (Tons) 160,000



### Limestone Handling and Preparation System: The function of the balance-of-plant limestone handl ing system is to receive and store prepared limestone on an as-needed delivery basis. The syst em consists of a receiving station, unloading system with blowers, and silos to accommodate 3 days operation.

Bottom Ash Removal: Bottom ash constitutes approximately two-thirds of the solid waste material discharged by the steam generator. This bottom ash is discharg ed through a submerged scraper conveyor (SSC). The steam generator scope terminates at the outlet stream of the SSC.

Fly Ash Removal: Fly ash comprises approximately one-third of the solid waste discharged from the steam generator. Approximately 8 percent of the total so lids (fly ash plus bottom ash) are separated out in the economizer and air heater hoppers; 25 percent of the total solids is carried in the gases leaving the steam generator en route to the bag house. Fly ash is removed from the stack gas through an electrostatic precipitator.
Ash Handling: The function of the ash handling system is to c onvey, prepare, store, and dispose of the flyash and bottom ash produced on a daily basis by the bo iler. The scope of the system is from the precipitator hoppers, air heater and economizer hopper collectors, and bottom ash hoppers to the truck filling stations.
The flyash collected in the precipitator, economiz er, and the air heaters is conveyed to the flyash storage silo. A pneumatic transport system using low-pressure air from a blower provides the transport mechanism for the flyash. Flyash is discharged through a wet un-loader, which conditions the flyash and conveys it through a te lescopic unloading chute into a truck for disposal.
The bottom ash from the boiler is discharged to a drag chain type conveyor for transport to the bottom ash silo.
The silos are sized for a nominal holdup capacity of 36 hours of full-load operation. At periodic intervals, a convoy of ash hauling trucks will transit the unloading station underneath the silos and remove a quantity of ash for disposal.
Circulating Water System: The function of the circulating water system is to supply cooling water to condense the main turbine exhaust steam. The system consists of tw o 50 percent capacity vertical circulating water pumps, a multi-cell mechanical draft evaporative cooling tower, and carbon steel cement-lined interconnecting piping. The condenser is a single-pass, horizontal type with divided water boxes. There are two separate circulating water circuits in each box. One-half of each condenser can be removed from service for cleaning or plugging tubes. This can be done during normal operationat reduced load. The condenser cooling load varies significantly from case to case with Case PC1 being the highest (2,808 x 10 6 

### Btu/hr) and Case PC-5 being the lowest (2,480 x 10 6 

### Btu/hr).ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 36 

### Although the cooling load varies among the cases, the design of the system is similar for all cases. Only capacity changes are required fo r the circulating water system equipment.
Waste Treatment System: An onsite water treatment facility treats all ru noff, cleaning wastes, blowdown, and backwash to within U.S. Environmental Protection Agency (EPA) standards for suspended solids, oil and grease, pH, and miscellaneous metals. All waste treatment equipment is housed in a separate building. The waste treatment system consists of a water collection basin, three raw waste pumps, an acid neutralization system, an oxidation system, flocculation, clarification/thickening, and sludge de-watering. The water collection basin is a synthetic-membrane-lined earthen basin, which collects rainfall runoff, maintenance cleaning wastes and backwash flows.

The raw waste is pumped to the treatment system at a controlled rate by the raw waste pumps. The neutralization system neutralizes the acidic wastewater with hydrated lime in a two-stage system, consisting of a lime storage silo/lime slur ry makeup system with 50-ton lime silo, a 0 - 1,000 lbm/hour dry lime feeder, a 5,000-gallon lim e slurry tank, slurry tank mixer, and 25 gpm lime slurry feed pumps.
Miscellaneous systems: Miscellaneous systems consisting of fuel oil, service air, instru ment air, and service water are provided. A 200,000-gallon storage tank provides a supply of No. 2 fuel oil used for startup and for a small auxiliary boiler. Fuel oil is delivered by truck. All truck roadways and unloading stations inside the fence area are provided.
Accessory Electric Plant: The accessory electric plant consists of all switchgear and control equipment, generator equipment, station service equipment, conduit and cabl e trays, all wire and cable. It also includes the main power transformer, all re quired foundations, and standby equipment.

Instrumentation and Control: An integrated plant-wide distributed control and monitoring system (DCS) is provided. The DCS is a redundant microprocessor-based, functionally distributed system. The control room houses an array of multiple video monitor (CRT) and keyboard units. The CRT/keyboard units are the primary interface between the generating process and operations personnel. The DCS incorporates plant monitoring and control functions for all the major plant equipment. The DCS is designed to provide 99.5 percent availability. The plant equipment and the DCS are designed for automatic response to load changes from mini mum load to 100 percent. Startup and shutdown routines are implemented as supervised manual wi th operator selection of modular automation routines available.
Buildings and Structures: A soil-bearing load of 5,000 lb/ft 2 

### is used for foundation design. Foundations are provided for the support structures, pumps, tanks, and other plant components. The following buildings are included in the design basis:

• Steam turbine building

• Boiler building

• Administration and service building

• Makeup water and pretreatment building

• Pump house and electrical equipment building

• Fuel oil pump house

• Continuous emissions monitoring buildingECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 37 

### • Coal crusher building

• River water intake structure

• Guard house

• Runoff water pump house



## • Industrial waste treatment building

Plant Layout: The plants are arranged functionally to address the flow of material and utilities through the plant site.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 38 

### 2.3.4 Overall Plant Performance Comparison for the PC Cases

Table 2.3.5 shows a fairly detailed comparison of various plant performance parameters for the five PC cases including plant auxiliary power, steam conditions, generator output, net plant output, fuel heat input, net plant heat rate, and thermal efficiency. Figure 2.3.9 shows a comparison of thermal efficiency for the PC case s. This plot shows the effect of steam cycle parameters (temperature, pressure ) on plant thermal efficiency.

Table 2.3. 5: Overall Plant Performance Comparison for PC Cases

PC-1 PC-2 PC-3 PC-4 PC-5 

### Auxiliary Power Listing (units) Feedwater Pumps (mechanical) (kw) 15606 15187 22799 25858 29316 Feedwater Pumps (electrical) (kw) 17340 16874 25332 28731 32573 Main Condensate Extraction Pumps (kw) 1255 1197 1347 1317 1026 Main Cooling Water Pumps (kw) 4799 4728 4627 4521 4237 Secondary Cooling Water Pumps (kw) 202 199 234 228 214 Closed Circuit Cooling Water Pumps (kw) 370 365 428 418 392 Cooling Tower Fans (kw) 3300 3251 3182 3109 2914 Forced Draft Fans (kw) 1589 1589 1589 1589 1589 Primary Air Fans (kw) 1322 1322 1322 1322 1322 Induced Draft Fans (kw) 8950 8950 8950 8950 8950 Fluidizing Air Blowers (kw) n/a n/a n/a n/a n/a Coal Handling (kw) 350 350 350 350 350 Pulverizers (kw) 1949 1949 1949 1949 1949 Ash Handling (kw) 2417 2417 2417 2417 2417 Limestone Handling (kw) 741 741 741 741 741 Electrostatic Precipitator (kw) 1400 1400 1400 1400 1400 FGD or FDA System (kw) 13200 13200 13200 13200 13200 SCR or SNCR Auxiliary Power (kw) 200 200 200 200 200 Boiler Circulation Pumps (kw) 621 621 n/a n/a n/a Misc. Aux. Power (Control s, Lighting, HVAC, etc.) (kw) 3000 3000 3000 3000 3000 Transformer Loss (kw) 2785 2845 2945 3016 3285 Total Auxiliary Power Consumption (kw) 65790 65198 73212 76458 79759 Fraction of Generator Output (fraction) 0.094 0.092 0.099 0.101 0.097 Fraction of Generator Output (w/o BFP) (fraction) 0.070 0.068 0.065 0.063 0.057


### Steam Cycle Parameters Main Steam Pressure (psia) 2408 2408 3625 3915 5075 Main Steam Temperature (Deg F) 1000 1049 1049 1085 1292 Reheat Steam Temperature (Deg F) 1000 1112 1112 1148 1328 Feedwater Temperature (Deg F) 500 500 500 554 626 Number of Feedwater Heaters (no.) 77789


### Efficiency and Output Boiler Efficiency (HHV basis) (fraction) 0.8975 0.8975 0.8975 0.8975 0.8975

Steam Cycle Efficiency (fraction) 0.4442 0.4543 0.4650 0.4745 0.5161 (Btu/kwhr) 7683 7512 7339 7193 6613

Generator Output (kw) 696316 711278 736148 753937 821374

Net Plant Output (kw) 630526 646080 662936 677479 741615

Fuel Heat Input (HHV basis) (MM-Btu/hr) 5812 5812 5812 5812 5812

Net Plant Heat Rate (HHV basis) (Btu/kwhr) 9218 8997 8768 8580 7838 Thermal Efficiency (HHV basis) (fraction) 0.3702 0.3794 0.3893 0.3978 0.4355ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 39 0.3702 0.3794 0.3893 0.3978 0.4355

0.32 0.34 0.36 0.38 0.40 0.42 0.44 0.46

PC-1 PC-2 PC-3 PC-4 PC-5Thermal Efficiency - HHV (fraction)



### Figure 2.3. 9: Thermal Efficien cy for PC Cases (HHV Basis)

In general, the transition from a subcritical plant with 2,400 psi main steam pressure to a supercritical plant with 3,625 psi, given co nstant fuel heat input and the same steam temperatures leads to an increase in net pl ant output, and efficiency, of approximately 2.9% (Case PC-3 vs. PC-2). The ultra high steam conditions case offers more than a 18% efficiency improvement over a conventional subcritical desi gn (Case PC-5 vs. PC-1). This represents more than 6.5 percentage points in thermal efficien cy improvement and an 18% reduction in CO 2 

### emissions.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 40 

### 2.4 Circulating Fluidized Bed (CFB) Cases

The three Circulating Fluidized Bed (CFB) st eam generators (all ~700-750 MWe gross output) were designed to fire the same amount of fuel and produce the following steam conditions:

• CFB-2 : 1,049°F/1,112°F/2,408 psia

• CFB-3 : 1,049°F/1,112°F/3,625 psia

• CFB-4 : 1,085°F/1,148°F/3,915 psia
The steam cycle used for Case CFB-2 is identical to that used for Case PC-2. The steam cycle used for Case CFB-3 is identical to that used for Case PC-3 and Case CMB TM 

### -3 (refer to Section 2.4). The steam cycle used for Case CFB-4 is identic al to that used for Case PC-4. Thus there is good comparability from group to group allowing identification of advantag es and disadvantages of one type combustion system as compared to anot her in addition to identification of the best steam cycle parameters.
Each CFB case includes a fabric filter baghouse for particulate removal integrated with a flash dryer absorber (FDA) system for sulfur capture. NO x 

### emissions are inherently low with CFB boilers. The basic design of the furnace combined with high efficiency cyclones and intensive air staging results in NO x 

### emissions of 0.20 lbm/MM-Btu. Addi tional reduction to 0.05 lbm/MM-Btu level is achieved by integration of the SNCR sy stem with the furnace. All three CFB cases are identical with respect to the gas side energ y and material balance. Figure 2.4.1 shows a simplified gas side process flow diagram for t he three CFB cases and Table 2.4.1 shows the associated inlet and outlet stream conditions.

Air Heater

Coal

Limestone Primary Air Fan

Fluidizing Air Blower Secondary Air Fan Induced Draft Fan

5

3 Combustor Cyclone
Convection Pass Heat Exchangers CFB Steam Generator Unit

1

2 FDA & Particulate Removal

Ash Cooler 6

7 External Heat Exchanger 4 S t

a
c k Ammonia for SNCR



### Figure 2.4. 1 Simplified Gas Side Process Flow Diagram for the CFB CasesECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 41 

### Table 2.4. 1: Gas Side Material and Energy Balance for the CFB Cases

CFB Cases Point 1 Point 2 Point 3 Point 4 Point 5 Point 6 Point 7 Coal Limestone A sh Cooler ID Fan PA Fan SA Fan FA Fan Units In In Out Out In In In Flow lbm/hr 524,875 64,128 58,298 6,045,094 2,987,042 2,196,779 388,016 Temperature Deg F 80 80 250 268 80 80 80 Gas Analysis N2 % weight n/a n/a n/a 71.04 74.55 74.55 74.55 CO2 % weight n/a n/a n/a 19.66 0.04 0.04 0.04 H2O % weight n/a n/a n/a 4.26 1.30 1.30 1.30 O2 % weight n/a n/a n/a 4.89 22.84 22.84 22.84 SO2 % weight n/a n/a n/a 0.06 0.00 0.00 0.00 Ar % weight n/a n/a n/a 0.09 1.27 1.27 1.27



### A brief performance summary for these three CFB cases, each of which consumes fuel at the same rate, reveals the following information. The Case CFB-2 subcritical plant produces a net output of about 648 MWe with a net plant heat ra te and thermal efficiency of 8,976 Btu/kWh and 38.03 percent respectively (HHV basis). The Case CFB-3 supercritical plant produces a net output of about 664 MWe with a net plant heat ra te and thermal efficiency of 8,756 Btu/kWh and 38.98 percent respectively. Similarly, the Case CFB-4 supercritical plant produces a net output of about 678 MWe with a net plant heat rate and thermal efficiency of 8,568 Btu/kWh and 39.83 percent respectively. Detailed plant performance for the three CFB cases is shown in Section 2.4.4.

2.4.1 Steam Cycles for the CFB Cases The steam cycles for the three CFB cases (CFB-2, CFB-3, CFB-4) are identical to three of the steam cycles used for the PC case s (PC-2, PC-3, PC-4) and the de scription is not repeated here. Additionally, the steam cycle used for Case CF B-3 is identical to that used for Case CMB TM 

### -3 (refer to Section 2.5). Refer to Section 2.2. 1 for the description of these steam cycles.
2.4.2 Steam Generator Designs for the CFB Cases Three CFB steam generator units of a nominal capacity of 700-750 MWe gross were designed for the three steam cycles described above. Each steam cycle requires the same boiler heat output. Although this size is significantly larger than any units built to date, the design procedure utilized for these units (described below) was developed to assure design parameters that fall within our proven experience and knowledge base. The three CFB units are directly comparable to the appropriate PC fired units that utilize the identical steam cycle. One of the CFB units (CFB-3) is also directly comparable to one of the CMB TM 

### units (CMB TM 

### -3) described in Section 2.5.

2.4.2.1 CFB Steam Generator Design Philosophy and Scale-up: In designing a CFB unit, the parameters whic h affect the ability to meet performance requirements (emissions, Ca/S, and efficiency) ar e analyzed along with the fuel to be fired. Careful consideration is given to the geometry of the combustor as this impacts fuel, air, and sorbent mixing. In scaling-up CFB design from existing units, ALSTOM increases the combustor height only slightly to ensure the solids pressu re profile, and therefore heat transfer to the waterwalls is within our proven experience and knowledge base.
The lower furnace design used by ALSTOM enables the fuel, air, and sorbent to mix in an area that is roughly one-half of the overall combustor plan area. As the unit size increases, the depth of the unit remains constant to ensure good mixing of fuel, air, and sorbent in the lower furnace. The width of the unit increases and cyclones are a dded as required to maintain gas velocities at optimum levels. Figure 2.4.2 illustrates this desi gn philosophy. As units increase in size to a point where four (4) cyclones are required, the combustor design changes to a pant-leg style (see Figure 2.4.3).ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 42 

## < 100 MW et



## 200 – 300MW et 

## 300 - 400MW et 

## 100 – 200MW et



## >400MW et



### Figure 2.4. 2: Cyclone Arrangements and Scale Up

Figure 2.4. 3: Pant Leg Style Combustor – Side View Schematic

The combustion of the fuel, sulfur capture, and he at transfer to the combustor walls and other incombustor surface are a result of fluidization of the bed. The bed material is fluidized by primary air, which is introduced into the combustor through a nozzle grid in the floor of the combustor. Primary air nozzles have been developed using pilot scale tests and computer modeling.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 43 

### Properly designed nozzles allow for proper air distribution in the lower combustor region, which contributes to optimal residence time of the f uel, sorbent and ash in the primary loop. The location of the secondary air along the front and re ar walls of the combustor aids in combustion as well as creates conditions to minimize NO x 

### formation.

Cyclones in a CFB separate the entrained solid pa rticles from the flue gas leaving the combustor and return the hot solids to the combustor. The resulting high recycle rate ensures a uniform temperature in the combustor. The efficiency of the cyclone impacts the c apture rate of the fines fraction of the solids entering the cyclone. This in turn affects limestone utilization and carbon burn-up. Scale-up to larger size cyclones has been gradual. Optimization of the cyclone collection efficiency has occurred through changes to the inlet and outlet duct design and to the vortex finder length and location. As the unit si ze increases, cyclone size increases or cyclones are added as required to maintain optimum gas velocities.
Recirculated ash from the furnace/cyclone is directed from below the cyclone hopper at temperatures of 1550-1650° F to a bubbling fluidized bed heat exchanger (FBHE) for the purpose of performing additional boiler heat duty. Solids are diverted using a high temperature ash discharge valve to a series of heat exchanger bundles, which perform superheater, reheater, and evaporator duties.
As CFB’s get larger in size, the combustor surface-to-volume ratio decreases and it is not possible to perform the required heat duty in the furnace and backpass. The FBHE’s allow incremental duty by passing a sufficient amount of recycle solids into the bundles. An inherent benefit of using a FBHE is the high heat transfer rate from the hot solids to the tube bundles. By standardizing tube bundle arrangements and by ut ilizing a modular approach, an increase in unit size can be accommodated without developing a new FBHE design.
The backpass of the CFB boiler accommodates hori zontal surfaces including the low temperature superheater, low temperature reheater, and econom izer. The arrangement is similar to that utilized in a conventional pulveriz ed coal fired unit. The largest backpass used in a PC boiler is approximately three times larger than the size used for a 300-350 MW CFB. The light, dry flyash of the CFB enables the designer to utilize either an in-line spiral finned or bare tube economizer in the design.

2.4.2.2 Heat Transfer Surfaces and Arrangement for the CFB Boilers A 700MW CFB can be designed with only modest extrapolation from smaller size units. While the combustor size is increased in both height and plan area, its increase is limited to maintain overall size and operating parameters within ALSTOM’s experience base. Height has been limited to assure accurate heat transfer predi ctions, solids recirculation at part loads and to minimize overall building and steel costs. Plan area has been increased in a manner which maintains fuel/air/solids mixing lengths. Cycl ones are added in diameters which do not exceed our current operating base. Backpass width has been increased, but not beyond that used in conventional PC unit design. Regardless of t he firing technology used, backpass sizing is a welldefined, low-risk procedure. Finally, modular ized FBHE construction has been used in the design. The resulting 700MW designs are essent ially two 350MW side by side units arranged in the pant leg configuration with the approximate combustor dimensions of 52ft by 77ft.
Similar to the PC designs, there is relatively little difference between the subcritical and supercritical CFB arrangements. The combustor size and auxiliaries are the same. All designs have panels and two division walls suspended in the combustor. In addition, the primary superheater, reheater, and economizer surfaces ar e installed the backpass. The division walls, in addition to absorbing heat, channel the combustion flue gas to six refractory lined cyclones, three cyclones per side. Coal and limestone are also being fed from the two si des ensuring appropriate mixing of coal, air, and sorbent.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 44 

### The major difference between the subcritical and su percritical design is the size and materials used in the construction of the heat transfer and other pressure part components. The second significant difference is in the quantity of FBHE’s used in each design. The supercritical designs require more heat transfer surface, the installa tion of which necessitated increasing either the size or the quantity of the FBHE’s. The deci sion was made to maintain a standard size design. The supercritical designs (CFB-3 and CFB-4) are equipped with eight FBHE’s, while the subcritical unit (CFB-2) has six. Figure 2.4.4 shows a side elevation view of the 700Mw supercritical CFB boiler.
The designs developed herein were specifically developed for this study. A second generation of CFB boilers, not considered in this study, has been developed by ALSTOM for more generic large supercritical designs. These designs may offer an additional investment cost reduction for the CFB boilers. Figure 2.4.5 shows an isometric view of the second generation supercritical CFB boiler.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 45 

### Figure 2.4. 4: Side View Elevation of a 700 MW Supercritical CFB BoilerECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 46 

### Figure 2.4. 5: Isometric View of Sec ond-Generation Supercritical CFB Boiler

2.4.2.3 Materials for the CFB Boilers The materials of construction for the pressure parts are similar to the ones used in the PC designs. For the subcritical case, the waterwall panels are made of carbon steel. Low (T12, T22) and high Chrome (T91) ferritic alloys predom inate in the construction of the low temperature reheat and superheat sections. The finishing rehe ater and superheater tubes are constructed of stainless steels, TP304 H, TP347, and HR3C.

The once-through supercritical CFB’s feature slight ly higher-grade alloys. For the waterwalls the vertical tubes require T12 and T23 alloys. The su percritical designs employ more stainless steel than the subcritical design and the requirement for stainless steel increases for the higher temperature supercritical case. The same SH finish and RH finish materials are used in the construction of the superheat and reheat finish ing tubes. For the hottest metal temperature surfaces, high strength stainle ss steel Super 304H is applied.

2.4.2.4 Firing System for the CFB Boilers The firing system for the CFB boilers is designed to provide controlled efficient conversion of the chemical energy of the fuel into heat energy while minimizing pollutant formation. The heat energy produced is transferred to the heat absorbing surfaces throughout the steam generator. To accomplish this, the firing system introduces fuel, recycle solids, air for combustion, and limestone for sulfur capture. The firing system is designed to mix the reactants and ignite theECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 47 

### mixture. The firing system is comprised of several components or sub-systems including the ignition system, the fuel feed sy stem, and the sorbent feed system.
Ignition System: The ignition system for the CFB cases includes the light oil start-up burners, the HEA igniters, the flame scanners, the burner comb ustion air system, the fuel oil and atomizing media supply systems, and controls.
Fuel Feed System: The fuel feed system transports prepared coal fr om the storage silos to the lower combustor. The system includes the storage silos, silo isolation valves, fuel feed ers, feeder isolation valves, and fuel piping to the furnace.
Sorbent Feed System: The limestone feed system pneumatically transports prepared limestone from the storage silo to the lower combustor. The system includes the stor age silos, silo isolation valves, rotary feeders, blower, and piping from the blower to the furnac e injection ports and furnace isolation valves.

2.4.2.5 Air Heater System for the CFB Boilers The air heater system for the CFB boilers is very similar to that for the PC boilers except that no steam coils are installed. Refer to Section 2.3.2.4 for the description.

2.4.2.6 Start-up System for Supercritical CFB Boilers The start-up system for the supercritical CFB boilers is identical to that for the PC boilers. Refer to Section 2.3.2.5 for the description.

2.4.3 Balance of Plant Equipment for the CFB Cases The balance of plant equipment described in th is section includes the gas cleanup system equipment and other BOP equipment. The equipment in the category of other BOP equipment includes the draft system equipment, the coo ling system equipment, the material handling equipment (coal, limestone, and ash), electrical equipment, and miscellaneous BOP equipment. Refer to Appendix I for equipment lists and Appendix II for drawings.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### 2.4.3.1 Gas Clean-up Syst ems for the CFB Cases To achieve the NO x 

### emissions of 0.05 lbm/MM-Btu the CFB combustor is integrated with the SNCR system. The SNCR method requires the inject ion of ammonia in the upper region of the combustor. With today’s technology such low NO x 

### emissions are possible for relatively few coals. However, new combustion arrangements, aide d by CFD modeling, are being developed to enlarge the range of coals that ca n be burned producing very low NO x 

### emissions.
A Flash Dryer Absorber (FDA) system is used for combined particulate and sulfur removal in the CFB cases. The process and equipment are exactly the same for the three CFB cases sinceeach case has the same flue gas flow and analysis. The FDA system is an advanced, dryscrubbing process, in which the processes of gas cooling and SO 2 

### removal are integrated into the functions of the fabric filter. Please refer to the simplified FDA process schematic shown in Figure 2.4.6.

Flue Gas



### Figure 2.4. 6: Flash Dryer Absorber (FDA) Process Schematic Diagram

In the variation of the FDA process used for the present application, limestone is used as the sulfur-capture reagent. A crushed limestone produc t is purchased and this material is metered into to each fuel feeder along with the coal. The limestone is fed to the combustor through the fuel feed system, and once inside the combus tion zones, undergoes calcination to produce calcium oxide (lime). This calcium product is entrained in the combustion gases and carries through the boiler. In the transit through the un it, capture of about one-thi rd of the coal-derived sulfur, as calcium sulfate, occurs. The gas di scharge from the boiler to the FDA system thus contains some SO 2 

### , and a burden of particulate matter consisting of reacted and unreacted calcium compounds as well as fly ash. Approximatel y 88% of the sulfur is captured in the furnace. The additional 10% is captured in the FDA.

This particulate-laden flue gas then enters the fa bric filter inlet duct, or FDA reactor, where additional (recycle) particulate is added to the gas stream. This flow is then directed into the filter bag compartments where it is distributed to the indi vidual filter bags. The particulate is retained on the outside of the filter bags and the cleaned ga s flows out the top of the bags and into the clean-gas outlet ductwork. When the dust dep osits on the exterior of the bags reach a point where cleaning is required, a pulse of compressed air removes a portion of the dust cake. The removed dust falls into the fluidized dust hoppers, where the majority of the dust is recycled intoECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### the dust humidifier/conditioner. A smaller fraction of the dust is discharged to the flyash handling system.

The process uses a proprietary design fabric filt er that is a high-ratio, intermediate-pressure, pulse-cleaning unit known as an LKP. The fabr ic filter incorporates many unique and proven features that have been developed to insure minimum emissions and maximum equipment and filter media life. Filtration is accomplished on t he outside of the bags, with a tubular cage used to support each bag. The coating of Ca-based dust developed on the filter bags during normal operation contributes subst antially to the overall SO 2 

### removal efficiency of the system.

A mixer/conditioner is located under each fabric filter compartment where water is added to the dust stream. Dust is metered into the mixer/co nditioner from the fluidized fabric-filter hopper where water is uniformly blended with the dust via internal fluidization and mechanical mixing. Control of the water addition rate is based on the amount of flue gas cooling required to allow the acid gas components to react with the lime and recycled alkaline dust. The SO 2 

### reacts readily with the calcium in the recirculated dust under the relatively cool, damp conditions of the gas stream in the duct from the mixer to the fabr ic filter compartment. The water added for gas cooling and humidification is fully evaporated before the dust reaches the filter bags. Completion of the SO 2 

### -calcium reactions occurs in the filter cake on the bags and result in very high overall sulfur removal efficiency.

To maintain a constant inventory of solids in the recycle system, a sma ll portion of the solids collected in the fabric filter must be discharged for disposal. This end product, that constitutes the scrubbing waste product, is a fine, dry material composed primarily of calcium-sulfur compounds, un-reacted lime, and flyash. A mechanical conveyor system is used to collect the discharge from the various fabric filter hoppers and to consolidate it in a transfer bin for pickup by the plant flyash system.

The FDA process is lower in cost, more compact, and higher in efficiency than traditional FGD processes. It has been commercia lly applied to utility coal-fired boilers. The process has been tested on diesel engines as well as wastes-to-ene rgy flue-gas cleaning applications. The process entered the commercial market in mid-1997, a fter approximately five years of development



## .
Mercury Removal Refer to Section 2.3.3.1 for a discussion of this subject.

2.4.3.2 Other BOP Systems for the CFB Cases

The equipment in the category of other BOP equi pment includes the draft system equipment, the cooling system equipment, the material handling equipment (coal, limestone, and ash), electrical equipment and miscellaneous BOP equipment. Other than the differences described below for the draft system, the equipment descriptions for other BOP systems for the CFB cases are identical to those for the PC cases and the descriptions are not be repeated here. Refer to Section 2.3.3.2 for the descript ion of the other BOP equipment.
Draft System: The draft system for the CFB cases differs from the PC cases. In addition to the PA fan, SA fan, and ID fan (which are also used in the PC cases) a fluidizing air (FA) fan is also used in the CFB cases. Furthermore, the pressure rises, flow rates, and power requirements for the CFB cases fans are different than for the corresponding fans for the PC cases.
The following fans are provided for the CFB steam generator:ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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## • Primary air fans, which provide forced draft pr imary airflow to the combustor grate and fuel feed chutes. These fans are centrifugal type uni ts, supplied with electric motor drives, inlet screens, inlet vanes, and silencers. The total electric power required for the electric motor drives is 7,904 kW. This power requirement is the same for all three CFB cases.



## • Secondary air fans, which provide forced draft secondary airflow to the combustor. These fans are centrifugal type units supplied with elec tric motor drives, inlet screens, inlet vanes, and silencers. The total electric power required for the electric motor drives is 3,876 kW. This power requirement is the same for all three CFB cases.



## • Induced draft fans, centrifugal un its supplied with electric motor drives and inlet dampers. The total electric power required for the electr ic motor drives is 10,924 kW. This power requirement is the same for all three CFB cases.



## • Fluidizing air blowers, which provide air to t he external fluidized bed heat exchangers, the seal pots, and solids return piping. These are centrifugal units supplied with electric motor drives and inlet dampers. The total electric power required for the electric motor drives is 2,875 kW. This power requirement is the same for all three CFB cases.

The total power requirement for the CFB case fans is 25,579 kW, which is about 7% higher than the CMB TM 

### cases and about 2.2 times higher than for the PC cases.

2.4.4 Overall Plant Performance Comparison for the CFB Cases

Table 2.4.2 shows a fairly detailed comparis on of various plant performance parameters, including plant auxiliary power, steam conditions, boiler efficiency, steam cycle efficiency, generator output, net plant output, fuel heat input, net plant heat rate, and thermal efficiency. Generator output ranges from about 711–754 MWe with improved steam conditions, while total auxiliary power ranges from about 9.0 – 10.0 percent of generator output. The increase is primarily the result of increasing feedwater pumping power requirements for the higher steam pressure cases. The resulting net output ranges from 648-678 MWe. Fuel heat input is constant for these three cases. Figure 2. 4.7 shows a comparison of therma l efficiency for the CFB cases. This plot visually illustrates t he effect of steam cycle parameter s (temperature, pr essure) on plant thermal efficiency. The thermal efficiency change s for the CFB cases are nearly identical to those for the PC fired cases as would be expected.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### Table 2.4. 2: Overall Plant Performance Comparison for CFB Cases

CFB-2 CFB-3 CFB-4 

## Auxiliary Power Listing (units) 

### Feedwater Pumps (mechanical) (kw) 

### 15187 22799 25858 Feedwater Pumps (electrical) (kw) 

### 16874 25332 28731 Main Condensate Extraction Pumps (kw) 

### 1197 1347 1317 Main Cooling Water Pumps (kw) 

### 4728 4627 4521 Secondary Cooling Water Pumps (kw) 

### 199 234 228 Closed Circuit Cooling Water Pumps (kw) 

### 365 428 418 Cooling Tower Fans (kw) 

### 3251 3182 3109 Forced Draft Fans (kw) 

### 3876 3876 3876 Primary Air Fans (kw) 

### 7904 7904 7904 Induced Draft Fans (kw) 

### 10924 10924 10924 Fluidizing Air Blowers (kw) 

### 2875 2875 2875 Coal Handling (kw) 

### 350 350 350 Pulverizers (kw) 

### n/a n/a n/a Ash Handling (kw) 

### 2783 2783 2783 Limestone Handling (kw) 

### 1153 1153 1153 Electrostatic Precipitator (kw) 

### n/a n/a n/a FGD or FDA System (kw) 

### 1260 1260 1260 SCR or SNCR Auxiliary Power (kw) 

### 106 106 106 Boiler Circulation Pumps (kw) 

### n/a n/a n/a Misc. Aux. Power (Controls, Lighting, HVAC, etc.) (kw) 

### 3000 3000 3000 Transformer Loss (kw) 

### 2845 2945 3016 Total Auxiliary Power Consumption (kw) 

### 63690 72325 75571 Fraction of Generator Output (fraction) 

### 0.090 0.098 0.100 Fraction of Generator Output (w/o BFP) (fraction) 

### 0.066 0.064 0.062


## Steam Cycle Parameters Main Steam Pressure (psia) 

### 2408 3625 3915 Main Steam Temperature (Deg F) 

### 1049 1049 1085 Reheat Steam Temperature (Deg F) 

### 1112 1112 1148 Feedwater Temperature (Deg F) 

### 500 500 554 Number of Feedwater Heaters (no.) 

### 778


## Efficiency and Output Boiler Efficiency (HHV basis) (fraction) 

### 0.8975 0.8975 0.8975

Steam Cycle Efficiency (fraction) 

### 0.4543 0.4650 0.4745 (Btu/kwhr) 

### 7512 7339 7193

Generator Output (kw) 

### 711278 736148 753937

Net Plant Output (kw) 

### 647588 663823 678366

Fuel Heat Input (HHV basis) (MM-Btu/hr) 

### 5812 5812 5812

Net Plant Heat Rate (HHV basis) (Btu/kwhr) 

### 8976 8756 8568 Thermal Efficiency (HHV basis) (fraction) 

### 0.3803 0.3898 0.3983ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 52 0.3803 0.3898 0.3983

0.37 0.38 0.39 0.40

CFB-2 CFB-3 CFB-4Thermal Efficiency - HHV (fraction)



### Figure 2.4. 7: Thermal Efficiency for CFB CasesECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### 2.5 Circulating Moving Bed (CMB TM 

### ) Cases

Two steam cycles (~736 & 821 MWe gross output ) with the following steam conditions are selected for plants equipped with advanced CMB TM 

### steam generators. The CMB TM 

### steam generators both fire the same amount of fuel. These cases are designated CMB TM 

### -3 and CMB TM



### 5 as shown below.

• CMB TM 

### -3 : 1,049°F/1,112°F/3,625 psia

• CMB TM 

### -5 : 1,292°F/1,328°F/5,075 psia
The steam cycle used for Case CMB TM 

### -3 is identical to that used for Case PC-3 and Case CFB-3. The steam cycle used for Case CMB TM 

### -5 is identical to that used for Case PC-5. This commonality of steam cycles provides for compar ative analysis of the various coal combustion systems.

Each CMB TM 

### case includes a fabric filter baghouse for particulate removal integrated with a flash dryer absorber (FDA) system fo r sulfur capture. Both CMB TM 

### cases are identical with respect to the gas side energy and material balance. Figure 2.5.1 shows a simplified gas side process flow diagram for the two CMB TM 

### cases and Table 2.5.1 shows the associated inlet and outlet stream conditions.

Air Heater

Secondary Air Fan

Primary Air Fan

Transport Air Coal

Fluidizing Air Blower Limestone

Cooled Solids Falling Solids Combustor Cyclone CMB Steam Generator Unit

1

2

Moving Bed Heat Exchanger Induced Draft Fan
FDA & Particulate Remova l

3 Ash Cooler Cyclone

7 S t

a
c k

4

6

5 Ammonia for SNCR



### Figure 2.5. 1: Simplified Gas Side Process Flow Diagram for the CMB TM 

### CasesECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### Table 2.5. 1: Gas Side Material and Energy Balance for the CMB TM 

### Cases

CMB Cases Point 1 Point 2 Point 3 Point 4 Point 5 Point 6 Point 7 Coal Limestone A sh Cooler ID Fan PA Fan SA Fan FA Fan Units In In Out Out In In In Flow lbm/hr 526,447 64,320 58,472 6,037,959 4,647,850 801,465 113,970 Temperature Deg F 80 80 250 268 80 80 80 Gas Analysis N2 % weight n/a n/a n/a 71.02 74.55 74.55 74.55 CO2 % weight n/a n/a n/a 19.74 0.04 0.04 0.04 H2O % weight n/a n/a n/a 4.28 1.30 1.30 1.30 O2 % weight n/a n/a n/a 4.82 22.84 22.84 22.84 SO2 % weight n/a n/a n/a 0.06 0.00 0.00 0.00 Ar % weight n/a n/a n/a 0.08 1.27 1.27 1.27


### A performance summary for these two CMB TM 

### cases, each of which consumes fuel at the same rate, reveals the following information. The Case CMB TM 

### -3 supercritical plant produces a net output of about 665 MWe with a net plant heat ra te and thermal efficiency of 8,781 Btu/kWh and 38.87 percent respectively. Similarly, the Case CMB TM 

### -5 ultra-supercritical plant produces a net output of about 744 MWe with a net plant heat ra te and thermal efficiency of 7,853 Btu/kWh and 43.46 percent respectively. Detail ed plant performance for the CMB TM 

### cases is shown in Section 2.5.4.
2.5.1 Steam Cycles for the CMB TM 

### Cases The steam cycles for the two CMB TM 

### cases (CMB TM 

### -3, CMB TM 

### -5) are identical to the two steam cycles used for the cases PC-3, and PC-5 respec tively, and the description is not repeated here. Refer to Section 2.2.1 for a description of t hese steam cycles. Additionally, the case CMB TM 

### -3 steam cycle is also the same as was used for case CFB-3.

2.5.2 Steam Generator Designs for the CMB TM 

### Cases Two CMB TM 

### steam generator units of a nominal capa city of 736 & 821 MWe gross were designed for the two steam cycles described above. Each steam cycle requires the same boiler heat output from the CMB TM 

### boiler. The two CMB TM 

### units are directly comparable to the appropriate PC fired units that utilize the identical steam cycle. One of the CMB TM 

### units (CMB TM 

### -3) is also directly comparable to one of the CFB units (CFB-3) described in Section 2.4.

2.5.2.1 CMB TM 

### Background Circulating Moving Bed (CMB TM 

### ) combustion system technology (ill ustrated in Figure 2.5.2) is a new method for solid fuel combustion and heat transfer, which has roots in the traditional circulating fluidized bed (CFB) technology. In the CMB TM 

### combustion system concept there are two separate chambers. The upper chamber, or combustor, has two zones. Coal or other alternate fuels are fed into a high velocity bubbli ng bed in the lower zone of the combustor, where combustion temperatures may approach 2,000 ° F. These temperatures are higher than the combustion temperatures of 1,500 to 1,650 ° F used in traditional CFB boiler designs. Above the bubbling bed, the upper zone is a relatively long residence time reactor that exchanges (recuperates) the heat from the products of co mbustion (upward gas flow) to a flow of highdensity solid particles flowing downward. High alumina content particles can be used for this flow because they have high density, are chem ically inert, and are readily available.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### Figure 2.5. 2: CMB TM 

### Combustion System Schematic

Once the solids have recuperated the heat of co mbustion, they collect at the bottom of the combustor where they are fluidized and transfer red to a lower chamber through standpipes. The lower chamber consists of a counterflow, di rect contact “moving bed heat exchanger” (MBHE) that uses a simple mass flow of solids that move downward at low velocity through a series of tubular heat exchangers. Heat from the moving pa rticles is transferred to the tube circuits that heat steam to the required process temperatures.
The high alumina content particles pass through a MBHE environment largely free of corrosion, erosion, and plugging. This region thus lends it self to a wide range of finned surface heat transfer pressure parts. The heat transfer mechanism in the moving bed is dominated by conduction/convection, with heat transfer rate s higher than gas-only convection. The use of extended heat transfer surfaces t hat have significant contact surface with the moving solids is a key attribute that makes the CMB TM 

### combustion system a cost-effective technology. Leaving the bottom of the moving bed heat exchanger, the cooled solids are transported back to the top of the combustor to restart the heat recuperation process.
In addition to enabling high temperature power plant cycles, the combustion temperature offers excellent carbon burnout, low N 2 

### O emissions, low carbon monoxide emissions, and hence, increased combustion efficiency with reduced po llutant emission. A unique feature of the CMB TM 

### combustion system process is that combusti on, heat transfer, and environmental control processes are effectively de-coupled and can be optimized separately. The lower combustor is staged for NO x 

### control, while flyash entrained in the flue gas is captured in a low temperature cyclone and recycled back to the high temperature lower combustor to reduce carbon loss. The SO 2 

### emissions will be controlled primarily by a backend cleanup system such as ALSTOM’sECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### Flash Dry Absorber (FDA). Limestone is calc ined in the combustor for use in the backend desulfurization system and additional sulfur c apture can be achieved in the combustor also.
Through an extensive test campaign that has be en conducted at the ALSTOM’s Multi-Use Test Facility (MTF) in Windsor, Connecticut during the past several years, combustion and heat transfer processes unique to the CMB TM 

### design have been characterized. The test campaign has explored the issues related to combustion, carbon loss, NO x 

### and SO 2 

### emissions gas flow and bed dynamics, gas to solids heat transfer, solids to tube heat transfer, heat tr ansfer surface fouling, and agglomeration. The information developed so far has been used in the conceptual design and analysis of the two 700MWe CMB TM 

### boilers shown in this study.
2.5.2.2 Heat Transfer Surfaces and Arrangement for the CMB TM 

### Boilers The two CMB TM 

### designs, supercritical (Case CMB TM 

### -3) and ultra-supercritical (Case CMB TM 

### -5), have many components in common and have the same general arrangement of heat transfer surface and auxiliaries. Both ar e designed for the same firing ra te and have the same size and quantity of combustors, ductwork, and other boiler auxiliaries. Low NO x 

### and SO 2 

### emissions are controlled by the injection of aqueous ammonia and limestone. Both designs are equipped with the FDA system for sulfur capture.
The main differences between the designs are in the pressure part components, which are selected for different steam parameters. Figur e 2.5.3 shows a side view elevation of the supercritical CMB TM 

### design while Figure 2.5.4 shows a side view of the moving bed heat exchanger showing the arrangement of the variou s heat exchanger sections within the moving bed. Both these figures are for Case CMB TM 

### -3 although as mentioned, Case CMB TM 

### -5 looks very much the same. As shown, the finishing superheater and reheater sections are located at the top of the moving bed, followed by the low temperature superheater and reheater sections, and finally two banks of evaporator. The ho t high alumina content particles leaving the combustor enters the top of the moving bed heat exchanger and flows by gravity across the various heat exchanger sections. The particles ar e progressively cooled wh ile transferring their heat to the steam/water working fluid. The cooled particles leave the moving bed heat exchanger at the bottom where they transported pneumatically with primary air to the top of the combustor.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### Figure 2.5. 3: Side Elevation View of a 700MW Supercritical CMB TM 

### Boiler (Case CMB TM 

### -3)ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 58 

### Figure 2.5. 4: Side Elevation of Moving Bed Heat Exchanger (Case CMB TM 

### -3)

There is a refractory lined combustor constr ucted of three octagonal shaped and connected modules. The overall approximate depth and widt h dimensions are 45 ft by 131 ft. The coal and limestone feed systems are similar to what were used for the CFB designs. Hot high alumina content particles from the combustor bottom ar e transported to the three MBHE’s via the standpipes. The working fluid heat transfer surfac e is installed in the MBHE’s. The feedwater and steam heat exchangers are arranged in countercurr ent flow with respect to the moving particles. The three MBHE’s are identical modules, each module is 32 ft wide and 31ft deep. The heat transfer surfaces in each module are arranged in parallel steam/water circuits and are connected by links. The heat exchanger tubes are finned a nd are arranged in staggered configuration for maximum heat transfer. The tube banks are top supported by water cooled hanger tubes.

The cooled particles leaving the three MBHE’s are pneumatically transported back to the top of the combustor using several parallel vertical pipes. Air leaving the primary air heater is used for particle transport. At the top of the combustor, the particles are separated from the transport air in an array of relatively small cyclones. Th e particles are then ready to restart the heat recuperation process. The air streams leaving t he small cyclones are used for combustion as part of the secondary air.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### 2.5.2.3 Materials for the CMB TM 

### Boilers Case CMB TM 

### -3: The materials of construction for the supercritical design (CMB TM 

### -3) are conventional alloys. Low temperature tubing and fins are constructed of carbon steel, T12, T91, and T409 as listed below:

Low Temperature Materials: Tubing Fins Carbon Carbon T12 T12 T91 T409
Higher temperature sections are constructed of stainless steel 304H and HR3C (25Cr20Ni).

The headers and piping materials are similar to the ones used for the equivalent steam cycle in the PC and CFB designs.

The fin materials varied from carbon steel for t he economizer tubes to stainless steel for the superheat and reheat finish tubes.

Case CMB TM 

### -5: The materials for the construction of tubing for the ultra-supercritical design (CMB TM 

### -5) require Ni-based alloys for high temperature sections. T he primary alloys used for the high temperature superheat and reheat sections are IN 617 and IN 740.

The fin material varied from carbon steel for t he economizer tubes to stainless steel for the reheat and superheat finish tubes.

The header and piping materials are similar to the selection made for the PC fired ultrasupercritical design.
2.5.2.4 Firing System for the CMB TM 

### Boilers The firing system for the CMB TM 

### boilers is very similar to that for the CFB boilers. Refer to Section 2.4.2.4 for the description.

2.5.2.5 Air Heater System for the CMB TM 

### Boilers The air heater system for the CMB TM 

### boilers is very similar to that for the CFB boilers. Refer to Section 2.4.2.5 for the description.

2.5.2.6 Start-up System for Supercri tical and Ultra-Supercritical CMB TM 

### Boilers The start-up system for the supercritical and ultra- supercritical CMB boilers is identical to that for the PC boilers. Refer to Section 2.3.2.5 for the description.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 60 

### 2.5.3 Balance of Plant Equipment for the CMB TM 

### Cases The balance of plant equipment described in th is section includes the gas cleanup system equipment and other BOP equipment. The equipment in the category of other BOP equipment includes the draft system equipment, the coo ling system equipment, the material handling equipment (coal, limestone, and ash), electrical equipment, and miscellaneous BOP equipment. Refer to Appendix I for equipment lists and Appendix II for drawings.

2.5.3.1 Gas Clean-up Systems for the CMB TM 

### Cases The gas cleanup systems (NO x 

### control, particulate removal, and sulfur removal) for the CMB TM 

### cases are similar to those used for the CFB cases except that most of the SO 2 

### produced is captured in the FDA system. The description of this equipment is not repeated here. Refer to Section 2.4.3.1 for the descript ion of the gas cleanup system.

Mercury Removal Refer to CFB Revised Section on Hg. 2.4.3.1 for a discussion of this subject.

2.5.3.2 Other BOP Systems for the CMB TM 

### Cases The equipment in the category of other BOP equi pment includes the draft system equipment, the cooling system equipment, the material handling equipment (coal, limestone, and ash), electrical equipment and miscellaneous BOP equipment. Other than the differences described below for the draft system, the equipment descript ions for other BOP systems for the CMB TM 

### cases are identical to those for the PC cases and the desc riptions are not repeated here. Refer to Section 2.3.3.2 for the description of the other BOP equipment.
The other BOP equipment for the two CMB TM 

### cases are nearly identical to equipment used for the CFB cases and the description is not repeated here. Refer to Secti on 2.4.3.2 for the description of the other BOP equipment.
Draft System: The draft system for the CMB TM 

### cases differs from the PC cases. In addition to the PA fan, SA fan and ID fan (which are also used in the PC cases) a fluidizing air (FA) fan is also used in the CMB TM 

### cases. Furthermore, the pr essure rises, flow rates, and power requirements for the CMB TM 

### cases fans are different than for t he corresponding fans for the PC cases.
The following fans are provided for the CMB TM 

### steam generators:



## • Primary air fans, which provide forced draft pr imary airflow to the combustor grate and fuel feed chutes. These fans are centrifugal type uni ts, supplied with electric motor drives, inlet screens, inlet vanes, and silencers. The total electric power required for the electric motor drives is 14,037 kW. This power requirement is the same for both 

## CMB TM 

### cases.



## • Secondary air fans, which provide forced draft secondary airflow to the combustor. These fans are centrifugal type units supplied with elec tric motor drives, inlet screens, inlet vanes, and silencers. The total electric power required for the electric motor drives is 1,219 kW. This power requirement is the same for both 

## CMB TM 

### cases.



## • Induced draft fans, centrifugal un its supplied with electric motor drives and inlet dampers. The total electric power required for the electric motor drives is 7,740 kW. This power requirement is the same for both 

## CMB TM 

### cases.



## • Fluidizing air blowers, which provide air to t he external fluidized bed heat exchangers, the seal pots, and solids return piping. These are centrifugal units supplied with electric motor drives and inlet dampers. The total electric powe r required for the electric motor drives is 840 kW. This power requirement is the same for both 

## CMB TM 

### cases.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 61 

### The total power requirement for the CMB TM 

### case fans is 23,835 kW, which is about 7% lower than the CFB cases and about 2.0 times higher than for the PC cases.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 62 

### 2.5.4 Overall Plant Performance Comparison for the CMB TM 

### Cases

Table 2.5.2 shows a fairly detailed comparison of various plant performance parameters including plant auxiliary power, steam conditions, boiler e fficiency, steam cycle efficiency, generator output, net plant output, fuel heat input, net plant heat rate, and thermal efficiency. Generator output ranges from about 736–821 MWe with improved steam conditions, while total auxiliary power ranges from about 9.4 - 9.6 per cent of generator output. The re sulting net output ranges from 666-744 MWe. Fuel heat input is constant for these two cases. Figure 2.5.5 shows a comparison of thermal efficiency for the two CMB TM 

### cases. This plot visually illustrates the effect of steam cycle parameters (temperature, pressure) on plant thermal efficiency. The efficiency improvement for the CMB TM 

### cases is almost the same as was shown for the PC fired cases as would be expected.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 63 

### Table 2.5. 2: Overall Plant Performance Comparison for CMB TM 

### Cases
CMB-3 CMB-5 

## Auxiliary Power Listing (units) 

### Feedwater Pumps (mechanical) (kw) 

### 22799 29316 Feedwater Pumps (electrical) (kw) 

### 25332 32573 Main Condensate Extraction Pumps (kw) 

### 1347 1026 Main Cooling Water Pumps (kw) 

### 4627 4237 Secondary Cooling Water Pumps (kw) 

### 234 214 Closed Circuit Cooling Water Pumps (kw) 

### 428 392 Cooling Tower Fans (kw) 

### 3182 2914 Forced Draft Fans (kw) 

### 1219 1219 Primary Air Fans (kw) 

### 14037 14037 Induced Draft Fans (kw) 

### 7740 7740 Fluidizing Air Blowers (kw) 

### 840 840 Coal Handling (kw) 

### 352 352 Pulverizers (kw) 

### n/a n/a Ash Handling (kw) 

### 2783 2783 Limestone Handling (kw) 

### 1159 1159 Electrostatic Precipitator (kw) 

### n/a n/a FGD or FDA System (kw) 

### 1267 1267 SCR or SNCR Auxiliary Power (kw) 

### 106 106 Boiler Circulation Pumps (kw) 

### n/a n/a Misc. Aux. Power (Controls, Lighting, HVAC, etc.) (kw) 

### 3000 3000 Transformer Loss (kw) 

### 2945 3285 Total Auxiliary Power Consumption (kw) 

### 70596 77144 Fraction of Generator Output (fraction) 

### 0.096 0.094 Fraction of Generator Output (w/o BFP) (fraction) 

### 0.061 0.054


## Steam Cycle Parameters Main Steam Pressure (psia) 

### 3625 5075 Main Steam Temperature (Deg F) 

### 1049 1292 Reheat Steam Temperature (Deg F) 

### 1112 1328 Feedwater Temperature (Deg F) 

### 500 626 Number of Feedwater Heaters (no.) 

### 7 9


## Efficiency and Output Boiler Efficiency (HHV basis) (fraction) 

### 0.8926 0.8926

Steam Cycle Efficiency (fraction) 

### 0.4650 0.5161 (Btu/kwhr) 

### 7339 6613

Generator Output (kw) 

### 736148 821374

Net Plant Output (kw) 

### 665552 744230

Fuel Heat Input (HHV basis) (MM-Btu/hr) 

### 5844 5844

Net Plant Heat Rate (HHV basis) (Btu/kwhr) 

### 8781 7853 Thermal Efficiency (HHV basis) (fraction) 

### 0.3887 0.4346ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 64 

### 0.3887 0.4346



### 0.36 0.37 0.38 0.39 0.40 0.41 0.42 0.43 0.44

CMB-3 CMB-5Thermal Efficiency - HHV (fraction)



### Figure 2.5. 5: Thermal Efficiency Comparison for CMB TM 

### CasesECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 65 

### 2.6 Repowering Case

Most of the older existing coal fired power plants generate power at lower efficiencies than could be produced with the modern state-of-the-art powe r plants. In exploring a means of upgrading the efficiencies of these plants, a study was performed to determine the economic benefit of a repowered plant for hig her steam cycle parameters. Unit #4 of the Philip Sporn power plant, owned and operated by American Electric Power (AEP), has been selected for the analysis. The existing plant (Unit #4) is a pulverized coal unit burning low sulfur coal and capable of generating approximately 169 MWe utilizing a steam cycle wi th steam turbine conditions of 1,050°F /1,000°F/2,015 psia.

The proposed repowering concept is illustrated in Figure 2.6.1. It uses a number of new plant components and integrates and utilizes the existi ng components to the maximum extent practical. The repowered plant includes a new CMB TM 

### boiler (refer to Section 2.5.2.1 for CMB TM 

### background) capable of producing steam at 1,292°F/1,005°F/4,337psia conditions. It also includes a new topping steam turbine that expands steam from the new CMB TM 

### boiler at 1,292°F/4,337psia to the steam conditions of 1, 050°F/2,015 psia, which match the throttle conditions of the existing steam turbine. T he topping turbine produces an output of about 32 MWe. The exhaust steam from the topping steam tu rbine, at 2,015 psia and 1,050oF, is piped to the existing steam turbine where it expands through the HP turbine. From the HP turbine exhaust, the steam, at about 505 psia, is piped to the new reheater section installed in the CMB TM 

### boiler where it is reheated to 1,005°F. The reh eated steam is then piped back to the existing IP turbine for further expansion and power generation. The installation of the small sized topping steam turbine close to the CMB TM 

### boiler minimizes the length of the very expensive high temperature steam piping.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 66 2

2

27

31 22 20

Demineralizer From Cond pump

To first feedwater hrt 4

1

17 19

5

3

10

9

11
14

16 15 6

7

8 12 34

33

23

24 26

28

32 30

29 13

15 21 18

4

1 coal feed 13 primary air leaving air htr 25 Fin reheater 2 combustor 14 fluidizing air to nozzles 26 Fin reheat to the existing IP turbine 3 flue gas 15 primary air bauxite transport 27 Primary reheater 4 cyclone 16 bauxite 28 RH inlet piping from the existing HP turbine 5 flue gas leav cyclone 17 primary air/bauxite transport 29 existing feedwater pipe 6 air heater 18 Bauxite cyclone 30 feedwater booster pump 7 flue gas to exist precipitator 19 primary air leaving bauxite cycln 31 Economizer 8 secondary air 20 SH fin system in MBHE 32 feedwater piping to economizer 9 overfire sec air 21 Main steam line 33 primary air fan 10 recycled ash/carbon 22 Topping steam turbine 34 secondary air fan 11 combustion air 23 Generator 12 primary air 24 Exhaust steam to existing HP steam turbine



### Figure 2.6. 1: Simplified Schematic of AEP’ s Philip Sporn Plant Repowered with a High Efficiency Steam Cycle

This case utilizes the existing electrostatic precipit ator for particulate removal and also the existing ID fan, some existing ductwork, and the existing stack. Figure 2.6.2 shows a simplified process flow diagram for the Boiler Island and Table 2.6.1 shows the inlet and outlet stream conditions.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 67 

### Figure 2.6. 2: Simplified Gas Side Process Flow Diagram for the Repowering Case

Air Heater

Secondary A ir Fan

Primary A ir Fan

Transport Air Coal

Fluidizing A ir Blower Limestone

Cooled Solids Falling Solids Combustor Cyclone CMB TM Steam Generator Unit

1

2

Moving Bed Heat Exchanger Induced Draft Fan
FDA & Particulate Removal

3 A sh Cooler Cyclone

7 S t

a
c k

4

6

5



### Table 2.6. 1: Gas Side Material and Energy Balance for the Repowering Case
Sporn Repowering Point 1 Point 2 Point 3 Point 4 Point 5 Point 6 Point 7 Coal Limestone A sh Cooler ID Fan PA Fan SA Fan FA Fan Units In In Out Out In In In Flow lbm/hr 135,967 0 5,275 1,707,351 1,384,658 157,939 24,528 Temperature Deg F 80 80 250 267 80 80 80 Gas Analysis N2 % weight n/a n/a n/a 70.71 74.55 74.55 74.55 CO2 % weight n/a n/a n/a 19.07 0.04 0.04 0.04 H2O % weight n/a n/a n/a 5.00 1.30 1.30 1.30 O2 % weight n/a n/a n/a 4.97 22.84 22.84 22.84 SO2 % weight n/a n/a n/a 0.16 0.00 0.00 0.00 Ar % weight n/a n/a n/a 0.09 1.27 1.27 1.27


### A brief performance summary for this repowering case reveals the following information. The topping steam turbine will generate approximat ely 32 MWe thereby increasing total plant generator output to approximately 204 MWe. In addition to the increased generating capacity the net plant heat rate improves by approximately 8% or 2.7 percentage points in plant thermal efficiency. The new CMB TM 

### boiler is sized for the required additional firing rate that is about 9.8% higher than in the existing boiler. The repowe red supercritical plant produces a net output of about 185 MWe with a net plant heat rate and thermal efficiency of 8,889 Btu/kWh and 39.40 percent respectively. Detailed plant performance fo r the Repowering Case as well as the existing Sporn plant for comparison is shown in Section 2.6.5.

2.6.1 Steam Cycle for the CMB TM 

### Repowering Case The steam cycle for the repowering case starts at the inlet to the new topping steam turbine. Refer to figure 2.6.3 for the repowering case steam cycle schematic. The new topping steam turbine provides 1,077,835 lbm/hr of steam at 1,292°F/4,337psia from the new CMB TM 

### boiler. This steam is expanded in the topping turbine to exhaust conditions of 1,050°F/2,015 psia. The new topping steam turbine generator produces about 32 MWe of output. The topping turbine was selected such that the exhaust conditions match the required thro ttle conditions of the existing steam turbine. The topping turbine steam flow is selected to provide the existing high-pressureECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 68 

### turbine with the same flow as it would nor mally expand under MCR conditions. The steam from the topping steam turbine exhaust is piped directly to the existing HP steam turbine inlet where it expands through the existing HP turbine section. From the HP turbine exhaust, the steam is piped to the new reheater section located in the new CMB TM 

### boiler. The steam is reheated to 1,005°F in the new boiler. The hot reheated steam is then piped back to the existing IP turbine for further expansion through the existing IP and LP turbine sections and power generation. The existing HP, IP, and LP steam turbine sections produce about 172 MWe generator output. The total generator output from the new topping turb ine and the existing steam turbine is about 204 MWe.ECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 200469HHGEGEGSGS5.4SESEHEAT BALANCE DIAGRAMPHILIP SPORN PLANTTopping SP 700C ,HP Flow as wasMikael_JoenssonTSDAH-22003-04-30/11:12WinAlpro - V3.09/2002-12-02/2Water/Steam IFC67Drawn:Checked:Approved:2003-04-09Doc F L Sh.No. N.o.Sh.EPTHMTSPressureTemperatureEnthalpyMassflowSaturation temperaturepsia'FBtu/lblb/h'FWe 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 Copyright © ALSTOM Power (Switzerland) Ltd 2003S:\AEP\Final2\AEP_Philip_Sporn_Topping.algM59H1338M174H1338M174H1338M59H1338P 14.94P 11.60E_KIN9.2E_KIN9.2M60H1521P 11.60M11H1521M16H1521M59H1338M101H1338P14.94M101H133811.15.1 5.432.45.45.25.3M221H1354M283H1354M20H1505M18H1505M327H1474M-25H1466P11.60P14.94P85.93M483H1354M432H1505GGland system sprayGland system excess steamGland sealing system excessGSGESEQin_Boiler 1256406900Qin_Reheater 201830290Qin_Total 1458237200Gross_KW 203807Gross_HeatRate 7154Steam_Cycle_Aux_Power 6798Semi_Net_HeatRate 7401G2.88.0 11.58.1 11.6P 504.9T 699.0H 1356.8M 98929P 196.4T 785.9H 1418.4M 6938P 2522T 316.6H 291.3M 1077835P 46.81T 276.9H 1147.8M 49843P 20.74T 327.4H 1204.4M 19521P 11.60T 794.9H 1430.7M 8929P 9.671T 213.2H 1153.0M 39326P 3.100T 142.8H 1086.5M 32499P 310.0T 267.9H 237.3M 942566T 366.3H 342.5M 40340T 310.7H 280.8P 458.6T 1000.0H 1521.5M 964416P 504.9T 699.0H 1356.8M 1023005P 4242T 1292.0H 1609.9M 1077835P 9.671T 213.2H 1153.0M 826100T 60.0H 28.2M 6239M 6239M 1200T 93.6H 61.6M 832174P 0.781T 93.6H 107.7M 32499T 220.7H 189.6T 197.5H 166.2T 183.7H 152.4T 134.4H 103.1T 95.9H 64.7P_EL 43886P_EL 128081P 2016T 1050.0H 1505.0M 1039500T 671.3H 1365.9M 52518T 374.4H 351.6T 312.0H 299.1T 188.4H 168.4T 200.3H 194.2T 225.9H 242.2P 0.781H 1024.0M 795899P 85.93T 979.0H 1521.5M 5476T 671.3H 1365.9M 16791M15H1503M197H1503M42H1609M26H1609M10H1609M140H1609P11.60P14.94P196.4M199H1503M140H1609GP 196.4T 1034.4H 1547.3M 34015P 4587T 460.0H 444.2M 1077835P 2522T 452.7H 434.5M 1077835P_EL 31840Figure 2.6. 3: Repowering Case Steam Cycle Schematic DiagramECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 70 

### Exhaust steam from the existing LP turbine is condensed in the existing condenser and also utilizes the existing condensate an d feedwater systems to provi de preheated feedwater to the new CMB TM 

### boiler as described below.
The condensate leaving the existing condenser fl ows to the suction of the existing condensate pumps, which increase the pressure of the fl uid and transport it through the new condensate polishing system, the existing low-pressure f eedwater heaters, and the existing condensate piping system which enables it to enter the ex isting open contact heater or deaerator. The condensate passes through the existing gland steam condenser first, followed in series by five low-pressure feedwater heaters. The heaters successively increa se the condensate temperature to 267.9°F by condensing and partially sub-coo ling steam extracted from the existing LP steam turbine section. Each heater receives a separat e extraction steam stream at successively higher pressure and temperature. The condensed st eam (now referred to as heater drains) is progressively passed to the next lower pressure heater.
The condensate entering the deaerator is furt her heated and stripped of non-condensable gases by contact with the steam entering the deaerator . The steam is condensed and, along with the heated condensate, flows by gravity to a deaerato r storage tank. The existing boiler feedwater pumps take suction from the storage tank and increase the fluid pressure to 2,522 psia. Both the condensate pump and boiler feed pump are electr ic motor driven. The boosted condensate flows through two existing high-pressure feedwater heat ers, increasing in temperature to 452.7°F. The condensate (referred to as boiler feedwater) then enters the new boiler feedwater booster pump where the pressure is increased to 4,587 psia. The new boiler feedwater booster pump is electric motor driven. Each high-pressure feedwater heat er receives a separate extraction steam stream at successively higher pressure and temperature. The condensed steam (drains) is progressively passed to the next lower pressure heater, with t he drains from the lowest high-pressure heater draining to the deaerator.

Within the new CMB TM 

### boiler, the feedwater is progressi vely heated to superheater outlet conditions in a “once through” arrangement and supplied to the new topping steam turbine completing the steam cycle for the repowering case.

2.6.2 Steam Generator Design for the CMB TM 

### Repowering Case The CMB TM 

### steam generator unit for the repowering case was designed for a nominal capacity of 204 MWe gross to match the repowered steam cy cle described above. The basic description of operation and CMB TM 

### background information was provided previously for Cases CMB TM 

### -3 and CMB TM 

### -5 in Section 2.5.2 and is not repeated here.

2.6.2.1 Heat Transfer Surfaces and Arrangement for the CMB TM 

### Repowering Boiler

The CMB TM 

### combustor, shown on the general arra ngement drawings, Figure 2.6.4 and Figure 2.6.5 is a cylindrical vessel having an approximate diameter of 38 feet. Crushed coal is uniformly distributed across the combustor plan area to insure a uniform temperature profile in the combustor. The combustor walls are refractory lined. The upward moving products of combustion transfer the heat generated by burni ng the coal to the downward falling high alumina content solid particles, injected at the top of the combustor. These solid particles form a bubbling bed at the bottom of the combustor. The bubbling bed temperature is controlled to maintain 2000°F. The flue gas with some entrained solid particles and ash, which includes some unburned carbon, exits the combustor at 1200°F and enters four refractory lined cyclones. The solid particles are removed in the cyclone and are recycl ed back to the combustor. From the cyclone, the flue gas then enters the un-cooled backpass where a finned tube economizer is installed. Downstream of the economizer there is a last he at transfer surface, the Ljungstrom air preheater, that captures heat from the flue gas to raise the temperature of the primary and secondary airECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 71 

### entering the furnace. The flue ga s exiting the air preheater proceeds to the existing ESP for the final clean up.

Figure 2.6. 4: CMB TM 

### Combustor General Arrangement Drawing (Side Elevation)

Figure 2.6. 5: CMB TM 

### Combustor General Arrangement Drawing (Plan View)ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 72 

### The hot solid particles from the combustor bubbling bed are transported to a single square shaped (22x22’) moving bed heat exchanger via a set of standpipes. The heat exchanger accommodates the heat transfer surfaces and the solids moving downward transfer heat to the SH finishing section, RH finishing section, LT SH section, LTRH section, and finally the oncethrough evaporator. The surface arrangement is shown on Figure 2.6.6. All heat transfer surfaces are constructed with finned tubes.

Figure 2.6. 6: CMB TM 

### Moving Bed Heat Exchanger Surface Arrangement

The water-steam system includes an integrated start-up system similar to the one discussed in Section 2.3.2.5. The cooled solid particles l eave the moving bed heat exchanger at about 1000 0 

### F and are transported by the secondary air to the top of the combustor. At the top of the combustor there are four small cyclones that separate the solid particles and distribute them uniformly across the combustor to repeat the flue gas to solid particles heat exchange process again. The air leaving the cyclones provides se condary combustion air for the furnace.

2.6.2.2 Materials for the CMB TM 

### Repowering Boiler The tubing materials for the construction of the superheater require Ni-based alloys for high temperature sections. The primary alloy used fo r the superheat section are IN 740, Hayness 230, and stainless steel 347H. The materials of constr uction for the reheater se ction are stainless steel 304H and 347H.
The once-through evaporator and ec onomizer sections are constructed of ferritic alloys T-91, T12 and carbon steel SA-106B.

The fin material varied from carbon steel for the economizer tubes to ferritic for the evaporator and stainless steel for the reheat and superheat tubes.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 73 

### The headers and piping, except for the superheat finishing header and main steam piping to the topping turbine are made of conventional boiler a lloys. Inconel 617was used for these higher temperature components.
2.6.2.3 Firing System for the CMB TM 

### Repowering Boiler The firing system for the CMB TM 

### repowering boiler is of the same basic design as was used for the Greenfield CMB TM 

### boilers. It is described previously in Section 2.5.2.4 and is not repeated here. The components for the repowering case, ho wever, are much smaller since the repowering case produces about 204 MWe and the Greenfield CMB TM 

### cases produce more than 730 MWe.

2.6.2.4 Air Heater System for the CMB TM 

### Repowering Boiler The air heater system for the CMB TM 

### repowering boiler is of the same basic design as was used for the Greenfield CMB TM 

### boilers. A single tri-sector unit was selected for this case. It is described previously in Section 2.5.2.5 and is not repeated here. The components for the repowering case, however, are much smaller since the repowering case produces about 204 MWe and the Greenfield CMB TM 

### cases produce more than 730 MWe.

2.6.2.5 Start up System for the CMB TM 

### Repowering Case The start-up system used for the CMB TM 

### repowering is the same as was used for the Greenfield CMB TM 

### boilers. It was described previously in Se ction 2.5.2.6 and it is not repeated here.

2.6.3 Balance of Plant Equipment for the CMB TM 

### Repowering Case The CMB TM 

### boiler inherently generates low NO x 

### emissions. Compared to the existing boiler emission of 0.57 lbm/MM-Btu, the predicted emission from the CMB TM 

### boiler would be 0.10 lbm/MM-Btu. The balance of plant equipment descr ibed in this section includes the gas cleanup system equipment and other BOP equipment. The equipment in the category of other BOP equipment includes the draft system equipmen t, the cooling system equipment, the material handling equipment (coal, limestone, and ash), electrical equipment, and miscellaneous BOP equipment. Refer to Appendix I for equipment lists and Appendix II for drawings.

2.6.3.1 Gas Clean-up Systems for the CMB TM 

### Repowering Case The gas cleanup system used for the repowering case is the same as what is used for the existing Sporn plant, which consists of an electros tatic precipitator for particulate removal. No sulfur removal equipment is used for the exis ting plant. Because of the limited scope for this repowering study, it was agreed with AEP that in the framew ork of this study, no additional environmental control systems would be consid ered as long as the repowered system meets current emission levels. However, as a part of the economic analysis (Section 4.3.3) limestone injection to remove 30% of the sulfur was also considered.

2.6.3.2 Other BOP Systems for the CMB TM 

### Repowering Case Other BOP equipment includes the draft system equipment, the cooling system equipment, the material handling equipment (coal and ash), electrical equipment, and miscellaneous BOP equipment.
Analysis has shown that for the repowered pl ant, the increased firing rate should not be a problem for many of the existi ng components such as the ESP and ID fans. Much of the existing Sporn Unit #4 balance of plant equipment is utilized for the repowered case. The following additional new balance of plant equipment has been identified (major items only):

• FW booster pump

• Condensate polishing system (full flow)

• Coal feed system

• Air fans and blowers

• TransformerECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 74 

### • Ductwork and dampers

• Feedwater and steam piping
Draft System: The flue gas is moved through the new CMB TM 

### boiler, the existing precipitator, and other Boiler Island equipment with the draft system as shown in Figure 2.6.7. The draft system includes new primary and secondary air fans, the existing induc ed draft (ID) fan, the associated ductwork and expansion joints (some existing), and the existing stack, which disperses the flue gas leaving the system to the atmosphere. The induced draft (existing), primary air, and secondary air fans are driven with electric motors and controlled to oper ate the unit in a balanced draft mode with the furnace outlet maintained at a slightly negative pr essure (typically, -0.5 inwg). A forced draft primary air (PA) fan provides hot air to the comb ustor bottom. It is preheated in a regenerative air preheater. Part of this stream is also used for transport of cooled particles leaving the MBHE to the cyclones at the top of the combustor where the particles are recirculated to the combustor. The air leaving the cyclones is used for combustion air in the combustor as shown below.

ESP

A i

r

H

e
a t

e
r Cold PA to Fuel Feed ISO Valves

PA Fan SA Fan ID Fan

A E E1 F O

COMBUSTOR S

K

J N

MBHX R Hot PA to Fuel Chutes D1

D

R1 G1

L L

C G

B K BACKPASS



### Figure 2.6. 7: Draft System Schematic Diagram

A forced draft secondary air (SA) fan provides an ai r stream to the combustor that is preheated in a regenerative air preheater and is then introduced into the furnace as secondary air for combustion of the coal.
The flue gas exiting the furnace passes throug h the cyclones and convection pass of the unit, which contains the economizer section. The fl ue gas leaving the convection pass flows through the regenerative air preheater and then exits t he unit and flows to the precipitator for final particulate capture. The flue gas is drawn throug h the precipitator and other equipment with the Induced Draft (ID) Fan (existing) and is discharged to atmosphere through the stack.
The following fans are provided with the scope of supply of the steam generator:



## • Primary air fans, which provides forced draft pr imary airflow. These fans are centrifugal type units, supplied with electric motor drives, inlet screens, inlet vanes, and silencers. The total electric power required for the electric motor drives is 4,182 kW.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 75 

## • Secondary air fans, which provides forced draft secondary airflow. These fans are centrifugal type units supplied with electric motor drives , inlet screens, inlet vanes, and silencers. The total electric power required for the electric motor drives is 240 kW.



## • Induced draft fans (existing), centrifugal units with electric motor drives and inlet dampers. The total electric power required for the electric motor drives is 2,224 kW for all five cases.

2.6.4 Existing Sporn Plant Description and Performance

The existing Philip Sporn plant is owned by AEP and is located in New Haven, West Virginia on a site adjacent to the Ohio River. The plant includes five coal-fired units. Units 1-4 are identical subcritical units generating about 170 MWe each at full load and unit 5 is a large supercritical unit.
The unit selected for the retrofit study is Unit #4 of the Philip Sporn plan t. This unit burns low sulfur mid-western high volatile bituminous coal in a pulverized coal fired boiler. The existing boiler was designed by Babcock & Wilcox and is a front wall fired reheat unit with subcritical steam conditions. The unit is a relatively old unit in their system but still operates and dispatches quite well with availability typically in the 85% range.
A partial view of the site is shown below in Fi gure 2.6.7. Unit #4 is located in the upper right center of Figure 2.6.7. The site was determined to have sufficient space available, adjacent to the existing Unit #4 building and precipitator, to allow installation of the new equipment.

Figure 2.6. 8: Existing Sporn Site PlanECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 76 

### Unit #4 utilizes an electrostatic precipitator for particulate re moval and has no sulfur removal equipment. This section will show the performance of the existing unit for comparison to the repowered unit. Figure 2.6.8 shows a simplified ga s side process flow diagram for the existing unit and Table 2.6.2 shows the associated inlet and outlet stream conditions for the Boiler Island of this unit.

Tri-Sector

Ash Air Heater

Coal Induced Draft Fan

Secondary Air Fan

Coal Mill System 1 2 ESP Steam Generator Unit S t

a
c k

5 4 3

Primary Air Fan



### Figure 2.6. 9: Simplified Gas Side Process Flow Diagram for the Existing Sporn Unit #4

Table 2.6. 2: Gas Side Material and Energy Balance for the Existing Sporn Unit #4 

### Sporn Existing Point 1 Point 2 Point 3 Point 4 Point 5 Coal A sh Cooler ID Fan PA Fan SA Fan Units In Out Out In In Flow lbm/hr 123,798 2,836 1,554,555 286,735 1,140,143 Temperature Deg F 80 250 290 80 80 Gas Analysis N2 % weight n/a n/a 70.71 74.55 74.55 CO2 % weight n/a n/a 19.07 0.04 0.04 H2O % weight n/a n/a 5.00 1.30 1.30 O2 % weight n/a n/a 4.97 22.84 22.84 SO2 % weight n/a n/a 0.16 0.00 0.00

Ar % weight n/a n/a 0.09 1.27 1.27



### A brief performance summary for this existing case reveals the following information. The existing steam turbine will generate approximately 169 MWe at full load. The subcritical plant produces a net output of about 157 MWe with an auxiliary power consumption of about 7.2 percent of generator output. The resulting net plant heat rate and thermal efficiency are 9,561 Btu/kWh and 35.70 percent respectively. Detailed plant perfor mance for the existing Sporn Unit #4 and the repowering case are shown in Section 2.6.5.
The existing Unit #4 steam turbine is a General Electric turbine which generates ~169 MWe gross output with steam conditions of 1,050°F/1,000°F /2,015 psia. The steam cycle utilizes eight feedwater heaters to provide feedwater to the boile r at 453°F. Figure 2.6.10 shows the existing Sporn Plant Unit #4 steam cycle.ECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 200477HHGEG EG SGS5.1SESEHEAT BALANCE DIAGRAMPHILIP SPORN PLANTAs IsMikael_Joens sonTSDAH-2200 3-0 4-3 0/16:26Win Alpro - V3.09/2002Water/Steam IFC67Drawn:Checked :App roved:2003 -04 -09Doc F L Sh.No. N.o.Sh.EPTHMTSPressureTemperatureEnthalpyMassf lowSaturation temperaturepsia'FBtu/lblb/h'FWe r eserve all r ights in this doc ument and in the infor mation c ontained therein Reproduc tion use or dis clos ure to third parties without expres s authority is str ictly forbidden C opyright © ALSTO M Power (Switz erland) Ltd 2003S:\AE P\Final2\A EP_Philip_Spor n.alg M 604 H 1329.6 M 1764 H 1329.6 M 1764 H 1329.6 M 604 H 1329.6P 14.94P 11.60

E_KIN8.7 E_KIN8.7

M 604 H 1521.7P 11.60

M 8 H 1521.7 M 166 H 1521.7 M 604 H 1329.6

M 1032 H 1329.6P 14.94

M 1032 H 1329.610.85 .0 5.432.45.15.05.0

M 2213 H 1353.3 M 2638 H 1353.3 M 202 H 1505.0

M 183 H 1505.0 M 3499 H 1390.6

M -2823 H 1363.2P 11.60P 14.94P 82.50

M 4938 H 1353.3 M 4301 H 1505.0GGland s ystem sprayGland s ystem ex ces s steamGland s ealing s ystem ex ces sGSGESEQin_Boiler 1118629Qin_Reheater 2030178Qin_Total 1321647Gross _KW 168604Gross _HeatRate 7839Steam_Cy cle_Aux_Pow er 3642Semi_Net_HeatRate 8012Total_Aux _Pow er 11170Boiler_Eff icienc y 0.89NUHR 9429GMis c. SteamLos ses &Blow dow n4.87.9 12.07.8 12.0P 499.7T 696.9H 1356.0M 98476P 188.6T 779.3H 1415.4M 43329P 2522T 451.6H 433.4M 1050334P 2522T 313.7H 288.3M 1050334P 44.90T 274.3H 975.8M 58046P 19.90T 322.9H 1202.4M 18528P 11.60T 696.9H 1382.5M 8496P 9.300T 209.6H 1151.4M 36982P 3.006T 141.5H 1085.6M 30590P 310.0T 264.9H 234.3M 914367T 363.2H 339.2M 40340T 307.8H 277.8P 452.9T 1000.0H 1521.7M 965013P 499.7T 696.9H 1356.0M 1023148P 2015T 1050.0H 1505.0M 1041594P 9.300T 209.6H 1151.4M 795611T 60.0H 28.2M 14979M 6239M 1200T 93.6H 61.6M 799131P 0.781T 93.6H 106.7M 30590T 218.8H 187.7T 195.5H 164.3T 182.4H 151.1T 133.7H 102.5T 95.9H 64.8M 8740P_EL 44166P_EL 124438P 2015T 1050.0H 1505.0M 1039500T 669.7H 1365.3M 50719T 371.0H 348.8T 309.1H 296.5T 186.7H 168.4T 200.3H 192.1T 223.8H 238.9P 0.781H 1024.3M 767341P 82.50T 979.1H 1521.7M 5485T 669.7H 1365.3M 16216Figure 2.6.10: Existing Sporn PlantSteam Cycle Schematic DiagramECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 78 

### 2.6.5 Overall Plant Performance for the CMB TM 

### Repowering Case

Table 2.6.3 shows a fairly detailed breakdown of various plant performance parameters for the repowering case and the existing unit for comparison. T he table compares pl ant auxiliary power, steam conditions, generator output, net plant output, fuel heat input, net plant heat rate, and thermal efficiency. Figure 2.6.10 illustrates the th ermal efficiency improv ement for the repowered case. The improved steam conditions for the repowe red case are shown to improve plant thermal efficiency by about 2.7 percentage points or about 7.6 percent.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 79 

### Table 2.6. 3: Overall Plant Performance Comparison for Repowering Case Repower Existing 

## Auxiliary Power Listing (units) 

### Feedwater Pumps (mechanical) (kw) 

### 6379 3231 Feedwater Pumps (electrical) (kw) 

### 7088 3590 Main Condensate Extraction Pumps (kw) 

### 280 269 Main Cooling Water Pumps (kw) 

### 1309 1262 Secondary Cooling Water Pumps (kw) 

### 55 53 Closed Circuit Cooling Water Pumps (kw) 

### 101 97 Cooling Tower Fans (kw) 

### n/a n/a Forced Draft Fans (kw) 

### 240 470 Primary Air Fans (kw) 

### 4182 524 Induced Draft Fans (kw) 

### 2224 2025 Fluidizing Air Blowers (kw) 

### 182 n/a Coal Handling (kw) 

### 99 90 Pulverizers (kw) 

### n/a 986 Ash Handling (kw) 

### 783 622 Limestone Handling (kw) 

### n/a n/a Electrostatic Precipitator (kw) 

### 719 655 FGD or FDA System (kw) 

### n/a n/a SCR or SNCR Auxiliary Power (kw) 

### n/a n/a Boiler Circulation Pumps (kw) 

### n/a n/a Misc. Aux. Power (Controls, Lighting, HVAC, etc.) (kw) 

### 844 768 Transformer Loss (kw) 

### 815 674 Total Auxiliary Power Consumption (kw) 

### 18920 12086 Fraction of Generator Output (fraction) 

### 0.093 0.072 Fraction of Generator Output (w/o BFP) (fraction) 

### 0.058 0.050


## Steam Cycle Parameters Main Steam Pressure (psia) 

### 4242 2015 Main Steam Temperature (Deg F) 

### 1292 1050 Reheat Steam Temperature (Deg F) 

### 1000 1000 Feedwater Temperature (Deg F) 

### 460 453 Number of Feedwater Heaters (no.) 

### 8 8


## Efficiency and Output Boiler Efficiency (HHV basis) (fraction) 

### 0.8873 0.8816

Steam Cycle Efficiency (fraction) 

### 0.4604 0.4269 (Btu/kwhr) 

### 7413 7994

Generator Output (kw) 

### 203807 168604

Net Plant Output (kw) 

### 184887 156518

Fuel Heat Input (HHV basis) (MM-Btu/hr) 

### 1643 1496

Net Plant Heat Rate (HHV basis) (Btu/kwhr) 

### 8889 9561 Thermal Efficiency (HHV basis) (fraction) 

### 0.3840 0.3570 

## --Sporn Unit #4--ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 80 

### 0.3840

0.3570



### 0.34 0.35 0.35 0.36 0.36 0.37 0.37 0.38 0.38 0.39 0.39

Repower ExistingThermal Efficiency - HHV (fraction)



### Figure 2.6.11: Thermal Efficiency Compar ison for the Repowered and Existing UnitECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 81 

### 2.7 Overall Plant Performance Comparison (all Cases)

Steam power production is based on a thermody namic cycle known as the Rankine cycle. The measure of the ability of the Rankine plant to convert heat released in a furnace to generate electrical power is the plant thermal efficiency. In the industry, it is customary to express this efficiency in terms of a net plant heat rate (N PHR). Since, by definition, one kilowatt-hour of electrical power is equivalent to 3412.7 Btu, to c onvert the thermal efficiency to net plant heat rate divide 3412.7 Btu/kWh by the efficiency fraction. The thermal efficiency may be determined in one of several ways. In the “input-output method, the fuel energy input and the net plant power output are determined and the plant heat rate and thermal efficiency are calculated as follows:

NPHR = Mcoal x HHV / (Wgen out - Waux)

Or:
Thermal Efficiency = (3412.7/NPHR) x 100%

Where:
NPHR = Net plant heat rate (Btu/kWh) Mcoal = Mass flow rate of coal fired (lbm/hr) HHV = Higher heating value of coal (Btu/lbm) Wgen out = Gross generator output (kW) Waux = Power consumed by auxiliary components (kW)

The net plant heat rate depends on many factor s. Some of the major factors are listed below:

• Steam turbine throttle pressure

• Main steam and reheat steam temperatures

• Number of reheat stages

• Number of feedwater heaters

• Steam turbine design

• Steam turbine isentropic expansion efficiencies

• Condenser pressure

• Type of coal fired

• Auxiliary components

• Component pressure drops

2.7.1 Auxiliary Power Basis: The largest power consumers in the cycle are the electrically driven boiler feedwater pumps. The sum of the mechanical drives power requi rements at the pump shaft for the two pumps operating in parallel was determined by a program for circuit computation. These values were then entered into the appropriate st eam cycle energy balances. The efficiency of the entire boiler feed pump drive system, which comprises a me chanical speed-transforming gear, a hydraulic variable-speed gear, and an asynchronous motor, was estimated at 0.90 for the 100 % load point.
Power consumption for other auxiliary compo nents and systems were then determined rigorously for Case PC-1. Using the Case PC-1 as t he basis, the auxiliary power requirements wereECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 82 

### determined for all other cases by linear interpolati on. Specifically, the interpolation was performed in accordance with the following list:

• Main condensate extraction pumps: Proportional to the condensate mass flow (But 15 % higher in supercritical cases because of the additional pressure loss of the condensate polishing plant)



### • Main cooling water pumps: Proportional to the condenser heat rejection quantity

• Secondary cooling water pumps: Proportional to the condenser heat rejection quantity (But 20 % higher in supercritical cases because of the higher feedwater pump power consumption)



### • Closed circuit cooling water pumps: Proportional to the secondary cooling water pump power consumption

• Forced draft fans: Proportional to the fuel heat input

• Primary air fans: "

• Induced draft fans: "

• Coal handling system: "

• Pulverizers: "

• Ash handling system: "

• Electrostatic precipitator: "

• Boiler circulation pumps: " (Zero for supercritical cases)



### • Other auxiliary power consumpti on: Constant value for all cases

• Transformer efficiency 99.6 %

2.7.2 Plant Performance Summary: Table 2.7.1 shows a fairly detailed comparison of the various plant performance parameters for all cases. This table includes detailed plant auxiliary power breakdowns, boiler and steam cycle efficiencies, steam conditions, generator outputs, net plant outputs, fuel heat inputs, net plant heat rates, and plant thermal efficiencies for all the cases considered in this study.
Figures 2.7.1 – 2.74 illustrate, fo r all the cases, the primary plant performance parameters which contribute to the plants overall thermal efficien cy. Bars of a uniform color and case numbers indicate common steam cycles among the cases. The last two bars compare the repowered and existing unit cases of the Sporn Unit #4 repowering study.
Figure 2.7.1 shows the comparison of boiler effi ciency for all cases. The PC and CFB cases of the Greenfield study are identical whereas the CMB TM 

### case is about 0.5 percentage points lower. The lower value for the CMB TM 

### cases is due to partial sulfation in the combustor.
Figure 2.7.2 shows for all cases the comparison of steam cycle thermal efficiency and the effects of steam parameters.
Figure 2.7.3 shows for all cases the comparison of tota l plant auxiliary power. The CMB TM 

### cases are slightly lower than the PC and CFB cases at the same steam conditions. Also because the boiler feed pumps are electrically driven, the steam cycle variation also affects this parameter.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 83 

### Finally, Figure 2.7.4 shows for all cases the compar ison of overall plant thermal efficiency, which represents the combined effects of changes in boiler efficiency, steam cycle efficiency, and auxiliary power.
Additionally, Figure 2.7.5 shows a comparison of specific CO 2 

### emissions (lbm/kWh) for all the cases. This figure in combination with Fi gure 2.7.4 shows the dire ct correlation of CO 2 

### emissions and plant thermal efficiency.ECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 200484Table 2.7. 1: Overall Plant Performance Comparison (all Cases)PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 Repower ExistingAuxiliary Power Listing(units)Feedwater Pumps (mechanical)(kw)15606 15187 22799 25858 29316 15187 22799 25858 22799 29316 6379 3231Feedwater Pumps (electrical)(kw)17340 16874 25332 28731 32573 16874 25332 28731 25332 32573 7088 3590Main Condensate Extraction Pumps(kw)1255 1197 1347 1317 1026 1197 1347 1317 1347 1026 280 269Main Cooling Water Pumps(kw)4799 4728 4627 4521 4237 4728 4627 4521 4627 4237 1309 1262Secondary Cooling Water Pumps(kw)202 199 234 228 214 199 234 228 234 214 55 53Closed Circuit Cooling Water Pumps(kw)370 365 428 418 392 365 428 418 428 392 101 97Cooling Tower Fans(kw)3300 3251 3182 3109 2914 3251 3182 3109 3182 2914 n/a n/aForced Draft Fans(kw)1589 1589 1589 1589 1589 3876 3876 3876 1219 1219 240 470Primary Air Fans(kw)1322 1322 1322 1322 1322 7904 7904 7904 14037 14037 4182 524Induced Draft Fans(kw)8950 8950 8950 8950 8950 10924 10924 10924 7740 7740 2224 2025Fluidizing Air Blowers(kw)n/a n/a n/a n/a n/a 2875 2875 2875 840 840 182 n/aCoal Handling(kw)350 350 350 350 350 350 350 350 352 352 99 90Pulverizers(kw)1949 1949 1949 1949 1949 n/a n/a n/a n/a n/a n/a 986Ash Handling(kw)2417 2417 2417 2417 2417 2783 2783 2783 2783 2783 783 622Limestone Handling(kw)741 741 741 741 741 1153 1153 1153 1159 1159 n/a n/aElectrostatic Precipitator(kw)1400 1400 1400 1400 1400 n/a n/a n/a n/a n/a 719 655FGD or FDA System(kw)13200 13200 13200 13200 13200 1260 1260 1260 1267 1267 n/a n/aSCR or SNCR Auxiliary Power(kw)200 200 200 200 200 106 106 106 106 106 n/a n/aBoiler Circulation Pumps(kw)621 621 n/a n/a n/a n/a n/a n/a n/a n/a n/a n/aMisc. Aux. Power (Controls, Lighting, HVAC, etc.)(kw)3000 3000 3000 3000 3000 3000 3000 3000 3000 3000 844 768Transformer Loss(kw)2785 2845 2945 3016 3285 2845 2945 3016 2945 3285 815 674Total Auxiliary Power Consumption(kw)65790 65198 73212 76458 79759 63690 72325 75571 70596 77144 18920 12086Fraction of Generator Output (fraction)0.094 0.092 0.099 0.101 0.097 0.090 0.098 0.100 0.096 0.094 0.093 0.072Fraction of Generator Output (w/o BFP) (fraction)0.070 0.068 0.065 0.063 0.057 0.066 0.064 0.062 0.061 0.054 0.058 0.050Steam Cycle ParametersMain Steam Pressure(psia)2408 2408 3625 3915 5075 2408 3625 3915 3625 5075 4242 2015Main Steam Temperature(Deg F)1000 1049 1049 1085 1292 1049 1049 1085 1049 1292 1292 1050Reheat Steam Temperature(Deg F)1000 1112 1112 1148 1328 1112 1112 1148 1112 1328 1000 1000Feedwater Temperature(Deg F)500 500 500 554 626 500 500 554 500 626 460 453Number of Feedwater Heaters(no.)777897787988Efficiency and OutputBoiler Efficiency (HHV basis)(fraction)0.8975 0.8975 0.8975 0.8975 0.8975 0.8975 0.8975 0.8975 0.8926 0.8926 0.8873 0.8816Steam Cycle Efficiency(fraction)0.4442 0.4543 0.4650 0.4745 0.5161 0.4543 0.4650 0.4745 0.4650 0.5161 0.4604 0.4269(Btu/kwhr)7683 7512 7339 7193 6613 7512 7339 7193 7339 6613 7413 7994Generator Output(kw)696316 711278 736148 753937 821374 711278 736148 753937 736148 821374 203807 168604Net Plant Output(kw)630526 646080 662936 677479 741615 647588 663823 678366 665552 744230 184887 156518Fuel Heat Input (HHV basis)(MM-Btu/hr)5812 5812 5812 5812 5812 5812 5812 5812 5844 5844 1643 1496Net Plant Heat Rate (HHV basis)(Btu/kwhr)9218 8997 8768 8580 7838 8976 8756 8568 8781 7853 8889 9561Thermal Efficiency (HHV basis)(fraction)0.3702 0.3794 0.3893 0.3978 0.4355 0.3803 0.3898 0.3983 0.3887 0.4346 0.3840 0.3570--Sporn Unit #4--ECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004850.8975 0.8975 0.8975 0.8975 0.8975 0.8975 0.8975 0.89750.8926 0.89260.88730.88160.870.880.880.890.890.900.90PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 Repower Existing

Boiler Efficiency - (Fraction of HHV)Figure 2.7. 1: Boiler Efficiency Comparison for all CasesECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004860.44420.45430.46500.47450.51610.45430.46500.47450.46500.51610.46040.42690.400.420.440.460.480.500.520.54PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 Repower Existing

Steam Cycle Thermal Efficiency - (Fraction )Figure 2.7. 2: Steam Cycle ThermalEfficiency Comparison for all CasesECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004870.0940.0920.0990.1010.0970.0900.0980.1000.0960.0940.0930.0720.060.070.080.090.100.11PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 Repower Existing

Total Auxilliary Power - (Fraction of Generator Output)Figure 2.7. 3: Total Auxiliary Power Comparison for all CasesECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004880.37020.37940.38930.39780.43550.38030.38980.39830.38870.43460.38400.35700.300.320.340.360.380.400.420.440.46PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 Repower Existing

Plant Thermal Efficiency - HHV (fraction)Figure 2.7. 4: Plant Thermal Efficiency Comparison for all CasesECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004891.8931.8471.8001.7621.6091.8431.7981.7591.8031.6121.8031.9391.501.551.601.651.701.751.801.851.901.952.00PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 Repower Existing

CO 2 Emissions - (lbm/kwhr)Figure 2.7. 5: Plant CO2Emission Comparison for all CasesECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 90 

### 2.7.3 The Effect of Steam Cycle Parameters on Plant Performance: Figures 2.7.6 and 2.7.7 show the net plant heat rate variation as a function of steam and feedwater conditions for twenty-five (25) pulve rized coal (PC) fired power plants (Palkes, Liljedahl, Kruger, Weirich; 1999). Similar re sults would be achieved for plants utilizing CFB and CMB TM 

### combustion systems since boiler efficiency and auxiliary power re quirements for these combustion systems are very comparable to pulverized coal firing.

Figure 2.7.6 is a three-dimensional plot depict ing eleven subcritical cycles and Figure 2.7.7 shows a similar plot for fourteen supercritical cases. All calculations were made for a condenser pressure of 2.5” Hg and the net power output is calculated at the output side of the transformer.
Five of the cases shown on these plots (Cases 23, 7, 18. 27, and 28 ) represent cases also included in this study, as listed below. The other cases shown on the plots, although not included in this study, have thermal efficiencies calculated on a directly comparable basis to those in this study and therefore are shown for comparison.

• Case PC-1 = Case 23

• Case PC-2 = Case 7

• Case PC-3 = Case 18

• Case PC-4 = Case 27

• Case PC-5 = Case 28

482 500 525 525 545 554 1050/1115 1005/1040 1005/1005 

### 9,218 9,185
9,158 9,141 9,146
9,106 9,098

8,997 8,981
8,946 8,941
8800 8850 8900 8950 9000 9050 9100 9150 9200 9250Heat Rate (Btu/kwhr)

Feedwater Temperature (Deg F) SHOT/RHOT (Case #'s) 

### ( )

(7, 8, 9, 10) (2, 3, 4, 24, 5) (23, 1)



### Figure 2.7. 6: Net Plant Heat Rates (HHV ba sis) for Subcritical (2,400 psia) CyclesECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 91 482 500 525 525 554 572 626 5075-1292/1328 4011-1090/1153 4011-1054/1117 3721-1054/1117 3721-1005/1045 3721-1005/1005 8983 8985 8947 8932 8916 8877 8874 8768 8743 8715 8702 8681

8581

7838

7200 7400 7600 7800 8000 8200 8400 8600 8800 9000Heat Rate (Btu/kwhr)

Feedwater Temperature (Deg F) SHOP-SHOT/RHOT (Case #'s) (27) (18,19,20,21) (Base-25)
(11a,12a,14a,13,15a,16a)

(26)

(28)



### Figure 2.7. 7: Net Plant Heat Rates ( HHV basis) for Supercritical Cycles

These plots illustrate and quantify the effects on net plant heat rate of changes in steam conditions for pulverized coal fired steam plants. Results for CFB and CMB TM 

### combustion systems would be nearly identical. In general, t he transition from a subcritical plant with 2,400 psia main steam pressure to a supercritical plan t with 3,625 psia, given constant fuel heat input and the same steam temperatures (i.e. PC-2 vs . PC-3 or Case-7 vs. Case-18) leads to an improvement in thermal efficiency of approximate ly 2.4%. The ultra high steam conditions case (Case PC-5 or Case 28 on Figure 2.7.2) offers al most 18% thermal efficiency improvement over a conventional subcritical design (Case PC-1 or Case-23).

2.7.4 The Effect of Combustion System on Plant Performance: Three combustion systems were utilized in this st udy; pulverized coal (PC), circulating fluidized bed (CFB), and circulating moving bed (CMB TM 

### ). The effect of the combustion system on plant thermal efficiency is quantified in Table 2.7.1 by comparing the cases with common steam cycles. For example, a comparison of cases PC-3, CFB-3, and CMB TM 

### -3 indicates that the PC fired case is essentially equivalent to the CFB case and the CMB TM 

### based plant is about 0.10 percentage points lower. The steam cycle efficiencies for these three cases are identical. Therefore the difference in plant thermal efficiency results from slight differences in boiler efficiency and/or plant auxiliary power.
The boiler efficiency for Case PC-3 is 89.75%, the same as Case CFB-3 (89.75%), and Case CMB TM 

### -3 is 89.26%. The primary contributors to CFB and CMB TM 

### boiler efficiency differences are the calcination and sulfation reac tions associated with the CFB and CMB TM 

### cases. In the CMB TM 

### designs, only partial sulfation takes place in the boiler as most of the sulfur is captured in the FDA reactor.
The auxiliary power for Case PC-3 and CFB-3 is about 73 MWe or about 9.9 percent of the generator output. The auxiliary power for Case CMB TM 

### -3 is about 71 MWe or about 9.6 percentECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 92 

### of the generator output. The main difference in auxiliary power between cases CFB-3 and CMB TM 

### -3 is due to the fans. The Case CMB TM 

### -3 fans utilize about 97% as much power as Case CFB-3. In comparing the auxiliary power requirements of Case PC-3 to Case CFB-3 several individual differences are apparent, which tend to cancel each other out when totaled. The primary differences occur in the fans, pulverizers (for the PC cases), ash and limestone handling systems, and in the FGD system (used for PC) or FDA system (used for CFB and CMB TM 

### ) which are used for sulfur removal.

The above comments with respect to the effect of combustion system type on plant thermal efficiency, boiler efficiency, and plant auxiliary po wer can be further quantified by comparing other cases with common steam cycles (i.e.; PC-2 vs. CFB-2; PC-4 vs. CFB-4; PC-5 vs. CMB TM 

### -5). These additional comparisons indicate nearly the same differences described above and these differences will not be repeated here.

2.7.5 Comparison of CO 2 

### Emissions for All Cases: The following figure shows a comparison of specific CO 2 

### emissions (lbm/kWh) for all the cases. This figure, in combination with the thermal efficiency results shown above, shows the direct correlation of CO 2 

### emissions and plant thermal efficiency. For example, Case PC-5 is about 18% more efficient than Case PC-1 and it also emits about 18% less CO 2 

### per kWh of net output.

1.893

1.847

1.800

1.762

1.609 1.843

1.798

1.759 1.803

1.612 1.803 1.939

1.50 1.55 1.60 1.65 1.70 1.75 1.80 1.85 1.90 1.95 2.00

PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 Repower ExistingCO2Emissions - (lbm/kwhr)



### Figure 2.7. 8: CO 2 

### Emissions (lbm/kWh) – All CasesECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 93 

## 3. Cost Analysis

The plant investment cost estimate summaries, including engineering, procurement, and construction (EPC basis), are shown in this se ction for the eleven (11) power plants included in this study. The EPC basis does not include owner’ s costs. Owner’s costs are, however, included in the economic analysis (Section 4). Operating and Maintenance costs are also shown in this section. The costs are expressed in July 2003 dollars. The level of accuracy of the cost estimates for these conceptual level designs is expected to be about +/- 30 percent.

Investment Cost Basis: These plants are assumed to be constructed on a common Greenfield site in the Gulf Coast region of southeastern Texas. The boundary limit for these plants includes the complete plant facility within the “fence line”. It includes t he coal receiving and water supply systems and terminates at the high-voltage side of the main power transformers.
The EPC costs for the pulverized coal cases, ci rculating fluidized bed cases, and circulating moving bed cases include all required equipment, including the traditional Boiler Island equipment, and Balance of Plant equipment (steam turbine, condensate and feedwater system, draft system gas clean-up, material handling, co oling, electrical, instrumentation and control, and misc.).

The cost estimates include equipment, material s, labor, indirect construction costs, and engineering. The labor cost to install the e quipment and materials was estimated on the basis of labor man-hours. The labor costing approach was a multiple contract labor basis with the labor cost including direct and indirect labor cost pl us fringe benefits and allocations for contractor expenses and markup.
The costs included in the Engineering, CM, H.O. & Fee category consist of professional services and “other costs”. Professional services incl ude the cost for engineering, construction management, and startup assistance. The engineering services include all preliminary and detailed engineering and design for the total plant scope. It includes specifying equipment for purchase, procurement, performing project scheduli ng and cost control services for the project; providing engineering and design liaison during the construction period; and providing startup support. Construction management (CM) servic es cost includes a field management staff capable of performing all field contract adminis tration; field inspection and quality assurance; project construction control; safety and medica l services as required; field and construction insurance administration, field office clerical and administrative support. The “other costs” category includes a cost allowance for freigh t costs, heavy haul, insurance, taxes, and indirect startup spares.
The investment cost estimates for these plants were calculated based on a combination of vendor-furnished quotes and cost estimating database values. The Boiler Island costs were estimated based on calculated material wei ghts for all components, conceptual equipment arrangement drawings, and equipment lists which were developed as a part of the conceptual design of the required equipment.
The following assumptions were made in developing the EPC cost estimates for each concept evaluated:

• Investment costs are expressed in July 2003 US dollars

• Construction labor rates are based on Gulf Coast non-union rates

• The plant is constructed on a Greenfield site in southeastern Texas

• All costs are based on mature level (n th 

### plant) commercial designECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 94 

### • Owners costs (including interest during constr uction, start-up fuel, land, land rights, plant licensing, permits, etc.) are not included in the investment costs but are included in the Cost of Electricity analysis

• Ash is to be shipped off site with provisions for short-term storage only

• Investment in new utility sy stems is outside the scope

• No special limitations for transportation of large equipment

• No protection against unusual airborne contaminants (dust, salt, etc.)

• No unusual wind storms

• No earthquakes

• No piling required

• Annual operating time is 7008 h/ yr (80 percent capacity factor).

• The investment cost estimate was developed as a factored estimate based on a combination of vendor quotes and in-house data for the major equipment. Such an estimate can be expected to have an accuracy of +/-30 percent.

• No purchases of utilities or ch arges for shutdown time have been charged agai nst the project.

Other exclusions from the EPC invest ment cost estimate are as follows:

• Fuels required for startup

• Relocation or removal of buildings, utilities, and highways

• Permits

• Land and land rights

• Soil investigation

• Environmental Permits

• Disposal of hazardous or toxic waste

• Disposal of existing materials

• Custom's and Import duties

• Sales/Use tax.

• Forward Escalation

• Capital spare parts

• Chemical loading facilities

• Financing cost

• Owners costs

• Guards during construction

• Site Medical and Ambulance service

• Cost & Fees of Authorities

• Overhead High voltage feed lines

• Cost to run a natural gas pipeline to the plant

• Excessive piling
Overall plant investment costs and the associated specific plant investment costs ($/kW) can vary quite significantly for any given plant design d epending on several factors. Some of the more important factors are listed below.

• Plant Location and Site Conditions

• Construction Labor Basis

• Coal Analysis

• Ambient Conditions

For the cases in this study, the design coal a nalysis, design ambient conditions, plant location and site conditions are described in Section 2.1 u nder Plant Design Basis. The construction labor basis used is Gulf Coast non-union. The sensitivity of plant specific cost to construction labor basis is indicated by observing that for t hese studies, changing from Gulf Coast non-union toECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 95 

### Ohio River Valley union basis, for example, w ould increase the EPC plant costs by about 20 percent.
Operating and Maintenance Costs Basis: Operating and Maintenance (O&M) costs are calc ulated for each plant and are listed as either fixed or variable. The fixed costs are those cost s which are incurred irrespective of the number of hours of plant operation, whereas the variable costs are directly proportional to the operating hours. The variable operating and maintenance (VOM) costs for the new equipment included such categories as chemicals, waste handling, maintenance material and labor, supplemental fuel usage, and contracted services. The fi xed operating and maintenance (FOM) costs for the new equipment includes operating labor only.
The O&M costs for the power plant equipment was developed quantitatively by Parsons and ALSTOM. Operating labor cost was calculated based on the number of operator jobs (O.J.) required. Table 3.0.1 shows the operating labo r requirements for both the Greenfield plants and Sporn Unit #4. The operating labor requirements shown for Sporn Unit #4 were used for both the repowering and existing cases.

Table 3.0. 1: Operating Labor Requirements

Operating Labor Requirements (O.J.) per shift Greenfield Sporn Unit #4 

### Skilled Operator 2 1 Operator 9 7 Foreman 1 1 Lab Tech's, etc. 2 1 TOTAL Operator Jobs (O.J.'s) 14 10



### The average labor rate used to determine the annual cost was 30.90 $/hr, with a labor burden of 30 percent. The labor administration and overhead cost was assessed at a rate of 25 percent of the O&M labor. Maintenance cost was evaluated as a percentage of the initial capital cost.

Consumable Costs Basis: Consumable costs including fuel, limestone, ammonia, water, and chemicals were determined on the basis of individual flow rates as listed in the material and energy balances, individual unit costs (listed below), and the plant annual operating hours. Waste disposal cost was also based on flow rates from the material and energy balances, unit costs, and operating hours.

• Coal cost - 1.25 $/MM-Btu

• Limestone cost - 10.00 $/Ton

• Ammonia cost – 150.00 $/Ton

• Water cost - 1.00 $/1,000 gallons

• Water Treatment Chemicals cost - 0.16 $/lbm

• Ash Disposal cost - 8.00 $/Ton

• By-product credits were not considered for these casesECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 96 

### 3.1 Greenfield Cases Investment Costs The estimated investment cost for each Greenfield case includes all major ALSTOM and vendor supplied components. The investment cost wa s first estimated for cases PC-3, CFB-3, and CMB TM 

### -3. The plant cost for each other case was determined by estimating new absolute costs or cost differences from the Base Cases for t he components that required modifications because of changes in combustion system, gas cleanup system, steam cycle system, electrical, and feedwater system design parameter s. The cost differences were then added to the cost of the corresponding Base Cases components to generate the cost for the other cases.
In estimating the costs, following assumptions were made:

• The configuration of components was similar to the Base Case designs and the structure of all buildings remained un changed for all cases.

• Within a given combustion system group (PC, CFB, or CMB TM 

### ), the locations of the terminal points for pipe connections to the steam generat or were the same for all subcritical cases. Similarly, this assumption was also made for supercritical designs.

• For the PC cases, the cold reheat connection for the subcritical designs was in front of the boiler while for the supercritical designs the same connection was in the boiler backpass.

• Location of the terminal points for the st eam turbines was the same for all cases.

• Electrical components (except for the generator, transformer and large motors) and the instrumentation and controls package remained unchanged among the cases.

3.1.1 Total Plant Investment Costs: The total plant investment cost breakdown for the ten (10) Greenfield plants are summarized in Table 3.1.1 and these re sults are illustrated on Figure 3.1. 1. These costs were developed consistent with the approach and basis identified in the design basis. The capital cost estimate (EPC basis) is expressed in July 2003 dollars.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### Table 3.1. 1: Total Plant Investment Cost Summary for the Greenfield Cases

Acct No. Item/Description $ x 1000 $/kW $ x 1000 $/kW $ x 1000 $/kW $ x 1000 $/kW $ x 1000 $/kW 1 COAL & SORBENT HANDLING 28,275 45 28,275 44 28,275 43 28,275 42 28,275 38 2 COAL & SORBENT PREP & FEED 22,262 35 22,262 34 22,262 34 22,262 33 22,262 30 3 FEEDWATER & MISC. BOP SYSTEMS 45,686 72 47,010 73 47,834 72 49,024 72 52,523 71 4 BOILER & ACCESSORIES 128,693 204 129,534 200 132,145 199 134,345 198 199,460 269 5 FLUE GAS CLEANUP 136,384 216 136,384 211 136,384 206 136,384 201 136,384 184 6 COMBUSTION TURBINE/ACCESSORIES 0 0 0 0 0 0 0 0 0 0 7 HRSG, DUCTING & STACK 34,160 5 4 34,160 53 34,160 52 34,160 50 34,160 46 8 STEAM TURBINE GENERATOR 104,782 166 111,507 173 115,360 174 120,839 178 174,326 235 9 COOLING WATER SYSTEM 38,723 61 38,581 60 38,415 58 38,240 56 37,773 51 10 ASH/SPENT SORBENT HANDLING SYS 34,358 54 34,358 53 34,358 52 34,358 51 34,358 46 11 ACCESSORY ELECTRIC PLANT 39,585 63 39,702 61 40,229 61 40,516 60 41,324 56 12 INSTRUMENTATION & CONTROL 22,780 36 22,780 35 22,780 34 22,780 34 22,780 31 13 IMPROVEMENTS TO SITE 13,810 22 13,810 21 13,810 21 13,810 20 13,810 19 14 BUILDINGS & STRUCTURES 68,867 109 68,867 107 68,867 104 68,867 102 68,867 93 TOTAL COST 718,365 1,139 727,231 1,126 734,880 1,109 743,861 1,098 866,303 1,168

Acct No. Item/Description $ x 1000 $/kW $ x 1000 $/kW $ x 1000 $/kW $ x 1000 $/kW $ x 1000 $/kW 1 COAL & SORBENT HANDLING 28,867 45 28,867 43 28,867 43 28,867 43 28,867 39 2 COAL & SORBENT PREP & FEED 23,414 36 23,414 35 23,414 35 23,414 35 23,414 31 3 FEEDWATER & MISC. BOP SYSTEMS 47,010 73 47,834 72 49,024 72 47,834 72 52,523 71 4 BOILER & ACCESSORIES 146,955 227 150,114 226 159,692 235 138,887 209 179,650 241 5 FLUE GAS CLEANUP 61,889 96 61,889 93 61,889 91 61,889 93 61,889 83 6 COMBUSTION TURBINE/ACCESSORIES 0 0 0 0 0 0 0 0 0 0 7 HRSG, DUCTING & STACK 34,160 5 3 34,160 51 34,160 50 34,160 51 34,160 46 8 STEAM TURBINE GENERATOR 111,507 172 115,360 174 120,839 178 115,360 173 164,939 222 9 COOLING WATER SYSTEM 38,581 60 38,415 58 38,240 56 38,415 58 37,773 51 10 ASH/SPENT SORBENT HANDLING SYS 43,037 66 43,037 65 43,037 63 43,037 65 43,037 58 11 ACCESSORY ELECTRIC PLANT 39,702 61 40,229 61 40,516 60 40,229 60 41,324 56 12 INSTRUMENTATION & CONTROL 22,780 35 22,780 34 22,780 34 22,780 34 22,780 31 13 IMPROVEMENTS TO SITE 13,810 21 13,810 21 13,810 20 13,810 21 13,810 19 14 BUILDINGS & STRUCTURES 68,867 106 68,867 104 68,867 102 68,867 103 68,867 93 TOTAL COST 680,579 1,051 688,776 1,038 705,135 1,039 677,549 1,018 773,033 1,039 Case PC-1 Case PC-4 Case PC-5 Case PC-2 Case PC-3

Case CMB-5 Case CFB-2 Case CFB-3 Case CFB-4 Case CMB-3

1,139 1,126 1,109 1,098 1,168

1,051 1,038 1,039 1,018 1,039

900 950 1,000 1,050 1,100 1,150 1,200

PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5Specific Total Pant Cost ($/KW-net)



### Figure 3.1. 1: EPC Plant Costs – Summary of all Cases

Specific investment costs for the entire spec trum of Greenfield cases range from 1,018 – 1,168$/kW-net. The incremental cost of the repowering case is 413 $/kW-net. Taken as groups, the effect of combustion system (PC, CFB, or CMB TM 

### ) on specific investment cost ($/kW-net) were as follows:

• There was about a 7% difference between the to tal plant specific investment costs for the PC and CFB combustion systems (PC-2 vs. CFB-2; PC -3 vs. CFB-3; PC-4 vs. CFB-4) with the CFB cases being lower. The investment cost difference was primarily attributable to cost differences in the gas cleanup system.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 98 

### • The CMB TM 

### combustion system was shown to have sli ghtly lower total plant investment cost than the CFB system (CMB TM 

### -3 vs. CFB-3). It requires also about 8-11% less investment cost than the PC power plant (CMB TM 

### -3 vs. PC-3, CMB TM 

### -5 vs. PC-5). The lower investment cost is attributed to the lower cost of the back-end installed clean-up systems (SCR, ESP, and wet FGD for the PC and SNCR and FDA for the CMB TM 

### ) the use of the finned tube surfaces, and the reduction in application of the Ni materials for the design of the ultra-supercritical cases.
Similarly, the effect of steam cycle parameters on total plant specific investment cost ($/kW-net) were as follows:

• The higher temperatures and pressures genera lly were shown to reduce specific investment costs ($/kW) slightly as the increase in net output was enough to more than break even with the increase in investment cost.

• This trend held true for all cases except for t he cases with ultra-supercritical steam conditions (Cases PC-5 and CMB TM 

### -5) where the higher temperature and pressure of these cases increased the total plant specific investm ent cost significantly. It should be emphasized however that the costs for t he ultra-supercritical cases are somewhat more uncertain because of the use of the Ni based alloys. This cost uncertainty for these alloys is discussed further and results of a sensitiv ity study are shown in Section 4.

The procedure involved in developing cost estimates for the individual components is briefly explained in the sections below. Unless othe rwise specified a linear cost behavior for the component cost as a function of the output was assumed. This may lead to inaccuracies for individual components, but totaling the individual costs minimizes any errors. Otherwise, the results would be invalid if cost jumps (step ch anges in cost) were not smoothed out; the results would then be exact only for the pa rticular output range concerned.

3.1.2 Boiler Island Costs: The total Boiler Island cost for each case was computed on the basis of the cost differential between the Base Cases (Case PC-3, CFB-3, CMB TM 

### -3) and all other cases. In developing the Boiler Island costs the following assumptions were made:

• Within a given combustion system group (PC, CFB, or CMB TM 

### ), fuel, sorbent, air, and flue gas dependent components were the same for all cases.

• Within a given combustion system group (PC, CFB, or CMB TM 

### ), the number of wallblowers and sootblowers were the same for all cases.

• Steam loading per foot of drum length wa s constant for all subcritical designs.

• Header velocities were similar for all cases.

• To simplify cost analyses tube intermesh for heat transfer surfaces was consistent with the base case within a given combustion system group (PC, CFB, or CMB TM 

### ).

• Potential changes in the circ ulation system design due to di fferences in the superheat steam flow for subcritical designs were assumed to be too small to effect cost differences among subcritical designs and were neglected.

• Similarly, design differences between the circulation and start-up systems designs for supercritical units were neglected.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 99 

### For each case, in addition to the cost of the heat transfer surfaces, estimates were made to account for changes in drum length (subcr itical pressure), headers and connecting links diameters and materials, and the steam cooled back - pass height.
Figure 3.1.2 shows the spec ific ($/kW) boiler costs (Account 4) for all Greenfield cases. Account 4 includes the boiler, boiler structure, boiler f oundations, and fans. The shading and case numbers in this figure indicates common steam cycles . In general, an increase in steam parameters (Temperature and Pressure) causes a slight decrease in the specific boiler costs as the increase in net output was greater, on a relative basis, than the increase in investment cost. This trend held true except for the ultra-supercritical cases (PC-5, CMB TM 

### -5).

The costs of the PC-5 and CMB TM 

### -5 boiler are not easily determined since both of these designs require high strength Ni based alloys. These allo ys have not been used by the boiler industry in the past and the costs for tubing, piping, plates , fabrication, and welding are very uncertain. These materials, including fabrication techni ques, are being investigated under the DOE sponsored program, “ Boiler Materials for Ultra-supercritical Coal Fired Plants”. For the economic analysis, the cost of these alloys wa s assumed to be at $28.00/lbm. Because of the uncertainty involved with the costs, an economic sensitivity study was performed at two other costs of $20.00/lbm and $32. 90/lbm (see Section 4.3.4).

204 200 199 198 269

227 226 235

209 241

100 120 140 160 180 200 220 240 260 280

PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5Specific Boiler Cost ($/KW-net)(Account 4)



### Figure 3.1. 2: Specific Boiler Costs (Account 4)

Similarly, Figure 3.1.3 shows the specific Boiler Island costs, which include the boiler, the flue gas cleanup equipment, ducting and stack (Accounts 4, 5 and 7 respectively). Again, an increase in steam parameters (Temperature and Pressure) ca uses a slight decrease in the specific Boiler Island specific costs as the increase in net output was greater, on a relative basis, than the increase in investment cost except for the ultra-supercritical cases (PC-5, CMB TM 

### -5).ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 100 475 464 457 450 499

375 371 377

353 370

300 350 400 450 500 550

PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5Specific Boiler Island Cost ($/KW-net)(Accounts 4,5,7)



### Figure 3.1. 3: Specific Boiler Island Costs (Accounts 4, 5 and 7)

3.1.3 Turbine Island Costs: The total Turbine Island cost for each case was computed on the basis of the cost differential between the Base Case (Case PC-3) and all other cases. In developing the Turbine Island costs the following assumptions were made:

• Steam Turbine: The procedure used to develop the costs for t he steam turbine was the same as for formal quotation preparation.

• Generators: Two types of generators cover the entire output range (50 MT 23E-120 and 50 MT 23E – 138). The prices for these two generators differ by 1.7 %. Due to this relatively insignificant difference, the average value was used for the base case. Other cases were proportioned to the output.

• Feedwater Heaters: The data from the steam turbine balances were used to select all feedwater heaters. Weights were determined for casings and tubing and costs were obtained.

• Condenser, Cooling Water System: The condenser of the Base Case was dimensioned in the same fashion as the heaters, and the costs were estimated. The costs for the ot her cases were linearly proportioned to the heat rejection.

• Piping, incl. Valves and Insulation, Bypass Equipment: Calculations included piping costs for main steam, hot reheat, cold reheat extraction steam, and feedwater. The piping design (diameter, wall-thickness, and material) is individually adapted to the physical parameters (mass flow , pressure, and temperature). Ni based alloy piping was estimated at $28.00/lbm. An econ omic sensitivity study was performed at $20.00/lbm and $32.90/lbm also (see Section 4.3.4).ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 101 

### • Other Equipment: For the supercritical cases a high-pressure and low-pressure bypass system (each 2 x 50 %) have been estimated.

• For the supercritical cases the cost for a condensate polishing plant was estimated.

• The price for the main transformer and station-service transformer for the Base Case were estimated. The costs for the other cases were linearly proportioned to the net output and the unit auxiliary power consumption respectively.
Figure 3.1.4 shows the s pecific ($/kW-net) turbine costs (Account 8) for all Greenfield cases. Account 8 includes the steam turbine, generator , condenser, steam piping and turbine generator foundations. The shading in this figure indicates common steam cycles. In general, an increase in steam parameters (Temperature and Pressure) ca uses a slight increase in the specific turbine costs as the increase in net output was smaller, on a relative basis, than the increase in investment cost. The ultra high steam conditions of cases PC-5 and CMB TM 

### -5 however were shown to cause about a 35% and 28% increase in specific turbine cost as compared to cases PC-3 and CMB TM 

### -3 respectively. The smaller increase for the CMB TM 

### case as compared to the PC case is due to shorter steam piping runs for the CMB TM 

### cases.

166 173 174 178 235

172 174 178 173 222

100 120 140 160 180 200 220 240 260

PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5Specific Turbine Condenser & Piping Cost ($/KWnet)(Account 8)



### Figure 3.1. 4: Specific Turbine Costs (Account 8)

Similarly, Figure 3.1.5 shows the specific Tu rbine Island costs, which include the turbine generator system, feedwater system, cooling water system, and the accessory electrical equipment (Accounts 8, 3, 9 and 11 respectively). Here, the increased turbine costs shown above associated with increased steam conditions ar e compensated for by decreases in feedwater system, cooling water system, and the accessory el ectrical equipment specific costs for all cases except PC-5 and CMB TM 

### -5. The ultra high steam conditions of cases PC-5 and CMB TM 

### -5 were shown to cause about a 13% and 10% increase in specific Turbine Island cost as compared to cases PC-3 and CMB TM 

### -3 respectively.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 102 363 367 365 367 413

366 364 366 363 398

300 320 340 360 380 400 420

PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5Specific Turbine Island Cost ($/KW-net)(Accounts 3,8,9,11)



### Figure 3.1. 5: Specific Turbine Isla nd Costs (Accounts 8, 3, 9, and 11)

3.1.4 Other Balance of Plant Equipment Costs: Figure 3.1.6 shows the s pecific costs for “other BOP equipment”. This includes the coal and sorbent handling system, the coal and sorbent preparation and feed system, the ash and spent sorbent handling system, the inst rumentation and control system, improvements to the site, and the buildings and structures (Accounts 1, 2, 10, 12, 13, and 14 respectively). Here, the other BOP equipment costs shown in Table 3.1.1 above are constant within a given combustion system group and the increased output associated with improved steam conditions causes a significant reduction in the specific costs as shown.

302 295 287 281

257 310 302 296 302

270

200 220 240 260 280 300 320

PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5Specific Other BOP Equipment($/KW-net)(Accounts 1,2,10,12,13,14)



### Figure 3.1. 6: Specific Other BOP Equipment Costs (Accounts 1, 2, 10, 12, 13, and 14)ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### 3.2 Repowering Case Investment Costs The total plant investment cost breakdown for the Sporn Unit #4 repowering case is summarized in Table 3.2.1. A more detailed breakdown is shown in Appendix III. These costs were developed consistent with the approach and basis identified in the design basis. The capital cost estimate (EPC basis) is expr essed in July 2003 dollars. The following list indicates the major items included in the equipment scope.

• CMB TM 

### Boiler

• Topping Steam Turbine

• Main Steam Piping

• FW booster pump

• Condensate polishing system

• Coal feed system

• Air fans and blowers

• Transformer

• Ductwork and dampers

• Feedwater and steam piping

Table 3.2. 1: Total Plant Investment Cost Summary for the Repowering Case



## Equipment Description Installed Cost 

### $/kW net $/kW incr Boiler: 

### 54,182,000 293.1 1909.9 Topping Turbine/Generator: 

### 10,725,000 58.0 378.1 Balance of Plant Equipment: 

### 5,607,000 30.3 197.6 Piping: 

### 5,830,000 31.5 205.5 TOTAL COST 76,344,000 413 2,691



### The two columns on the right side of Table 3.2. 1 show specific investment costs expressed as $/kW-net and $/kW-incremental. These totals are 413 $/kW-net and 2,691 $/kW-incremental respectively.
The vast majority of the investment costs (about 85%) are for the new CMB TM 

### Boiler and new topping steam turbine/generator. Lesser am ounts are expended for the balance of plant equipment, which includes new feedwater booster pumps, the coal feed system, topping turbine transformer, and new ductwork/dampers from t he new boiler to the existing electrostatic precipitator.
Piping is also broken out as a separate account in Table 3.2.1, as this also represents a significant expense. The piping acco unt includes the following major items:

• A link from the existing condensate pumps to the Demineralizer.

• A link from the Demineralizer to the existing #1 feedwater heater.

• Main steam piping from the new CMB TM 

### boiler to the new topping turbine.

• A link from the new topping turbine exhaust to the existing HP turbine inlet.

• New reheater inlet and reheater outlet links.

• A link from the new feedwater booster pump to the new economizer.
The cost estimate presented for this repowering case assumes that the existing Sporn Unit #4 boiler is left in place and the new CMB TM 

### boiler is located on available land adjacent to the existing Unit #4 boiler building. ALSTOM estimated the cost for the new CMB TM 

### boiler and newECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 104 

### topping steam turbine. AEP estimated the balance of plant costs. Addi tional assumptions and exclusions from the AEP cost estimate are listed below:

• Construction Equipment: Erection of large prefabricated pieces was assumed.

• General site preparation including moving the lab building and providing construction access and permanent access was not included in the AEP estimate.

• Cost of construct management was not included in the AEP estimate.

• Permits were not included in the AEP estimate.

• Refurbishment of existing equipment to obtai n lifetime and availability goals consistent with the new equipment was not in cluded in the AEP estimate.

• Contingency was not incl uded in the AEP estimate.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### 3.3 Operating and Maintenance Costs The production costs consist of plant operatin g labor, maintenance (material and labor), an allowance for administrative and support labor, consumables, solid waste disposal, and fuel costs. The production cost and expenses were developed on a first-year basis with a July 2003 plant in-service date. The costs were determin ed assuming an equivalent plant operating capacity factor of 80 percent.
The operating and maintenance (O&M) results for t he ten (10) Greenfield plants, the Sporn Unit #4 repowering case, and the unmodified existing Sporn Unit #4 are summarized in Table 3.3.1.

Table 3.3. 1: Total Plant Operating and Maintenance Costs

($/year) ($/kW) ($/year) ($/kWh) Case PC-1 9,639,466 15.3 18,326,741 0.0041 27,966,208 4,419 0.633 Case PC-2 9,683,793 15.0 18,369,295 0.0041 28,053,088 4,528 0.620 Case PC-3 9,722,038 14.7 18,406,010 0.0040 28,128,048 4,646 0.605 Case PC-4 9,766,944 14.4 18,449,120 0.0039 28,216,064 4,748 0.594 Case PC-5 10,379,154 14.0 19,036,841 0.0037 29,415,995 5,197 0.566 Case CFB-2 9,531,512 14.7 12,723,866 0.0028 22,255,378 4,538 0.490 Case CFB-3 9,572,495 14.4 12,763,210 0.0027 22,335,705 4,652 0.480 Case CFB-4 9,654,292 14.2 12,841,735 0.0027 22,496,027 4,754 0.473 Case CMB-3 9,516,360 14.3 12,724,400 0.0027 22,240,761 4,664 0.477 Case CMB-5 9,993,780 13.4 13,182,724 0.0025 23,176,504 5,216 0.444 Sporn #4 Repowering 5,543,775 30.0 2,512,502 0.0018 8,056,277 1,377 0.585 Sporn #4 Existing 5,543,775 35.4 2,137,534 0.0018 7,681,309 1,165 0.659 Case Number Operating & Maintenance (O&M) Costs Total O&M (Cents/kWh) Fixed Variable @ 80% CF Total ($/year) Annual Generation ( 10 6 kWh )



### The range of O&M costs for the Greenfield cases is from 0.44 – 0.63 Cent s/kWh. The O&M costs for the existing unmodified Sporn Unit #4 is shown in addition to the repowering case since it was utilized to calculate the incremental cost of elec tricity for the repowering case. A more detailed breakdown of the individual O&M costs for each case is shown in Appendix III.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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## 4. Economic Analysis

A comprehensive economic evaluation compari ng the various Rankine cycle power plants was performed. These comparisons were done for three types of plants (PC, CFB, and CMB TM 

### ). In addition the economics of repowering an ex isting coal fired plant with a new CMB TM 

### boiler and supercritical topping steam turbine was also in vestigated. An economic sensitivity analysis was also completed for all cases.
The purpose of the evaluation was to quantify the impact of steam cycle and boiler type on the Cost of Electricity (COE) of new Greenfield co al fired plants including PC, CFB, and advanced CMB TM 

### type units. Additionally a comparison betw een all cases is also provided. The economic evaluation results are presented as Cost s of Electricity (levelized basis).
The model used to perform the economic evaluations is the proprietary ALSTOM Power Plant Laboratories’ Project Economic Evaluation Pro-Fo rma Model. This cash flow model, developed by the Company’s Project & Trade Finance gr oup, has the capability to analyze the economic effects of different technologies based on differi ng efficiencies, investment costs, operating and maintenance costs, fuel costs, and cost of capital assumptions. Various categories of results are available from the model. In addition to cost of el ectricity, net present val ue, project internal rate of return, payback period, and other evaluation parameters are available.



### 4.1 Economic Analysis Assumptions

Numerous financial assumptions were required in performing the economic evaluations. These assumptions are listed in Table 4.1.1. The assu mptions are grouped in the Greenfield cases and the repowering case. The parameters that vary between the Greenfield cases and the repowering case are availability factor, fuel co st, interest rate, and discount factor. All other financial inputs are equivalent for all cases.
The 30-month construction period of the PC an d CFB systems are known from the experience in the industry. The construction period for the CMB TM 

### systems is thought to be similar to the CFB systems since the system complexity is very si milar. The construction period for the repowering case is 30-month based on a CMB TM 

### system.
Table 4.1.1 summarizes the primary technical and financial assumptions used in the model for the Greenfield and repowering cases. Items that are indicated as “Case Sensitive” are discussed in the corresponding case study section of this report. Items shaded in yellow represent parameters that were varied in the econ omic sensitivity study (Section 4.3.4).ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### Table 4.1. 1: Economic Evaluation Study Assumptions

POWER GENERATION DEBT PORTFOLIO Net output (MW) Case Sensitive Case Sensitive Interest Rates (Financed) 2 Capacity factor (%) 100% 100% During Construction Availability factor (%) 80% 85% Base Rate 1.32% 2.22% Net plant heat rate, HHV (Btu per kWh) Case Sensitive Case Sensitive Swap/Reinvestment cushion 1.28% 1.28% Degradation factor (%) 0.0% 0.0% Fixed Rate Margin 3.00% 3.00% All-In Fixed Rate 5.60% 6.50% TIME FRAME Construction period (months) 30 30 During Operation Depreciation Term (years) 30 20 Base Rate 1.32% 2.22% Analysis Horizon (years) 30 20 Swap/Reinvestment cushion 1.28% 1.28% Fixed Rate Margin 2.50% 3.00% PROJECT COSTS All-In Fixed Rate 5.10% 6.50% EPC Price ($1000s) Case Sensitive Case Sensitive High Temperature Alloy Costs ($/lb) 1 28.00 28.00 Up-front Fee (Financed) 2.0% 2.0% Fixed O&M costs ($ per kW) Case Sensitive Case Sensitive Commitment Fee 1.0% 1.0% Variable O&M costs (cents per kWh) Case Sensitive Case Sensitive Grace Period (months) 0 0 Owner's EPC Contingency 0.0% 0.0% Loan Tenor (years after construction) 30 30 Initial spares and consumables 1.0% 1.0% Insurance TAXES Insurance during Construction 1.0% 1.0% Corporate Tax 20.0% 20.0% Insurance during first year of operation 0.5% 0.5% Tax holiday (years after commissioning) 0.0% 0.0% Development Costs Customs Duty 0.0% 0.0% Development Costs & Fees 4.0% 4.0% Customs Clearance Fee 0.0% 0.0% Reimburseable Dev't Costs 3.0% 3.0% Advisory Fees 3.0% 3.0% COST OF CAPITAL ASSUMPTIONS Financial and Legal Fees 3.0% 3.0% Discount Factor 10.0% 15.0% Start-up Fuel 0.5% 0.5% Fuel Stock Pile 0.5% 0.5% PROGRESS PAYMENT SCHEDULES Other Costs 0.5% 0.5% Month Total Initial Project Costs (% of EPC) 17.0% 17.0% 1 10% 10% 8 15% 15% FUEL COST 10 Coal Price ($ per MMBtu) 1.25 1.27 16 17 25% 25% EMISSIONS CREDITS 20 NOx ($ per ton) N/A 0 22 20% 20% SOx ($ per ton) N/A 0 25 26 20% 20% ESCALATION FACTORS 30 10% 10% Coal Price 0.0% 0.0% 31 Variable O&M 0.0% 0.0% 32 Fixed O&M (including payroll) 0.0% 0.0% 36 Consumer Price Index 0.0% 0.0% 41 48 FINANCING ASSUMPTIONS Total 100% 100% Equity 50.0% 50.0% Debt 50.0% 50.0%
1 PC-5, CMB-5, and Repowering Cases Only
2 Wall Street Journal, 4/23/03, London Interbank Offered Rate (LIBOR) Swap Curve Base and Repowering PC, CFB, and CMB Systems - Cases PC-1, PC-2, PC-3, PC-4, PC-5, CFB-2,

CFB-3, CFB-4, CMB-3, CMB-5 Base and Repowering PC, CFB, and CMB Systems - Cases PC-1, PC-2, PC-3, PC-4, PC-5, CFB-2,

CFB-3, CFB-4, CMB-3, CMB-5



### 4.2 Cost of Electricity Calculation

Levelized cost of electricity (COE) was used as one criterion to compare the systems in this study. The cost of electricity result consists of the following components: financial, fixed O&M, variable O&M, and fuel. The cash flow model is structured to calculate the corresponding annual cash flows for each of these items over the ev aluation life of the project. The annual expenses are distributed over the corresponding net annual electricity generated (kWh/year) in order to determine a unit cost (cents/kWh). These costs are subsequently levelized to get a corresponding value of each component over the plant life. In other words, each of the cash flow streams is converted to annuity payments corresponding to a const ant value over the life of the study.
The financial component of the COE represents t he costs which are associated with payment of the original engineered, procured and constructe d (EPC) price, all associated owner’s costs, custom’s and financing fees, and interests accr ued both during construction and during operation. The fixed O&M component represents the costs that occu r regardless of whether the unit is inECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### operation or not. The variable O&M component re presents the incremental costs which occur when the unit is in operation. The fuel cost component represents the cost of the fuel, which is consumed by a given technology.



### 4.3 Economic Analysis Results

The economic analysis results of the PC system s are discussed in Section 4.3.1. The CFB and CMB TM 

### systems are discussed in Sect ion 4.3.2. The Repowering system is discussed in Section 4.3.3. The case studies are compared using le velized cost of electricity (COE) evaluation criterion.

4.3.1 Pulverized Coal Fired Cases

The levelized COE for the PC systems is summariz ed in Table 4.3.1. The supercritical cases PC3, PC-4and PC-5 have relatively low produ ction costs among the PC systems. The high investment cost for the PC-5 is partially offset by the decreased fuel cost of the high efficiency cycle.

Table 4.3. 1: Pulverized Coal Systems (PC-1, PC-2, PC-3, PC-4, PC-5) – Economic Analysis Summary

PC-1 PC-2 PC-3 PC-4 PC-5 Levelized Cost of Electricity at 80% Availability Factor (cents / kWh)

Financial 2.18 2.15 2.12 2.10 2.23 Fixed O&M 0.22 0.21 0.21 0.21 0.20 Variable O&M 0.41 0.40 0.40 0.38 0.36 Fuel 1.15 1.12 1.10 1.07 0.98 Total 3.96 3.89 3.82 3.76 3.77



### 4.3.2 CFB and CMB TM 

### Cases

The levelized COE values for the CFB and CMB TM 

### systems are summarized in Table 4.3.2. Case CMB TM 

### -5 had the lowest production cost of the CFB and CMB TM 

### systems because of its highest net plant efficiency and the relatively low inve stment cost. Compared to the increase in the investment cost for the PC-5, the incremental increase in the investment cost of CMB TM 

### -5 was not as high since the design required significant ly less amounts of expensive Ni materials.

Table 4.3. 2: CFB and CMB TM 

### Systems (CFB-2, CFB-3, CMB TM 

### -3, CMB TM 

### -4, CMB TM 

### -5) – Economic Analysis Summary

CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 Levelized Cost of Electricity at 80% Availability Factor (cents / kWh)

Financial 2.01 1.98 1.99 1.95 1.99 Fixed O&M 0.21 0.21 0.20 0.20 0.19 Variable O&M 0.28 0.27 0.27 0.27 0.25 Fuel 1.12 1.09 1.07 1.10 0.98 Total 3.62 3.56 3.53 3.52 3.41ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### 4.3.3 Repowering Case

The levelized incremental Cost of Electricit y (COE) value for the Repowering Case and Base Case are summarized in Table 4.3.3 and Figure 4. 3.1. The incremental COE (2.80 - 1.87 = 0.93 Cents/kWh) is relative to the existing plant without any modifications and does not include any NO x 

### trading benefits.

Table 4.3. 3: Repowering System – Economic Analysis Summary

Retrofit Base

Financial 1.11 0.00 Fixed O&M 0.40 0.48 Variable O&M 0.16 0.18 Fuel 1.13 1.21 Total 2.80 1.87 Levelized Cost of Electricity at 85% Availability Factor (cents / kWh)

2.80

1.87

0.0 0.5 1.0 1.5 2.0 2.5 3.0

Repower BaseLevelized COE (cents per kWh)

Fuel
Variable O&M
Fixed O&M
Financial



### Figure 4.3. 1: Levelized Cost of Electricity Comparison for Repowering Versus Base Plant (without Emissions Sold or Purchased)

A more realistic economic picture is presented in Figure 4.3.2, which accounts for purchasing and selling of NO x 

### credits. For the existing unit, the NO x 

### emission is 0.57 lbm/MM-Btu. During the five months ozone season that limits NO x 

### emission to 0.15 lbm/MM-Btu the plant is required to purchase NO x 

### credits which amount to a difference of 0.42 lbm/MM-Btu. For the repowered case, since the NO x 

### emission is only 0.1 lbm/MM-Btu, a cred it of 0.05 lbm/MM-Btu could be traded for additional revenue during the ozone season. This reduces the incremental COE by 50% to 0.47 cents/KWh.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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2.29

0.0 0.5 1.0 1.5 2.0 2.5 3.0

Repower, Sell NOx Credits at $5k/ton, No SOx Credits Base, Purchase NOx Credits at $5k/tonLevelized COE (cents per kWh)



### Figure 4.3. 2: Repowering versus Base Case – With NO x 

### Credits

4.3.4 Economic Sensitivity Study Summary

Sensitivity analyses were conducted for all ca se studies to determine the effect on COE of variation of selected base parameter values by ± 25 percent. These parameters (shaded in yellow in Table 4.1.1) are availability factor, EPC pr ice, coal price, equity rate, corporate tax rate, and the discount rate for cost of capital. The ba se parameter values represent the point where all the sensitivity curves intersect (point 0, 0). Se lected sensitivity analysis “spider plots” for selected cases are provided in the following section. The complete package of sens itivity results for all case studies are provided in Appendix IV. In gener al, for the variable ranges studied, availability factor, plant investment cost, and discount rate , in order of decreasing significance, have the greatest effect on the COE.
Other COE sensitivity studies were conducted on:
1) High temperature Nickel alloy cost ($20, $28, and $32.90 per pound) for cases PC-5, CMB TM 

### -5, and the repowering case.
2) NO x 

### emissions credit on the repowering case.
3) SO x 

### emissions credit on the repowering case.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### 4.3.4.1 Case PC-3 Results for the Case PC-3 COE sensitivity study ar e shown in Figure 4.3.3. The tabulated results for Case PC-3 are provided in Appendix IV. The levelized COE for the base parameter values is 3.8 cents per kWh. Levelized COE ranges from a low of 3.3 to a high of 4.6 cents per kWh.

-20% -15% -10%

-5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

3.1 3.3 3.5 3.7 3.9 4.1 4.3 4.5 4.7 4.9Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate


### Figure 4.3. 3: Case PC-3 - Economic Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### 4.3.4.2 Case CFB-3 Results for the Case CFB-3 COE sensitivity study are shown in Figure 4.3.4. The tabulated results for Case CFB-3 are provided in Appendix IV. The levelized COE for the base parameter values is 3.6 cents per kWh. Levelized COE ranges from a low of 3.1 to a high of 4.3 cents per kWh. These results are similar to those for Case PC-3.

-20% -15% -10% -5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

2.8 3.0 3.2 3.4 3.6 3.8 4.0 4.2 4.4Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate


### Figure 4.3. 4: Case CFB-3 - Economic Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### 4.3.4.3 High Temperature Nickel Alloy Sensitivity Study In general, the cost of Ni alloys affected t he COE by about -1 1⁄4% when the alloy cost is decreased from $28 to $20 per pound and by about +1 1⁄4% when the alloy cost is increased from $28 to $32.90 per pound.
Results for the high temperature alloy Case PC-5 COE sensitivity study are shown in Figure 4.3.5 and tabulated in Appendix IV. The levelized COE for the base parameter values is 3.77 cents per kWh. Levelized COE ranges from a low of 3.71 to a high of 3.81 cents per kWh.

-2.50% -1 .25% 0.00% 1 .25% 2.50%

1 8.0 22.0 26.0 30.0 34.0 High Temperature Alloy Cost ($ / pound)Percent Change in COE

3.68 3.70 3.72 3.74 3.76 3.78 3.80 3.82 3.84 3.86Levelized COE (cents / kWh)



### Figure 4.3. 5: Case PC-5 – High Temperature Alloy Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### Similarly, the results for the high temperature alloy Case CMB TM 

### -5 COE sensitivity study are shown in Figure 4.3.6 and tabulated in Appendix IV. The levelized COE for the base parameter values is 3.41 cents per kWh. Levelized COE ra nges from a low of 3.40 to a high of 3.42 cents per kWh.

-2.50% -1.25% 0.00% 1.25% 2.50%

18.0 22.0 26.0 30.0 34.0 High Temperature Alloy Cost ($ / pound)Percent Change in COE

3.32 3.34 3.36 3.38 3.40 3.42 3.44 3.46 3.48Levelized COE (cents / kWh)



### Figure 4.3. 6: Case CMB TM 

### -5 – High Temperature Alloy Sensitivity Results

Results for the high temperature alloy repowe ring Case COE sensitivity study are shown in Figure 4.3.7 and tabulated in Appendix IV. The levelized COE for the base parameter values is 2.8 cents per kWh. Levelized COE ranges from a low of 2.76 to a high of 3.83 cents per kWh.

-2.50% -1.25% 0.00% 1.25% 2.50%

18.0 22.0 26.0 30.0 34.0 High Temperature Alloy Cost ($ / pound)Percent Change in COE

2.73 2.75 2.77 2.79 2.81 2.83 2.85 2.87Levelized COE (cents / kWh)



### Figure 4.3. 7: Case Repowering – High Temperature Alloy Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### 4.3.4.4 NO x 

### / SO x 

### Credit Sensitivity Study for Repowering Case

Results for the NO x 

### / SO x 

### credit for the repowering Case CO E sensitivity study are shown in Figure 4.3.8 and tabulated in Appendix IV. The NO x 

### credits are based on the reduction of NO x 

### emissions with repowering versus the base pl ant during the five month ozone season which the base plant purchases NO x 

### credits. The SO x 

### credits are based on the reduction of SO x 

### emissions by 30% from the repowering case versus the base plant for the entire year. The sulfur capture is in-furnace only and no additional back-end equipm ent is provided to facilitate higher percent of sulfur removal. The investment cost was increased by about $1,000,000 to account for a limestone feed system.
When comparing the COE of the repowering ca ses selling emissions credits versus the base plant purchasing credits, NO x 

### credits of about $6,500 per ton NO x 

### sold would produce a COE similar to the COE of the base plant purchasing NO x 

### credits at $5,000 per ton NO x 

### .

2.78

2.29 2.73 2.75 2.85 2.53

0.0 0.5 1.0 1.5 2.0 2.5 3.0

No NOx / SOx Credits Sold Sell NOx Credits at $2k/ton Sell NOx Credits at $5k/ton Sell NOx Credits at

$8k/ton Base, Purchase NOx Credits at $5k/ton Base, Purchase NOx Credits at $8k/tonLevelized COE (cents per kWh) Repowering

$200/ton SOx Credit



### Figure 4.3. 8: Case Repowering – NO x 

### Credit Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### Figure 4.3.9 provides the break down of levelized COE for the scenarios shown in Figure 4.3.8. NO X 

### and SO x 

### credits offset the variable O&M cost for the repowering case.

0.0 0.5 1.0 1.5 2.0 2.5 3.0

No NOx / SOx Credits Sold Sell NOx Credits at $2k/ton Sell NOx Credits at $5k/ton Sell NOx Credits at $8k/ton Base, Purchase NOx Credits at $5k/ton Base, Purchase NOx Credits at $8k/tonLevelized COE Breakdown (cents per kWh)

Fuel
Variable O&M
Fixed O&M
Financial Repowering

$200/ton SOx Credit



### Figure 4.3. 9: Case Repowering – Breakdown of COE from NO x 

### Credit Sensitivity StudyECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### 4.4 Economic Study Summary and Conclusions

The economic study results are summarized by co mparing the levelized COE results for the PC, CFB, and CMB TM 

### cases as shown in Figure 4.4.1. The ultra-supercritical case CMB TM 

### -5 has the lowest cost of electricity. The lower cost is di rectly related to high efficiency of power generation and the lower cost of finned surfaces applied in the boiler. The finned surface arrangement minimizes the need for expensive Ni alloy tubing and piping. Among the state-of-the-art technology, the supercritical CFB cases, CFB-3 and CFB-4, have the lowest COE. The CFB and CMB TM 

### based systems both produce lower COE than the PC based systems. The main reason for the lower cost is that the PC-systems, to achieve environmental goals, require more expensive flue gas cl ean-up systems (SCR, ESP, and we t FGD). There is no significant difference in COE within the supercritical PC cases (PC-3, PC-4, and PC-5). Subcritical PC cases have the highest electricity production cost s. Similarly, there are no significant differences in COE within the CFB and CMB TM 

### cases.

3.96 3.89 3.82 3.76 3.77 3.62 3.56 3.53 3.52 3.41

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5

PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 Case StudyLevelized COE (cents per kWh)

Fuel
Variable O&M
Fixed O&M
Financial



### Figure 4.4. 1: Levelized Cost of Electricity Comparison for PC and CFB/ CMB TM 

### CasesECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 118 

### The economic study results for repowering the base plant are summarized by comparing the levelized COE results for the repowering and base plant cases as shown in Figure 4.4.2. This figure illustrates ho w the cost of NO x 

### credits impacts the COE. As the price of NO x 

### credits increases, the difference in the COE between the repowering case and the base case becomes progressively smaller. It should be noted that the comparison shown is based on the new boiler that is subject to amortization in future ye ars and the existing boiler that is already fully depreciated. It should be also noted that any majo r investment cost required to refurbish the existing old boiler or potential decrease in futu re availability caused by the aging equipment has not been considered in estimating the COE of the base case.

2.78

2.29 2.73 2.75 2.85 2.53

0.0 0.5 1.0 1.5 2.0 2.5 3.0

No NOx / SOx Credits Sold Sell NOx Credits at $2k/ton Sell NOx Credits at $5k/ton Sell NOx Credits at

$8k/ton Base, Purchase NOx Credits at $5k/ton Base, Purchase NOx Credits at $8k/tonLevelized COE (cents per kWh) Repowering

$200/ton SOx Credit



### Figure 4.4. 2: Levelized Cost of Electricity Comparison for Repowering versus Base PlantECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 119 

### The effect of coal cost on the COE for the PC Cases are shown in Figure 4.4.3. Case PC-5 shows the lowest COE at coal costs greater th an about $1.40 per MM-Btu. PC-4 has the lowest COE of coal costs less than $1.40 per MM-Btu



### 3.0 3.2 3.4 3.6 3.8 4.0 4.2 4.4

0.90 1.00 1.10 1.20 1.30 1.40 1.50 1.60 Coal Cost ($ / MMBtu)Levelized COE (cents / kWh)

PC-1 (37.0%) PC-2 (37.9%) PC-3 (38.9%) PC-4 (39.8%) PC-5 (43.6%)



### Figure 4.4. 3: Effect of Coal Cost on COE for PC Cases

The effect of coal cost on the COE for the CFB/ CMB TM 

### Cases are shown in Figure 4.4.4. Case CMB TM 

### -5 has the lowest COE over the entire c oal cost range of $0.90 per MM-Btu to $1.60 per MM-Btu.



### 3.0 3.2 3.4 3.6 3.8 4.0 4.2 4.4

0.90 1.00 1.10 1.20 1.30 1.40 1.50 1.60 Coal Cost ($ / MMBtu)Levelized COE (cents / kWh)

CFB-2 (38.0%) CFB-3 (39.0%) CFB-4 (39.8%) CMB-3 (38.9%) CMB-5 (43.5%)



### Figure 4.4. 4: Effect of Coal Cost on COE for CFB/ CMB TM 

### CasesECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 120 

### The study has also investigated the impact of potential taxes placed on CO 2 

### emissions. The figure below illustrates the changes in the COE as the potential CO 2 

### tax increases for the PC power plant cases. As expected, the COE increa ses significantly with the increase in the tax. The figure also shows that the tax would become a major driver in utilit y companies’ selection process of the power plant cycle parameters an d the high efficiency plants would become the technologies of choice.



## 3.0 4.0 5.0 6.0 7.0 8.0 9.0

0 10 20 30 40 50 CO2 Tax ($/Ton CO2)Cents/kwhr PC-1 (2400/1000/1000)

PC-2 (2400/1049/1112)

PC-3 (3625/1049/1112)

PC-4 (3915/1085/1148)

PC-5 (5075/1292/1328)



### Figure 4.4. 5: Cost of Electricity for PC Power Plant Cases For Different CO 2 

### Emissions Tax RateECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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## 5. Conclusions and Recommendations

Primary results for both parts of the study (Greenfield and Repowering) are summarized in terms of thermal efficiency, investment costs, and co st of electricity (COE). The table shown below defines the case studies in terms of steam cycl e parameters and combustion technology and also summarizes the primary results (thermal efficiency, investment cost, and COE) for all the cases.

Table 5.0. 1: Primary Results Summary: Thermal Efficiency, Investment Costs, and Cost of Electricity

PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 Repower Existing
Steam Cycle Parameters Main Steam Pressure (psia) 2408 2408 3625 3915 5075 2408 3625 3915 3625 5075 4242 2015 Main Steam Temperature (Deg F) 1000 1049 1049 1085 1292 1049 1049 1085 1049 1292 1292 1050 Reheat Steam Temperature (Deg F) 1000 1112 1112 1148 1328 1112 1112 1148 1112 1328 1000 1000 Feedwater Temperature (Deg F) 500 500 500 554 626 500 500 554 500 626 460 453 Number of Feedwater Heaters (no.) 777897787988
Efficiency and Output Boiler Efficiency (HHV basis) (fraction) 0.8975 0.8975 0.8975 0.8975 0.8975 0.8975 0.8975 0.8975 0.8926 0.8926 0.8873 0.8816

Steam Cycle Efficiency (fraction) 0.4442 0.4543 0.4650 0.4745 0.5161 0.4543 0.4650 0.4745 0.4650 0.5161 0.4604 0.4269 (Btu/kwhr) 7683 7512 7339 7193 6613 7512 7339 7193 7339 6613 7413 7994

Generator Output (kw) 696316 711278 736148 753937 821374 711278 736148 753937 736148 821374 203807 168604

Net Plant Output (kw) 630526 646080 662936 677479 741615 647588 663823 678366 665552 744230 184887 156518

Fuel Heat Input (HHV basis) (MM-Btu/hr) 5812 5812 5812 5812 5812 5812 5812 5812 5844 5844 1643 1496

Net Plant Heat Rate (HHV basis) (Btu/kwhr) 9218 8997 8768 8580 7838 8976 8756 8568 8781 7853 8889 9561 Thermal Efficiency (HHV basis) (fraction) 0.3702 0.3794 0.3893 0.3978 0.4355 0.3803 0.3898 0.3983 0.3887 0.4346 0.3840 0.3570

Costs and Economics Investment Costs ($/kWe net) 1,139 1,126 1,109 1,098 1,168 1,051 1,038 1,039 1,018 1,039 413 n/a

Levelized Cost of Electricity (Cents/kWh) 3.96 3.89 3.82 3.76 3.77 3.62 3.56 3.53 3.52 3.41 2.76 2.29



### Greenfield Cases: For the ten Greenfield cases, the calculated th ermal efficiencies (HHV basis) range from 37.02% to 43.55%. With respect to thermal efficiency, for the same steam conditions, there is little difference when comparing among the combustion systems (PC, CFB, and CMB TM 

### ) as would be expected. In general, the thermal efficiency of the PC fired systems are about the same as for the CFB based systems. The CFB and PC systems thermal efficiency are about 0.1 percentage points higher than the CMB TM 

### systems which is due to only partial sulfation in the CMB TM 

### combustor. The effect of the increasing st eam cycle parameters (Tem perature and Pressure) is also clearly illustrated.
The specific investment cost results for the Gr eenfield cases shown in the table above range from about 1,018 to 1,168 $/kW-net. For t he same steam conditions, the CMB TM 

### combustion system plants require the lowest investment costs as compared to PC or CFB plants. This cost advantage increases as steam cycle conditions (T emperature and Pressure) are raised. The CFB systems are about 70 $/kW lower in cost than t he PC type combustion systems. This difference is primarily attributable to the differences in the costs for the gas cl eanup system equipment.
The cost of electricity (COE) results for the Gr eenfield cases shown in the table above range from about 3.4 to 4.0 Cents/kWh. These results indicate that Case CMB TM 

### -5 is the most economical from a COE basis. Compared to Case PC-5, it re quires significantly less of very expensive Ni alloy tubing. The effect of increased steam conditions on COE is also shown in the graph below with the increased steam conditions offering a slight advantage. For the same steam conditions there is very little difference in the COE between CFB and CMB TM 

### designs.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 122 3.96 3.89 3.82 3.76 3.77 3.62 3.56 3.53 3.52 3.41

2.76

2.29

0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 4.50

PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 Repower ExistingCost of Electricity - (Cents/kwhr)



### Figure 5.0. 1: Cost of Electricity Comparison (All Cases)

Similar to the investment cost results, the PC cases are about 7% higher than the CFB type combustion systems with respect to COE at t he same steam conditions. The advantage of the CFB systems is attributable to the investment co st savings discussed above. Because of the additional reduction in investment cost associated with CMB TM 

### based systems, the CMB TM 

### combustion system offers a COE advantage as compared to PC of about 8-10% (greater advantage at higher steam conditions).
The cost of electricity is directly related to t he cost of fuel. The above COE’s are calculated for the price of fuel of $1.25/MBtu. As the cost of fuel increases, as shown in Figure 5.0.2, the cost of electricity increases also and at the same ti me the economics continue to shift towards the more efficient power plant systems. For example, at a of coal price of $1.80 MM-Btu the COE is the lowest for the ultra-supercritical case PC -5 among the PC power plant cases. The ultrasupercritical CMB-5 continues to offer the lowe st COE among the power plant cycles analyzed.

4.46 4.39 4.30 4.23 4.21 4.12 4.04 4.00 4.00 3.84

3.24

2.80

0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 4.50 5.00PC-1PC-2PC-3PC-4PC-5CFB-2CFB-3CFB-4CMB-3CMB-5RepowerBase $1.25 per MMBtu ($1.27 per MMBtu for Sporn Plant) $1.80 per MMBtu



### Figure 5.0. 2: Cost of Electricity Comparison for 1.25 and 1.80 $/MM-Btu Fuel Cost – All CasesECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 123 

### Repowering Case: For the Repowering case, the calc ulated thermal efficiency (HHV basis) is improved from 35.70% for the existing unit to 38.40%. The investment co sts necessary for all the equipment required for this repowering project is 413 $/kW-net and t he resulting incremental cost of electricity is calculated to be 0.47 Cents/kWh (2.76 – 2.29 Cents/kWh). Incremental is calculated relative to the unmodified existing unit. This difference may quickly disappear if the price of NO x 

### credits continues to increase and/or a major capital inve stment is required to refurbish the existing boiler of if there is loss of availab ility caused by the aging equipment.

Recommendations: In summary, from the results of the study the ev aluated power plant systems fall either into the near term or long term category with respec t to technology implementation. All combustion technologies can achieve low levels of pollutants and comply with the CURC 2010 air pollution targets. Technology is available to day to facilitate constr uction of all the PC cycles, except for the ultra-supercitical steam conditions of Case PC -5, and all the CFB steam cycles. Technology is being developed to enable market introduction of Case PC-5 and both CMB TM 

### cycles in a 10 to 15 year timeframe. The very high steam temperat ures of the ultra-supecritical steam cycle do not appear to be practical for conventional CFB technology where combustion temperature is generally limited to 1,550 0 

### F. CMB TM 

### technology with the combustion temperature of 2000 0 

### F allows greater latitude in selecting the range of steam cycle parameters. The ultra-supecritical CMB TM 

### design offers the prospect of the lowest COE.
The CFB power plants are the technology of choice for high sulfur coals. For low sulfur coals the PC power plants that don’t requi re installation of the back end NO x 

### and SO x 

### control technologies would be favored. The supercritical CFB plants have the lowest cost of electricity and its cost continues to improve for higher steam conditions.

Building up on these results, the next step in t he development effort of the Rankine power plant cycle is recommended. It should include a CFB design with steam conditions of 4,000 psi to 5000 psi and main and reheat steam te mperatures of approximately 1,200 0 

### F. The potential plant efficiency improvement would be significant and the efficiency should be in the range of 41-42% (HHV basis). These steam conditions may require some CFB process modifications to enable the higher steam temperatures but would represent the upper limit for conventional boiler alloys. Such a design would fulfill the promise of high effi ciency and low cost of the intermediate term (3 to 5 years) power plant cycle.

Based on reliability, investment costs, emissions and cost of electricity a coal fired steam power plant will continue to be a good investment for power plant owners especially compared to other options such as IGCC for coal powered electric power production. The thermal efficiencies of today’s steam power plants with supercritical steam cycles are higher than today’s IGCC plants. For power plants of the future, studies show that coal fired steam plants with ultra-supercritical steam cycles will maintain this efficiency advan tage over future IGCC plants with advanced gas turbines. (MARION,10)ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 124 

## 6. Bibliography

Bustard et al., DOE Full Scale Data, Ai r Quality III Conferen ce, September 2002.

Coal Utilization Research Co uncil - CURC (www.coal.org).

Jukkola, G.; Turek, D.; Levasseur, A.; Tei gen, B.; “Operating Experience with ALSTOM’s Circulating Moving Bed Combustor”, Proceedings of FBC-2003, 17 th 

### International Fluidized Bed Combustion Conference, Jacksonville, Florida USA, May 18-21, 2003.

Marchetti, M.; Semedard, J.; Devroe, S.; Czarne cki, T.; Lemasle, J.; “ ALSTOM’s Large CFB’s and Results” Proceedings of FBC-2003, 17 th 

### International Fluidized Bed Combustion Conference, Jacksonville, Florida USA, May 18-21, 2003.
Marion,J.; Liljedahl, G.; Black, S.; “ A review of the State-of-the-art and a View of the Future for Combustion-Based Coal Power Generation” 29 th 

### International Technical Conference on Coal Utilization and Fuel Science, Clearwater, Florida USA, April 18-22, 2004.
Palkes, M.; “Boiler Materials for Ultra Supercrit ical Coal Power Plants”, Task 1A, Conceptual Design, ALSTOM Approach, Topical Report, Prepar ed for the U.S. Department of Energy Grant Number DE-FG26-01NT41175, Ohio Coal Development Office Grant No: D-00-20, February 2003.
Palkes, M.; Banas, J.; Weissinger, G.; Kessel, W.; “State-of-the-Art Sliding Pressure Supercritical Steam Generators” International Power Generation Conference, Las Vegas, Nevada USA, December 2001.
Palkes, M.; Liljedahl, G.; Kruger, H.; Weirich, P .; “The Next Step Power Plant – a Boiler/Turbine Optimization Study” Alstom Power Propri etary Internal Publication, March 1999.
Palkes, M.; Waryasz, R.; Kamalendu, D.; “Economics and Feasibility of Rankine Cycle Improvements for Coal Fired Power Plants”, Twentieth Annual International Pittsburgh Coal Conference, September 15-19, 2003.
Singer, J.; “Combustion Fossil Power” Fourth Edition; Copyright 1991; Combustion Engineering Inc.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 125 

## 7. Appendices

The four appendices provided in this section are described and listed below:

• Appendix I : Plant equipment lists

• Appendix II : Plant investment cost and operating and maintenance cost breakdowns

• Appendix III : Boiler drawings

• Appendix IV : Economic sensitivity study resultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 126 

### 7.1 Appendix I - Plant Equipment Lists This appendix provides a listing of all major plant equipment provided for all power plants included in this study. The equipment lists are divided into two groups, Boiler island equipment and Balance of plant equipment.
The Boiler Island equipment for the Greenfield ca ses is subdivided by combustion system type (i.e. PC, CFB, and CMB TM 

### ).
Balance of Plant Equipment for the Greenfield ca ses is shown in a single list. Because much of the equipment is common to all the Greenfield plants , a single list is used with differences among the cases indicated where necessary. For exam ple, the Coal Receiving and Handling equipment (Account 1) is the same for all cases ant theref ore it is only listed once and is identified as “Common to all Cases”. Where there are differe nces, they are indicated. For example, the Feedwater Systems (Account 3A) are differentiated by using five separate lists for this equipment account and indicating Steam Cycle 1, 2, 3, 4, and 5, for the five different steam cycles used in this study. Specific study case identifiers (i.e . PC-1) are also listed where differences occur.
The equipment required for the Sporn repowering ca se (Boiler Island and Balance of Plant) are listed after the Greenfield cases. The Balance of Plant list shows only the new major items that were added for the repowering and does not include existing BOP equipment.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### 7.1.1 Boiler Island Equipment for Greenfield Cases

7.1.1.1 PC Cases Boiler Island Equipment This section contains a list of all equipment asso ciated with the boiler scope of supply for the PC boilers for cases PC-1, PC-2, PC-3, PC-4, and PC-5. Cases PC-1 and PC-2 are subcritical pressure designs and Cases PC-3, PC-4, and PC-5 are supercritical pressure designs. A large portion of the equipment is common to all five boilers and therefore a single equipment list is provided with differences between the three cases indicated in this list where necessary.

Fuel Feeding System: - Day Silo - Fuel Silo Isolation Valves - Fuel Feeders - Feeder Isolation Valves - Piping to Furnace Furnace Equipment: - PC-1,-2 Drum Including Internals, Nozzles, Lugging, Hanger Rods Downcomer System - PC-3,-4,-5 Separator Including Nozzles, Lugging, Hanger Rods Start-up System Including Recirculation Pump, Storage Tank, Piping - Connecting Tubes/Piping - Furnace Tube Panels/Headers - PC-1, PC-2, PC-3, PC-4 and PC-5 Fu rnace Superheater Pendants/Headers/Piping (panels and platens) - PC-3,-4,-5 In Tunnel Superh eat Pendant/Headers/Piping (spaced) - PC-1, PC-2, PC-3, PC-4 and PC-5 Above Arch Reheater Pendants/Headers/Piping (platens) - PC-1,-2 In Tunnel Reheater Pendant/Headers/Piping (spaced) - PC-1,-2 Reheater Radiant Wall/Headers/Piping - Bottom Ash Removal System - Start-up Burner System (Including Burn ers, Piping, Ducts, and Local Control Equipment) - Backpass Enclosure - Metal/Fabric Expansion Joints - Buckstay System:
Furnace Backpass 

### Backpass Equipment: - Connecting Tubes/Piping - Backpass Tube Panels/Headers - Backpass Heat Absorbing Surface: PC-1,-2 Horizontal Superheater/Economizer PC-3.-4.-5 Horizontal Reheater/Economizer - Superheater/Reheater Desuperheaters - Desuperheater Block Valves - Desuperheater PipingECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 128 

### - PC-1,-2 Economizer Piping to Drum - PC-3,-4,-5 Economizer Piping to Furnace Walls - Superheater Interconnecting Piping - Feedwater Stop, Feedwater Check - Safety Valves/Discharge Piping/Silencers - Electro. Relief Valve/Sile ncer and Discharge Piping

Trim Valves: - Double Valving Drum Level Gauge and Indicators Sootblowing System: - Economizer - Superheater/Reheater - Airheater - Sootblower Control System Air System: - Primary Air Fan w/Drive (by others) - Secondary Air Fan w/Drive (by others) - Fan and Blower Inlet Silencers (by others) - Sealing Air System - Ljungstrom Regenerative Air Heater - Ductwork - Fan Outlet(s) to Airheater Inlet(s) - Steam Coil Air Preheaters - Air Duct Expansion Joints Combustion Gas System: - Ductwork and Expansion Joints - Economizer Outlet to Airheater - Ductwork - Airheater Outlet (including airheater plenum & hoppers) to ESP - Ductwork ESP Outlet to I.D. Fan Inlet - I.D. Fan w/Drive (by others) - Ductwork – I.D. Fan Outlet to FGD Flange Connection Ash Handling System: - Bottom ash Scraper Conveyor System Fuel System: - Pulverized Coal Burners and Windbox - Pulverizers and Motors with Accessories - Pulverized Coal Piping - Pulverizer Inerting and Cleaning System - Ignition Equipment

Structural: - Structural Steel including platform s, walkways, stairways, and ladders - Boiler Internal Grid Steel - Boiler Island Elevator - Pressure Part Support Steel - Boiler Building Siding, Weather Enclosure, HVAC

Instrumentation and Controls: - Burner Management System (BMS) Logic - Field Instruments - Controller Drives

Refractories:ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 129 

### - Material for All Internal Refractory Linings for Furnished Process and Boiler

Equipment Insulation and Lagging: - Material for Insulation and Lagging for Heat Conservation and Personnel Protection for furnished equipment Painting: - Shop Prime Paint Coating for Seller furnished Equipment

Miscellaneous: - Operator Training Program - Maintenance Training Program - Instruction Manuals - Spare Parts for commissioning - Technical Representation during start-up and testing - Field Erection of Equipment Scope - Freight to SiteECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 130 

### 7.1.1.2 CFB Cases Boiler Island Equipment This section contains a list of all equipment asso ciated with the boiler scope of supply for the CFB boilers for cases CFB-2, CFB-3, and CFB-4. Ca se CFB-2 is a subcritical pressure design and Cases CFB-3 and CFB-4 are both supercritical pressure designs. A large portion of the equipment is common to all three boilers and ther efore a single equipment list is provided with differences between the three cases indicated in this list where necessary.

Fuel Feeding System: - Day Silo - Fuel Silo Isolation Valves - Fuel Feeders - Feeder Isolation Valves - Piping to Furnace Limestone Feeding System: - Day Silo - Limestone Silo Isolation Valves - Rotary Feeder - Blower - Piping from Blower to Furnace Injection Points Furnace Loop Equipment: - CFB-2 Drum Including Internals, Nozzles, Lugging, Hanger Rods Downcomer System - CFB-3,-4 Separator Including Nozzles, Lugging, Hanger Rods Start-up System Including Recirculation Pump, Storage Tank, Piping - Connecting Tubes/Piping - Furnace Tube Panels/Headers - Furnace Superheater Pe ndants/Headers/Piping - CFB-2 Furnace Evaporator Pendants/Headers/Piping - CFB-3,-4 Furnace Once Though Pendants/Headers/Piping - Furnace Grate and Plenum Including Air Nozzles - Ash Drain Valve(s) - Start-up Burner System (Including Burn ers, Piping, Ducts, and Local Control Equipment) - Ductwork – Furnace to Recycle Particle Separators - Refractory-Lined Recycle Particle Separator – Complete - Ductwork – Recycle Particle Separator to Backpass Inlet - Backpass Enclosure - Metal/Fabric Expansion Joints - Seal pots and Seal pot Grate – Including Air Nozzles and Plenum - Buckstay System:
Furnace Backpass 

### Backpass & FBHE Equipment: - Connecting Tubes/Piping - Backpass Tube Panels/Headers - Backpass Heat Absorbing Surface: CFB-2,-3 Horizont al Reheater/Economizer CFB-4 Horizontal Supe rheater/Reheater/EconomizerECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 131 

### - FBHE Heat Absorbing Surface: CFB-2 Superheater/Reheater CFB-3,-4 Superheater/Reheater/Economizer - Superheater/Reheater Desuperheaters - Desuperheater Block Valves - Desuperheater Piping - CFB-2 Economizer Piping to Drum - CFB-3,-4 Economizer Piping to Furnace Walls - Superheater Interconnecting Piping - Feedwater Stop, Feedwater Check - Safety Valves/Discharge Piping/Silencers - Electro. Relief Valve/Sile ncer and Discharge Piping

Trim Valves: - Double Valving Drum Level Gauge and Indicators Sootblowing System: - Economizer - Superheater/Reheater - Airheater - Sootblower Control System Air System: - Primary Air Fan w/Drive (by others) - Secondary Air Fan w/Drive (by others) - Fluidizing Air Blower w/Drive (by others) - Fan and Blower Inlet Silencers (by others) - Ljungstrom Regenerative Air Heater - Ductwork - Fan Outlet(s) to Airheater Inlet(s) - Ductwork - Blower Outlets to Seal pots - Steam Coil Air Preheater - Air Duct Expansion Joints Combustion Gas System: - Ductwork and Expansion Joints - Economizer Outlet to Airheater - Ductwork - Airheater Outlet (including airheater plenum & hoppers) - Ductwork Outlet to I.D. Fan Inlet - I.D. Fan w/Drive (by others) - Ductwork – I.D. Fan Outlet to Stack Flange Connection Ash Handling System: - Bed Ash Drains and Ash Coolers

Structural: - Structural Steel including platform s, walkways, stairways, and ladders - Boiler Internal Grid Steel - Boiler Island Elevator - Pressure Part Support Steel - Boiler Building Siding, Weather Enclosure, HVAC

Instrumentation and Controls: - Burner Management (FBSS) Logic - CFB Field Instruments - Controller Drives

Refractories:ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 132 

### - Material for All Internal Refractory Linings for Furnished Process and Boiler

Equipment Insulation and Lagging: - Material for Insulation and Lagging for Heat Conservation and Personnel Protection for furnished equipment Painting: - Shop Prime Paint Coating for Seller furnished Equipment

Miscellaneous: - Operator Training Program - Maintenance Training Program - Instruction Manuals - Spare Parts for commissioning - Technical Representation during start-up and testing - Field Erection of Equipment Scope - Freight to SiteECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 133 

### 7.1.1.3 CMB TM 

### Cases Boiler Island Equipment This section contains a list of all equipment a ssociated with the boiler scope of supply for the CMB TM 

### boilers for cases CMB TM 

### -3, and CMB TM 

### -5. Cases CMB TM 

### -3 and CMB TM 

### -5 are supercritical and ultra-supercritical pressure desi gns. A large portion of the equipment is common to both boilers and therefore a single equipment lis t is provided with differences between the two cases indicated in this list where necessary.

Fuel Feeding System: - Day Silo - Fuel Silo Isolation Valves - Fuel Conveyors & Feeders - Feeder Isolation Valves - Piping to Furnace Limestone Feeding System: - Day Silo - Limestone Silo Isolation Valves - Rotary Feeder - Blower - Piping from Blower to Furnace Injection Points Furnace Loop Equipment: - Furnace Grate and Plenum Includ ing Air Nozzles & Drain Tubes - Ash Drain Valve(s) - Start-up Burner System (Including Burn ers, Piping, Ducts, and Local Control Equipment) - Ductwork – Furnace to Recycle Particle Separators - Particle Separator – Complete - Ductwork – Recycle Particle Separator to Air Heater Inlet - Metal/Fabric Expansion Joints - Seal pots and Seal pot Grate – Including Air Nozzles and Plenum - Buckstay System MBHE Equipment: - Separator Including Nozzles, Lugging, Hanger Rods - Start-up System Including Recirculation Pump, Storage Tank, Piping - Connecting Tubes/Piping - Tubing /Headers - Buckstay System - MBHE Heat Absorbing Surface: Horizontal Superheaters Horizontal Reheater Horizontal Once Through Heat Exchanger Steam Cooled Support System 

### - Superheater/Reheater Desuperheaters - Reheat Steam Temperature Control Valving - Desuperheater Block Valves - Desuperheater Piping - Once Through Heat Exchanger Piping to Separator - Superheater Interconnecting Piping - Feedwater Stop, Feedwater Check valvesECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 134 

### - Safety Valves/Discharge Piping/Silencers - Electro. Relief Valve/Sile ncer and Discharge Piping Particle Return System: -Particle Removal Cyclones -Ductwork PA Fan to MBHE Outlet Particle transport pipes from MB HE outlet to Cyclone separator Cyclone gas outlets to Furnace


### Trim Valves: - Double Valving Sootblowing System: - Air heater - Sootblower Control System Combustion Gas System: - Ductwork and Expansion Joints - Cyclone Outlet to Air Heater Inlet - Ductwork – Air Heater Outlet to FDA Inlet - Ductwork FDA Outlet to ID Fan Inlet - I.D. Fan w/Drive (by others) - Ductwork ID Fan Outlet to Stack Air System: - PA Fan w/Drive (by others) - Ductwork – PA Fan Outlets to Air Heater - Ductwork – Air Heater Outlet to Furnace - SA Fan w/Drive (by others) - Ductwork – SA Fan Outlets to Air Heater - Ductwork – Air Heater Outlet to Furnace - Fluidizing Air Blower w/Drive (by others) - Ductwork – FA Blower Outlets to Seal pot Ash Handling System: - Bed Ash Drains and Ash Coolers

Structural: - Structural Steel including platform s, walkways, stairways, and ladders - Boiler Internal Grid Steel - Boiler Island Elevator - Pressure Part Support Steel - Boiler Building Siding, Weather Enclosure, HVAC

Instrumentation and Controls: - Burner Management (FBSS) Logic - CFB Field Instruments - Controller Drives

Refractories: - Material for All Internal Refractory Linings for Furnished Process and Boiler

Equipment Insulation and Lagging: - Material for Insulation and Lagging for Heat Conservation and Personnel Protection for furnished equipment Painting: - Shop Prime Paint Coating for Seller furnished EquipmentECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 135 

### Miscellaneous: - Operator Training Program - Maintenance Training Program - Instruction Manuals - Spare Parts for commissioning - Technical Representation during start-up and testing - Field Erection of Equipment Scope - Freight to SiteECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 136 

### 7.1.2 Balance of Plant Equipment for Greenfield Cases

This section contains the balance of plant equi pment list corresponding to the Greenfield power plant configurations. This list, along with the material and energy balances and supporting performance data, was used to generate plant costs used in the financial analysis. In the following, all feet (ft) conditions specified for process pumps correspond to feet of liquid being pumped.
Because much of the equipment is common to all t he Greenfield plants, a single list is used with differences among the cases indicated where nece ssary. For example, the Coal Receiving and Handling equipment (Account 1) is the same for a ll cases and therefore it is only listed once and is identified as “Common to all Cases”. Where there are differences, they are indicated. For example, the Feedwater Systems (A ccount 3A) are differentiated by using five separate lists for this equipment account and indicating Steam Cycle 1, 2, 3, 4, and 5, for the five different steam cycles used in this study. Specific study case identifiers (i.e. PC-1) are also listed where differences occur.ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 137 

### ACCOUNT 1 COAL RECEIVING AND HANDLING (Common to all cases)

Equipment No. Description Type Design Condition Qty 1 Bottom Trestle Dumper and Receiving Hoppers N/A 200 ton 3

2 Feeder Vibratory 700 tph 2 3 Conveyor 1 54" belt 700 tph 2

4 As-Received Coal Sampling System Two-stage N/A 1

5 Conveyor 2 54" belt 700 tph 2 6 Reclaim Hopper N/A 40 ton 2 7 Feeder Vibratory 350 tph 2 8 Conveyor 3 48" belt 700 tph 1 9 Crusher Tower N/A 700 tph 1 10 Coal Surge Bin w/ Vent Filter Compartment 700 ton 1ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 138 

### ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED

ACCOUNT 2A COAL PREPARATION AND FEED SYSTEM (Common to all cases)

Equipment No. Description Type Design Condition Qty

1 Crusher Granulator reduction 6" x 0 - 3" x 0 1 2 Crusher Impactor reduction 3" x 0 – 1/4" x 0 1 3 As-Fired Coal Sampling System Swing hammer 700 tph 2

4 Conveyor 4 48" belt 700 tph 1 5 Transfer Tower N/A 700 tph 1 6 Tripper N/A 700 tph 1

7 Coal Silo w/ Vent Filter and Slide Gates N/A Boiler Scope

8 Feeder Gravimetric Boiler Scope

ACCOUNT 2B LIMESTONE PREPARATION AND FEED SYSTEM (Common to all cases)

Equipment No. Description Type Design Condition Qty 1 Bin Activator 20 tph 1 2 Weigh Feeder Gravimetric 20 tph 1 3 Storage Silo Cylindrical 1,000 ton 1

4 Blowers Roots Site 2ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

ACCOUNT 3A FEEDWATER SYSTEMS FEEDWATER SYSTEMS (Steam Cycle #1; Case PC-1)

Equipment No. Description Type Design Condition Qty 1 Condensate Storage Tank Field fabricated 400,000 gal. 1
2 Surface Condenser Two shell, transverse tubes 3,000,000 lbm/hr 2.5 in. Hg 1

3 Condenser Vacuum Pumps Rotary water sealed 2,500/25 scfm 2

4 Condensate Pumps and drive motors Vertical canned 1,300,000 lbm/hr 800 ft 3

5 Gland Steam Condenser Horizontal U Tube 3,700,000 lbm/hr 109°F to 110°F 1

5 LP Feedwater Heater 1 Horizontal U Tube 3,700,000 lbm/hr 110°F to 154°F 1

6 LP Feedwater Heater 2 Horizontal U Tube 3,700,000 lbm/hr 154°F to 197°F 1

7 LP Feedwater Heater 3 Horizontal U Tube 3,700,000 lbm/hr 197°F to 247°F 1

8 LP Feedwater Heater 4 Horizontal U Tube 3,700,000 lbm/hr 247°F to 282°F 1

9 Deaerator and Storage Tank Horizontal spray type 3,700,000 lbm/hr 282°F to 361°F 1

10 Boiler Feedwater Booster Pumps and drive motors Horizontal split 2,350,000 lbm/hr 2,900 psia 2

11 Startup Boiler Feedwater Pumps and drive motors Barrel type multistage centrifugal 800,000 lbm/hr 2,900 psia 2

12 HP Feedwater Heater 6 Horizontal U Tube 4,400,000 lbm/hr 368°F to 434°F 1

13 HP Feedwater Heater 7 Horizontal U Tube 4,400,000 lbm/hr 434°F to 500°F 1ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 140 

### FEEDWATER SYSTEMS (Steam Cycle #2; Cases PC-2, CFB-2)

Equipment No. Description Type Design Condition Qty 1 Condensate Storage Tank Field fabricated 400,000 gal. 1
2 Surface Condenser Two shell, transverse tubes 2,900,000 lbm/hr 2.5 in. Hg 1

3 Condenser Vacuum Pumps Rotary water sealed 2,500/25 scfm 2

4 Condensate Pumps and drive motors Vertical canned 1,200,000 lbm/hr 800 ft 3

5 Gland Steam Condenser Horizontal U Tube 3,600,000 lbm/hr 109°F to 110°F 1

5 LP Feedwater Heater 1 Horizontal U Tube 3,600,000 lbm/hr 110°F to 152°F 1

6 LP Feedwater Heater 2 Horizontal U Tube 3,600,000 lbm/hr 152°F to 196°F 1

7 LP Feedwater Heater 3 Horizontal U Tube 3,600,000 lbm/hr 196°F to 246°F 1

8 LP Feedwater Heater 4 Horizontal U Tube 3,600,000 lbm/hr 246°F to 282°F 1

9 Deaerator and Storage Tank Horizontal spray type 3,600,000 lbm/hr 282°F to 361°F 1

10 Boiler Feedwater Booster Pumps and drive motors Horizontal split 2,200,000 lbm/hr 3,000 psia 2

11 Startup Boiler Feedwater Pumps and drive motors Barrel type multistage centrifugal 800,000 lbm/hr 3,000 psia 2

12 HP Feedwater Heater 6 Horizontal U Tube 4,400,000 lbm/hr 368°F to 434°F 1

13 HP Feedwater Heater 7 Horizontal U Tube 4,400,000 lbm/hr 434°F to 500°F 1ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 141 

### FEEDWATER SYSTEMS (Steam Cycle #3; Cases PC-3, CFB-3, CMB TM 

### -3)

Equipment No. Description Type Design Condition Qty 1 Condensate Storage Tank Field fabricated 400,000 gal. 1
2 Surface Condenser Two shell, transverse tubes 2,800,000 lbm/hr 2.5 in. Hg 1

3 Condenser Vacuum Pumps Rotary water sealed 2,500/25 scfm 2

4 Condensate Pumps and drive motors Vertical canned 1,200,000 lbm/hr 800 ft 3

5 Gland Steam Condenser Horizontal U Tube 3,500,000 lbm/hr 109°F to 110°F 1

5 LP Feedwater Heater 1 Horizontal U Tube 3,500,000 lbm/hr 110°F to 151°F 1

6 LP Feedwater Heater 2 Horizontal U Tube 3,500,000 lbm/hr 151°F to 195°F 1

7 LP Feedwater Heater 3 Horizontal U Tube 3,500,000 lbm/hr 195°F to 245°F 1

8 LP Feedwater Heater 4 Horizontal U Tube 3,500,000 lbm/hr 245°F to 280°F 1

9 Deaerator and Storage Tank Horizontal spray type 3,500,000 lbm/hr 280°F to 364°F 1

10 Boiler Feedwater Booster Pumps and drive motors Horizontal split 2,200,000 lbm/hr 4,500 psia 2

11 Startup Boiler Feedwater Pumps and drive motors Barrel type multistage centrifugal 800,000 lbm/hr 4,500 psia 2

12 HP Feedwater Heater 6 Horizontal U Tube 4,400,000 lbm/hr 375°F to 442°F 1

13 HP Feedwater Heater 7 Horizontal U Tube 4,400,000 lbm/hr 442°F to 500°F 1ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 142 

### FEEDWATER SYSTEMS (Steam Cycle #4; Cases PC-4, CFB-4)

Equipment No. Description Type Design Condition Qty 1 Condensate Storage Tank Field fabricated 400,000 gal. 1
2 Surface Condenser Two shell, transverse tubes 2,800,000 lbm/hr 2.5 in. Hg 1

3 Condenser Vacuum Pumps Rotary water sealed 2,500/25 scfm 2

4 Condensate Pumps and drive motors Vertical canned 1,150,000 lbm/hr 800 ft 3

5 Gland Steam Condenser Horizontal U Tube 3,400,000 lbm/hr 109°F to 110°F 1

5 LP Feedwater Heater 1 Horizontal U Tube 3,400,000 lbm/hr 110°F to 150°F 1

6 LP Feedwater Heater 2 Horizontal U Tube 3,400,000 lbm/hr 150°F to 194°F 1

7 LP Feedwater Heater 3 Horizontal U Tube 3,400,000 lbm/hr 194°F to 244°F 1

8 LP Feedwater Heater 4 Horizontal U Tube 3,400,000 lbm/hr 244°F to 278°F 1

9 Deaerator and Storage Tank Horizontal spray type 3,400,000 lbm/hr 278°F to 361°F 1

10 Boiler Feedwater Booster Pumps and drive motors Horizontal split 2,300,000 lbm/hr 4,900 psia 2

11 Startup Boiler Feedwater Pumps and drive motors Barrel type multistage centrifugal 800,000 lbm/hr 4,900 psia 2

12 HP Feedwater Heater 6 Horizontal U Tube 4,600,000 lbm/hr 373°F to 440°F 1

13 HP Feedwater Heater 7 Horizontal U Tube 4,600,000 lbm/hr 440°F to 509°F 1

14 HP Feedwater Heater 8 Horizontal U Tube 4,600,000 lbm/hr 509°F to 554°F 1ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 143 

### FEEDWATER SYSTEMS (Steam Cycle #5; Cases PC-5, CMB TM 

### -5)

Equipment No. Description Type Design Condition Qty 1 Condensate Storage Tank Field fabricated 400,000 gal. 1
2 Surface Condenser Two shell, transverse tubes 2,600,000 lbm/hr 2.5 in. Hg 1

3 Condenser Vacuum Pumps Rotary water sealed 2,500/25 scfm 2

4 Condensate Pumps and drive motors Vertical canned 900,000 lbm/hr 800 ft 3

5 Gland Steam Condenser Horizontal U Tube 2,700,000 lbm/hr 109°F to 110°F 1

5 LP Feedwater Heater 1 Horizontal U Tube 2,700,000 lbm/hr 110°F to 148°F 1

6 LP Feedwater Heater 2 Horizontal U Tube 2,900,000 lbm/hr 148°F to 191°F 1

7 Heater #2 Drain Pump Vertical canned 112,000 lbm/hr 800 ft 1

8 LP Feedwater Heater 3 Horizontal U Tube 2,900,000 lbm/hr 191°F to 242°F 1

9 LP Feedwater Heater 4 Horizontal U Tube 3,200,000 lbm/hr 242°F to 280°F 1

10 Heater #4 Drain Pump Vertical canned 104,000 lbm/hr 800 ft 1

11 LP Feedwater Heater 5 Horizontal U Tube 3,200,000 lbm/hr 280°F to 340°F 1

12 Deaerator and Storage Tank Horizontal spray type 3,200,000 lbm/hr 340°F to 407°F 1

13 Boiler Feedwater Booster Pumps and drive motors Horizontal split 2,200,000 lbm/hr 5,700 psia 2

14 Startup Boiler Feedwater Pumps and drive motors Barrel type multistage centrifugal 800,000 lbm/hr 5,700 psia 2

15 HP Feedwater Heater 7 Horizontal U Tube 4,300,000 lbm/hr 423°F to 468°F 1

16 HP Feedwater Heater 8 Horizontal U Tube 4,300,000 lbm/hr 468°F to 554°F 1

17 HP Feedwater Heater 9 Horizontal U Tube 4,300,000 lbm/hr 1ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 144 

### 554°F to 617°F
18 Topping de-superheater Horizontal U Tube 4,300,000 lbm/hr 617°F to 626°F 1ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 145 

### ACCOUNT 3B MISCELLANEOUS SYSTEMS (Common to all cases) Equipment No. Description Type Design Condition Qty 1 Auxiliary Boiler Shop fabricated water tube 400 psig, 650°F 1

2 Fuel Oil Storage Tank Vertical, cylindrical 500,000 gal 1 3 Fuel Oil Unloading Pump Gear 150 ft, 800 gpm 1 4 Fuel Oil Supply Pump Gear 400 ft, 80 gpm 2 5 Service Air Compressors SS, double acting 100 psig, 800 scfm 3 6 Inst. Air Dryers Duplex, regenerative 400 scfm 1 7 Service Water Pumps SS, double suction 100 ft, 6,000 gpm 2 8 Closed Cycle Cooling Heat Exch. Shell and tube 50% cap. each 2

9 Closed Cycle Cooling Water Pumps Horizontal, centrifugal 185 ft, 600 gpm 2

11 Fire Service Booster Pump Two-stage centrifugal 250 ft, 700 gpm 1

12 Engine-Driven Fire Pump Vertical turbine, diesel engine 350 ft, 1,000 gpm 1

13 Raw Water Pumps SS, single suction 100 ft, 1,000 gpm 2 14 Filtered Water Pumps SS, single suction 200 ft, 200 gpm 2 15 Filtered Water Tank Vertical, cylindrical 15,000 gal 1 16 Makeup Demineralizer Anion, cation, and mixed bed 150 gpm 2

17 Liquid Waste Treatment System - Site 1ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 146 

### ACCOUNT 4 BOILER AND ACCESSORIES (different for each case as shown)

Equipment No. Description Type Design Condition Qty

1 Power Boiler Pulverized Coal Fired Case PC-1 4.7 x 10 6 

### lbm/hr 2,400psi 1,000°F/1,000°F 1

1 Power Boiler Pulverized Coal Fired Case PC-2 4.4 x 10 6 

### lbm/hr 2,400psi 1,049°F/1,112°F 1

1 Power Boiler Pulverized Coal Fired Case PC-3 4.3 x 10 6 

### lbm/hr 3,625 psi 1,049°F/1,112°F 1

1 Power Boiler Pulverized Coal Fired Case PC-4 4.6 x 10 6 

### lbm/hr 3,915 psi 1,085°F/1,148°F 1

1 Power Boiler Pulverized Coal Fired Case PC-5 4.3 x 10 6 

### lbm/hr 5,075 psi 1,292°F/1,328°F 1

1 Power Boiler Circulating Fluidized Bed Case CFB-2 4.4 x 10 6 

### lbm/hr 2,400 psi 1,049°F/1,112°F 1

1 Power Boiler Circulating Fluidized Bed Case CFB-3 4.3 x 10 6 

### lbm/hr 3,625 psi 1,049°F/1,112°F 1

1 Power Boiler Circulating Fluidized Bed Case CFB-4 4.6 x 10 6 

### lbm/hr 3,915 psi 1,085°F/1,148°F 1

1 Power Boiler Circulating Moving Bed Case CMB TM 

### -3 4.6 x 10 6 

### lbm/hr 3,915 psi 1,085°F/1,148°F 1

1 Power Boiler Circulating Moving Bed Case CMB TM 

### -5 4.3 x 10 6 

### lbm/hr 5,075 psi 1,292°F/1,328°F 1

2 Primary Air Fan Centrifugal (Cases PC-1, PC-2, PC-3, PC-4, PC-5) 1,165,000 pph, 281,000 acfm, 98" wg, 1,322 kW 1

3 Secondary Air Fan Centrifugal (Cases PC-1, PC-2, PC-3, PC-4, PC-5) 

### 677,000 pph, 163,000 acfm, 78" wg, 1,589 kW 1

4 ID Fan Centrifugal (Cases PC-1, PC-2, PC-3, PC-4, PC-5) 

### 2,168,000 pph, 724,000 acfm, 39" wg, 8,950 kW 1ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 147 

### 2 Primary Air Fan Centrifugal (Cases CFB-2, CFB-3, CFB-4) 1,165,000 pph, 281,000 acfm, 98" wg, 7,904 kW 1

3 Secondary Air Fan Centrifugal (Cases CFB-2, CFB-3, CFB-4) 

### 677,000 pph, 163,000 acfm, 78" wg, 3,876 kW 1

4 ID Fan Centrifugal (Cases CFB-2, CFB-3, CFB-4) 

### 2,168,000 pph, 724,000 acfm, 39" wg, 10,924 kW 1

5 Fluidizing Air Blower Centrifugal (Cases CFB-2, CFB-3, CFB-4) 

### 16,000 acfm, 25 psig, 2,875 kW 2

2 Primary Air Fan Centrifugal (Cases CMB TM 

### -3, CMB TM 

### -5) 1,165,000 pph, 281,000 acfm, 98" wg, 1,219 kW 1

3 Secondary Air Fan Centrifugal (Cases CMB TM 

### -3, CMB TM 

### -5) 677,000 pph, 163,000 acfm, 78" wg, 3,182 kW 1

4 ID Fan Centrifugal (Cases CMB TM 

### -3, CMB TM 

### -5) 2,168,000 pph, 724,000 acfm, 39" wg, 7,740kW 1

5 Fluidizing Air Blower Centrifugal (Cases CMB TM 

### -3, CMB TM 

### -5) 16,000 acfm, 25 psig, 840 kW 2ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 148 

### ACCOUNT 5 FLUE GAS CLEANUP

ACCOUNT 5A PARTICULATE CONTROL

Equipment No. Description Type Design Condition Qty 1 Bag Filter for CFB and CMB TM 

### cases as part of FDA system (Cases CFB-2, CFB-3, CFB-4, CMB TM 

### -3, and CMB TM


### - 5) Pulse-jet cleaned ~6,100,000 lbm/hr, total removal efficiency = 99.9%+ 1

1 ESP for PC Cases (Cases PC-1, PC-2, PC-3, PC-4, and PC-5) N/A ~6,100,000 lbm/hr, total removal efficiency = 99.9%+ 1

ACCOUNT 5B FLUE GAS DESULFURIZATION

Equipment No. Description Type Design Condition Qty 1 Flash Dryer Absorber System for CFB and CMB TM 

### cases (Cases CFB-2, CFB-3, CFB-4, CMB TM 

### -3, and CMB TM


### - 5) N/A ~6,100,000 lbm/hr, total removal efficiency = 98% 1

1 Wet FGD System for PCCases (Cases PC-1, PC2, PC-3, PC-4, and PC-5) N/A ~6,100,000 lbm/hr, total removal efficiency = 98% 1

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES Not applicable.

ACCOUNT 7 DUCTING AND STACK (Common to all cases)

Equipment No. Description Type Design Condition Qty

1 Boiler Stack Concrete with FRP liner ~6,100,000 lbm/hr 1ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 149 

### ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES (Note: differences between Steam Cycles are indicated)

Equipment No. Description Type Design Condition Qty

1 696 MW Turbine Generator Subcritical, 2 flow IP, 4 flow LP; Steam Cycle #1 (Case PC-1) 2,400 psig/1,000°F/ 1,000°F/ 1

1 711 MW Turbine Generator Subcritical, 2 flow IP, 4 flow LP; Steam Cycle #2 (Cases PC-2, CFB-2) 2,400 psig/1,049°F/ 1,112°F/ 1

1 736 MW Turbine Generator Supercritical, 2 flow IP, 4 flow LP; Steam Cycle #3 (Cases PC-3, CFB-3, CMB TM 

### -3) 3,625 psig/1,049°F/ 1,112°F/ 1

1 754 MW Turbine Generator Supercritical, 2 flow IP, 4 flow LP; Steam Cycle #4 (Cases PC-4, CFB-4) 3,915 psig/1,085°F/ 1,148°F/ 1

1 821 MW Turbine Generator Ultra-supercritical, 2 flow IP, 4 flow LP; Steam Cycle #5 (Cases PC-5, CMB TM



### - 5) 5,075 psig/1,292°F/ 1,328°F/ 1

2 Bearing Lube Oil Coolers Plate and frame - 2

3 Bearing Lube Oil Conditioner Pressure filter closed loop - 1

4 Control System Electro-hydraulic 1,600 psig 1

5 Generator Coolers Shell and tube - 2 6 Hydrogen Seal Oil System Closed loop - 1

7 Generator Exciter Solid state brushless - 1ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 150 

### ACCOUNT 9 COOLING WATER SYSTEM (Not e: differences between Steam Cycles are indicated)

Equipment No. Description Type Design Condition Qty 1 Cooling Tower Mechanical draft Steam Cycle #1 = 2,810 MM-Btu/hr (Case PC-1) Steam Cycle #2 = 2,770 MM-Btu/hr (Cases PC-2, CFB-2) Steam Cycle #3 = 2,710 MM-Btu/hr (Cases PC-3, CFB-3, CMB TM 

### -3) Steam Cycle #4 = 2,650 MM-Btu/hr (Cases PC-4, CFB-4) Steam Cycle #5 = 2,480 MM-Btu/hr(Cases PC-5, CMB5)

Al Cases 95°F to 75°F 1

2 Circ. W. Pumps Vertical wet pit 60,000 gpm @ 80 ft 6ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 151 

### ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING

ACCOUNT 10A BOTTOM ASH HANDLING In boiler scope of supply.



### ACCOUNT 10B FLY ASH HANDLING (Common to all cases)

Equipment No. Description Type Design Condition Qty 1 Baghouse/ESP Hoppers (part of Baghouse/ESP scope of supply) 12

2 Air Heater Hopper (part of boiler scope of supply) 1

3 Air Blower 1,800 cfm 1 4 Fly Ash Silo Reinforced concrete 800 tons 2

5 Slide Gate Valves 2 6 Wet Unloader 30 tph 1 7 Telescoping Unloading Chute 1ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 152 

### 7.1.3 Sporn Repowering Case Equipment List This section provides a listing of all major pl ant equipment provided for the repowered Sporn Unit #4 power plant. The list is subdivided into Boiler Island and Balance of Plant Equipment.

7.1.3.1 Sporn Repowering Case Boiler Island Equipment This section contains a list of all equipment a ssociated with the boiler scope of supply for the CMB TM 

### boiler for the Sporn Unit #4 repowering case.

Fuel Feeding System: - Day Silo - Fuel Silo Isolation Valves - Fuel Conveyors & Feeders - Feeder Isolation Valves - Piping to Furnace Limestone Feeding System: (not used) Furnace Loop Equipment: - Furnace Grate and Plenum Includ ing Air Nozzles & Drain Tubes - Ash Drain Valve(s) - Start-up Burner System (Including Burn ers, Piping, Ducts, and Local Control Equipment) - Ductwork – Furnace to Recycle Particle Separators - Particle Separator – Complete - Ductwork – Recycle Particle Separator to Air Heater Inlet - Metal/Fabric Expansion Joints - Seal pots and Seal pot Grate – Including Air Nozzles and Plenum - Buckstay System MBHE Equipment: - Separator Including Nozzles, Lugging, Hanger Rods - Start-up System Including Recirculation Pump, Storage Tank, Piping - Connecting Tubes/Piping - Tubing /Headers - Buckstay System - MBHE Heat Absorbing Surface: Horizontal Superheaters Horizontal Reheater Horizontal Once Through Heat Exchanger Steam Cooled Support System 

### - Superheater/Reheater Desuperheaters - Reheat Steam Temperature Control Valving - Desuperheater Block Valves - Desuperheater Piping - Once Through Heat Exchanger Piping to Separator - Superheater Interconnecting Piping - Feedwater Stop, Feedwater Check valves - Safety Valves/Discharge Piping/Silencers - Electro. Relief Valve/Sile ncer and Discharge Piping Particle Return System: -Particle Removal Cyclones -Ductwork PA Fan to MBHE Particle Outlet Particle transport pipes from MB HE outlet to Cyclone separatorECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 153 Cyclone gas outlets to Furnace


### Trim Valves: - Double Valving Sootblowing System: - Air heater - Sootblower Control System Combustion Gas System: - Ductwork and Expansion Joints - Cyclone Outlet to Air Heater Inlet - Ductwork – Air Heater Outlet to ESP Inlet - I.D. Fan w/Drive (existing) - Ductwork – ID Fan Outlet to Stack (existing) Air System: - PA Fan w/Drive (by others) - Ductwork – PA Fan Outlets to Air Heater - Ductwork – Air Heater Outlet to Furnace - SA Fan w/Drive (by others) - Ductwork – SA Fan Outlets to Air Heater - Ductwork – Air Heater Outlet to Furnace - Fluidizing Air Blower w/Drive (by others) - Ductwork – FA Blower Outlets to Seal pot Ash Handling System: - Bed Ash Drains and Ash Coolers

Structural: - Structural Steel including platform s, walkways, stairways, and ladders - Boiler Internal Grid Steel - Boiler Island Elevator - Pressure Part Support Steel - Boiler Building Siding, Weather Enclosure, HVAC

Instrumentation and Controls: - Burner Management (FBSS) Logic - CFB Field Instruments - Controller Drives

Refractories: - Material for All Internal Refractory Linings for Furnished Process and Boiler

Equipment Insulation and Lagging: - Material for Insulation and Lagging for Heat Conservation and Personnel Protection for furnished equipment Painting: - Shop Prime Paint Coating for Seller furnished Equipment

Miscellaneous: - Operator Training Program - Maintenance Training Program - Instruction Manuals - Spare Parts for commissioning - Technical Representation during start-up and testing - Field Erection of Equipment Scope - Freight to SiteECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 154 

### 7.1.3.2 Sporn Repowering Case Balance of Plant Equipment This section contains the balance of plant equipment list corresponding to the Sporn Unit #4 repowering case. This list, along with the material and energy balances and supporting performance data, was used to generate plant cost s used in the financial analysis. The list below shows only the major new items that were added to the existing plant and does not show existing BOP equipment still in use.

Equipment Description Measures Comments & Issues

Topping Turbine/Generator: ~32 MWe, 1,080,000 lbm/hr, no extraction 4,242 psi, 1,292F inlet; 2,015 psi, 1,050F exhaust

Balance of Plant Equipment: FW booster pump including valves and controls Actual discharge head 4,842psi and inlet pressure 2,522psi, flow 1,080,000 lbm/hr Single pump

Full flow condensate polishing system 950,000 lb/hr condensate flow Includes foundation and sump

Coal feed system from the coal pile to the coal bunker Top of feeders elev. 676 ft (90 ft above grade) Includes top works on silos (head house). Assumes conveyor tube can be routed through obstructions with slight rotation of the silos.

Transformer 37.5 MVA Includes generator leads to transmission interconnection, pad, fire protection, oil containment, metering and protection CTs, etc. Topping turbine rotated 180 deg. Flue gas duct and dampers to precipitator 210 ft Includes foundations and crane rental for installation
Piping: Link to Demin. from condensate 1 x 275 ft Link from Demin. to #1 Feedwater Heater 1 x 275 ft Main Steam to Topping Turbine 1 x 100 ft Insulated, 1 line, 4,242 psi, 1,292F Topping Turbine to Existing Turbine 1 x 200 ft Insulated, 1 line R.H. Inlet Link 2 x 200 ft Insulated, 2 lines R.H. Outlet Link 2 x 200 ft Insulated, 2 lines Economizer Inlet Link from new Feedwater Booster Pump 2 x 300 ft Insulated, 2 linesECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 155 

### 7.2 Appendix II - Drawings

This appendix shows drawings of the various Greenfield case boilers (PC, CFB, and CMB TM 

### ) used in the study. Drawings for the repowering case are also included in this appendix. All drawings included in this appendix are listed below.

Greenfield Cases:
Figure 7.2. 1 Front Arrangement of 700M W Supercritical CFB Steam Generator
Figure 7.2. 2 Side Arrangement of 700MW Supercritical CFB Steam Generator
Figure 7.2. 3 Plan Arrangement of 700MW Supercritical CFB Steam Generator
Figure 7.2. 4 Front Arrangement of 700MW Subcritical CFB Steam Generator
Figure 7.2. 5 Side Arrangement of 700MW Subcritical CFB Steam Generator
Figure 7.2. 6 Side Arrangement of 700MW Subcritical CFB Steam Generator

Figure 7.2. 7 Front Arrangement of 700MW Supercritical CMB TM 

### Steam Generator
Figure 7.2. 8 Side Arrangement of 700MW Supercritical CMB TM 

### Steam Generator

Figure 7.2. 9 Plan Arrangement of 700MW Supercritical CMB TM 

### Steam Generator

Repowering Cases:
Figure 7.2. 10 Philip Sporn Plant – Plan View of Existing Site
Figure 7.2. 11 Topping Steam Turbine for Sporn Unit # 4 Repowering Case
Figure 7.2. 12 Philip Sporn Sectional Side El evation of Steam Generator Repowering Case
Figure 7.2. 13 Philip Sporn Sectional Side El evation of Steam Generator Repowering Case
Figure 7.2. 14 Philip Sporn Plan View of Steam Generato r Repowe ring CaseECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004156Figure 7.2. 1 Front Arrangement of 700MW Supercritical CFB Steam GeneratorECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004157Figure 7.2. 2 Side Arrangement of 700MW Supercritical CFB Steam GeneratorECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004158Figure 7.2. 3 Plan Arrangement of 700MW Supercritical CFB Steam GeneratorECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004159Figure 7.2. 4 Front Arrangement of 700MW Subcritical CFB Steam GeneratorECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004160Figure 7.2. 5 Side Arrangement of 700MW Subcritical CFB Steam GeneratorECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004161Figure 7.2. 6 Side Arrangement of 700MW Subcritical CFB Steam GeneratorECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004162Figure 7.2. 7 Front Arrangement of 700MW Supercritical CMB Steam GeneratorECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004163Figure 7.2. 8 Side Arrangement of 700MW Supercritical CMB Steam GeneratorECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004164Figure 7.2. 9 Plan Arrangement of 700MW Supercritical CMB Steam GeneratorECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004165Figure 7.2.10:Philip Sporn Plant - Plan View of Existing SiteECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004166Figure 7.2.11:Topping Steam Turbine for Sporn Unit #4 Repowering CaseECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004167Figure 7.2.12: Philip Sporn Sectional Side Elevation of Steam Generator Repowering CaseECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004168Figure 7.2.13:Philip Sporn Front Elevation of Steam Generator Repowering CaseECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004169Figure 7.2. 14: Philip Sporn Plan Viewof Steam Generator Repowering CaseECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 170 

### 7.3 Appendix III – Detailed Investment Costs and Operating and Maintenance Costs This appendix provides plant investment cost breakdowns and operating & maintenance cost breakdowns for each of the ten Greenfield plant s studied. The costs tables are presented in the following order: Case PC-1, PC-2, PC-3, PC-4, PC-5, CFB-2, CFB-3, CFB-5, CMB TM 

### -3, and finally Case CMB TM 

### -5.
Additionally, the investment cost breakdown for the Sporn Unit #4 r epowering case is also shown as well as operating & maintenance cost breakdowns for both the repowering case and the existing Sporn Unit #4 without modifications.ECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004171Table 7.3. 1: Case PC-1 Investment CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 172 Client: DOE - NETL Cost Base: Jul-03 Project: Economics and Feasibility of Rankine Cycle Impronements for Coal Fired Power Plants Case PC-1 - 1 x 630 MW PC Fired Steam Plant

Net Plant Heat Rate (Btu/kWh): 9,218

Net Power Output (kW): 630,526

Capacity Factor (%): 80

OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate (Base): 30.90 $/hour Operating Labor Burden: 30.00 % Labor O-H change Rate: 25.00 % of O&M labor

Operating Labor Requirements (O.J.) per shift 1 unit/mod. Total Plant Skilled Operator 2.0 2.0 Operator 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 2.0 2.0 TOTAL Operator Jobs (O.J.'s) 14.0 14.0 Annual Cost Annual Unit Cost $ / year $/kW-net Annual Operating Labor Costs (calc'd) 4,926,449 7.81 Maintenance Labor Costs (calc'd) 2,785,124 4.42 Administrative & Support Labor (calc'd) 1,927,893 3.06 TOTAL FIXED OPERATING COST S 9,639,46 6 15.29

$/kWh-net Maintenance Material Cost (calc'd) 3,342,149 0.00076

Consumables Unit Initial Initial Per Day Cost Cost Water (1000 gallons) 3,039 1.00 887,253 0.00020

Chemicals MU & WT Chem. (lbs.) 741,960 24,732 0.16 118,714 1,155,479 0.00026 Limestone (ton) 19,880 662.7 10.00 198,801 1,935,000 0.00044 Formic Acid (lbs.) 0.60 Ammonia, NH3 (ton) 210 7.0 150 31,500 306,600 0.00007 Subtotal Chemicals: 349,015 3,397,079 0.00077

Other Consumables Supplemental Fuel (MBtu) SCR Catalyst Replacement (MBtu) 5,840,000 0.0013 Emissions Penalties Subtotal Other:

Waste Disposal Fly Ash & Bottom Ash (ton) 1,180.6 8.00 2,757,860 0.0006 Subtotal Solid Waste Disposal: 2,757,860 0.0006

By-Products Gypsum (ton) 0.0 8.00 0 0.0000 Sludge (ton) 900.0 8.00 2,102,400 0.0005 Subtotal By-Products: 2,102,400 0.0005

TOTAL VARIABLE OPERATING COST 18,326,741 0.0041

Annual Generation 4419 (MM-kwhr/yr)

Total O&M Cost 0.63 (Cents/kwhr) INITIAL & ANNUA L O&M E XPENSES

Consumption



### Table 7.3. 2: Case PC-1 Operating and Maintenance CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004173Table 7.3. 3: Case PC-2 Investment CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 174 Client: DOE - NETL Cost Base: Jul-03 Project: Economics and Feasibility of Rankine Cycle Impronements for Coal Fired Power Plants Case PC-2 - 1x650 MW PC Fired Steam Plant

Net Plant Heat Rate (Btu/kWh): 8,997

Net Power Output (kW): 646,080

Capacity Factor (%): 80

OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate (Base): 30.90 $/hour Operating Labor Burden: 30.00 % Labor O-H change Rate: 25.00 % of O&M labor

Operating Labor Requirements (O.J.) per shift 1 unit/mod. Total Plant Skilled Operator 2.0 2.0 Operator 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 2.0 2.0 TOTAL Operator Jobs (O.J.'s) 14.0 14.0 Annual Cost Annual Unit Cost $ / year $/kW-net Annual Operating Labor Costs (calc'd) 4,926,449 7.63 Maintenance Labor Costs (calc'd) 2,820,586 4.37 Administrative & Support Labor (calc'd) 1,936,759 3.00 TOTAL FIXED OPERATING COST S 9,683,793 14.99

$/kWh-net Maintenance Material Cost (calc'd) 3,384,703 0.00075

Consumables Unit Initial Initial Per Day Cost Cost Water (1000 gallons) 3,039 1.00 887,253 0.00020

Chemicals MU & WT Chem. (lbs.) 741,960 24,732 0.16 118,714 1,155,479 0.00026 Limestone (ton) 19,880 662.7 10.00 198,801 1,935,000 0.00043 Formic Acid (lbs.) 0.60 Ammonia, NH3 (ton) 7.0 150 31,500 306,600 0.00007 Subtotal Chemicals: 349,015 3,397,079 0.00075

Other Consumables Supplemental Fuel (MBtu) SCR Catalyst Replacement (MBtu) 5,840,000 0.0013 Emissions Penalties Subtotal Other:

Waste Disposal Fly Ash & Bottom Ash (ton) 1,180.6 8.00 2,757,860 0.0006 Subtotal Solid Waste Disposal: 2,757,860 0.0006

By-Products Gypsum (ton) 0.0 8.00 0 0.0000 Sludge (ton) 900.0 8.00 2,102,400 0.0005 Subtotal By-Products: 2,102,400 0.0005

TOTAL VARIABLE OPERATING COST 18,369,295 0.0041

Annual Generation 4528 (MM-kwhr/yr)

Total O&M Cost 0.62 (Cents/kwhr) INITIAL & ANNUA L O&M E XPENSES

Consumption



### Table 7.3. 4: Case PC-2 Operating and Maintenance CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004175Table 7.3. 5: Case PC-3 Investment CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 176 Client: DOE - NETL Cost Base: Jul-03 Project: Economics and Feasibility of Rankine Cycle Impronements for Coal Fired Power Plants Case PC-3 - 1x660 MW PC Fired Steam Plant

Net Plant Heat Rate (Btu/kWh): 8,768

Net Power Output (kW): 662,936

Capacity Factor (%): 80

OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate (Base): 30.90 $/hour Operating Labor Burden: 30.00 % Labor O-H change Rate: 25.00 % of O&M labor

Operating Labor Requirements (O.J.) per shift 1 unit/mod. Total Plant Skilled Operator 2.0 2.0 Operator 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 2.0 2.0 TOTAL Operator Jobs (O.J.'s) 14.0 14.0 Annual Cost Annual Unit Cost $ / year $/kW-net Annual Operating Labor Costs (calc'd) 4,926,449 7.43 Maintenance Labor Costs (calc'd) 2,851,182 4.30 Administrative & Support Labor (calc'd) 1,944,408 2.93 TOTAL FIXED OPERATING COST S 9,722,038 14.67

$/kWh-net Maintenance Material Cost (calc'd) 3,421,418 0.00074

Consumables Unit Initial Initial Per Day Cost Cost Water (1000 gallons) 3,039 1.00 887,253 0.00019

Chemicals MU & WT Chem. (lbs.) 741,960 24,732 0.16 118,714 1,155,479 0.00025 Limestone (ton) 19,880 662.7 10.00 198,801 1,935,000 0.00042 Formic Acid (lbs.) 0.60 Ammonia, NH3 (ton) 7.0 150 31,500 306,600 0.00007 Subtotal Chemicals: 349,015 3,397,079 0.00073

Other Consumables Supplemental Fuel (MBtu) SCR Catalyst Replacement (MBtu) 5,840,000 0.0013 Emissions Penalties Subtotal Other:

Waste Disposal Fly Ash & Bottom Ash (ton) 1,180.6 8.00 2,757,860 0.0006 Subtotal Solid Waste Disposal: 2,757,860 0.0006

By-Products Gypsum (ton) 0.0 8.00 0 0.0000 Sludge (ton) 900.0 8.00 2,102,400 0.0005 Subtotal By-Products: 2,102,400 0.0005

TOTAL VARIABLE OPERATING COST 18,406,010 0.0040

Annual Generation 4646 (MM-kwhr/yr)

Total O&M Cost 0.61 (Cents/kwhr) INITIAL & ANNUA L O&M E XPENSES

Consumption



### Table 7.3. 6: Case PC-3 Operating and Maintenance CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004177Table 7.3. 7: Case PC-4 Investment CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 178 Client: DOE - NETL Cost Base: Jul-03 Project: Economics and Feasibility of Rankine Cycle Impronements for Coal Fired Power Plants Case PC-4 - 1x680 MW PC Fired Steam Plant

Net Plant Heat Rate (Btu/kWh): 8,580

Net Power Output (kW): 677,479

Capacity Factor (%): 80

OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate (Base): 30.90 $/hour Operating Labor Burden: 30.00 % Labor O-H change Rate: 25.00 % of O&M labor

Operating Labor Requirements (O.J.) per shift 1 unit/mod. Total Plant Skilled Operator 2.0 2.0 Operator 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 2.0 2.0 TOTAL Operator Jobs (O.J.'s) 14.0 14.0 Annual Cost Annual Unit Cost $ / year $/kW-net Annual Operating Labor Costs (calc'd) 4,926,449 7.27 Maintenance Labor Costs (calc'd) 2,887,106 4.26 Administrative & Support Labor (calc'd) 1,953,389 2.88 TOTAL FIXED OPERATING COST S 9,766,944 14.4 2

$/kWh-net Maintenance Material Cost (calc'd) 3,464,528 0.00073

Consumables Unit Initial Initial Per Day Cost Cost Water (1000 gallons) 3,039 1.00 887,253 0.00019

Chemicals MU & WT Chem. (lbs.) 741,960 24,732 0.16 118,714 1,155,479 0.00024 Limestone (ton) 19,880 662.7 10.00 198,801 1,935,000 0.00041 Formic Acid (lbs.) 0.60 Ammonia, NH3 (ton) 7.0 150 31,500 306,600 0.00006 Subtotal Chemicals: 349,015 3,397,079 0.00072

Other Consumables Supplemental Fuel (MBtu) SCR Catalyst Replacement (MBtu) 5,840,000 0.0012 Emissions Penalties Subtotal Other:

Waste Disposal Fly Ash & Bottom Ash (ton) 1,180.6 8.00 2,757,860 0.0006 Subtotal Solid Waste Disposal: 2,757,860 0.0006

By-Products Gypsum (ton) 0.0 8.00 0 0.0000 Sludge (ton) 900.0 8.00 2,102,400 0.0004 Subtotal By-Products: 2,102,400 0.0004

TOTAL VARIABLE OPERATING COST 18,449,120 0.0039

Annual Generation 4748 (MM-kwhr/yr)

Total O&M Cost 0.59 (Cents/kwhr) INITIAL & ANNUA L O&M E XPENSES

Consumption



### Table 7.3. 8: Case PC-4 Operating and Maintenance CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004179Table 7.3. 9: Case PC-5 Investment CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 180 Client: DOE - NETL Cost Base: Jul-03 Project: Economics and Feasibility of Rankine Cycle Impronements for Coal Fired Power Plants Case PC-5 - 1x740 MW PC Fired Steam Plant

Net Plant Heat Rate (Btu/kWh): 7,838

Net Power Output (kW): 741,615

Capacity Factor (%): 80

OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate (Base): 30.90 $/hour Operating Labor Burden: 30.00 % Labor O-H change Rate: 25.00 % of O&M labor

Operating Labor Requirements (O.J.) per shift 1 unit/mod. Total Plant Skilled Operator 2.0 2.0 Operator 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 2.0 2.0 TOTAL Operator Jobs (O.J.'s) 14.0 14.0 Annual Cost Annual Unit Cost $ / year $/kW-net Annual Operating Labor Costs (calc'd) 4,926,449 6.64 Maintenance Labor Costs (calc'd) 3,376,874 4.55 Administrative & Support Labor (calc'd) 2,075,831 2.80 TOTAL FIXED OPERATING COST S 10,379,154 14.00

$/kWh-net Maintenance Material Cost (calc'd) 4,052,249 0.00078

Consumables Unit Initial Initial Per Day Cost Cost Water (1000 gallons) 3,039 1.00 887,253 0.00017

Chemicals MU & WT Chem. (lbs.) 741,960 24,732 0.16 118,714 1,155,479 0.00022 Limestone (ton) 19,880 662.7 10.00 198,801 1,935,000 0.00037 Formic Acid (lbs.) 0.60 Ammonia, NH3 (ton) 7.0 150 31,500 306,600 0.00006 Subtotal Chemicals: 349,015 3,397,079 0.00065

Other Consumables Supplemental Fuel (MBtu) SCR Catalyst Replacement (MBtu) 5,840,000 0.0011 Emissions Penalties Subtotal Other:

Waste Disposal Fly Ash & Bottom Ash (ton) 1,180.6 8.00 2,757,860 0.0005 Subtotal Solid Waste Disposal: 2,757,860 0.0005

By-Products Gypsum (ton) 0.0 8.00 0 0.0000 Sludge (ton) 900.0 8.00 2,102,400 0.0004 Subtotal By-Products: 2,102,400 0.0004

TOTAL VARIABLE OPERATING COST 19,036,841 0.0037

Annual Generation 5197 (MM-kwhr/yr)

Total O&M Cost 0.57 (Cents/kwhr) INITIAL & ANNUA L O&M E XPENSES

Consumption



### Table 7.3.10: Case PC-5 Operating and Maintenance CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004181Table 7.3.11: Case CFB-2 Investment CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 182 Client: DOE - NETL Cost Base: Jul-03 Project: Economics and Feasibility of Rankine Cycle Impronements for Coal Fired Power Plants Case CFB-2 - 1 x 650 MW CFB Steam Plant

Net Plant Heat Rate (Btu/kWh): 8,976

Net Power Output (kW): 647,588

Capacity Factor (%): 80

OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate (Base): 30.90 $/hour Operating Labor Burden: 30.00 % Labor O-H change Rate: 25.00 % of O&M labor

Operating Labor Requirements (O.J.) per shift 1 unit/mod. Total Plant Skilled Operator 2.0 2.0 Operator 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 2.0 2.0 TOTAL Operator Jobs (O.J.'s) 14.0 14.0 Annual Cost Annual Unit Cost $ / year $/kW-net Annual Operating Labor Costs (calc'd) 4,926,449 7.61 Maintenance Labor Costs (calc'd) 2,698,760 4.17 Administrative & Support Labor (calc'd) 1,906,302 2.94 TOTAL FIXED OPERATING COST S 9,531,512 14.72

$/kWh-net Maintenance Material Cost (calc'd) 3,238,513 0.00071

Consumables Unit Initial Initial Per Day Cost Cost Water (1000 gallons) 3,039 1.00 887,253 0.00020

Chemicals MU & WT Chem. (lbs.) 741,960 24,732 0.16 118,714 1,155,479 0.00025 Limestone (ton) 23,086 769.5 10.00 230,861 2,247,045 0.00050 Formic Acid (lbs.) 0.60 Ammonia, NH3 (ton) 150 85,680 0.00002 Subtotal Chemicals: 349,574 3,488,204 0.00075

Other Consumables Supplemental Fuel (MBtu) SCR Catalyst Replacement (MBtu) Emissions Penalties Subtotal Other:

Waste Disposal Fly Ash & Bottom Ash (ton) 2,187.5 8.00 5,109,896 0.0011 Subtotal Solid Waste Disposal: 5,109,896 0.0011

By-Products Gypsum (ton) 0.0 8.00 0 0.0000 Sludge (ton) 0.0 8.00 0 0.0000 Subtotal By-Products: 0 0.0000

TOTAL VARIABLE OPERATING COST 12,723,866 0.0028

Annual Generation 4538 (MM-kwhr/yr)

Total O&M Cost 0.49 (Cents/kwhr) INITIAL & ANNUA L O&M EXPENSES

Consumption



### Table 7.3.12: Case CFB-2 Operating and Maintenance CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004183Table 7.3.13: Case CFB-3 Investment CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 184 Client: DOE - NETL Cost Base: Jul-03 Project: Economics and Feasibility of Rankine Cycle Impronements for Coal Fired Power Plants Case CFB-3 - 1 x 660 MW CFB Steam Plant

Net Plant Heat Rate (Btu/kWh): 8,756

Net Power Output (kW): 663,823

Capacity Factor (%): 80

OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate (Base): 30.90 $/hour Operating Labor Burden: 30.00 % Labor O-H change Rate: 25.00 % of O&M labor

Operating Labor Requirements (O.J.) per shift 1 unit/mod. Total Plant Skilled Operator 2.0 2.0 Operator 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 2.0 2.0 TOTAL Operator Jobs (O.J.'s) 14.0 14.0 Annual Cost Annual Unit Cost $ / year $/kW-net Annual Operating Labor Costs (calc'd) 4,926,449 7.42 Maintenance Labor Costs (calc'd) 2,731,547 4.11 Administrative & Support Labor (calc'd) 1,914,499 2.88 TOTAL FIXED OPERATING COST S 9,572,495 14.4 2

$/kWh-net Maintenance Material Cost (calc'd) 3,277,857 0.00070

Consumables Unit Initial Initial Per Day Cost Cost Water (1000 gallons) 3,039 1.00 887,253 0.00019

Chemicals MU & WT Chem. (lbs.) 741,960 24,732 0.16 118,714 1,155,479 0.00025 Limestone (ton) 23,086 769.5 10.00 230,861 2,247,045 0.00048 Formic Acid (lbs.) 0.60 Ammonia, NH3 (ton) 150 85,680 0.00002 Subtotal Chemicals: 349,574 3,488,204 0.00073

Other Consumables Supplemental Fuel (MBtu) SCR Catalyst Replacement (MBtu) Emissions Penalties Subtotal Other:

Waste Disposal Fly Ash & Bottom Ash (ton) 2,187.5 8.00 5,109,896 0.0011 Subtotal Solid Waste Disposal: 5,109,896 0.0011

By-Products Gypsum (ton) 0.0 8.00 0 0.0000 Sludge (ton) 0.0 8.00 0 0.0000 Subtotal By-Products: 0 0.0000

TOTAL VARIABLE OPERATING COS T 12,763,210 0.0027

Annual Generation 4652 (MM-kwhr/yr)

Total O&M Cost 0.48 (Cents/kwhr) INITIAL & ANNUA L O&M E XPENSES

Consumption



### Table 7.3.14: Case CFB-3 Operating and Maintenance CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004185Table 7.3.15: Case CFB-4 Investment CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 186 Client: DOE - NETL Cost Base: Jul-03 Project: Economics and Feasibility of Rankine Cycle Impronements for Coal Fired Power Plants Case CFB-4 - 1 x 680 MW CFB Steam Plant

Net Plant Heat Rate (Btu/kWh): 8,568

Net Power Output (kW): 678,366

Capacity Factor (%): 80

OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate (Base): 30.90 $/hour Operating Labor Burden: 30.00 % Labor O-H change Rate: 25.00 % of O&M labor

Operating Labor Requirements (O.J.) per shift 1 unit/mod. Total Plant Skilled Operator 2.0 2.0 Operator 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 2.0 2.0 TOTAL Operator Jobs (O.J.'s) 14.0 14.0 Annual Cost Annual Unit Cost $ / year $/kW-net Annual Operating Labor Costs (calc'd) 4,926,449 7.26 Maintenance Labor Costs (calc'd) 2,796,985 4.12 Administrative & Support Labor (calc'd) 1,930,858 2.85 TOTAL FIXED OPERATING COST S 9,654,292 14.23

$/kWh-net Maintenance Material Cost (calc'd) 3,356,382 0.00071

Consumables Unit Initial Initial Per Day Cost Cost Water (1000 gallons) 3,039 1.00 887,253 0.00019

Chemicals MU & WT Chem. (lbs.) 741,960 24,732 0.16 118,714 1,155,479 0.00024 Limestone (ton) 23,086 769.5 10.00 230,861 2,247,045 0.00047 Formic Acid (lbs.) 0.60 Ammonia, NH3 (ton) 150 85,680 0.00002 Subtotal Chemicals: 349,574 3,488,204 0.00072

Other Consumables Supplemental Fuel (MBtu) SCR Catalyst Replacement (MBtu) Emissions Penalties Subtotal Other:

Waste Disposal Fly Ash & Bottom Ash (ton) 2,187.5 8.00 5,109,896 0.0011 Subtotal Solid Waste Disposal: 5,109,896 0.0011

By-Products Gypsum (ton) 0.0 8.00 0 0.0000 Sludge (ton) 0.0 8.00 0 0.0000 Subtotal By-Products: 0 0.0000

TOTAL VARIABLE OPERATING COST 12,841,735 0.0027

Annual Generation 4754 (MM-kwhr/yr)

Total O&M Cost 0.47 (Cents/kwhr) INITIAL & ANNUAL O&M EXPENSES

Consumption



### Table 7.3.16: Case CFB-4 Operating and Maintenance CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004187Table 7.3.17: Case CMB-3 Investment CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 188 Client: DOE - NETL Cost Base: Jul-03 Project: Economics and Feasibility of Rankine Cycle Impronements for Coal Fired Power Plants Case CMB-3 - 1 x 670 MW CMB Steam Plant

Net Plant Heat Rate (Btu/kWh): 8,781

Net Power Output (kW): 665,552

Capacity Factor (%): 80

OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate (Base): 30.90 $/hour Operating Labor Burden: 30.00 % Labor O-H change Rate: 25.00 % of O&M labor

Operating Labor Requirements (O.J.) per shift 1 unit/mod. Total Plant Skilled Operator 2.0 2.0 Operator 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 2.0 2.0 TOTAL Operator Jobs (O.J.'s) 14.0 14.0 Annual Cost Annual Unit Cost $ / year $/kW-net Annual Operating Labor Costs (calc'd) 4,926,449 7.40 Maintenance Labor Costs (calc'd) 2,686,639 4.04 Administrative & Support Labor (calc'd) 1,903,272 2.86 TOTAL FIXED OPERATING COST S 9,516,360 14.30

$/kWh-net Maintenance Material Cost (calc'd) 3,223,967 0.00069

Consumables Unit Initial Initial Per Day Cost Cost Water (1000 gallons) 3,039 1.00 887,253 0.00019

Chemicals MU & WT Chem. (lbs.) 741,960 24,732 0.16 118,714 1,155,479 0.00025 Limestone (ton) 23,086 769.5 10.00 230,861 2,247,045 0.00048 Formic Acid (lbs.) 0.60 Ammonia, NH3 (ton) 150 85,680 0.00002 Subtotal Chemicals: 349,574 3,488,204 0.00073

Other Consumables Supplemental Fuel (MBtu) SCR Catalyst Replacement (MBtu) Emissions Penalties Subtotal Other:

Waste Disposal Fly Ash & Bottom Ash (ton) 2,193.9 8.00 5,124,976 0.0011 Subtotal Solid Waste Disposal: 5,124,976 0.0011

By-Products Gypsum (ton) 0.0 8.00 0 0.0000 Sludge (ton) 0.0 8.00 0 0.0000 Subtotal By-Products: 0 0.0000

TOTAL VARIABLE OPERATING COST 12,724,400 0.0027

Annual Generation 4664 (MM-kwhr/yr)

Total O&M Cost 0.48 (Cents/kwhr) INITIAL & ANNUAL O&M EXPENSES

Consumption



### Table 7.3.18: Case CMB-3 Operating and Maintenance CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004189Table 7.3.19: Case CMB-5 Investment CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 190 Client: DOE - NETL Cost Base: Jul-03 Project: Economics and Feasibility of Rankine Cycle Impronements for Coal Fired Power Plants Case CMB-5 - 1 x 750 MW CMB Steam Plant

Net Plant Heat Rate (Btu/kWh): 7,853

Net Power Output (kW): 744,230

Capacity Factor (%): 80

OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate (Base): 30.90 $/hour Operating Labor Burden: 30.00 % Labor O-H change Rate: 25.00 % of O&M labor

Operating Labor Requirements (O.J.) per shift 1 unit/mod. Total Plant Skilled Operator 2.0 2.0 Operator 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 2.0 2.0 TOTAL Operator Jobs (O.J.'s) 14.0 14.0 Annual Cost Annual Unit Cost $ / year $/kW-net Annual Operating Labor Costs (calc'd) 4,926,449 6.62 Maintenance Labor Costs (calc'd) 3,068,575 4.12 Administrative & Support Labor (calc'd) 1,998,756 2.69 TOTAL FIXED OPERATING COST S 9,993,780 13.43

$/kWh-net Maintenance Material Cost (calc'd) 3,682,290 0.00071

Consumables Unit Initial Initial Per Day Cost Cost Water (1000 gallons) 3,039 1.00 887,253 0.00017

Chemicals MU & WT Chem. (lbs.) 741,960 24,732 0.16 118,714 1,155,479 0.00022 Limestone (ton) 23,086 769.5 10.00 230,861 2,247,045 0.00043 Formic Acid (lbs.) 0.60 Ammonia, NH3 (ton) 150 85,680 0.00002 Subtotal Chemicals: 349,574 3,488,204 0.00065

Other Consumables Supplemental Fuel (MBtu) SCR Catalyst Replacement (MBtu) Emissions Penalties Subtotal Other:

Waste Disposal Fly Ash & Bottom Ash (ton) 2,193.9 8.00 5,124,976 0.0010 Subtotal Solid Waste Disposal: 5,124,976 0.0010

By-Products Gypsum (ton) 0.0 8.00 0 0.0000 Sludge (ton) 0.0 8.00 0 0.0000 Subtotal By-Products: 0 0.0000

TOTAL VARIABLE OPERATING COST 13,182,724 0.0025

Annual Generation 5216 (MM-kwhr/yr)

Total O&M Cost 0.44 (Cents/kwhr) INITIAL & ANNUAL O&M E XPENSES

Consumption



### Table 7.3.20: Case CMB-5 Operating and Maintenance CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLEIMPROVEMENTS FOR COAL FIRED POWER PLANTSALSTOM Power Inc.September 8, 2004191Equipment Description Measures Installed Cost Comments & Issues$/kW net $/kW incrBoiler:~186 MWe-net (1,080,000 lbm/hr steam) 54,182,000Circulating Moving Bed(4,500Psia/1,292F/1,000F)293.1 1909.9Topping Turbine/Generator:~32 MWe, 1,080,000 lbm/hr, no extraction 10,725,0004,242 psi, 1,292F inlet; 2,015 psi, 1,050Fexhaust58.0 378.1Balance of Plant Equipment:FW booster pump including valvesand controlsActual discharge head 4,842psi and inletpressure 2,522psi, flow 1,080,000 lbm/hr 500,000 Single pump2.7 17.6Full flow condensate polishing system 950,000 lb/hr condensate flow 1,067,000 Includes foundation and sump5.8 37.6Coal feed system from the coal pile tothe coal bunkerTop of feeders elev. 676 ft (90 ft abovegrade) 1,510,000Includes top works on silos (headhouse). Assumes conveyor tube can berouted through obstructions with slightrotation of the silos.8.2 53.2Transformer 37.5 MVA 1,700,000Includes generator leads to transmissioninterconnection, pad, fire protection, oilcontainment, metering and protection CTs,etc. Topping turbine rotated 180 deg.9.2 59.9Flue gas duct and dampers toprecipitator 210 ft 830,000Includes foundations and crane rental forinstallation4.5 29.3Piping:Link to Demin. from condensate 1 x 275 ft 37,0000.2 1.3Link from Demin. to #1 FeedwaterHeater 1 x 275 ft 29,0000.2 1.0Main Steam to Topping Turbine 1 x 100 ft 4,180,000 Insulated, 1 line, 4,242 psi, 1,292F22.6 147.3Topping Turbine to Existing Turbine 1 x 200 ft 615,000 Insulated, 1 line3.3 21.7R.H. Inlet Link 2 x 200 ft 331,000 Insulated, 2 lines1.8 11.7R.H. Outlet Link 2 x 200 ft 396,000 Insulated, 2 lines2.1 14.0Economizer Inlet Link from newFeedwater Booster Pump 2 x 300 ft 242,000 Insulated, 2 lines1.3 8.5TOTAL COST76,344,000413 2,691Table 7.3.21: Sporn Unit #4 Repowering Case Investment CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 192 Client: DOE - NETL Cost Base: Jul-03 Project: Economics and Feasibility of Rankine Cycle Impronements for Coal Fired Power Plants Sporn Unit #4 Repowering Case - 1 x 185 MW CMB Steam Plant

Net Plant Heat Rate (Btu/kWh): 8,889

Net Power Output (kW): 184,887

Capacity Factor (%): 85

OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate (Base): 30.90 $/hour Operating Labor Burden: 30.00 % Labor O-H change Rate: 25.00 % of O&M labor

Operating Labor Requirements (O.J.) per shift 1 unit/mod. Total Plant Skilled Operator 1.0 1.0 Operator 7.0 7.0 Foreman 1.0 1.0 Lab Tech's, etc. 1.0 1.0 TOTAL Operator Jobs (O.J.'s) 10.0 10.0 Annual Cost Annual Unit Cost $ / year $/kW-net Annual Operating Labor Costs (calc'd) 3,518,892 19.03 Maintenance Labor Costs (calc'd) 916,128 4.96 Administrative & Support Labor (calc'd) 1,108,755 6.00 TOTAL FIXED OPERATING COST S 5,543,775 29.98

$/kWh-net Maintenance Material Cost (New Equipment) 389,354 0.00028 Maintenance Material Cost (Existing Equipment) 778,709 0.00057

Consumables Unit Initial Initial Per Day Cost Cost Water (1000 gallons) 887 1.00 275,325 0.00020

Chemicals MU & WT Chem. (lbs.) 205,696 6,857 0.16 32,911 340,359 0.00025 Limestone (ton) 3,290 109.7 10.00 32,896 340,194 0.00025 Formic Acid (lbs.) 0.60 Ammonia, NH3 (ton) 150 Subtotal Chemicals: 65,807 680,553 0.0005

Other Consumables Supplemental Fuel (MBtu) SCR Catalyst Replacement (MBtu) Emissions Penalties Subtotal Other:

Waste Disposal Fly Ash & Bottom Ash (ton) 156.6 8.00 388,560 0.0003 Subtotal Solid Waste Disposal: 388,560 0.0003

By-Products Gypsum (ton) 0.0 8.00 0 0.0000 Sludge (ton) 0.0 8.00 0 0.0000 Subtotal By-Products: 0 0.0000

TOTAL VARIABLE OPERATING COST 2,512,50 2 0.0018

Annual Generation 1377 (MM-kwhr/yr)

Total O&M Cost 0.59 (Cents/kwhr) INITIAL & ANNUA L O&M E XPENSES

Consumption



### Table 7.3.22: Sporn Unit #4 Repowering Case Operating and Maintenance CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 193 Client: DOE - NETL Cost Base: Jul-03 Project: Economics and Feasibility of Rankine Cycle Impronements for Coal Fired Power Plants Sporn Unit #4 Existing - 1 x 155 MW CMB Steam Plant

Net Plant Heat Rate (Btu/kWh): 9,561

Net Power Output (kW): 156,518

Capacity Factor (%): 85

OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate (Base): 30.90 $/hour Operating Labor Burden: 30.00 % Labor O-H change Rate: 25.00 % of O&M labor

Operating Labor Requirements (O.J.) per shift 1 unit/mod. Total Plant Skilled Operator 1.0 1.0 Operator 7.0 7.0 Foreman 1.0 1.0 Lab Tech's, etc. 1.0 1.0 TOTAL Operator Jobs (O.J.'s) 10.0 10.0 Annual Cost Annual Unit Cost $ / year $/kW-net Annual Operating Labor Costs (calc'd) 3,518,892 22.48 Maintenance Labor Costs (calc'd) 916,128 5.85 Administrative & Support Labor (calc'd) 1,108,755 7.08 TOTAL FIXED OPERATING COST S 5,543,775 35.4 2

$/kWh-net Maintenance Material Cost (Existing Equipment) 1,168,063 0.00100

Consumables Unit Initial Initial Per Day Cost Cost Water (1000 gallons) 887 1.00 275,325 0.00024

Chemicals MU & WT Chem. (lbs.) 205,696 6,857 0.16 32,911 340,359 0.00029 Limestone (ton) 0 0.0 10.00 0 - 0.00000 Formic Acid (lbs.) 0.60 Ammonia, NH3 (ton) 150 Subtotal Chemicals: 32,911 340,359 0.0003

Other Consumables Supplemental Fuel (MBtu) SCR Catalyst Replacement (MBtu) Emissions Penalties Subtotal Other:

Waste Disposal Fly Ash & Bottom Ash (ton) 142.5 8.00 353,786 0.0003 Subtotal Solid Waste Disposal: 353,786 0.0003

By-Products Gypsum (ton) 0.0 8.00 0 0.0000 Sludge (ton) 0.0 8.00 0 0.0000 Subtotal By-Products: 0 0.0000

TOTAL VARIABLE OPERATING COST 2,137,534 0.0018

Annual Generation 1165 (MM-kwhr/yr)

Total O&M Cost 0.66 (Cents/kwhr) INITIAL & ANNUA L O&M E XPENSES

Consumption



### Table 7.3.23: Existing Sporn Unit #4 Operating and Maintenance CostsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 194 

### 7.4 Appendix IV - Economic Sensitivity Study Results

Sensitivity analyses were conducted for all PC and CFB/ CMB TM 

### case studies to determine the effect on COE of variation of selected base param eter values by ± 25 percent. These parameters (shaded in yellow in Table 4.1.1) are availability factor, EPC price, coal price, equity rate, corporate tax rate, and the discount rate for cost of capital. The base parameter values represent the point where all the sensitivity curves intersect (point 0, 0). Sensitivity analysis results tables and “spider plots” for all cases are provided in this appendix.
Other COE sensitivity studies were conducted on: 1) High temperature alloy cost ($20, $28, and $32.90 per pound) for PC-5, CMB TM 

### -5, and the repowering case. 2) NO x 

### emissions credit on the repowering case.

7.4.1 Case PC-1 – 1 x 630 MW PC Fired Steam Plant with SCR

Results for the Case PC-1 COE sensitivity study are shown in Figure 7.4.1 and summarized in Table 7.4.1. The levelized COE for the base pa rameter values is 4.0 cents per kWh. Levelized COE ranges from a low of 3.4 to a high of 4.8 cents per kWh.

-20% -15% -10% -5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in Variable Pe
rc en t Ch
an ge in C O

3.2 3.4 3.6 3.8 4.0 4.2 4.4 4.6 4.8 5.0 Le vel ize d C O E (c
en ts / k

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate



### Figure 7.4. 1: Case PC-1 - 1 x 630 MW PC Fi red Steam Plant with SCR Economic Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 195 

### Table 7.4. 1: Case PC-1 – 1 x 630 MW PC Fi red Steam Plant with SCR Sensitivity Analysis Results

Parameter Units Case PC-1 - 1 x 630 MW PC Fired Steam Plant w/ SCR Power Generation

Net Output kW 630,525 630,525 630,525 630,525 630,525 630,525 630,525 630,525 630,525 630,525 630,525 630,525 630,525 Availability Factor % 80 60 70 90 100 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 5,256 6,132 7,884 8,760 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 37.0 37.0 37.0 37.0 37.0 37.0 37.0 37.0 37.0 37.0 37.0 37.0 37.0 Net Plant Heat Rate, HHV Btu / kWh 9218 9218 9218 9218 9218 9218 9218 9218 9218 9218 9218 9218 9218 Net Generation MWh / year 4,418,719 4,418,719 4,418,719 4,418,719 4,418,719 4,418,719 4,418,719 4,418,719 4,418,719 4,418,719 4,418,719 4,418,719 4,418,719 Costs

EPC Price $ / kW 1,139 1,139 1,139 1,139 1,139 854 997 1,282 1,424 1,139 1,139 1,139 1,139 EPC Price $1000s 718,365 718,365 718,365 718,365 718,365 538,774 628,570 808,161 897,957 718,365 718,365 718,365 718,365 Fixed O&M Costs $1000 / year 9,639 9,639 9,639 9,639 9,639 9,639 9,639 9,639 9,639 9,639 9,639 9,639 9,639 Fixed O&M Costs $ / kW 15.29 15.29 15.29 15.29 15.29 15.29 15.29 15.29 15.29 15.29 15.29 15.29 15.29 Variable O&M Costs $1000 / year 18,020 13,515 15,768 20,273 22,525 18,020 18,020 18,020 18,020 18,020 18,020 18,020 18,020 Variable O&M Costs cents / kWh 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 Total O&M Costs cents / kWh 0.63 0.70 0.66 0.60 0.58 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.63 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 0.94 1.09 1.41 1.56 Financin g Assumptions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 10 10 10 10 10 Levelized Cost of Electricity (cents / kWh)

Financial Component 2.18 2.91 2.49 1.94 1.74 1.63 1.91 2.45 2.72 2.18 2.18 2.18 2.18 Fixed O&M 0.22 0.29 0.25 0.19 0.17 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 Variable O&M 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 Fuel 1.15 1.15 1.15 1.15 1.15 1.15 1.15 1.15 1.15 0.86 1.01 1.30 1.44 Total 3.96 4.76 4.30 3.69 3.48 3.41 3.68 4.23 4.50 3.67 3.81 4.10 4.25

Parameter Units Case PC-1 - 1 x 630 MW PC Fired Steam Plant w/ SCR Power Generation

Net Output kW 630,525 630,525 630,525 630,525 630,525 630,525 630,525 630,525 630,525 630,525 630,525 630,525 Availability Factor % 80 80 80 80 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 37.0 37.0 37.0 37.0 37.0 37.0 37.0 37.0 37.0 37.0 37.0 37.0 Net Plant Heat Rate, HHV Btu / kWh 9218 9218 9218 9218 9218 9218 9218 9218 9218 9218 9218 9218 Net Generation MWh / year 4,418,719 4,418,719 4,418,719 4,418,719 4,418,719 4,418,719 4,418,719 4,418,719 4,418,719 4,418,719 4,418,719 4,418,719 Costs

EPC Price $ / kW 1,139 1,139 1,139 1,139 1,139 1,139 1,139 1,139 1,139 1,139 1,139 1,139 EPC Price $1000s 718,365 718,365 718,365 718,365 718,365 718,365 718,365 718,365 718,365 718,365 718,365 718,365 Fixed O&M Costs $1000 / year 9,639 9,639 9,639 9,639 9,639 9,639 9,639 9,639 9,639 9,639 9,639 9,639 Fixed O&M Costs $ / kW 15.29 15.29 15.29 15.29 15.29 15.29 15.29 15.29 15.29 15.29 15.29 15.29 Variable O&M Costs $1000 / year 18,020 18,020 18,020 18,020 18,020 18,020 18,020 18,020 18,020 18,020 18,020 18,020 Variable O&M Costs cents / kWh 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 Total O&M Costs cents / kWh 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.63 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 Financin g Assumptions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 8 9 11 13 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 2.03 2.11 2.25 2.32 2.11 2.14 2.22 2.25 1.83 2.00 2.37 2.56 Fixed O&M 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 Variable O&M 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41 Fuel 1.15 1.15 1.15 1.15 1.15 1.15 1.15 1.15 1.15 1.15 1.15 1.15 Total 3.81 3.88 4.03 4.10 3.89 3.92 3.99 4.03 3.60 3.78 4.15 4.34ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 196 

### 7.4.2 Case PC-2 – 1 x 650 MW PC Fired Steam Plant with SCR

Results for the Case PC-2 COE sensitivity study are shown in Figure 7.4.2 and summarized in Table 7.4.2. The levelized COE for the base pa rameter values is 3.9 cents per kWh. Levelized COE ranges from a low of 3.4 to a high of 4.7 cents per kWh.

-20% -15% -10%

-5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

3.1 3.3 3.5 3.7 3.9 4.1 4.3 4.5 4.7 4.9Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate



### Figure 7.4. 2: Case PC-2 – 1 x 650 MW PC Fired Steam Plant with SCR Sensitivity Analysis ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 197 

### Table 7.4. 2: Case PC-2 – 1 x 650 MW PC Fi red Steam Plant with SCR Sensitivity Analysis Results

Parameter Units Case PC-2 - 1 x 650 MW PC Fired Steam Plant w/ SCR Power Generation

Net Output kW 646,080 646,080 646,080 646,080 646,080 646,080 646,080 646,080 646,080 646,080 646,080 646,080 646,080 Availability Factor % 80 60 70 90 100 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 5,256 6, 132 7,884 8,760 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 37.9 37.9 37.9 37.9 37.9 37.9 37.9 37.9 37.9 37.9 37.9 37.9 37.9 Net Plant Heat Rate, HHV Btu / kWh 8997 8997 8997 8997 8997 8997 8997 8997 8997 8997 8997 8997 8997 Net Generation MWh / year 4,527,729 4,527,729 4,527,729 4,527,729 4,527,729 4,527,729 4,527,729 4,527,729 4,527,729 4,527,729 4,527,729 4,527,729 4,527,729 Costs

EPC Price $ / kW 1,126 1,126 1,126 1,126 1,126 844 985 1,266 1,407 1,126 1,126 1,126 1,126 EPC Price $1000s 727,230 727,230 727,230 727,230 727,230 545,423 636,327 818,134 909,038 727,230 727,230 727,230 727,230 Fixed O&M Costs $1000 / year 9,684 9,684 9,684 9,684 9,684 9,684 9,684 9,684 9,684 9,684 9,684 9,684 9,684 Fixed O&M Costs $ / kW 14.99 14.99 14.99 14.99 14.99 14.99 14.99 14.99 14.99 14.99 14.99 14.99 14.99 Variable O&M Costs $1000 / year 18,063 13,547 15,805 20,321 22,578 18,063 18,063 18,063 18,063 18,063 18,063 18,063 18,063 Variable O&M Costs cents / kWh 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 Total O&M Costs cents / kWh 0.61 0.68 0.64 0.59 0.57 0.61 0.61 0.61 0.61 0.61 0.61 0.61 0.61 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 0.94 1.09 1.41 1.56 Financin g Assumptions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 10 10 10 10 10 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 2.15 2.87 2.46 1.91 1.72 1.61 1.88 2.42 2.69 2.15 2.15 2.15 2.15 Fixed O&M 0.21 0.29 0.24 0.19 0.17 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 Variable O&M 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 Fuel 1.12 1.12 1.12 1.12 1.12 1.12 1.12 1.12 1.12 0.84 0.98 1.27 1.41 Total 3.89 4.68 4.23 3.63 3.42 3.35 3.62 4.16 4.43 3.61 3.75 4.03 4.17

Paramete r Units Case PC-2 - 1 x 650 MW PC Fired Steam Plant w/ SCR Power Generation

Net Output kW 646,080 646,080 646,080 646,080 646,080 646,080 646,080 646,080 646,080 646,080 646,080 646,080 Availability Factor % 80 80 80 80 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 37.9 37.9 37.9 37.9 37.9 37.9 37.9 37.9 37.9 37.9 37.9 37.9 Net Plant Heat Rate, HHV Btu / kWh 8997 8997 8997 8997 8997 8997 8997 8997 8997 8997 8997 8997 Net Generation MWh / year 4,527,729 4,527,729 4,527,729 4,527,729 4,527,729 4,527,729 4,527,729 4,527,729 4,527,729 4,527,729 4,527,729 4,527,729 Costs

EPC Price $ / kW 1,126 1,126 1,126 1,126 1,126 1,126 1,126 1,126 1,126 1,126 1,126 1,126 EPC Price $1000s 727,230 727,230 727,230 727,230 727,230 727,230 727,230 727,230 727,230 727,230 727,230 727,230 Fixed O&M Costs $1000 / year 9,684 9,684 9,684 9,684 9,684 9,684 9,684 9,684 9,684 9,684 9,684 9,684 Fixed O&M Costs $ / kW 14.99 14.99 14.99 14.99 14.99 14.99 14.99 14.99 14.99 14.99 14.99 14.99 Variable O&M Costs $1000 / year 18,063 18,063 18,063 18,063 18,063 18,063 18,063 18,063 18,063 18,063 18,063 18,063 Variable O&M Costs cents / kWh 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 Total O&M Costs cents / kWh 0.61 0.61 0.61 0.61 0.61 0.61 0.61 0.61 0.61 0.61 0.61 0.61 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 Financin g Assumptions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 8 9 11 13 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 2.01 2.08 2.22 2.29 2.09 2.12 2.19 2.23 1.80 1.97 2.34 2.53 Fixed O&M 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 Variable O&M 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 Fuel 1.12 1.12 1.12 1.12 1.12 1.12 1.12 1.12 1.12 1.12 1.12 1.12 Total 3.74 3.82 3.96 4.03 3.82 3.86 3.93 3.96 3.54 3.71 4.08 4.27ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 198 

### 7.4.3 Case PC-3 – 1 x 660 MW PC Fired Steam Plant with SCR

Results for the Case PC-3 COE sensitivity study are shown in Figure 7.4.3 and summarized in Table 7.4.3. The levelized COE for the base pa rameter values is 3.8 cents per kWh. Levelized COE ranges from a low of 3.3 to a high of 4.6 cents per kWh.

-20% -15% -10%

-5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

3.1 3.3 3.5 3.7 3.9 4.1 4.3 4.5 4.7 4.9Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate



### Figure 7.4. 3: Case PC-3 – 1 x 660 MW PC Fired Steam Plant with SCR Sensitivity Analysis ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 199 

### Table 7.4. 3: Case PC-3 – 1 x 660 MW PC Fi red Steam Plant with SCR Sensitivity Analysis Results

Parameter Units Case PC-3 - 1 x 660 MW PC Fired Steam Plant w/ SCR Power Generation

Net Output kW 662,936 662,936 662,936 662,936 662,936 662,936 662,936 662,936 662,936 662,936 662,936 662,936 662,936 Availability Factor % 80 60 70 90 100 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 5,256 6, 132 7,884 8,760 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 Net Plant Heat Rate, HHV Btu / kWh 8768 8768 8768 8768 8768 8768 8768 8768 8768 8768 8768 8768 8768 Net Generation MWh / year 4,645,856 4,645,856 4,645,856 4,645,856 4,645,856 4,645,856 4,645,856 4,645,856 4,645,856 4,645,856 4,645,856 4,645,856 4,645,856 Costs

EPC Price $ / kW 1,109 1,109 1,109 1,109 1,109 831 970 1,247 1,386 1,109 1,109 1,109 1,109 EPC Price $1000s 734,879 734,879 734,879 734,879 734,879 551,160 643,020 826,739 918,599 734,879 734,879 734,879 734,879 Fixed O&M Costs $1000 / year 9,722 9,722 9,722 9,722 9,722 9,722 9,722 9,722 9,722 9,722 9,722 9,722 9,722 Fixed O&M Costs $ / kW 14.67 14.67 14.67 14.67 14.67 14.67 14.67 14.67 14.67 14.67 14.67 14.67 14.67 Variable O&M Costs $1000 / year 18,406 13,805 16,105 20,707 23,008 18,406 18,406 18,406 18,406 18,406 18,406 18,406 18,406 Variable O&M Costs cents / kWh 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 Total O&M Costs cents / kWh 0.61 0.68 0.64 0.58 0.56 0.61 0.61 0.61 0.61 0.61 0.61 0.61 0.61 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 0.94 1.09 1.41 1.56 Financin g Assumptions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 10 10 10 10 10 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 2.12 2.83 2.42 1.88 1.70 1.59 1.86 2.39 2.65 2.12 2.12 2.12 2.12 Fixed O&M 0.21 0.28 0.24 0.19 0.17 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 Variable O&M 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 Fuel 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 0.82 0.96 1.23 1.37 Total 3.82 4.60 4.15 3.56 3.36 3.29 3.56 4.09 4.35 3.55 3.68 3.96 4.10

Parameter Units Case PC-3 - 1 x 660 MW PC Fired Steam Plant w/ SCR Power Generation

Net Output kW 662,936 662,936 662,936 662,936 662,936 662,936 662,936 662,936 662,936 662,936 662,936 662,936 Availability Factor % 80 80 80 80 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 Net Plant Heat Rate, HHV Btu / kWh 8768 8768 8768 8768 8768 8768 8768 8768 8768 8768 8768 8768 Net Generation MWh / year 4,645,856 4,645,856 4,645,856 4,645,856 4,645,856 4,645,856 4,645,856 4,645,856 4,645,856 4,645,856 4,645,856 4,645,856 Costs

EPC Price $ / kW 1,109 1,109 1,109 1,109 1,109 1,109 1,109 1,109 1,109 1,109 1,109 1,109 EPC Price $1000s 734,879 734,879 734,879 734,879 734,879 734,879 734,879 734,879 734,879 734,879 734,879 734,879 Fixed O&M Costs $1000 / year 9,722 9,722 9,722 9,722 9,722 9,722 9,722 9,722 9,722 9,722 9,722 9,722 Fixed O&M Costs $ / kW 14.67 14.67 14.67 14.67 14.67 14.67 14.67 14.67 14.67 14.67 14.67 14.67 Variable O&M Costs $1000 / year 18,406 18,406 18,406 18,406 18,406 18,406 18,406 18,406 18,406 18,406 18,406 18,406 Variable O&M Costs cents / kWh 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 Total O&M Costs cents / kWh 0.61 0.61 0.61 0.61 0.61 0.61 0.61 0.61 0.61 0.61 0.61 0.61 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 Financin g Assumptions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 8 9 11 13 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.98 2.05 2.19 2.26 2.06 2.09 2.16 2.19 1.78 1.94 2.30 2.50 Fixed O&M 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 Variable O&M 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 Fuel 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 Total 3.68 3.75 3.89 3.96 3.76 3.79 3.86 3.90 3.48 3.65 4.01 4.20ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 200 

### 7.4.4 Case PC-4 – 1 x 680 MW PC Fired Steam Plant with SCR

Results for the Case PC-4 COE sensitivity study are shown in Figure 7.4.4 and summarized in Table 7.4.4. The levelized COE for the base pa rameter values is 3.8 cents per kWh. Levelized COE ranges from a low of 3.2 to a high of 4.5 cents per kWh.

-20% -15% -10%

-5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

3.0 3.2 3.4 3.6 3.8 4.0 4.2 4.4 4.6 4.8Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate



### Figure 7.4. 4: Case PC-4 – 1 x 680 MW PC Fired Steam Plant with SCR Sensitivity Analysis ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 201 

### Table 7.4. 4: Case PC-4 – 1 x 680 MW PC Fi red Steam Plant with SCR Sensitivity Analysis Results

Parameter Units Case PC-4 - 1 x 680 MW PC Fired Steam Plant w/ SCR Power Generation

Net Output kW 677,479 677,479 677,479 677,479 677,479 677,479 677,479 677,479 677,479 677,479 677,479 677,479 677,479 Availability Factor % 80 60 70 90 100 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 5,256 6,132 7,884 8,760 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 Net Plant Heat Rate, HHV Btu / kWh 8580 8580 8580 8580 8580 8580 8580 8580 8580 8580 8580 8580 8580 Net Generation MWh / year 4,747,773 4,747,773 4,747,773 4,747,773 4,747,773 4,747,773 4,747,773 4,747,773 4,747,773 4,747,773 4,747,773 4,747,773 4,747,773 Costs

EPC Price $ / kW 1,098 1,098 1,098 1,098 1,098 823 961 1,235 1,372 1,098 1,098 1,098 1,098 EPC Price $1000s 743,861 743,861 743,861 743,861 743,861 557,896 650,879 836,844 929,827 743,861 743,861 743,861 743,861 Fixed O&M Costs $1000 / year 9,767 9,767 9,767 9,767 9,767 9,767 9,767 9,767 9,767 9,767 9,767 9,767 9,767 Fixed O&M Costs $ / kW 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 Variable O&M Costs $1000 / year 18,143 13,607 15,875 20,410 22,678 18,143 18,143 18,143 18,143 18,143 18,143 18,143 18,143 Variable O&M Costs cents / kWh 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 Total O&M Costs cents / kWh 0.59 0.66 0.62 0.56 0.55 0.59 0.59 0.59 0.59 0.59 0.59 0.59 0.59 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 0.94 1.09 1.41 1.56 Financin g Assumptions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 10 10 10 10 10 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 2.10 2.80 2.40 1.87 1.68 1.58 1.84 2.36 2.63 2.10 2.10 2.10 2.10 Fixed O&M 0.21 0.27 0.24 0.18 0.16 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 Variable O&M 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 Fuel 1.07 1.07 1.07 1.07 1.07 1.07 1.07 1.07 1.07 0.80 0.94 1.21 1.34 Total 3.76 4.53 4.09 3.50 3.30 3.24 3.50 4.02 4.29 3.49 3.63 3.89 4.03

Paramete r Units Case PC-4 - 1 x 680 MW PC Fired Steam Plant w/ SCR Power Generation

Net Output kW 677,479 677,479 677,479 677,479 677,479 677,479 677,479 677,479 677,479 677,479 677,479 677,479 Availability Factor % 80 80 80 80 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 Net Plant Heat Rate, HHV Btu / kWh 8580 8580 8580 8580 8580 8580 8580 8580 8580 8580 8580 8580 Net Generation MWh / year 4,747,773 4,747,773 4,747,773 4,747,773 4,747,773 4,747,773 4,747,773 4,747,773 4,747,773 4,747,773 4,747,773 4,747,773 Costs

EPC Price $ / kW 1,098 1,098 1,098 1,098 1,098 1,098 1,098 1,098 1,098 1,098 1,098 1,098 EPC Price $1000s 743,861 743,861 743,861 743,861 743,861 743,861 743,861 743,861 743,861 743,861 743,861 743,861 Fixed O&M Costs $1000 / year 9,767 9,767 9,767 9,767 9,767 9,767 9,767 9,767 9,767 9,767 9,767 9,767 Fixed O&M Costs $ / kW 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 Variable O&M Costs $1000 / year 18,143 18,143 18,143 18,143 18,143 18,143 18,143 18,143 18,143 18,143 18,143 18,143 Variable O&M Costs cents / kWh 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 Total O&M Costs cents / kWh 0.59 0.59 0.59 0.59 0.59 0.59 0.59 0.59 0.59 0.59 0.59 0.59 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 Financin g Assumptions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 8 9 11 13 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.96 2.03 2.17 2.24 2.04 2.07 2.14 2.17 1.76 1.93 2.28 2.47 Fixed O&M 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 Variable O&M 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 0.38 Fuel 1.07 1.07 1.07 1.07 1.07 1.07 1.07 1.07 1.07 1.07 1.07 1.07 Total 3.62 3.69 3.83 3.90 3.70 3.73 3.80 3.83 3.42 3.59 3.94 4.13ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 202 

### 7.4.5 Case PC-5 $20 Nickel - 1 x 740 MW PC Fired Steam Plant with SCR and $20 per Pound High Temperature Alloy

Results for the Case PC-5 COE sensitivity study are shown in Figure 7.4.5 and summarized in Table 7.4.5. The levelized COE for the base pa rameter values is 3.7 cents per kWh. Levelized COE ranges from a low of 3.2 to a high of 4.5 cents per kWh.

-20% -15% -10%

-5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

3.0 3.2 3.4 3.6 3.8 4.0 4.2 4.4 4.6 4.8Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate


### Figure 7.4. 5: Case PC-5 20 Nickel - 1 x 740 MW PC Fired Steam Plant with SCR and $20 per Pound High Temperature Alloy Economic Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 203 

### Table 7.4. 5: Case PC-5 20 Nickel - 1 x 740 MW PC Fired Steam Plant with SCR and $20 per Pound High Temperature Alloy Economic Sensitivity Results

Parameter Units Case PC-5 - 1 x 740 MW PC Fired Steam Plant; $20/lb Nickel Power Generation

Net Output kW 741,615 741,615 741,615 741,615 741,615 741, 615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 Availability Factor % 80 60 70 90 100 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 5,256 6,132 7,884 8,760 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 Net Plant Heat Rate, HHV Btu / kWh 7838 7838 7838 7838 7838 7838 7838 7838 7838 7838 7838 7838 7838 Net Generation MWh / year 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197 ,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 Costs

EPC Price $ / kW 1,139 1,139 1,139 1,139 1,139 854 997 1,282 1,424 1,139 1,139 1,139 1,139 EPC Price $1000s 844,808 844,808 844,808 844,808 844,808 633,606 739,207 950,409 1,056,010 844,808 844,808 844,808 844,808 Fixed O&M Costs $1000 / year 10,272 10,272 10,272 10,272 10,272 10,272 10,272 10,272 10,272 10,272 10,272 10,272 10,272 Fixed O&M Costs $ / kW 13.85 13.85 13.85 13.85 13.85 13.85 13.85 13.85 13.85 13.85 13.85 13.85 13.85 Variable O&M Costs $1000 / year 18,627 13,970 16,299 20,955 23,284 18,627 18,627 18,627 18,627 18,627 18,627 18,627 18,627 Variable O&M Costs cents / kWh 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 Total O&M Costs cents / kWh 0.56 0.62 0.58 0.53 0.52 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 0.94 1.09 1.41 1.56 Financing Assumptions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 10 10 10 10 10 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 2.18 2.91 2.49 1.94 1.74 1.63 1.91 2.45 2.72 2.18 2.18 2.18 2.18 Fixed O&M 0.20 0.26 0.23 0.18 0.16 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 Variable O&M 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 Fuel 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.73 0.86 1.10 1.22 Total 3.71 4.51 4.05 3.45 3.24 3.17 3.44 3.99 4.26 3.47 3.59 3.84 3.96

Paramete r Units Case PC-5 - 1 x 740 MW PC Fired Steam Plant; $20/lb Nickel Power Generation

Net Output kW 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 Availability Factor % 80 80 80 80 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 Net Plant Heat Rate, HHV Btu / kWh 7838 7838 7838 7838 7838 7838 7838 7838 7838 7838 7838 7838 Net Generation MWh / year 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,19 7,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 Costs

EPC Price $ / kW 1,139 1,139 1,139 1,139 1,139 1,139 1,139 1,139 1,139 1,139 1,139 1,139 EPC Price $1000s 844,808 844,808 844,808 844,808 844,808 844,808 844,808 844,808 844,808 844,808 844,808 844,808 Fixed O&M Costs $1000 / year 10,272 10,272 10,272 10,272 10,272 10,272 10,272 10,272 10,272 10,272 10,272 10,272 Fixed O&M Costs $ / kW 13.85 13.85 13.85 13.85 13.85 13.85 13.85 13.85 13.85 13.85 13.85 13.85 Variable O&M Costs $1000 / year 18,627 18,627 18,627 18,627 18,627 18,627 18,627 18,627 18,627 18,627 18,627 18,627 Variable O&M Costs cents / kWh 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 Total O&M Costs cents / kWh 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 Financin g Assumptions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 8 9 11 13 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 2.03 2.11 2.25 2.32 2.11 2.14 2.22 2.25 1.83 2.00 2.37 2.56 Fixed O&M 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 Variable O&M 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 Fuel 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 Total 3.57 3.64 3.79 3.86 3.65 3.68 3.75 3.79 3.36 3.53 3.90 4.10ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 204 

### 7.4.6 Case PC-5 $28 Nickel - 1 x 740 MW PC Fired Steam Plant with SCR and $28 per Pound High Temperature Alloy Economic Sensitivity Results

Results for the Case PC-5 COE sensitivity study are shown in Figure 7.4.6 and summarized in Table 7.4.6. The levelized COE for the base pa rameter values is 3.8 cents per kWh. Levelized COE ranges from a low of 3.2 to a high of 4.6 cents per kWh.

-20% -15% -10%

-5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

3.0 3.2 3.4 3.6 3.8 4.0 4.2 4.4 4.6 4.8Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate



### Figure 7.4. 6: Case PC-5 $28 Nickel - 1 x 740 MW PC Fired Steam Plant with SCR and $28 per Pound High Temperature Alloy Economic Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 205 

### Table 7.4. 6: Case PC-5 $28 Nickel - 1 x 7 40 MW PC Fired Steam Plant with SCR and $28 per Pound High Temperature Alloy Economic Sensitivity Results

Parameter Units Case PC-5 - 1 x 740 MW PC Fired Steam Plant w/ SCR Power Generation

Net Output kW 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 Availability Factor % 80 60 70 90 100 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 5,256 6,132 7,884 8,760 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 Net Plant Heat Rate, HHV Btu / kWh 7838 7838 7838 7838 7838 7838 7838 7838 7838 7838 7838 7838 7838 Net Generation MWh / year 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 Costs

EPC Price $ / kW 1,168 1,168 1,168 1,168 1,168 876 1,022 1,314 1,460 1,168 1,168 1,168 1,168 EPC Price $1000s 866,303 866,303 866,303 866,303 866,303 649,728 758,016 974,591 1,082,879 866,303 866,303 866,303 866,303 Fixed O&M Costs $1000 / year 10,379 10,379 10,379 10,379 10,379 10,379 10,379 10,379 10,379 10,379 10,379 10,379 10,379 Fixed O&M Costs $ / kW 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 Variable O&M Costs $1000 / year 18,730 14,048 16,389 21,072 23,413 18,730 18,730 18,730 18,730 18,730 18,730 18,730 18,730 Variable O&M Costs cents / kWh 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 Total O&M Costs cents / kWh 0.56 0.63 0.59 0.54 0.52 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 0.94 1.09 1.41 1.56 Financin g Assumptions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 10 10 10 10 10 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 2.23 2.98 2.55 1.99 1.79 1.68 1.95 2.51 2.79 2.23 2.23 2.23 2.23 Fixed O&M 0.20 0.27 0.23 0.18 0.16 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 Variable O&M 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 Fuel 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.73 0.86 1.10 1.22 Total 3.77 4.59 4.12 3.50 3.29 3.22 3.49 4.05 4.33 3.53 3.65 3.90 4.02

Parameter Units Case PC-5 - 1 x 740 MW PC Fired Steam Plant w/ SCR Power Generation

Net Output kW 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 Availability Factor % 80 80 80 80 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 Net Plant Heat Rate, HHV Btu / kWh 7838 7838 7838 7838 7838 7838 7838 7838 7838 7838 7838 7838 Net Generation MWh / year 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 Costs

EPC Price $ / kW 1,168 1,168 1,168 1,168 1,168 1,168 1,168 1,168 1,168 1,168 1,168 1,168 EPC Price $1000s 866,303 866,303 866,303 866,303 866,303 866,303 866,303 866,303 866,303 866,303 866,303 866,303 Fixed O&M Costs $1000 / year 10,379 10,379 10,379 10,379 10,379 10,379 10,379 10,379 10,379 10,379 10,379 10,379 Fixed O&M Costs $ / kW 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 Variable O&M Costs $1000 / year 18,730 18,730 18,730 18,730 18,730 18,730 18,730 18,730 18,730 18,730 18,730 18,730 Variable O&M Costs cents / kWh 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 Total O&M Costs cents / kWh 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 Financin g Assum p tions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 8 9 11 13 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 2.08 2.16 2.31 2.38 2.17 2.20 2.27 2.31 1.87 2.05 2.43 2.63 Fixed O&M 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 Variable O&M 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 Fuel 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 Total 3.62 3.70 3.85 3.92 3.71 3.74 3.81 3.85 3.41 3.59 3.97 4.17ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 206 

### 7.4.7 Case PC-5 $32.9 Nickel - 1 x 740 MW PC Fired Steam Plant with SCR and $32.90 per Pound High Temperature Alloy Economic Sensitivity Results

Results for the Case PC-5 COE sensitivity study are shown in Figure 7.4.7 and summarized in Table 7.4.7. The levelized COE for the base pa rameter values is 3.8 cents per kWh. Levelized COE ranges from a low of 3.2 to a high of 4.6 cents per kWh.

-20% -15% -10%

-5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

3.0 3.2 3.4 3.6 3.8 4.0 4.2 4.4 4.6 4.8Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate 

### Figure 7.4. 7: Case PC-5 $32.9 Nickel - 1 x 740 MW PC Fired Steam Plant with SCR and $32.90 per Pound High Temperature Alloy Economic Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 207 

### Table 7.4. 7: Case PC-5 $32.9 Nickel - 1 x 740 MW PC Fired Steam Plant with SCR and $32.90 per Pound High Temperature Alloy Economic Sensitivity Results

Paramete r Units Case PC-5 - 1 x 740 MW PC Fired Steam Plant; $32.90/lb Nickel Power Generation

Net Output kW 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 Availability Factor % 80 60 70 90 100 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 5,256 6,132 7,884 8,760 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 Net Plant Heat Rate, HHV Btu / kWh 7838 7838 7838 7838 7838 7838 7838 7838 7838 7838 7838 7838 7838 Net Generation MWh / year 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 Costs

EPC Price $ / kW 1,186 1,186 1,186 1,186 1,186 889 1,038 1,334 1,482 1,186 1,186 1,186 1,186 EPC Price $1000s 879,468 879,468 879,468 879,468 879,468 659,601 769,534 989,401 1,099,335 879,468 879,468 879,468 879,468 Fixed O&M Costs $1000 / year 10,445 10,445 10,445 10,445 10,445 10,445 10,445 10,445 10,445 10,445 10,445 10,445 10,445 Fixed O&M Costs $ / kW 14.08 14.08 14.08 14.08 14.08 14.08 14.08 14.08 14.08 14.08 14.08 14.08 14.08 Variable O&M Costs $1000 / year 18,793 14,095 16,444 21,143 23,492 18,793 18,793 18,793 18,793 18,793 18,793 18,793 18,793 Variable O&M Costs cents / kWh 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 Total O&M Costs cents / kWh 0.56 0.63 0.59 0.54 0.52 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 0.94 1.09 1.41 1.56 Financin g Assum p tions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 10 10 10 10 10 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 2.27 3.02 2.59 2.02 1.81 1.70 1.98 2.55 2.84 2.27 2.27 2.27 2.27 Fixed O&M 0.20 0.27 0.23 0.18 0.16 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 Variable O&M 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 Fuel 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.73 0.86 1.10 1.22 Total 3.81 4.63 4.16 3.54 3.32 3.24 3.53 4.09 4.38 3.57 3.69 3.93 4.06

Paramete r Units Case PC-5 - 1 x 740 MW PC Fired Steam Plant; $32.90/lb Nickel Power Generation

Net Output kW 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 741,615 Availability Factor % 80 80 80 80 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 Net Plant Heat Rate, HHV Btu / kWh 7838 7838 7838 7838 7838 7838 7838 7838 7838 7838 7838 7838 Net Generation MWh / year 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 5,197,238 Costs

EPC Price $ / kW 1,186 1,186 1,186 1,186 1,186 1,186 1,186 1,186 1,186 1,186 1,186 1,186 EPC Price $1000s 879,468 879,468 879,468 879,468 879,468 879,468 879,468 879,468 879,468 879,468 879,468 879,468 Fixed O&M Costs $1000 / year 10,445 10,445 10,445 10,445 10,445 10,445 10,445 10,445 10,445 10,445 10,445 10,445 Fixed O&M Costs $ / kW 14.08 14.08 14.08 14.08 14.08 14.08 14.08 14.08 14.08 14.08 14.08 14.08 Variable O&M Costs $1000 / year 18,793 18,793 18,793 18,793 18,793 18,793 18,793 18,793 18,793 18,793 18,793 18,793 Variable O&M Costs cents / kWh 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 Total O&M Costs cents / kWh 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 Financin g Assum p tions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 8 9 11 13 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 2.11 2.19 2.34 2.42 2.20 2.23 2.31 2.35 1.90 2.08 2.46 2.67 Fixed O&M 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 Variable O&M 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.36 Fuel 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 Total 3.66 3.73 3.89 3.96 3.74 3.77 3.85 3.89 3.44 3.62 4.01 4.21ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 208 

### 7.4.8 Case CFB-2 - 1 x 650 MW CFB Steam Plant with SNCR Economic Sensitivity Results

Results for the Case CFB-2 COE sensitivity st udy are shown in Figure 7.4.8 and summarized in Table 7.4.8. The levelized COE for the base pa rameter values is 3.6 cents per kWh. Levelized COE ranges from a low of 3.1 to a high of 4.4 cents per kWh.

-20% -15% -10%

-5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

2.9 3.1 3.3 3.5 3.7 3.9 4.1 4.3 4.5 4.7Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate



### Figure 7.4. 8: Case CFB-2 - 1 x 650 MW CFB Steam Plant with SNCR Economic Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 209 

### Table 7.4. 8: Case CFB-2 - 1 x 650 MW CFB Steam Plant with SNCR Economic Sensitivity Results

Parameter Units Case CFB-2 - 1 x 650 MW CFB Steam Plant, SNCR Power Generation

Net Output kW 647,587 647,587 647,587 647,587 647,587 647,587 647,587 647,587 647,587 647,587 647,587 647,587 647,587 Availability Factor % 80 60 70 90 100 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 5,256 6,132 7,884 8,760 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 38.0 38.0 38.0 38.0 38.0 38.0 38.0 38.0 38.0 38.0 38.0 38.0 38.0 Net Plant Heat Rate, HHV Btu / kWh 8976 8976 8976 8976 8976 8976 8976 8976 8976 8976 8976 8976 8976 Net Generation MWh / year 4,538,290 4,538,290 4,538,290 4,538,290 4,538,290 4,538,290 4,538,290 4,538,290 4,538,290 4,538,290 4,538,290 4,538,290 4,538,290 Costs

EPC Price $ / kW 1,051 1,051 1,051 1,051 1,051 788 920 1,182 1,314 1,051 1,051 1,051 1,051 EPC Price $1000s 680,579 680,579 680,579 680,579 680,579 510,434 595,507 765,652 850,724 680,579 680,579 680,579 680,579 Fixed O&M Costs $1000 / year 9,532 9,532 9,532 9,532 9,532 9,532 9,532 9,532 9,532 9,532 9,532 9,532 9,532 Fixed O&M Costs $ / kW 14.72 14.72 14.72 14.72 14.72 14.72 14.72 14.72 14.72 14.72 14.72 14.72 14.72 Variable O&M Costs $1000 / year 12,724 9,543 11,133 14,314 15,905 12,724 12,724 12,724 12,724 12,724 12,724 12,724 12,724 Variable O&M Costs cents / kWh 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 Total O&M Costs cents / kWh 0.49 0.56 0.52 0.47 0.45 0.49 0.49 0.49 0.49 0.49 0.49 0.49 0.49 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 0.94 1.09 1.41 1.56 Financin g Assumptions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 10 10 10 10 10 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 2.01 2.68 2.30 1.79 1.61 1.51 1.76 2.26 2.51 2.01 2.01 2.01 2.01 Fixed O&M 0.21 0.28 0.24 0.19 0.17 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 Variable O&M 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 Fuel 1.12 1.12 1.12 1.12 1.12 1.12 1.12 1.12 1.12 0.84 0.98 1.26 1.40 Total 3.62 4.36 3.94 3.38 3.18 3.12 3.37 3.87 4.13 3.34 3.48 3.76 3.90

Paramete r Units Case CFB-2 - 1 x 650 MW CFB Steam Plant, SNCR Power Generation

Net Output kW 647,587 647,587 647,587 647,587 647,587 647,587 647,587 647,587 647,587 647,587 647,587 647,587 Availability Factor % 80 80 80 80 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 38.0 38.0 38.0 38.0 38.0 38.0 38.0 38.0 38.0 38.0 38.0 38.0 Net Plant Heat Rate, HHV Btu / kWh 8976 8976 8976 8976 8976 8976 8976 8976 8976 8976 8976 8976 Net Generation MWh / year 4,538,290 4,538,290 4,538,290 4,538,290 4,538,290 4,538,290 4,538,290 4,538,290 4,538,290 4,538,290 4,538,290 4,538,290 Costs

EPC Price $ / kW 1,051 1,051 1,051 1,051 1,051 1,051 1,051 1,051 1,051 1,051 1,051 1,051 EPC Price $1000s 680,579 680,579 680,579 680,579 680,579 680,579 680,579 680,579 680,579 680,579 680,579 680,579 Fixed O&M Costs $1000 / year 9,532 9,532 9,532 9,532 9,532 9,532 9,532 9,532 9,532 9,532 9,532 9,532 Fixed O&M Costs $ / kW 14.72 14.72 14.72 14.72 14.72 14.72 14.72 14.72 14.72 14.72 14.72 14.72 Variable O&M Costs $1000 / year 12,724 12,724 12,724 12,724 12,724 12,724 12,724 12,724 12,724 12,724 12,724 12,724 Variable O&M Costs cents / kWh 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 Total O&M Costs cents / kWh 0.49 0.49 0.49 0.49 0.49 0.49 0.49 0.49 0.49 0.49 0.49 0.49 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 Financin g Assumptions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 8 9 11 13 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.87 1.94 2.08 2.14 1.95 1.98 2.04 2.08 1.68 1.84 2.18 2.37 Fixed O&M 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 Variable O&M 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 0.28 Fuel 1.12 1.12 1.12 1.12 1.12 1.12 1.12 1.12 1.12 1.12 1.12 1.12 Total 3.49 3.56 3.69 3.75 3.56 3.59 3.66 3.69 3.30 3.46 3.80 3.98ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 210 

### 7.4.9 Case CFB-3 - 1 x 660 MW CFB Steam Plant with SNCR Economic Sensitivity Results

Results for the Case CFB-3 COE sensitivity st udy are shown in Figure 7.4.9 and summarized in Table 7.4.9. The levelized COE for the base pa rameter values is 3.6 cents per kWh. Levelized COE ranges from a low of 3.1 to a high of 4.3 cents per kWh.

-20% -15% -10%

-5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

2.8 3.0 3.2 3.4 3.6 3.8 4.0 4.2 4.4Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate


### Figure 7.4. 9: Case CFB-3 - 1 x 660 MW CFB Steam Plant with SNCR Economic Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 211 

### Table 7.4. 9: Case CFB-3 - 1 x 660 MW CFB Steam Plant with SNCR Economic Sensitivity Results

Parameter Units Case CFB-3 - 1 x 660 MW CFB Steam Plant, SNCR Power Generation

Net Output kW 663,823 663,823 663,823 663,823 663,823 663,823 663,823 663,823 663,823 663,823 663,823 663,823 663,823 Availability Factor % 80 60 70 90 100 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 5,256 6,132 7,884 8,760 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 39.0 39.0 39.0 39.0 39.0 39.0 39.0 39.0 39.0 39.0 39.0 39.0 39.0 Net Plant Heat Rate, HHV Btu / kWh 8756 8756 8756 8756 8756 8756 8756 8756 8756 8756 8756 8756 8756 Net Generation MWh / year 4,652,072 4,652,072 4,652,072 4,652,072 4,652,072 4,652,072 4,652,072 4,652,072 4,652,072 4,652,072 4,652,072 4,652,072 4,652,072 Costs

EPC Price $ / kW 1,038 1,038 1,038 1,038 1,038 778 908 1,167 1,297 1,038 1,038 1,038 1,038 EPC Price $1000s 688,776 688,776 688,776 688,776 688,776 516,582 602,679 774,873 860,970 688,776 688,776 688,776 688,776 Fixed O&M Costs $1000 / year 9,572 9,572 9,572 9,572 9,572 9,572 9,572 9,572 9,572 9,572 9,572 9,572 9,572 Fixed O&M Costs $ / kW 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 Variable O&M Costs $1000 / year 12,763 9,572 11,168 14,359 15,954 12,763 12,763 12,763 12,763 12,763 12,763 12,763 12,763 Variable O&M Costs cents / kWh 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 Total O&M Costs cents / kWh 0.48 0.55 0.51 0.46 0.44 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 0.94 1.09 1.41 1.56 Financin g Assumptions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 10 10 10 10 10 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.98 2.65 2.27 1.76 1.59 1.49 1.74 2.23 2.48 1.98 1.98 1.98 1.98 Fixed O&M 0.21 0.27 0.24 0.18 0.16 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 Variable O&M 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 Fuel 1.09 1.09 1.09 1.09 1.09 1.09 1.09 1.09 1.09 0.82 0.96 1.23 1.37 Total 3.56 4.29 3.87 3.32 3.12 3.06 3.31 3.81 4.06 3.29 3.42 3.70 3.83

Parameter Units Case CFB-3 - 1 x 660 MW CFB Steam Plant, SNCR Power Generation

Net Output kW 663,823 663,823 663,823 663,823 663,823 663,823 663,823 663,823 663,823 663,823 663,823 663,823 Availability Factor % 80 80 80 80 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 39.0 39.0 39.0 39.0 39.0 39.0 39.0 39.0 39.0 39.0 39.0 39.0 Net Plant Heat Rate, HHV Btu / kWh 8756 8756 8756 8756 8756 8756 8756 8756 8756 8756 8756 8756 Net Generation MWh / year 4,652,072 4,652,072 4,652,072 4,652,072 4,652,072 4,652,072 4,652,072 4,652,072 4,652,072 4,652,072 4,652,072 4,652,072 Costs

EPC Price $ / kW 1,038 1,038 1,038 1,038 1,038 1,038 1,038 1,038 1,038 1,038 1,038 1,038 EPC Price $1000s 688,776 688,776 688,776 688,776 688,776 688,776 688,776 688,776 688,776 688,776 688,776 688,776 Fixed O&M Costs $1000 / year 9,572 9,572 9,572 9,572 9,572 9,572 9,572 9,572 9,572 9,572 9,572 9,572 Fixed O&M Costs $ / kW 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 Variable O&M Costs $1000 / year 12,763 12,763 12,763 12,763 12,763 12,763 12,763 12,763 12,763 12,763 12,763 12,763 Variable O&M Costs cents / kWh 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 Total O&M Costs cents / kWh 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 Financin g Assumptions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 8 9 11 13 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.85 1.92 2.05 2.11 1.92 1.95 2.02 2.05 1.66 1.82 2.16 2.34 Fixed O&M 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 Variable O&M 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 Fuel 1.09 1.09 1.09 1.09 1.09 1.09 1.09 1.09 1.09 1.09 1.09 1.09 Total 3.43 3.49 3.62 3.69 3.50 3.53 3.59 3.63 3.24 3.39 3.73 3.91ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 212 

### 7.4.10 Case CFB-4 - 1 x 680 MW CFB Steam Plant with SNCR Economic Sensitivity Results

Results for the Case CFB-4 COE sensitivity study are shown in Figure 7.4.10 and summarized in Table 7.4.10. The levelized COE for the base par ameter values is 3.5 cents per kWh. Levelized COE ranges from a low of 3.0 to a high of 4.3 cents per kWh.

-20% -15% -10%

-5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

2.8 3.0 3.2 3.4 3.6 3.8 4.0 4.2 4.4Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate



### Figure 7.4.10: Case CFB-4 - 1 x 680 MW CFB Steam Plant with SNCR Economic Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 213 

### Table 7.4.10: Case CFB-4 - 1 x 680 MW CFB Steam Plant with SNCR Economic Sensitivity Results

Parameter Units Case CFB-4 - 1 x 680 MW CFB Steam Plant, SNCR Power Generation

Net Output kW 678,366 678,366 678,366 678,366 678,366 678,366 678,366 678,366 678,366 678,366 678,366 678,366 678,366 Availability Factor % 80 60 70 90 100 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 5,256 6,132 7,884 8,760 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 Net Plant Heat Rate, HHV Btu / kWh 8568 8568 8568 8568 8568 8568 8568 8568 8568 8568 8568 8568 8568 Net Generation MWh / year 4,753,989 4,753,989 4,753,989 4,753,989 4,753,989 4,753,989 4,753,989 4,753,989 4,753,989 4,753,989 4,753,989 4,753,989 4,753,989 Costs

EPC Price $ / kW 1,039 1,039 1,039 1,039 1,039 780 910 1,169 1,299 1,039 1,039 1,039 1,039 EPC Price $1000s 705,135 705,135 705,135 705,135 705,135 528,851 616,993 793,277 881,419 705,135 705,135 705,135 705,135 Fixed O&M Costs $1000 / year 9,654 9,654 9,654 9,654 9,654 9,654 9,654 9,654 9,654 9,654 9,654 9,654 9,654 Fixed O&M Costs $ / kW 14.23 14.23 14.23 14.23 14.23 14.23 14.23 14.23 14.23 14.23 14.23 14.23 14.23 Variable O&M Costs $1000 / year 12,842 9,631 11,237 14,447 16,052 12,842 12,842 12,842 12,842 12,842 12,842 12,842 12,842 Variable O&M Costs cents / kWh 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 Total O&M Costs cents / kWh 0.47 0.54 0.50 0.45 0.43 0.47 0.47 0.47 0.47 0.47 0.47 0.47 0.47 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 0.94 1.09 1.41 1.56 Financin g Assumptions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 10 10 10 10 10 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.99 2.65 2.27 1.77 1.59 1.49 1.74 2.24 2.49 1.99 1.99 1.99 1.99 Fixed O&M 0.20 0.27 0.23 0.18 0.16 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 Variable O&M 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 Fuel 1.07 1.07 1.07 1.07 1.07 1.07 1.07 1.07 1.07 0.80 0.94 1.20 1.34 Total 3.53 4.26 3.85 3.29 3.09 3.04 3.28 3.78 4.03 3.26 3.40 3.67 3.80

Parameter Units Case CFB-4 - 1 x 680 MW CFB Steam Plant, SNCR Power Generation

Net Output kW 678,366 678,366 678,366 678,366 678,366 678,366 678,366 678,366 678,366 678,366 678,366 678,366 Availability Factor % 80 80 80 80 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 39.8 Net Plant Heat Rate, HHV Btu / kWh 8568 8568 8568 8568 8568 8568 8568 8568 8568 8568 8568 8568 Net Generation MWh / year 4,753,989 4,753,989 4,753,989 4,753,989 4,753,989 4,753,989 4,753,989 4,753,989 4,753,989 4,753,989 4,753,989 4,753,989 Costs

EPC Price $ / kW 1,039 1,039 1,039 1,039 1,039 1,039 1,039 1,039 1,039 1,039 1,039 1,039 EPC Price $1000s 705,135 705,135 705,135 705,135 705,135 705,135 705,135 705,135 705,135 705,135 705,135 705,135 Fixed O&M Costs $1000 / year 9,654 9,654 9,654 9,654 9,654 9,654 9,654 9,654 9,654 9,654 9,654 9,654 Fixed O&M Costs $ / kW 14.23 14.23 14.23 14.23 14.23 14.23 14.23 14.23 14.23 14.23 14.23 14.23 Variable O&M Costs $1000 / year 12,842 12,842 12,842 12,842 12,842 12,842 12,842 12,842 12,842 12,842 12,842 12,842 Variable O&M Costs cents / kWh 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 Total O&M Costs cents / kWh 0.47 0.47 0.47 0.47 0.47 0.47 0.47 0.47 0.47 0.47 0.47 0.47 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 Financin g Assumptions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 8 9 11 13 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.85 1.92 2.05 2.12 1.93 1.96 2.02 2.06 1.67 1.82 2.16 2.34 Fixed O&M 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 Variable O&M 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 Fuel 1.07 1.07 1.07 1.07 1.07 1.07 1.07 1.07 1.07 1.07 1.07 1.07 Total 3.40 3.47 3.60 3.66 3.47 3.50 3.57 3.60 3.21 3.37 3.70 3.88ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 214 

### 7.4.11 Case CMB-3 - 1 x 670 MW CMB Steam Plant with SNCR Economic Sensitivity Results

Results for the Case CMB TM 

### -3 COE sensitivity study are show n in Figure 7.4.11 and summarized in Table 7.4.11. The levelized COE for the base parameter values is 3.5 cents per kWh. Levelized COE ranges from a low of 3.0 to a high of 4.2 cents per kWh.

-20% -15% -10%

-5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

2.8 3.0 3.2 3.4 3.6 3.8 4.0 4.2 4.4Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate



### Figure 7.4.11: Case CMB-3 - 1 x 670 MW CMB Steam Plant with SNCR Economic Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 215 

### Table 7.4.11: Case CMB-3 - 1 x 670 MW CMB Steam Plant with SNCR Economic Sensitivity Results

Parameter Units Case CMB-3 - 1 x 670 MW CMB Steam Plant, SNCR Power Generation

Net Output kW 665,552 665,552 665,552 665,552 665,552 665,552 665,552 665,552 665,552 665,552 665,552 665,552 665,552 Availability Factor % 80 60 70 90 100 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 5,256 6,132 7,884 8,760 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 Net Plant Heat Rate, HHV Btu / kWh 8781 8781 8781 8781 8781 8781 8781 8781 8781 8781 8781 8781 8781 Net Generation MWh / year 4,664,188 4,664,188 4,664,188 4,664,188 4,664,188 4,664,188 4,664,188 4,664,188 4,664,188 4,664,188 4,664,188 4,664,188 4,664,188 Costs

EPC Price $ / kW 1,018 1,018 1,018 1,018 1,018 764 891 1,145 1,273 1,018 1,018 1,018 1,018 EPC Price $1000s 677,549 677,549 677,549 677,549 677,549 508,162 592,856 762,243 846,936 677,549 677,549 677,549 677,549 Fixed O&M Costs $1000 / year 9,516 9,516 9,516 9,516 9,516 9,516 9,516 9,516 9,516 9,516 9,516 9,516 9,516 Fixed O&M Costs $ / kW 14.30 14.30 14.30 14.30 14.30 14.30 14.30 14.30 14.30 14.30 14.30 14.30 14.30 Variable O&M Costs $1000 / year 12,724 9,543 11,134 14,315 15,906 12,724 12,724 12,724 12,724 12,724 12,724 12,724 12,724 Variable O&M Costs cents / kWh 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 Total O&M Costs cents / kWh 0.48 0.54 0.51 0.45 0.44 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 0.94 1.09 1.41 1.56 Financin g Assumptions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 10 10 10 10 10 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.95 2.60 2.23 1.73 1.56 1.46 1.70 2.19 2.43 1.95 1.95 1.95 1.95 Fixed O&M 0.20 0.27 0.23 0.18 0.16 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 Variable O&M 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 Fuel 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 0.82 0.96 1.23 1.37 Total 3.52 4.24 3.83 3.28 3.09 3.03 3.28 3.77 4.01 3.25 3.38 3.66 3.80

Paramete r Units Case CMB-3 - 1 x 670 MW CMB Steam Plant, SNCR Power Generation

Net Output kW 665,552 665,552 665,552 665,552 665,552 665,552 665,552 665,552 665,552 665,552 665,552 665,552 Availability Factor % 80 80 80 80 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 38.9 Net Plant Heat Rate, HHV Btu / kWh 8781 8781 8781 8781 8781 8781 8781 8781 8781 8781 8781 8781 Net Generation MWh / year 4,664,188 4,664,188 4,664,188 4,664,188 4,664,188 4,664,188 4,664,188 4,664,188 4,664,188 4,664,188 4,664,188 4,664,188 Costs

EPC Price $ / kW 1,018 1,018 1,018 1,018 1,018 1,018 1,018 1,018 1,018 1,018 1,018 1,018 EPC Price $1000s 677,549 677,549 677,549 677,549 677,549 677,549 677,549 677,549 677,549 677,549 677,549 677,549 Fixed O&M Costs $1000 / year 9,516 9,516 9,516 9,516 9,516 9,516 9,516 9,516 9,516 9,516 9,516 9,516 Fixed O&M Costs $ / kW 14.30 14.30 14.30 14.30 14.30 14.30 14.30 14.30 14.30 14.30 14.30 14.30 Variable O&M Costs $1000 / year 12,724 12,724 12,724 12,724 12,724 12,724 12,724 12,724 12,724 12,724 12,724 12,724 Variable O&M Costs cents / kWh 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 Total O&M Costs cents / kWh 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 Financin g Assumptions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 8 9 11 13 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.82 1.88 2.01 2.07 1.89 1.92 1.98 2.01 1.63 1.79 2.12 2.29 Fixed O&M 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 Variable O&M 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 Fuel 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 Total 3.39 3.46 3.59 3.65 3.46 3.49 3.55 3.59 3.21 3.36 3.69 3.87ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 216 

### 7.4.12 Case CMB-5 20 Alloy - 1 x 750 MW CM B Steam Plant with SNCR and $20 per Pound High Temperature Alloy Economic Sensitivity Results

Results for the Case CMB TM 

### -5 COE sensitivity study are sh own in Figure 7.4.12 and summarized in Table 7.4.12. The levelized COE for the base parameter values is 3.4 cents per kWh. Levelized COE ranges from a low of 2.9 to a high of 4.1 cents per kWh.

-20% -15% -10%

-5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

2.7 2.9 3.1 3.3 3.5 3.7 3.9 4.1 4.3Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate



### Figure 7.4.12: Case CMB-5 20 Alloy - 1 x 670 MW CMB Steam Plant with SNCR and $20 per Pound High Temperature Alloy Economic Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 217 

### Table 7.4.12: Case CMB-5 20 Alloy - 1 x 670 MW CMB Steam Plant with SNCR and $20 per Pound High Temperature Alloy Economic Sensitivity Results

Parameter Units Case CMB-5 - 1 x 750 MW CMB Steam Plant; $20/lb Nickel Power Generation

Net Output kW 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 Availability Factor % 80 60 70 90 100 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 5,256 6,132 7,884 8,760 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 Net Plant Heat Rate, HHV Btu / kWh 7853 7853 7853 7853 7853 7853 7853 7853 7853 7853 7853 7853 7853 Net Generation MWh / year 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 Costs

EPC Price $ / kW 1,031 1,031 1,031 1,031 1,031 773 902 1,160 1,289 1,031 1,031 1,031 1,031 EPC Price $1000s 767,329 767,329 767,329 767,329 767,329 575,497 671,413 863,245 959,161 767,329 767,329 767,329 767,329 Fixed O&M Costs $1000 / year 9,965 9,965 9,965 9,965 9,965 9,965 9,965 9,965 9,965 9,965 9,965 9,965 9,965 Fixed O&M Costs $ / kW 13.39 13.39 13.39 13.39 13.39 13.39 13.39 13.39 13.39 13.39 13.39 13.39 13.39 Variable O&M Costs $1000 / year 13,155 9,867 11,511 14,800 16,444 13,155 13,155 13,155 13,155 13,155 13,155 13,155 13,155 Variable O&M Costs cents / kWh 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 Total O&M Costs cents / kWh 0.44 0.51 0.47 0.42 0.41 0.44 0.44 0.44 0.44 0.44 0.44 0.44 0.44 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 0.94 1.09 1.41 1.56 Financin g Assumptions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 10 10 10 10 10 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.97 2.63 2.25 1.75 1.58 1.48 1.73 2.22 2.47 1.97 1.97 1.97 1.97 Fixed O&M 0.19 0.25 0.22 0.17 0.15 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 Variable O&M 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 Fuel 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.74 0.86 1.10 1.23 Total 3.40 4.12 3.71 3.16 2.96 2.90 3.15 3.64 3.89 3.15 3.27 3.52 3.64

Parameter Units Case CMB-5 - 1 x 750 MW CMB Steam Plant; $20/lb Nickel Power Generation

Net Output kW 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 Availability Factor % 80 80 80 80 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 Net Plant Heat Rate, HHV Btu / kWh 7853 7853 7853 7853 7853 7853 7853 7853 7853 7853 7853 7853 Net Generation MWh / year 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 Costs

EPC Price $ / kW 1,031 1,031 1,031 1,031 1,031 1,031 1,031 1,031 1,031 1,031 1,031 1,031 EPC Price $1000s 767,329 767,329 767,329 767,329 767,329 767,329 767,329 767,329 767,329 767,329 767,329 767,329 Fixed O&M Costs $1000 / year 9,965 9,965 9,965 9,965 9,965 9,965 9,965 9,965 9,965 9,965 9,965 9,965 Fixed O&M Costs $ / kW 13.39 13.39 13.39 13.39 13.39 13.39 13.39 13.39 13.39 13.39 13.39 13.39 Variable O&M Costs $1000 / year 13,155 13,155 13,155 13,155 13,155 13,155 13,155 13,155 13,155 13,155 13,155 13,155 Variable O&M Costs cents / kWh 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 Total O&M Costs cents / kWh 0.44 0.44 0.44 0.44 0.44 0.44 0.44 0.44 0.44 0.44 0.44 0.44 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 Financin g Assumptions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 8 9 11 13 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.84 1.91 2.04 2.10 1.91 1.94 2.01 2.04 1.65 1.81 2.14 2.32 Fixed O&M 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 Variable O&M 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 Fuel 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 Total 3.26 3.33 3.46 3.53 3.34 3.37 3.43 3.47 3.08 3.23 3.57 3.75ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 218 

### 7.4.13 Case CMB-5 28 Alloy - 1 x 750 MW CM B Steam Plant with SNCR and $28 per Pound High Temperature Alloy Economic Sensitivity Results

Results for the Case CMB TM 

### -5 COE sensitivity study are show n in Figure 7.4.13 and summarized in Table 7.4.13. The levelized COE for the base parameter values is 3.4 cents per kWh. Levelized COE ranges from a low of 2.9 to a high of 4.1 cents per kWh.

-20% -15% -10%

-5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

2.7 2.9 3.1 3.3 3.5 3.7 3.9 4.1 4.3Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate



### Figure 7.4.13: Case CMB-5 28 Alloy - 1 x 750 MW CMB Steam Plant with SNCR and $28 per Pound High Temperature Alloy Economic Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 219 

### Table 7.4.13: Case CMB-5 28 Alloy - 1 x 750 MW CMB Steam Plant with SNCR and $28 per Pound High Temperature Alloy Economic Sensitivity Results

Parameter Units Case CMB-5 - 1 x 750 MW CMB Steam Plant; $28/lb Nickel Power Generation

Net Output kW 745,555 745,555 745,555 745,555 745,555 745,555 745,555 745,555 745,555 745,555 745,555 745,555 745,555 Availability Factor % 80 60 70 90 100 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 5,256 6,132 7,884 8,760 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 Net Plant Heat Rate, HHV Btu / kWh 7839 7839 7839 7839 7839 7839 7839 7839 7839 7839 7839 7839 7839 Net Generation MWh / year 5,224,849 5,224,849 5,224,849 5,224,849 5,224,849 5,224,849 5,224,849 5,224,849 5,224,849 5,224,849 5,224,849 5,224,849 5,224,849 Costs

EPC Price $ / kW 1,029 1,029 1,029 1,029 1,029 772 900 1,158 1,286 1,029 1,029 1,029 1,029 EPC Price $1000s 767,144 767,144 767,144 767,144 767,144 575,358 671,251 863,037 958,930 767,144 767,144 767,144 767,144 Fixed O&M Costs $1000 / year 9,994 9,994 9,994 9,994 9,994 9,994 9,994 9,994 9,994 9,994 9,994 9,994 9,994 Fixed O&M Costs $ / kW 13.40 13.40 13.40 13.40 13.40 13.40 13.40 13.40 13.40 13.40 13.40 13.40 13.40 Variable O&M Costs $1000 / year 13,097 9,823 11,460 14,734 16,371 13,097 13,097 13,097 13,097 13,097 13,097 13,097 13,097 Variable O&M Costs cents / kWh 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 Total O&M Costs cents / kWh 0.44 0.51 0.47 0.42 0.40 0.44 0.44 0.44 0.44 0.44 0.44 0.44 0.44 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 0.94 1.09 1.41 1.56 Financin g Assumptions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 10 10 10 10 10 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.97 2.62 2.25 1.75 1.57 1.48 1.72 2.21 2.46 1.97 1.97 1.97 1.97 Fixed O&M 0.19 0.25 0.22 0.17 0.15 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 Variable O&M 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 Fuel 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.73 0.86 1.10 1.22 Total 3.39 4.11 3.70 3.15 2.96 2.90 3.14 3.64 3.88 3.14 3.27 3.51 3.63

Parameter Units Case CMB-5 - 1 x 750 MW CMB Steam Plant; $28/lb Nickel Power Generation

Net Output kW 745,555 745,555 745,555 745,555 745,555 745,555 745,555 745,555 745,555 745,555 745,555 745,555 Availability Factor % 80 80 80 80 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 Net Plant Heat Rate, HHV Btu / kWh 7839 7839 7839 7839 7839 7839 7839 7839 7839 7839 7839 7839 Net Generation MWh / year 5,224,849 5,224,849 5,224,849 5,224,849 5,224,849 5,224,849 5,224,849 5,224,849 5,224,849 5,224,849 5,224,849 5,224,849 Costs

EPC Price $ / kW 1,029 1,029 1,029 1,029 1,029 1,029 1,029 1,029 1,029 1,029 1,029 1,029 EPC Price $1000s 767,144 767,144 767,144 767,144 767,144 767,144 767,144 767,144 767,144 767,144 767,144 767,144 Fixed O&M Costs $1000 / year 9,994 9,994 9,994 9,994 9,994 9,994 9,994 9,994 9,994 9,994 9,994 9,994 Fixed O&M Costs $ / kW 13.40 13.40 13.40 13.40 13.40 13.40 13.40 13.40 13.40 13.40 13.40 13.40 Variable O&M Costs $1000 / year 13,097 13,097 13,097 13,097 13,097 13,097 13,097 13,097 13,097 13,097 13,097 13,097 Variable O&M Costs cents / kWh 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 Total O&M Costs cents / kWh 0.44 0.44 0.44 0.44 0.44 0.44 0.44 0.44 0.44 0.44 0.44 0.44 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 Financin g Assumptions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 8 9 11 13 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.84 1.90 2.03 2.10 1.91 1.94 2.00 2.04 1.65 1.80 2.14 2.32 Fixed O&M 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 Variable O&M 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 Fuel 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 Total 3.26 3.32 3.45 3.52 3.33 3.36 3.42 3.46 3.07 3.23 3.56 3.74ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### 7.4.14 Case CMB-5 32.9 Alloy - 1 x 750 MW CMB Steam Plant with SNCR and $32.90 per Pound High Temperature Alloy Economic Sensitivity Results

Results for the Case CMB TM 

### -5 COE sensitivity study are show n in Figure 7.4.14 and summarized in Table 7.4.14. The levelized COE for the base parameter values is 3.4 cents per kWh. Levelized COE ranges from a low of 2.9 to a high of 4.2 cents per kWh.

-20% -15% -10%

-5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

2.7 2.9 3.1 3.3 3.5 3.7 3.9 4.1 4.3Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate



### Figure 7.4.14: Case CMB-5 32.9 Alloy - 1 x 750 MW CMB Steam Plant with SNCR and $32.90 per Pound High Temperature Alloy Economic Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 221 

### Table 7.4.14: Case CMB-5 32.9 Alloy - 1 x 750 MW CMB Steam Plant with SNCR and $32.90 per Pound High Temperature Alloy Economic Sensitivity Results

Parameter Units Case CMB-5 - 1 x 750 MW CMB Steam Plant, 32.9 Nickel Power Generation

Net Output kW 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 Availability Factor % 80 60 70 90 100 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 5,256 6,132 7,884 8,760 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 Net Plant Heat Rate, HHV Btu / kWh 7853 7853 7853 7853 7853 7853 7853 7853 7853 7853 7853 7853 7853 Net Generation MWh / year 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 Costs

EPC Price $ / kW 1,043 1,043 1,043 1,043 1,043 783 913 1,174 1,304 1,043 1,043 1,043 1,043 EPC Price $1000s 776,526 776,526 776,526 776,526 776,526 582,395 679,460 873,592 970,658 776,526 776,526 776,526 776,526 Fixed O&M Costs $1000 / year 10,011 10,011 10,011 10,011 10,011 10,011 10,011 10,011 10,011 10,011 10,011 10,011 10,011 Fixed O&M Costs $ / kW 13.45 13.45 13.45 13.45 13.45 13.45 13.45 13.45 13.45 13.45 13.45 13.45 13.45 Variable O&M Costs $1000 / year 13,199 9,900 11,550 14,849 16,499 13,199 13,199 13,199 13,199 13,199 13,199 13,199 13,199 Variable O&M Costs cents / kWh 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 Total O&M Costs cents / kWh 0.45 0.51 0.47 0.42 0.41 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 0.94 1.09 1.41 1.56 Financin g Assumptions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 10 10 10 10 10 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 2.00 2.66 2.28 1.77 1.60 1.50 1.75 2.25 2.49 2.00 2.00 2.00 2.00 Fixed O&M 0.19 0.26 0.22 0.17 0.15 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 Variable O&M 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 Fuel 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.74 0.86 1.10 1.23 Total 3.42 4.15 3.73 3.18 2.98 2.92 3.17 3.67 3.92 3.18 3.30 3.54 3.67

Paramete r Units Case CMB-5 - 1 x 750 MW CMB Steam Plant, 32.9 Nickel Power Generation

Net Output kW 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 744,230 Availability Factor % 80 80 80 80 80 80 80 80 80 80 80 80 Actual Operating Hours hours / year 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 7,008 Net Efficiency, HHV % 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 43.5 Net Plant Heat Rate, HHV Btu / kWh 7853 7853 7853 7853 7853 7853 7853 7853 7853 7853 7853 7853 Net Generation MWh / year 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 5,215,564 Costs

EPC Price $ / kW 1,043 1,043 1,043 1,043 1,043 1,043 1,043 1,043 1,043 1,043 1,043 1,043 EPC Price $1000s 776,526 776,526 776,526 776,526 776,526 776,526 776,526 776,526 776,526 776,526 776,526 776,526 Fixed O&M Costs $1000 / year 10,011 10,011 10,011 10,011 10,011 10,011 10,011 10,011 10,011 10,011 10,011 10,011 Fixed O&M Costs $ / kW 13.45 13.45 13.45 13.45 13.45 13.45 13.45 13.45 13.45 13.45 13.45 13.45 Variable O&M Costs $1000 / year 13,199 13,199 13,199 13,199 13,199 13,199 13,199 13,199 13,199 13,199 13,199 13,199 Variable O&M Costs cents / kWh 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 Total O&M Costs cents / kWh 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 Fuel Cost Calculation

Coal Price $ / MMBtu 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 Financin g Assumptions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 10 10 10 10 10 10 10 10 8 9 11 13 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.86 1.93 2.06 2.13 1.93 1.96 2.03 2.06 1.67 1.83 2.17 2.35 Fixed O&M 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 Variable O&M 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 Fuel 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 Total 3.29 3.36 3.49 3.55 3.36 3.39 3.46 3.49 3.10 3.26 3.60 3.78ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### 7.4.15 Case Base Phillip Sporn Unit 4 – Base Phillip Sporn Unit 4 Economic Sensitivity Results

Results for the Base Case Phillip Sporn Unit 4 COE sensitiv ity study are shown in Figure 7.4.15 and summarized in Table 7.4.15. The levelized COE for the base parameter values is 1.9 cents per kWh. Levelized COE ranges from a low of 1.6 to a high of 2.0 cents per kWh.

-20% -15% -10% -5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

1.5 1.6 1.7 1.8 1.9 2.0 2.1 2.2 2.3 2.4Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate


### Figure 7.4.15: Case Base Phillip Sporn Un it 4 – Base Phillip Sporn Unit 4 Economic Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 223 

### Table 7.4.15: Case Base Phillip Sporn Un it 4 – Base Phillip Sporn Unit 4 Economic Sensitivity Results

Parameter Units Sporn Unit #4 - Base Power Generation

Net Output kW 156,518 156,518 156,518 156,518 156,518 156,518 156,518 156,518 156,518 156,518 156,518 156,518 Availability Factor % 85 64 74 96 85 85 85 85 85 85 85 85 Actual Operating Hours hours / year 744,600 558,450 651,525 837,675 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 Net Efficiency, HHV % 35.7 35.7 35.7 35.7 35.7 35.7 35.7 35.7 35.7 35.7 35.7 35.7 Net Plant Heat Rate, HHV Btu / kWh 9561 9561 9561 9561 9561 9561 9561 9561 9561 9561 9561 9561 Net Generation MWh / year 1,165,433 874,075 1,019,754 1,311,112 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 Costs

EPC Price $ / kW 0 0 0 0 0 0 0 0 0 0 0 0 EPC Price $1000s 0 000000 00000 Fixed O&M Costs $1000 / year 5,544 5,544 5,544 5,544 5,544 5,544 5,544 5,544 5,544 5,544 5,544 5,544 Fixed O&M Costs $ / kW 35.42 35.42 35.42 35.42 35.42 35.42 35.42 35.42 35.42 35.42 35.42 35.42 Variable O&M Costs $1000 / year 2,138 1,603 1,870 2,405 2,138 2,138 2,138 2,138 2,138 2,138 2,138 2,138 Variable O&M Costs cents / kWh 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 Total O&M Costs cents / kWh 0.66 0.82 0.73 0.61 0.66 0.66 0.66 0.66 0.66 0.66 0.66 0.66 Fuel Cost Calculation

Coal Price $ / MMBtu 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 0.95 1.11 1.43 1.59 Financing Assumptions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 15 15 15 15 15 15 15 15 15 15 15 15 Levelized Cost of Electricity (cents / kWh)

Financial Component 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Fixed O&M 0.48 0.63 0.54 0.42 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 Variable O&M 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 Fuel 1.21 1.21 1.21 1.21 1.21 1.21 1.21 1.21 0.91 1.06 1.37 1.52 Total 1.87 2.03 1.94 1.82 1.87 1.87 1.87 1.87 1.57 1.72 2.03 2.18

Paramete r Units Sporn Unit #4 - Base Power Generation

Net Output kW 156,518 156,518 156,518 156,518 156,518 156,518 156,518 156,518 156,518 156,518 156,518 156,518 Availability Factor % 85 85 85 85 85 85 85 85 85 85 85 85 Actual Operating Hours hours / year 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 Net Efficiency, HHV % 35.7 35.7 35.7 35.7 35.7 35.7 35.7 35.7 35.7 35.7 35.7 35.7 Net Plant Heat Rate, HHV Btu / kWh 9561 9561 9561 9561 9561 9561 9561 9561 9561 9561 9561 9561 Net Generation MWh / year 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 Costs

EPC Price $ / kW 0 0 0 0 0 0 0 0 0 0 0 0 EPC Price $1000s 0 0 0 0 0 0 0 0 0 0 0 0 Fixed O&M Costs $1000 / year 5,544 5,544 5,544 5,544 5,544 5,544 5,544 5,544 5,544 5,544 5,544 5,544 Fixed O&M Costs $ / kW 35.42 35.42 35.42 35.42 35.42 35.42 35.42 35.42 35.42 35.42 35.42 35.42 Variable O&M Costs $1000 / year 2,138 2,138 2,138 2,138 2,138 2,138 2,138 2,138 2,138 2,138 2,138 2,138 Variable O&M Costs cents / kWh 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 Total O&M Costs cents / kWh 0.66 0.66 0.66 0.66 0.66 0.66 0.66 0.66 0.66 0.66 0.66 0.66 Fuel Cost Calculation

Coal Price $ / MMBtu 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 Financin g Assumptions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 15 15 15 15 15 15 15 15 11 13 17 19 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Fixed O&M 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 Variable O&M 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 Fuel 1.21 1.21 1.21 1.21 1.21 1.21 1.21 1.21 1.21 1.21 1.21 1.21 Total 1.87 1.87 1.87 1.87 1.87 1.87 1.87 1.87 1.87 1.87 1.87 1.87ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

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### 7.4.16 Case Base Phillip Sporn Unit 4 Purchase NO x 

### Credits – Base Phillip Sporn Unit 4 with Purchase of $5k per Ton NO x 

### Credits Economic Sensitivity Results

Results for the Base Case Phillip Sporn plant with NO x 

### credits purchased at $5k per ton COE sensitivity study are shown in Fi gure 7.4.16 and summarized in Table 7.4.16. The levelized COE for the base parameter values is 2.3 cents per kWh. Levelized COE ranges from a low of 2.0 to a high of 2.5 cents per kWh.

-20% -15% -10% -5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

1.8 2.0 2.2 2.4 2.6 2.8Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate



### Figure 7.4.16: Case Base Phillip Sporn Unit 4 Purchase NO x 

### Credits – Base Phillip Sporn Unit 4 with Purchase of $5k per Ton NO x 

### Credits Economic Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 225 

### Table 7.4.16: Case Base Phillip Sporn Unit 4 Purchase NO x 

### Credits – Base Phillip Sporn Unit 4 with Purchase of $5k per Ton NO x 

### Credits Economic Sensitivity Results

Parameter Units Sporn Unit #4 - Base, Purchase NOx Credits Power Generation

Net Output kW 156,518 156,518 156,518 156,518 156,518 156,518 156,518 156,518 156,518 156,518 156,518 156,518 Availability Factor % 85 64 74 96 85 85 85 85 85 85 85 85 Actual Operating Hours hours / year 744,600 558,450 651,525 837,675 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 Net Efficiency, HHV % 35.7 35.7 35.7 35.7 35.7 35.7 35.7 35.7 35.7 35.7 35.7 35.7 Net Plant Heat Rate, HHV Btu / kWh 9561 9561 9561 9561 9561 9561 9561 9561 9561 9561 9561 9561 Net Generation MWh / year 1,165,433 874,075 1,019,754 1,311,112 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 Costs

EPC Price $ / kW 0 0 0 0 0 0 0 0 0 0 0 0 EPC Price $1000s 0 000000 00000 Fixed O&M Costs $1000 / year 5,544 5,544 5,544 5,544 5,544 5,544 5,544 5,544 5,544 5,544 5,544 5,544 Fixed O&M Costs $ / kW 35.42 35.42 35.42 35.42 35.42 35.42 35.42 35.42 35.42 35.42 35.42 35.42 Variable O&M Costs $1000 / year 7,011 5,259 6,135 7,888 7,011 7,011 7,011 7,011 7,011 7,011 7,011 7,011 Variable O&M Costs cents / kWh 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 Total O&M Costs cents / kWh 1.08 1.24 1.15 1.02 1.08 1.08 1.08 1.08 1.08 1.08 1.08 1.08 Fuel Cost Calculation

Coal Price $ / MMBtu 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 0.95 1.11 1.43 1.59 Financing Assumptions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 15 15 15 15 15 15 15 15 15 15 15 15 Levelized Cost of Electricity (cents / kWh)

Financial Component 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Fixed O&M 0.48 0.63 0.54 0.42 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 Variable O&M 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 Fuel 1.21 1.21 1.21 1.21 1.21 1.21 1.21 1.21 0.91 1.06 1.37 1.52 Total 2.29 2.45 2.36 2.24 2.29 2.29 2.29 2.29 1.99 2.14 2.44 2.60

Paramete r Units Sporn Unit #4 - Base, Purchase NOx Credits Power Generation

Net Output kW 156,518 156,518 156,518 156,518 156,518 156,518 156,518 156,518 156,518 156,518 156,518 156,518 Availability Factor % 85 85 85 85 85 85 85 85 85 85 85 85 Actual Operating Hours hours / year 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 Net Efficiency, HHV % 35.7 35.7 35.7 35.7 35.7 35.7 35.7 35.7 35.7 35.7 35.7 35.7 Net Plant Heat Rate, HHV Btu / kWh 9561 9561 9561 9561 9561 9561 9561 9561 9561 9561 9561 9561 Net Generation MWh / year 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 1,165,433 Costs

EPC Price $ / kW 0 0 0 0 0 0 0 0 0 0 0 0 EPC Price $1000s 0 0 0 0 0 0 0 0 0 0 0 0 Fixed O&M Costs $1000 / year 5,544 5,544 5,544 5,544 5,544 5,544 5,544 5,544 5,544 5,544 5,544 5,544 Fixed O&M Costs $ / kW 35.42 35.42 35.42 35.42 35.42 35.42 35.42 35.42 35.42 35.42 35.42 35.42 Variable O&M Costs $1000 / year 7,011 7,011 7,011 7,011 7,011 7,011 7,011 7,011 7,011 7,011 7,011 7,011 Variable O&M Costs cents / kWh 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 Total O&M Costs cents / kWh 1.08 1.08 1.08 1.08 1.08 1.08 1.08 1.08 1.08 1.08 1.08 1.08 Fuel Cost Calculation

Coal Price $ / MMBtu 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 Financin g Assumptions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 15 15 15 15 15 15 15 15 11 13 17 19 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Fixed O&M 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 Variable O&M 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 Fuel 1.21 1.21 1.21 1.21 1.21 1.21 1.21 1.21 1.21 1.21 1.21 1.21 Total 2.29 2.29 2.29 2.29 2.29 2.29 2.29 2.29 2.29 2.29 2.29 2.29ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 226 

### 7.4.17 Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with No Emissions Credits Sold and $20 per Pound High Temperature Alloy Economic Sensitivity Results

Results for the Phillip Sporn Unit 4 Repowering Ca se COE sensitivity study are shown in Figure 7.4.17 and summarized in Table 7.4.17. The leveli zed COE for the base parameter values is 2.8 cents per kWh. Levelized COE ranges from a low of 2.5 to a high of 3.3 cents per kWh.

-20% -15% -10%

-5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

2.2 2.4 2.6 2.8 3.0 3.2 3.4Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate



### Figure 7.4.17: Case Repowering Phillip Spor n Unit 4 – Repowering Phillip Sporn Unit 4

with No Emissions Credits Sold and $20 per Pound High Temperature Alloy Economic Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 227 

### Table 7.4.17: Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with No Emissions Credits Sold and $20 per Pound High Temperature Alloy Economic Sensitivity Results

Parameter Units Sporn Unit #4 - Repowering; $20 per lb Nickel Power Generation

Net Output kW 184,487 184,487 184,487 184,487 184,487 184,487 184,487 184,487 184,487 184,487 184,487 184,487 Availability Factor % 85 64 74 96 85 85 85 85 85 85 85 85 Actual Operating Hours hours / year 744,600 558,450 651,525 837,675 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 Net Efficiency, HHV % 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 Net Plant Heat Rate, HHV Btu / kWh 8889 8889 8889 8889 8889 8889 8889 8889 8889 8889 8889 8889 Net Generation MWh / year 1,373,690 1,030,268 1,201,979 1,545,401 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 Costs

EPC Price $ / kW 400 400 400 400 300 350 451 501 400 400 400 400 EPC Price $1000s 73,880 73,880 73,880 73,880 55,410 64,645 83,115 92,350 73,880 73,880 73,880 73,880 Fixed O&M Costs $1000 / year 5,495 5,495 5,495 5,495 5,495 5,495 5,495 5,495 5,495 5,495 5,495 5,495 Fixed O&M Costs $ / kW 29.78 29.78 29.78 29.78 29.78 29.78 29.78 29.78 29.78 29.78 29.78 29.78 Variable O&M Costs $1000 / year 2,130 1,597 1,864 2,396 2,130 2,130 2,130 2,130 2,130 2,130 2,130 2,130 Variable O&M Costs cents / kWh 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 Total O&M Costs cents / kWh 0.56 0.69 0.61 0.51 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 Fuel Cost Calculation

Coal Price $ / MMBtu 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 0.95 1.11 1.43 1.59 Financing Assumptions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 15 15 15 15 15 15 15 15 15 15 15 15 Levelized Cost of Electricity (cents / kWh)

Financial Component 1.08 1.44 1.23 0.96 0.81 0.94 1.21 1.35 1.08 1.08 1.08 1.08 Fixed O&M 0.40 0.53 0.46 0.36 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 Variable O&M 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 Fuel 1.13 1.13 1.13 1.13 1.13 1.13 1.13 1.13 0.85 0.99 1.27 1.41 Total 2.76 3.25 2.97 2.60 2.49 2.63 2.90 3.03 2.48 2.62 2.90 3.04

Paramete r Units Sporn Unit #4 - Repowerin g ; $20 per lb Nickel Power Generation

Net Output kW 184,487 184,487 184,487 184,487 184,487 184,487 184,487 184,487 184,487 184,487 184,487 184,487 Availability Factor % 85 85 85 85 85 85 85 85 85 85 85 85 Actual Operating Hours hours / year 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 Net Efficiency, HHV % 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 Net Plant Heat Rate, HHV Btu / kWh 8889 8889 8889 8889 8889 8889 8889 8889 8889 8889 8889 8889 Net Generation MWh / year 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 Costs

EPC Price $ / kW 400 400 400 400 400 400 400 400 400 400 400 400 EPC Price $1000s 73,880 73,880 73,880 73,880 73,880 73,880 73,880 73,880 73,880 73,880 73,880 73,880 Fixed O&M Costs $1000 / year 5,495 5,495 5,495 5,495 5,495 5,495 5,495 5,495 5,495 5,495 5,495 5,495 Fixed O&M Costs $ / kW 29.78 29.78 29.78 29.78 29.78 29.78 29.78 29.78 29.78 29.78 29.78 29.78 Variable O&M Costs $1000 / year 2,130 2,130 2,130 2,130 2,130 2,130 2,130 2,130 2,130 2,130 2,130 2,130 Variable O&M Costs cents / kWh 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 Total O&M Costs cents / kWh 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 Fuel Cost Calculation

Coal Price $ / MMBtu 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 Financin g Assumptions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 15 15 15 15 15 15 15 15 11 13 17 19 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 0.97 1.03 1.13 1.18 1.04 1.06 1.09 1.11 0.90 0.98 1.18 1.28 Fixed O&M 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 Variable O&M 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 Fuel 1.13 1.13 1.13 1.13 1.13 1.13 1.13 1.13 1.13 1.13 1.13 1.13 Total 2.66 2.71 2.81 2.86 2.73 2.74 2.78 2.80 2.58 2.67 2.86 2.97ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 228 

### 7.4.18 Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with No Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity Results

Results for the Phillip Sporn Unit 4 Repowering Ca se COE sensitivity study are shown in Figure 7.4.18 and summarized in Table 7.4.18. The leveli zed COE for the base parameter values is 2.8 cents per kWh. Levelized COE ranges from a low of 2.5 to a high of 3.3 cents per kWh.

-20% -15% -10%

-5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

2.2 2.4 2.6 2.8 3.0 3.2 3.4 3.6Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate



### Figure 7.4.18: Case Repowering Phillip Spor n Unit 4 – Repowering Phillip Sporn Unit 4

with No Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 229 

### Table 7.4.18: Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with No Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity Results

Paramete r Units Sporn Unit #4 - Repowering; $28 per lb Nickel Power Generation

Net Output kW 184,487 184,487 184,487 184,487 184,487 184,487 184,487 184,487 184,487 184,487 184,487 184,487 Availability Factor % 85 64 74 96 85 85 85 85 85 85 85 85 Actual Operating Hours hours / year 744,600 558,450 651,525 837,675 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 Net Efficiency, HHV % 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 Net Plant Heat Rate, HHV Btu / kWh 8889 8889 8889 8889 8889 8889 8889 8889 8889 8889 8889 8889 Net Generation MWh / year 1,373,690 1,030,268 1,201,979 1,545,401 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 Costs

EPC Price $ / kW 414 414 414 414 310 362 466 517 414 414 414 414 EPC Price $1000s 76,344 76,344 76,344 76,344 57,258 66,801 85,887 95,430 76,344 76,344 76,344 76,344 Fixed O&M Costs $1000 / year 5,532 5,532 5,532 5,532 5,532 5,532 5,532 5,532 5,532 5,532 5,532 5,532 Fixed O&M Costs $ / kW 29.98 29.98 29.98 29.98 29.98 29.98 29.98 29.98 29.98 29.98 29.98 29.98 Variable O&M Costs $1000 / year 2,168 1,626 1,897 2,439 2,168 2,168 2,168 2,168 2,168 2,168 2,168 2,168 Variable O&M Costs cents / kWh 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 Total O&M Costs cents / kWh 0.56 0.69 0.62 0.52 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 Fuel Cost Calculation

Coal Price $ / MMBtu 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 0.95 1.11 1.43 1.59 Financing Assumptions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 15 15 15 15 15 15 15 15 15 15 15 15 Levelized Cost of Electricity (cents / kWh)

Financial Component 1.11 1.48 1.27 0.99 0.83 0.97 1.25 1.39 1.11 1.11 1.11 1.11 Fixed O&M 0.40 0.54 0.46 0.36 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 Variable O&M 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 Fuel 1.13 1.13 1.13 1.13 1.13 1.13 1.13 1.13 0.85 0.99 1.27 1.41 Total 2.80 3.31 3.02 2.63 2.52 2.66 2.94 3.08 2.52 2.66 2.94 3.08

Paramete r Units Sporn Unit #4 - Repowerin g ; $28 per lb Nickel Power Generation

Net Output kW 184,487 184,487 184,487 184,487 184,487 184,487 184,487 184,487 184,487 184,487 184,487 184,487 Availability Factor % 85 85 85 85 85 85 85 85 85 85 85 85 Actual Operating Hours hours / year 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 Net Efficiency, HHV % 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 Net Plant Heat Rate, HHV Btu / kWh 8889 8889 8889 8889 8889 8889 8889 8889 8889 8889 8889 8889 Net Generation MWh / year 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 Costs

EPC Price $ / kW 414 414 414 414 414 414 414 414 414 414 414 414 EPC Price $1000s 76,344 76,344 76,344 76,344 76,344 76,344 76,344 76,344 76,344 76,344 76,344 76,344 Fixed O&M Costs $1000 / year 5,532 5,532 5,532 5,532 5,532 5,532 5,532 5,532 5,532 5,532 5,532 5,532 Fixed O&M Costs $ / kW 29.98 29.98 29.98 29.98 29.98 29.98 29.98 29.98 29.98 29.98 29.98 29.98 Variable O&M Costs $1000 / year 2,168 2,168 2,168 2,168 2,168 2,168 2,168 2,168 2,168 2,168 2,168 2,168 Variable O&M Costs cents / kWh 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 Total O&M Costs cents / kWh 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 Fuel Cost Calculation

Coal Price $ / MMBtu 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 Financin g Assumptions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 15 15 15 15 15 15 15 15 11 13 17 19 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.00 1.06 1.17 1.22 1.08 1.10 1.13 1.15 0.93 1.02 1.22 1.33 Fixed O&M 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 Variable O&M 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 Fuel 1.13 1.13 1.13 1.13 1.13 1.13 1.13 1.13 1.13 1.13 1.13 1.13 Total 2.69 2.75 2.85 2.91 2.77 2.78 2.82 2.84 2.61 2.70 2.91 3.02ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 230 

### 7.4.19 Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with No Emissions Credits Sold and $32.90 per Pound High Temperature Alloy Economic Sensitivity Results

Results for the Phillip Sporn Unit 4 Repowering Ca se COE sensitivity study are shown in Figure 7.4.19 and summarized in Table 7.4.19. The leveli zed COE for the base parameter values is 2.8 cents per kWh. Levelized COE ranges from a low of 2.5 to a high of 3.3 cents per kWh.

-20% -15% -10%

-5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

2.3 2.5 2.7 2.9 3.1 3.3 3.5 3.7Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate


### Figure 7.4.19: Case Repowering Phillip Spor n Unit 4 – Repowering Phillip Sporn Unit 4 with No Emissions Credits Sold and $32.90 per Pound High Temperature Alloy Economic Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 231 

### Table 7.4.19: Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with No Emissions Credits Sold and $32.90 per Pound High Temperature Alloy Economic Sensitivity Results

Parameter Units S p orn Unit #4 - Re p owerin g ; $32.90 p er lb Nickel Power Generation

Net Output kW 184,487 184,487 184,487 184,487 184, 487 184,487 184,487 184,487 184, 487 184,487 184,487 184,487 Availability Factor % 85 64 74 96 85 85 85 85 85 85 85 85 Actual Operating Hours hours / year 744,600 558,450 651,525 837,675 744,600 744,600 744,600 744, 600 744,600 744,600 744,600 744,600 Net Efficiency, HHV % 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 Net Plant Heat Rate, HHV Btu / kWh 8889 8889 8889 8889 8889 8889 8889 8889 8889 8889 8889 8889 Net Generation MWh / year 1,373,690 1,030,268 1,201,979 1,545,401 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 Costs

EPC Price $ / kW 422 422 422 422 316 369 475 527 422 422 422 422 EPC Price $1000s 77,831 77,831 77,831 77,831 58,373 68,102 87,560 97,289 77, 831 77,831 77,831 77,831 Fixed O&M Costs $1000 / year 5,554 5,554 5,554 5,554 5,554 5,554 5,554 5, 554 5,554 5,554 5,554 5,554 Fixed O&M Costs $ / kW 30.11 30.11 30.11 30. 11 30.11 30.11 30.11 30.1 1 30.11 30.11 30.11 30.11 Variable O&M Costs $1000 / year 2,190 1,643 1, 917 2,464 2,190 2,190 2,190 2, 190 2,190 2,190 2,190 2,190 Variable O&M Costs cents / kWh 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 Total O&M Costs cents / kWh 0.56 0.70 0.62 0 .52 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 Fuel Cost Calculation

Coal Price $ / MMBtu 1.27 1.27 1.27 1.27 1.27 1.27 1. 27 1.27 0.95 1.11 1.43 1.59 Financin g Assum p tions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 15 15 15 15 15 15 15 15 15 15 15 15 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.13 1.51 1.30 1.01 0.85 0.99 1.28 1.42 1.13 1.13 1.13 1.13 Fixed O&M 0.40 0.54 0.46 0.36 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 Variable O&M 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 Fuel 1.13 1.13 1.13 1.13 1.13 1. 13 1.13 1.13 0.85 0.99 1.27 1.41 Total 2.83 3.34 3.05 2.66 2.54 2.69 2.97 3.11 2.55 2.69 2.97 3.11

Parameter Units S p orn Unit #4 - Re p owerin g ; $32.90 p er lb Nickel Power Generation

Net Output kW 184,487 184,487 184,487 184,487 184, 487 184,487 184,487 184,487 184,487 184,487 184,487 184,487 Availability Factor % 85 85 85 85 85 85 85 85 85 85 85 85 Actual Operating Hours hours / year 744,600 744,600 7 44,600 744,600 744,600 744,600 744,600 7 44,600 744,600 744,600 744,600 744,600 Net Efficiency, HHV % 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 38.4 Net Plant Heat Rate, HHV Btu / kWh 8889 8889 8889 8889 8889 8889 8889 8889 8889 8889 8889 8889 Net Generation MWh / year 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 1,373,690 Costs

EPC Price $ / kW 422 422 422 422 422 422 422 422 422 422 422 422 EPC Price $1000s 77,831 77,831 77,831 77,831 77, 831 77,831 77,831 77,831 77,831 77,831 77,831 77,831 Fixed O&M Costs $1000 / year 5,554 5,554 5,554 5,554 5,554 5,554 5,554 5, 554 5,554 5,554 5,554 5,554 Fixed O&M Costs $ / kW 30.11 30.11 30.11 30. 11 30.11 30.11 30.11 30.11 30.11 30.11 30.11 30.11 Variable O&M Costs $1000 / year 2,190 2,190 2,190 2,190 2,190 2,190 2,190 2, 190 2,190 2,190 2,190 2,190 Variable O&M Costs cents / kWh 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 Total O&M Costs cents / kWh 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 Fuel Cost Calculation

Coal Price $ / MMBtu 1.27 1.27 1.27 1. 27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 Financin g Assum p tions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 15 15 15 15 15 15 15 15 11 13 17 19 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.02 1.08 1.19 1.24 1.10 1.12 1.15 1.17 0.94 1.04 1.24 1.35 Fixed O&M 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 Variable O&M 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.16 Fuel 1.13 1.13 1.13 1.13 1.13 1. 13 1.13 1.13 1.13 1.13 1.13 1.13 Total 2.72 2.77 2.88 2.93 2.79 2.81 2.85 2.87 2.64 2.73 2.93 3.04ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 232 

### 7.4.20 Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with $2k per Ton NO x 

### and $200 per Ton SO x 

### Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity Results

Results for the Phillip Sporn Unit 4 Repowering Ca se COE sensitivity study are shown in Figure 9.4.20 and summarized in Table 9.4.20. The leveli zed COE for the base parameter values is 2.8 cents per kWh. Levelized COE ranges from a low of 2.5 to a high of 3.3 cents per kWh.

-20% -15% -10%

-5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

2.2 2.4 2.6 2.8 3.0 3.2 3.4Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate



### Figure 7.4.20: Case Repowering Phillip Spor n Unit 4 – Repowering Phillip Sporn Unit 4

with $2k per Ton NO x 

### and $200 per Ton SO x 

### Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 233 

### Table 7.4.20: Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with

$2k per Ton NO x 

### and $200 per Ton SO x 

### Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity Results

Parameter Units S p orn Unit #4 - Re p owerin g ; $2k/ton NOx & $200/ton SOx Credits Power Generation

Net Output kW 184,387 184,387 184,387 184,387 184, 387 184,387 184,387 184,387 184, 387 184,387 184,387 184,387 Availability Factor % 85 64 74 96 85 85 85 85 85 85 85 85 Actual Operating Hours hours / year 744,600 558,450 651,525 837,675 744,600 744,600 744,600 744, 600 744,600 744,600 744,600 744,600 Net Efficiency, HHV % 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 Net Plant Heat Rate, HHV Btu / kWh 8947 8947 8947 8947 8947 8947 8947 8947 8947 8947 8947 8947 Net Generation MWh / year 1,372,946 1,029,709 1,201,327 1,544,564 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 Costs

EPC Price $ / kW 419 419 419 419 315 367 472 524 419 419 419 419 EPC Price $1000s 77,344 77,344 77,344 77,344 58,008 67,676 87,012 96,680 77, 344 77,344 77,344 77,344 Fixed O&M Costs $1000 / year 5,529 5,529 5,529 5,529 5,529 5,529 5,529 5, 529 5,529 5,529 5,529 5,529 Fixed O&M Costs $ / kW 29.98 29.98 29.98 29. 98 29.98 29.98 29.98 29.9 8 29.98 29.98 29.98 29.98 Variable O&M Costs $1000 / year 1,586 1,189 1, 388 1,784 1,586 1,586 1,586 1, 586 1,586 1,586 1,586 1,586 Variable O&M Costs cents / kWh 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 Total O&M Costs cents / kWh 0.52 0.65 0.58 0 .47 0.52 0.52 0.52 0.52 0.52 0.52 0.52 0.52 Fuel Cost Calculation

Coal Price $ / MMBtu 1.27 1.27 1.27 1.27 1.27 1.27 1. 27 1.27 0.95 1.11 1.43 1.59 Financin g Assum p tions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 15 15 15 15 15 15 15 15 15 15 15 15 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.13 1.50 1.29 1.00 0.85 0.99 1.27 1.41 1.13 1.13 1.13 1.13 Fixed O&M 0.40 0.54 0.46 0.36 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 Variable O&M 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 Fuel 1.14 1.14 1.14 1.14 1.14 1. 14 1.14 1.14 0.85 0.99 1.28 1.42 Total 2.78 3.29 3.00 2.61 2.50 2.64 2.92 3.06 2.50 2.64 2.92 3.07

Parameter Units S p orn Unit #4 - Re p owerin g ; $2k/ton NOx & $200/ton SOx Credits Power Generation

Net Output kW 184,387 184,387 184,387 184,387 184, 387 184,387 184,387 184,387 184, 387 184,387 184,387 184,387 Availability Factor % 85 85 85 85 85 85 85 85 85 85 85 85 Actual Operating Hours hours / year 744,600 744, 600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 Net Efficiency, HHV % 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 Net Plant Heat Rate, HHV Btu / kWh 8947 8947 8947 8947 8947 8947 8947 8947 8947 8947 8947 8947 Net Generation MWh / year 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 Costs

EPC Price $ / kW 419 419 419 419 419 419 419 419 419 419 419 419 EPC Price $1000s 77,344 77,344 77,344 77,344 77, 344 77,344 77,344 77,344 77, 344 77,344 77,344 77,344 Fixed O&M Costs $1000 / year 5,529 5,529 5,529 5,529 5,529 5,529 5,529 5, 529 5,529 5,529 5,529 5,529 Fixed O&M Costs $ / kW 29.98 29.98 29.98 29. 98 29.98 29.98 29.98 29.98 29.98 29.98 29.98 29.98 Variable O&M Costs $1000 / year 1,586 1,586 1,586 1,586 1,586 1,586 1,586 1, 586 1,586 1,586 1,586 1,586 Variable O&M Costs cents / kWh 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 Total O&M Costs cents / kWh 0.52 0.52 0.52 0 .52 0.52 0.52 0.52 0.52 0.52 0.52 0.52 0.52 Fuel Cost Calculation

Coal Price $ / MMBtu 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 Financin g Assum p tions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 15 15 15 15 15 15 15 15 11 13 17 19 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.02 1.07 1.18 1.23 1.09 1.11 1.15 1.17 0.94 1.03 1.23 1.34 Fixed O&M 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 Variable O&M 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 Fuel 1.14 1.14 1.14 1.14 1.14 1. 14 1.14 1.14 1.14 1.14 1.14 1.14 Total 2.67 2.73 2.84 2.89 2.75 2.7 7 2.80 2.82 2.59 2.68 2.89 3.00ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 234 

### 7.4.21 Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with $5k per Ton NO x 

### and $200 per Ton SO x 

### Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity Results

Results for the Phillip Sporn Unit 4 Repowering Ca se COE sensitivity study are shown in Figure 9.4.21 and summarized in Table 9.4.21. The leveli zed COE for the base parameter values is 2.8 cents per kWh. Levelized COE ranges from a low of 2.5 to a high of 3.3 cents per kWh.

-20% -15% -10%

-5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

2.2 2.4 2.6 2.8 3.0 3.2 3.4Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate


### Figure 7.4.21: Case Repowering Phillip Spor n Unit 4 – Repowering Phillip Sporn Unit 4

with $5k per Ton NO x 

### and $200 per Ton SO x 

### Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 235 

### Table 7.4.21: Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with

$5k per Ton NO x 

### and $200 per Ton SO x 

### Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity Results

Parameter Units S p orn Unit #4 - Re p owerin g ; $5k/ton NOx & $200/ton SOx Credits Power Generation

Net Output kW 184,387 184,387 184,387 184,387 184, 387 184,387 184,387 184,387 184, 387 184,387 184,387 184,387 Availability Factor % 85 64 74 96 85 85 85 85 85 85 85 85 Actual Operating Hours hours / year 744,600 558,450 651,525 837,675 744,600 744,600 744,600 744, 600 744,600 744,600 744,600 744,600 Net Efficiency, HHV % 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 Net Plant Heat Rate, HHV Btu / kWh 8947 8947 8947 8947 8947 8947 8947 8947 8947 8947 8947 8947 Net Generation MWh / year 1,372,946 1,029,709 1,201,327 1,544,564 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 Costs

EPC Price $ / kW 419 419 419 419 315 367 472 524 419 419 419 419 EPC Price $1000s 77,344 77,344 77,344 77,344 58,008 67,676 87, 012 96,680 77,344 77,344 77,344 77,344 Fixed O&M Costs $1000 / year 5,529 5,529 5,529 5,529 5,529 5,529 5,529 5, 529 5,529 5,529 5,529 5,529 Fixed O&M Costs $ / kW 29.98 29.98 29.98 29. 98 29.98 29.98 29.98 29.9 8 29.98 29.98 29.98 29.98 Variable O&M Costs $1000 / year 1,203 903 1,053 1,354 1,203 1,203 1,203 1, 203 1,203 1,203 1,203 1,203 Variable O&M Costs cents / kWh 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 Total O&M Costs cents / kWh 0.49 0.62 0.55 0 .45 0.49 0.49 0.49 0.49 0.49 0.49 0.49 0.49 Fuel Cost Calculation

Coal Price $ / MMBtu 1.27 1.27 1.27 1.27 1.27 1.27 1. 27 1.27 0.95 1.11 1.43 1.59 Financin g Assum p tions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 15 15 15 15 15 15 15 15 15 15 15 15 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.13 1.50 1.29 1.00 0.85 0.99 1.27 1.41 1.13 1.13 1.13 1.13 Fixed O&M 0.40 0.54 0.46 0.36 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 Variable O&M 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 Fuel 1.14 1.14 1.14 1.14 1.14 1. 14 1.14 1.14 0.85 0.99 1.28 1.42 Total 2.75 3.26 2.97 2.58 2.47 2.61 2.90 3.04 2.47 2.61 2.90 3.04

Parameter Units S p orn Unit #4 - Re p owerin g ; $5k/ton NOx & $200/ton SOx Credits Power Generation

Net Output kW 184,387 184,387 184,387 184,387 184, 387 184,387 184,387 184,387 184, 387 184,387 184,387 184,387 Availability Factor % 85 85 85 85 85 85 85 85 85 85 85 85 Actual Operating Hours hours / year 744,600 744, 600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 Net Efficiency, HHV % 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 Net Plant Heat Rate, HHV Btu / kWh 8947 8947 8947 8947 8947 8947 8947 8947 8947 8947 8947 8947 Net Generation MWh / year 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 Costs

EPC Price $ / kW 419 419 419 419 419 419 419 419 419 419 419 419 EPC Price $1000s 77,344 77,344 77,344 77,344 77, 344 77,344 77,344 77,344 77, 344 77,344 77,344 77,344 Fixed O&M Costs $1000 / year 5,529 5,529 5,529 5,529 5,529 5,529 5,529 5, 529 5,529 5,529 5,529 5,529 Fixed O&M Costs $ / kW 29.98 29.98 29.98 29. 98 29.98 29.98 29.98 29.98 29.98 29.98 29.98 29.98 Variable O&M Costs $1000 / year 1,203 1,203 1,203 1,203 1,203 1,203 1,203 1, 203 1,203 1,203 1,203 1,203 Variable O&M Costs cents / kWh 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 Total O&M Costs cents / kWh 0.49 0.49 0.49 0 .49 0.49 0.49 0.49 0.49 0.49 0.49 0.49 0.49 Fuel Cost Calculation

Coal Price $ / MMBtu 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 Financin g Assum p tions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 15 15 15 15 15 15 15 15 11 13 17 19 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.02 1.07 1.18 1.23 1.09 1.11 1.15 1.17 0.94 1.03 1.23 1.34 Fixed O&M 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 Variable O&M 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 Fuel 1.14 1.14 1.14 1.14 1.14 1. 14 1.14 1.14 1.14 1.14 1.14 1.14 Total 2.65 2.70 2.81 2.86 2.72 2.7 4 2.77 2.79 2.56 2.66 2.86 2.97ECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 236 

### 7.4.22 Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with $8k per Ton NO x 

### and $200 per Ton SO x 

### Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity Results

Results for the Phillip Sporn Unit 4 Repowering Case COE sensitiv ity study are shown in Figure 9.4.22 and summarized in Table 9.4.22. The leveli zed COE for the base parameter values is 2.1 cents per kWh. Levelized COE ranges from a low of 1.8 to a high of 2.6 cents per kWh.

-20% -15% -10%

-5% 0% 5% 10% 15% 20% 25% 30%

-30% -20% -10% 0% 10% 20% 30% Percent Change in VariablePercent Change in COE

2.2 2.4 2.6 2.8 3.0 3.2 3.4Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price Equity Corporate Tax Discount Rate



### Figure 7.4.22: Case Repowering Phillip Spor n Unit 4 – Repowering Phillip Sporn Unit 4

with $8k per Ton NO x 

### and $200 per Ton SO x 

### Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity ResultsECONOMICS AND FEASIBILITY OF RANKINE CYCLE IMPROVEMENTS FOR COAL FIRED POWER PLANTS

ALSTOM Power Inc. September 8, 2004 237 

### Table 7.4.22: Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with

$8k per Ton NO x 

### and $200 per Ton SO x 

### Emissions Credits Sold and $28 per Pound High Temperature Alloy Economic Sensitivity Results

Parameter Units S p orn Unit #4 - Re p owerin g ; $8k/ton NOx & $200/ton SOx Credits Power Generation

Net Output kW 184,387 184,387 184,387 184,387 184, 387 184,387 184,387 184,387 184, 387 184,387 184,387 184,387 Availability Factor % 85 64 74 96 85 85 85 85 85 85 85 85 Actual Operating Hours hours / year 744,600 558,450 651,525 837,675 744,600 744,600 744,600 744, 600 744,600 744,600 744,600 744,600 Net Efficiency, HHV % 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 Net Plant Heat Rate, HHV Btu / kWh 8947 8947 8947 8947 8947 8947 8947 8947 8947 8947 8947 8947 Net Generation MWh / year 1,372,946 1,029,709 1,201,327 1,544,564 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 Costs

EPC Price $ / kW 419 419 419 419 315 367 472 524 419 419 419 419 EPC Price $1000s 77,344 77,344 77,344 77,344 58,008 67,676 87, 012 96,680 77,344 77,344 77,344 77,344 Fixed O&M Costs $1000 / year 5,529 5,529 5,529 5,529 5,529 5,529 5,529 5, 529 5,529 5,529 5,529 5,529 Fixed O&M Costs $ / kW 29.98 29.98 29.98 29. 98 29.98 29.98 29.98 29.9 8 29.98 29.98 29.98 29.98 Variable O&M Costs $1000 / year 821 616 718 924 821 821 821 821 821 821 821 821 Variable O&M Costs cents / kWh 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 Total O&M Costs cents / kWh 0.46 0.60 0.52 0 .42 0.46 0.46 0.46 0.46 0.46 0.46 0.46 0.46 Fuel Cost Calculation

Coal Price $ / MMBtu 1.27 1.27 1.27 1.27 1.27 1.27 1. 27 1.27 0.95 1.11 1.43 1.59 Financin g Assum p tions

Equity % 50 50 50 50 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 20 20 20 20 20 20 20 20 Discount Factor % 15 15 15 15 15 15 15 15 15 15 15 15 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.13 1.50 1.29 1.00 0.85 0.99 1.27 1.41 1.13 1.13 1.13 1.13 Fixed O&M 0.40 0.54 0.46 0.36 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 Variable O&M 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 Fuel 1.14 1.14 1.14 1.14 1.14 1. 14 1.14 1.14 0.85 0.99 1.28 1.42 Total 2.73 3.24 2.95 2.56 2.44 2.59 2.87 3.01 2.44 2.58 2.87 3.01

Parameter Units S p orn Unit #4 - Re p owerin g ; $8k/ton NOx & $200/ton SOx Credits Power Generation

Net Output kW 184,387 184,387 184,387 184,387 184, 387 184,387 184,387 184,387 184, 387 184,387 184,387 184,387 Availability Factor % 85 85 85 85 85 85 85 85 85 85 85 85 Actual Operating Hours hours / year 744,600 744, 600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 744,600 Net Efficiency, HHV % 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 38.1 Net Plant Heat Rate, HHV Btu / kWh 8947 8947 8947 8947 8947 8947 8947 8947 8947 8947 8947 8947 Net Generation MWh / year 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 1,372,946 Costs

EPC Price $ / kW 419 419 419 419 419 419 419 419 419 419 419 419 EPC Price $1000s 77,344 77,344 77,344 77,344 77, 344 77,344 77,344 77,344 77, 344 77,344 77,344 77,344 Fixed O&M Costs $1000 / year 5,529 5,529 5,529 5,529 5,529 5,529 5,529 5, 529 5,529 5,529 5,529 5,529 Fixed O&M Costs $ / kW 29.98 29.98 29.98 29. 98 29.98 29.98 29.98 29.98 29.98 29.98 29.98 29.98 Variable O&M Costs $1000 / year 821 821 821 821 821 821 821 821 821 821 821 821 Variable O&M Costs cents / kWh 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 Total O&M Costs cents / kWh 0.46 0.46 0.46 0 .46 0.46 0.46 0.46 0.46 0.46 0.46 0.46 0.46 Fuel Cost Calculation

Coal Price $ / MMBtu 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 Financin g Assum p tions

Equity % 38 44 56 63 50 50 50 50 50 50 50 50 Corporate Tax % 20 20 20 20 15 18 23 25 20 20 20 20 Discount Factor % 15 15 15 15 15 15 15 15 11 13 17 19 Levelized Cost of Electricit y ( cents / kWh )

Financial Component 1.02 1.07 1.18 1.23 1.09 1.11 1.15 1.17 0.94 1.03 1.23 1.34 Fixed O&M 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 Variable O&M 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 Fuel 1.14 1.14 1.14 1.14 1.14 1. 14 1.14 1.14 1.14 1.14 1.14 1.14 Total 2.62 2.67 2.78 2.83 2.69 2.7 1 2.75 2.77 2.54 2.63 2.83 2.94