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: OCTOBER 1, 2001 – FEBRUARY 28, 2004

PPL REPORT NO. PPL-04-CT-03
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. ii September 8, 2004

DISCLAIMER

This report was prepared as an account of work sponsored by an agency of the United Sates

Government. Neither the United States Government 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 necessarily 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 necessarily state or reflect those of the United

States Government or any agency thereof.
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IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. iii September 8, 2004

ACKNOWLEDGMENTS

The authors appreciatively acknowledge the following 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, Raymond Hickey, Diane Calkin, Glen Jukkola,

Srivats Srinivasachar, and Larry Cellilli of ALSTOM 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 CMBTM 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 providing performance and cost information for

the steam cycles.

• Richard Skowyra: For providing 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 information on mercury removal from boilers.

• Larry Cellilli: For providing contract administration.

 William McMahon of Parsons Energy and Chemical Group, Inc., of Wyomissing,

Pennsylvania: For providing complete design and 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, and design and cost information for balance of

plant equipment for the Repowering Case.

The financial support of this project by DOE National Energy Technology Laboratory (Contract No

DE-FCP-01NT41222), and ALSTOM Power Inc. is also appreciatively acknowledged.
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ALSTOM Power Inc. iv September 8, 2004

PUBLIC ABSTRACT

ALSTOM Power Inc.’s Power Plant Laboratories (ALSTOM) has teamed with the U.S.

Department of Energy National Energy Technology Laboratory (DOE NETL), American Electric

Company (AEP) and Parsons Energy and Chemical Group to conduct a comprehensive study

evaluating coal fired steam power plants, known as Rankine Cycles, equipped with three different

combustion systems: Pulverized Coal (PC), Circulating Fluidized Bed (CFB), and Circulating

Moving Bed (CMBTM). Five steam cycles utilizing a wide range of steam conditions were used

with these combustion systems.

The motivation for this study was to establish through engineering analysis, the most costeffective performance potential available through improvement in the Rankine Cycle steam

conditions and combustion systems while at the same time ensuring that the most stringent

emission performance based on CURC (Coal Utilization Research Council) 2010 targets are met.

• > 98% sulfur removal

• < 0.05 lbm/MM-Btu NOx

• < 0.01 lbm/MM-Btu Particulate Matter

• > 90% Hg removal

The final report discusses the results of a coal 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 (CMBTM) integrated with five

different steam cycles. The study explores the technical feasibility, thermal performance,

environmental performance, and economic 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 2,400 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) explores the means of upgrading the efficiency and

output of an older existing coal fired steam power plant. There are currently more than 1,400

coal-fired units in operation in the United States 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 service that could benefit from this repowering

technology. The study evaluates the technical feasibility, thermal performance, and economic

viability of this repowering concept.

Major conclusions:

Primary results for both parts of the study are summarized in terms of thermal efficiency,

environmental performance, investment costs, and cost of electricity (COE). For the ten

Greenfield cases, the calculated thermal efficiencies (HHV basis) range from 37.02% to 43.55%.

The effect of the increasing steam cycle parameters (Temperature and Pressure) is to increase

plant efficiency. The highest efficiency is achieved for the ultra supercritical steam cycle 1,292°F/

1,1328°F/5075 psi. With respect to thermal efficiency, for the same steam conditions, there is

little difference when comparing among the combustion systems (PC, CFB, and CMBTM) 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 CMBTM systems which is due to only partial sulfation in the CMBTM

combustor.
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ALSTOM Power Inc. v September 8, 2004

The specific plant investment cost results for the Greenfield cases range from about 1,018 to

1,168 $/kW-net. For the same steam conditions, the CMBTM combustion system plants require

the lowest investment costs as compared to PC or CFB plants. This cost advantage increases as

steam cycle conditions (Temperature and Pressure) are raised. The CFB systems are about 70

$/kW lower in cost than the PC type combustion systems. This difference is primarily attributable

to the differences in the costs for the gas cleanup system equipment.

The levelized cost of electricity (COE) results for the Greenfield cases range from about 3.4 to 4.0

Cents/kWh. These results indicate that the CMBTM 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 requires 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 CMBTM 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 the 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 CMBTM based systems, the CMBTM 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 time 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 CO2 emissions and plant thermal efficiency. For example, the ultra

supercritical PC case is about 18% more efficient than conventional subcritical PC case and it

also emits about 18% less CO2 per kWh of net output.

The study has also investigated the impact of potential taxes placed on CO2 emissions. As

expected, the COE increases significantly with the increase in the tax. 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.

For the Repowering Case, CMB combustion technology 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 unit. This difference may quickly disappear if the

price of NOx 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. CO2

emissions are decreased from about 1.94 to 1.80 lbm/kWh, a reduction of about 8 percent.

In summary, from the results of the study the evaluated power plant 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 facilitate 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 CMBTM cycles in a 10 to 15

year timeframe. The very high steam temperatures of the ultra-supercritical steam cycle do not

appear to be practical for conventional CFB technology where combustion temperature is

generally limited to 1,550o

F. CMBTM technology with the combustion temperature of 2000oF
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ALSTOM Power Inc. vi September 8, 2004

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

CMBTM 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 require installation of the back end NOx and SOx 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 the 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 temperatures of approximately 1,200o

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 efficiency 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 advantage over future IGCC plants with advanced gas

turbines.
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IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. vii September 8, 2004

Table of Contents

1. Introduction ................................................................................................................................. 1

2. Case Studies; Plant Performance, Design and Equipment........................................................ 6

2.1 Plant Design Basis and Scope:............................................................................................ 6

2.2 Steam Cycles for the Greenfield Cases............................................................................. 12

2.2.1 General Steam Cycle Description .......................................................................... 12

2.2.2 Steam Cycle Equipment ......................................................................................... 19

2.2.2.1 Steam Turbine Generators.......................................................................... 19

2.2.2.2 Condensate Systems .................................................................................. 19

2.2.2.3 Feedwater Systems..................................................................................... 19

2.3 Pulverized Coal (PC) Fired Cases ..................................................................................... 20

2.3.1 Steam Cycles for the PC Cases ............................................................................. 21

2.3.2 Steam Generator Designs for the PC Fired Cases ................................................ 21

2.3.2.1 Heat Transfer Surfaces and Arrangement for the PC Boilers..................... 21

2.3.2.2 Materials for the PC Fired Boilers: .............................................................. 25

2.3.2.3 Firing Systems for the PC Boilers: .............................................................. 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 Equipment for the PC Cases....................................................... 29

2.3.3.1 Gas Cleanup Systems for the PC Cases .................................................... 29

2.3.3.2 Other BOP Systems for the PC Cases ....................................................... 33

2.3.4 Overall Plant Performance Comparison for the PC Cases .................................... 38

2.4 Circulating Fluidized Bed (CFB) Cases ............................................................................. 40

2.4.1 Steam Cycles for the CFB Cases........................................................................... 41

2.4.2 Steam Generator Designs for the CFB Cases ....................................................... 41

2.4.2.1 CFB Steam Generator Design Philosophy and Scale-up: .......................... 41

2.4.2.2 Heat Transfer Surfaces and Arrangement for the CFB Boilers.................. 43

2.4.2.3 Materials for 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 Equipment for the CFB Cases..................................................... 47

2.4.3.1 Gas Clean-up Systems for the CFB Cases................................................. 48

2.4.3.2 Other BOP Systems for the CFB Cases ..................................................... 49

2.4.4 Overall Plant Performance Comparison for the CFB Cases .................................. 50

2.5 Circulating Moving Bed (CMBTM) Cases ............................................................................ 53

2.5.1 Steam Cycles for the CMBTM Cases....................................................................... 54

2.5.2 Steam Generator Designs for the CMBTM Cases................................................... 54

2.5.2.1 CMBTM Background..................................................................................... 54

2.5.2.2 Heat Transfer Surfaces and Arrangement for the CMBTM Boilers .............. 56

2.5.2.3 Materials for the CMBTM Boilers .................................................................. 59

2.5.2.4 Firing System for the CMBTM Boilers........................................................... 59

2.5.2.5 Air Heater System for the CMBTM Boilers ................................................... 59

2.5.2.6 Start-up System for Supercritical and Ultra-Supercritical CMBTM Boilers ... 59

2.5.3 Balance of Plant Equipment for the CMBTM Cases ................................................ 60

2.5.3.1 Gas Clean-up Systems for the CMBTM Cases ............................................ 60

2.5.3.2 Other BOP Systems for the CMBTM Cases................................................. 60

2.5.4 Overall Plant Performance Comparison for the CMBTM Cases .............................. 62

2.6 Repowering Case............................................................................................................... 65

2.6.1 Steam Cycle for the CMBTM Repowering Case...................................................... 67

2.6.2 Steam Generator Design for the CMBTM Repowering Case .................................. 70

2.6.2.1 Heat Transfer Surfaces and Arrangement for the CMBTM Repowering Boiler

..................................................................................................................... 70

2.6.2.2 Materials for the CMBTM Repowering Boiler................................................ 72
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2.6.2.3 Firing System for the CMBTM Repowering Boiler ........................................ 73

2.6.2.4 Air Heater System for the CMBTM Repowering Boiler................................. 73

2.6.2.5 Start up System for the CMBTM Repowering Case ..................................... 73

2.6.3 Balance of Plant Equipment for the CMBTM Repowering Case.............................. 73

2.6.3.1 Gas Clean-up Systems for the CMBTM Repowering Case.......................... 73

2.6.3.2 Other BOP Systems for the CMBTM Repowering Case .............................. 73

2.6.4 Existing Sporn Plant Description and Performance................................................ 75

2.6.5 Overall Plant Performance for the CMBTM Repowering Case ................................ 78

2.7 Overall Plant Performance Comparison (all Cases) .......................................................... 81

2.7.1 Auxiliary Power Basis: ............................................................................................ 81

2.7.2 Plant Performance Summary:................................................................................. 82

2.7.3 The Effect of Steam Cycle Parameters on Plant Performance: ............................. 90

2.7.4 The Effect of Combustion System on Plant Performance: ..................................... 91

2.7.5 Comparison of CO2 Emissions for All Cases:......................................................... 92

3. Cost Analysis ............................................................................................................................ 93

3.1 Greenfield Cases Investment Costs .................................................................................. 96

3.1.1 Total Plant Investment Costs:................................................................................. 96

3.1.2 Boiler Island Costs:................................................................................................. 98

3.1.3 Turbine Island Costs:............................................................................................ 100

3.1.4 Other Balance of Plant Equipment Costs:............................................................ 102

3.2 Repowering Case Investment Costs................................................................................ 103

3.3 Operating and Maintenance Costs .................................................................................. 105

4. Economic Analysis.................................................................................................................. 106

4.1 Economic Analysis Assumptions ..................................................................................... 106

4.2 Cost of Electricity Calculation........................................................................................... 107

4.3 Economic Analysis Results.............................................................................................. 108

4.3.1 Pulverized Coal Fired Cases ................................................................................ 108

4.3.2 CFB and CMBTM Cases ........................................................................................ 108

4.3.3 Repowering Case ................................................................................................. 109

4.3.4 Economic Sensitivity 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 Sensitivity Study ...................................... 113

4.3.4.4 NOx / SOx Credit Sensitivity Study for Repowering Case ......................... 115

4.4 Economic Study Summary and Conclusions................................................................... 117

5. Conclusions and Recommendations...................................................................................... 121

6. Bibliography ............................................................................................................................ 124

7. Appendices ............................................................................................................................. 125

7.1 Appendix I - Plant Equipment Lists .................................................................................. 126

7.1.1 Boiler Island Equipment for Greenfield Cases...................................................... 127

7.1.1.1 PC Cases Boiler Island Equipment ........................................................... 127

7.1.1.2 CFB Cases Boiler Island Equipment......................................................... 130

7.1.1.3 CMBTM Cases Boiler Island Equipment..................................................... 133

7.1.2 Balance of Plant Equipment for Greenfield Cases ............................................... 136

7.1.3 Sporn Repowering Case Equipment List.............................................................. 152

7.1.3.1 Sporn Repowering Case Boiler Island Equipment.................................... 152

7.1.3.2 Sporn Repowering Case Balance of Plant Equipment ............................. 154

7.2 Appendix II - Drawings ..................................................................................................... 155

7.3 Appendix III – Detailed Investment Costs and Operating and Maintenance Costs......... 170

7.4 Appendix IV - Economic Sensitivity Study Results .......................................................... 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 Temperature Alloy........................................................................................ 202
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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 Economic Sensitivity Results......................................... 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 Economic Sensitivity Results......................................... 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 Economic Sensitivity Results......................................... 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 NOx Credits – Base Phillip Sporn Unit 4

with Purchase of $5k per Ton NOx Credits Economic Sensitivity Results....................... 224

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 ............................................................................................................................. 226

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 ............................................................................................................................. 228

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 ............................................................................................................ 230

7.4.20 Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with $2k

per Ton NOx and $200 per Ton SOx Emissions Credits Sold and $28 per Pound High

Temperature Alloy Economic Sensitivity Results............................................................. 232

7.4.21 Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with $5k

per Ton NOx and $200 per Ton SOx Emissions Credits Sold and $28 per Pound High

Temperature Alloy Economic Sensitivity Results............................................................. 234

7.4.22 Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with $8k

per Ton NOx and $200 per Ton SOx Emissions Credits Sold and $28 per Pound High

Temperature Alloy Economic Sensitivity Results............................................................. 236
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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 Performance ...................................................... 14

Figure 2.2. 2: Steam Cycle #2 Schematic and Performance ...................................................... 15

Figure 2.2. 3: Steam Cycle #3 Schematic and Performance 16

Figure 2.2. 4: Steam Cycle #4 Schematic and Performance ...................................................... 17

Figure 2.2. 5: Steam Cycle #5 Schematic and Performance ...................................................... 18

Figure 2.3. 1: Simplified Gas Side Process Flow Diagram for the PC Cases............................. 20

Figure 2.3. 2: Pulverized Coal 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 Construction and Supporting Structure............................ 25

Figure 2.3. 5: Start-Up System with Low Load Circulation Pump for Supercritical Boilers......... 29

Figure 2.3. 6: SCR Typical Arrangement Diagram...................................................................... 30

Figure 2.3. 7: Simplified Process Flow Diagram for Wet FGD System....................................... 31

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

Injection Rate ......................................................................................................................... 32

Figure 2.3. 9: Thermal Efficiency for PC Cases (HHV Basis) ..................................................... 39

Figure 2.4. 1 Simplified Gas Side Process Flow Diagram for the CFB Cases........................... 40

Figure 2.4. 2: Cyclone Arrangements and Scale Up................................................................... 42

Figure 2.4. 3: Pant Leg Style Combustor – Side View Schematic .............................................. 42

Figure 2.4. 4: Side View Elevation of a 700 MW Supercritical CFB Boiler ................................. 45

Figure 2.4. 5: Isometric View of Second-Generation Supercritical CFB Boiler ........................ 46

Figure 2.4. 6: Flash Dryer Absorber (FDA) Process Schematic Diagram................................... 48

Figure 2.4. 7: Thermal Efficiency for CFB Cases........................................................................ 52

Figure 2.5. 1: Simplified Gas Side Process Flow Diagram for the CMBTM Cases ...................... 53

Figure 2.5. 2: CMBTM Combustion System Schematic................................................................ 55

Figure 2.5. 3: Side Elevation View of a 700MW Supercritical CMBTM Boiler (Case CMBTM -3).. 57

Figure 2.5. 4: Side Elevation of Moving Bed Heat Exchanger (Case CMBTM -3)........................ 58

Figure 2.5. 5: Thermal Efficiency Comparison for CMBTM Cases ............................................... 64

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

Efficiency Steam Cycle........................................................................................................... 66

Figure 2.6. 2: Simplified Gas Side Process Flow Diagram for the Repowering Case ................ 67

Figure 2.6. 3: Repowering Case Steam Cycle Schematic Diagram ........................................... 69

Figure 2.6. 4: CMBTM Combustor General Arrangement Drawing (Side Elevation).................... 71

Figure 2.6. 5: CMBTM Combustor General Arrangement Drawing (Plan View)........................... 71

Figure 2.6. 6: CMBTM Moving Bed Heat Exchanger Surface Arrangement ................................ 72

Figure 2.6. 7: Draft System Schematic Diagram......................................................................... 74

Figure 2.6. 8: Existing Sporn Site Plan........................................................................................ 75

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 Schematic Diagram........................................ 77

Figure 2.6.11: Thermal Efficiency Comparison for the Repowered and Existing Unit ................. 80

Figure 2.7. 1: Boiler Efficiency Comparison for all Cases........................................................... 85

Figure 2.7. 2: Steam Cycle Thermal Efficiency Comparison for all Cases ................................. 86

Figure 2.7. 3: Total Auxiliary Power Comparison for all Cases................................................... 87

Figure 2.7. 4: Plant Thermal Efficiency Comparison for all Cases.............................................. 88

Figure 2.7. 5: Plant CO2 Emission Comparison for all Cases ..................................................... 89

Figure 2.7. 6: Net Plant Heat Rates (HHV basis) 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: CO2 Emissions (lbm/kWh) – All Cases ................................................................. 92

Figure 3.1. 1: EPC Plant Costs – Summary of all Cases............................................................ 97

Figure 3.1. 2: Specific Boiler Costs (Account 4).......................................................................... 99

Figure 3.1. 3: Specific Boiler Island Costs (Accounts 4, 5 and 7) ............................................. 100

Figure 3.1. 4: Specific Turbine Costs (Account 8)..................................................................... 101

Figure 3.1. 5: Specific Turbine Island Costs (Accounts 8, 3, 9, and 11)................................... 102
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ALSTOM Power Inc. xi September 8, 2004

Figure 3.1. 6: Specific Other BOP Equipment Costs (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 Sold or Purchased) ............................................................................... 109

Figure 4.3. 2: Repowering versus Base Case – With NOx Credits ........................................... 110

Figure 4.3. 3: Case PC-3 - Economic Sensitivity Results ......................................................... 111

Figure 4.3. 4: Case CFB-3 - Economic Sensitivity Results....................................................... 112

Figure 4.3. 5: Case PC-5 – High Temperature Alloy Sensitivity Results .................................. 113

Figure 4.3. 6: Case CMBTM -5 – High Temperature Alloy Sensitivity Results........................... 114

Figure 4.3. 7: Case Repowering – High Temperature Alloy Sensitivity Results ....................... 114

Figure 4.3. 8: Case Repowering – NOx Credit Sensitivity Results............................................ 115

Figure 4.3. 9: Case Repowering – Breakdown of COE from NOx Credit Sensitivity Study ...... 116

Figure 4.4. 1: Levelized Cost of Electricity Comparison for PC and CFB/ CMBTM Cases ........ 117

Figure 4.4. 2: Levelized Cost of Electricity Comparison for Repowering 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/ CMBTM Cases .......................................... 119

Figure 4.4. 5: Cost of Electricity for PC Power Plant Cases For Different CO2 Emissions Tax

Rate ............................................................................................................................ 120

Figure 5.0. 1: Cost of Electricity Comparison (All Cases) ......................................................... 122

Figure 5.0. 2: Cost of Electricity Comparison for 1.25 and 1.80 $/MM-Btu Fuel Cost – All Cases.

............................................................................................................................ 122

Figure 7.2. 1 Front Arrangement of 700MW Supercritical CFB Steam Generator................... 156

Figure 7.2. 2 Side Arrangement of 700MW Supercritical CFB Steam Generator.................... 157

Figure 7.2. 3 Plan Arrangement of 700MW Supercritical CFB Steam Generator.................... 158

Figure 7.2. 4 Front Arrangement of 700MW Subcritical CFB Steam Generator...................... 159

Figure 7.2. 5 Side Arrangement of 700MW Subcritical CFB Steam Generator....................... 160

Figure 7.2. 6 Side Arrangement of 700MW Subcritical CFB Steam Generator....................... 161

Figure 7.2. 7 Front Arrangement of 700MW Supercritical CMB Steam Generator.................. 162

Figure 7.2. 8 Side Arrangement of 700MW Supercritical CMB Steam Generator................... 163

Figure 7.2. 9 Plan Arrangement of 700MW Supercritical CMB Steam Generator................... 164

Figure 7.2.10: Philip Sporn Plant - Plan View of Existing Site ................................................... 165

Figure 7.2.11: Topping Steam Turbine for Sporn Unit #4 Repowering Case ............................ 166

Figure 7.2.12: Philip Sporn Sectional Side Elevation 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 Fired Steam Plant with SCR Sensitivity Analysis

Results ............................................................................................................................ 196

Figure 7.4. 3: Case PC-3 – 1 x 660 MW PC Fired Steam Plant with SCR Sensitivity Analysis

Results ............................................................................................................................ 198

Figure 7.4. 4: Case PC-4 – 1 x 680 MW PC Fired 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 Economic Sensitivity Results............................................. 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 $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

Figure 7.4. 8: Case CFB-2 - 1 x 650 MW CFB Steam Plant with SNCR Economic Sensitivity

Results ............................................................................................................................ 208

Figure 7.4. 9: Case CFB-3 - 1 x 660 MW CFB Steam Plant with SNCR Economic Sensitivity

Results ............................................................................................................................ 210

Figure 7.4.10: Case CFB-4 - 1 x 680 MW CFB Steam Plant with SNCR Economic Sensitivity

Results ............................................................................................................................ 212

Figure 7.4.11: Case CMB-3 - 1 x 670 MW CMB Steam Plant with SNCR Economic Sensitivity

Results ............................................................................................................................ 214
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. xii September 8, 2004

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 Results............................................. 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 Economic Sensitivity Results............................................. 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 Sporn Unit 4 Economic Sensitivity

Results ............................................................................................................................ 222

Figure 7.4.16: Case Base Phillip Sporn Unit 4 Purchase NOx Credits – Base Phillip Sporn Unit 4

with Purchase of $5k per Ton NOx Credits Economic Sensitivity Results ........................... 224

Figure 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 ............................................................................................................................ 226

Figure 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 ............................................................................................................................ 228

Figure 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 ............................................................................................................................ 230

Figure 7.4.20: Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with $2k

per Ton NOx and $200 per Ton SOx Emissions Credits Sold and $28 per Pound High

Temperature Alloy Economic Sensitivity Results................................................................. 232

Figure 7.4.21: Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with $5k

per Ton NOx and $200 per Ton SOx Emissions Credits Sold and $28 per Pound High

Temperature Alloy Economic Sensitivity Results................................................................. 234

Figure 7.4.22: Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with $8k

per Ton NOx and $200 per Ton SOx Emissions Credits Sold and $28 per Pound High

Temperature Alloy Economic Sensitivity Results................................................................. 236
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. xiii September 8, 2004

List of Tables

Table 2.1. 1: Site Characteristics (Greenfield Cases)................................................................. 8

Table 2.1. 2: Design Coal Analysis (Medium Volatile Bituminous) for Greenfield Cases........... 9

Table 2.1. 3: Design Limestone Analysis for Greenfield Cases.................................................. 9

Table 2.1. 4: Design Coal Analysis (High Volatile Bituminous) for Repowering Case.............. 10

Table 2.2. 1: Steam Cycle Conditions for Greenfield Cases..................................................... 12

Table 2.3. 1: Gas Side Material and Energy Balance for the PC Cases .................................. 20

Table 2.3. 2: EPA Proposed Mercury Limits ............................................................................. 31

Table 2.3. 3: Stack Design Parameters .................................................................................... 34

Table 2.3. 4: Coal Receiving Design Summary ........................................................................ 35

Table 2.3. 5: Overall Plant Performance Comparison for PC Cases........................................ 38

Table 2.4. 1: Gas Side Material and Energy Balance for the CFB Cases ................................ 41

Table 2.4. 2: Overall Plant Performance Comparison for CFB Cases...................................... 51

Table 2.5. 1: Gas Side Material and Energy Balance for the CMBTM Cases ............................ 54

Table 2.5. 2: Overall Plant Performance Comparison for CMBTM Cases.................................. 63

Table 2.6. 1: Gas Side Material and Energy Balance for the Repowering Case...................... 67

Table 2.6. 2: Gas Side Material and Energy Balance for the Existing Sporn Unit #4............... 76

Table 2.6. 3: Overall Plant Performance Comparison for Repowering Case ........................... 79

Table 2.7. 1: Overall Plant Performance Comparison (all Cases) ............................................ 84

Table 3.0. 1: Operating Labor Requirements............................................................................ 95

Table 3.1. 1: Total Plant Investment Cost Summary for the Greenfield Cases ........................ 97

Table 3.2. 1: Total Plant Investment Cost Summary for the Repowering Case ..................... 103

Table 3.3. 1: Total Plant Operating and Maintenance Costs .................................................. 105

Table 4.1. 1: Economic Evaluation Study Assumptions.......................................................... 107

Table 4.3. 1: Pulverized Coal Systems (PC-1, PC-2, PC-3, PC-4, PC-5) – Economic Analysis

Summary ............................................................................................................................ 108

Table 4.3. 2: CFB and CMBTM Systems (CFB-2, CFB-3, CMBTM -3, CMBTM -4, CMBTM -5) –

Economic Analysis Summary............................................................................................... 108

Table 4.3. 3: Repowering System – Economic Analysis Summary ........................................ 109

Table 7.3. 1: Case PC-1 Investment Costs............................................................................. 171

Table 7.3. 2: Case PC-1 Operating and Maintenance Costs.................................................. 172

Table 7.3. 3: Case PC-2 Investment Costs............................................................................. 173

Table 7.3. 4: Case PC-2 Operating and Maintenance Costs.................................................. 174

Table 7.3. 5: Case PC-3 Investment Costs............................................................................. 175

Table 7.3. 6: Case PC-3 Operating and Maintenance Costs.................................................. 176

Table 7.3. 7: Case PC-4 Investment Costs............................................................................. 177

Table 7.3. 8: Case PC-4 Operating and Maintenance Costs.................................................. 178

Table 7.3. 9: Case PC-5 Investment Costs............................................................................. 179

Table 7.3.10: Case PC-5 Operating and Maintenance Costs.................................................. 180

Table 7.3.11: Case CFB-2 Investment Costs........................................................................... 181

Table 7.3.12: Case CFB-2 Operating and Maintenance Costs................................................ 182

Table 7.3.13: Case CFB-3 Investment Costs........................................................................... 183

Table 7.3.14: Case CFB-3 Operating and Maintenance Costs................................................ 184

Table 7.3.15: Case CFB-4 Investment Costs........................................................................... 185

Table 7.3.16: Case CFB-4 Operating and Maintenance Costs................................................ 186

Table 7.3.17: Case CMB-3 Investment Costs.......................................................................... 187

Table 7.3.18: Case CMB-3 Operating and Maintenance Costs............................................... 188

Table 7.3.19: Case CMB-5 Investment Costs.......................................................................... 189

Table 7.3.20: Case CMB-5 Operating and Maintenance Costs............................................... 190

Table 7.3.21: Sporn Unit #4 Repowering Case Investment Costs........................................... 191

Table 7.3.22: Sporn Unit #4 Repowering Case Operating and Maintenance Costs................ 192

Table 7.3.23: Existing Sporn Unit #4 Operating and Maintenance Costs................................ 193
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. xiv September 8, 2004

Table 7.4. 1: Case PC-1 – 1 x 630 MW PC Fired Steam Plant with SCR Sensitivity Analysis

Results ............................................................................................................................ 195

Table 7.4. 2: Case PC-2 – 1 x 650 MW PC Fired Steam Plant with SCR Sensitivity Analysis

Results ............................................................................................................................ 197

Table 7.4. 3: Case PC-3 – 1 x 660 MW PC Fired Steam Plant with SCR Sensitivity Analysis

Results ............................................................................................................................ 199

Table 7.4. 4: Case PC-4 – 1 x 680 MW PC Fired 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 Economic Sensitivity Results............................................. 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 Economic Sensitivity Results............................................. 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 Alloy Economic Sensitivity Results .......................... 207

Table 7.4. 8: Case CFB-2 - 1 x 650 MW CFB Steam Plant with SNCR Economic Sensitivity

Results ............................................................................................................................ 209

Table 7.4. 9: Case CFB-3 - 1 x 660 MW CFB Steam Plant with SNCR Economic Sensitivity

Results ............................................................................................................................ 211

Table 7.4.10: Case CFB-4 - 1 x 680 MW CFB Steam 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 Economic Sensitivity Results............................................. 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 Economic Sensitivity Results............................................. 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 NOx Credits – Base Phillip Sporn Unit 4

with Purchase of $5k per Ton NOx Credits Economic Sensitivity Results ........................... 225

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 ............................................................................................................................ 227

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 ............................................................................................................................ 229

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 ............................................................................................................................ 231

Table 7.4.20: Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with $2k

per Ton NOx and $200 per Ton SOx Emissions Credits Sold and $28 per Pound High

Temperature Alloy Economic Sensitivity Results................................................................. 233

Table 7.4.21: Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with $5k

per Ton NOx and $200 per Ton SOx Emissions Credits Sold and $28 per Pound High

Temperature Alloy Economic Sensitivity Results................................................................. 235

Table 7.4.22: Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with $8k

per Ton NOx and $200 per Ton SOx Emissions Credits Sold and $28 per Pound High

Temperature Alloy Economic Sensitivity Results................................................................. 237
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. xv September 8, 2004

acfm Actual cubic feet per minute

ANSI American National Standards Institute

ASME American 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

CO2 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. H2O 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 ABBREVIATIONS
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. xvi September 8, 2004

N2 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 & Maintenance
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. xvii September 8, 2004

Executive Summary

Due to 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 efficiency and lower emission, much of this attention has been

directed toward second generation technologies such as coal gasification combined cycle and

fuel cell systems that utilize hydrogen derived from coal gasification processes or natural gas fuel.

Other advanced power plant systems that in addition to power generation may also generate

chemical products have also been emphasized.

Less consideration has been given to potential improvements 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 Energy/ALSTOM Power Inc.

consortium has funded an assessment of Rankine Cycle power plants equipped with three

different combustion systems: Pulverized Coal (PC), Circulating Fluidized Bed (CFB), and

Circulating Moving Bed (CMBTM). Five steam cycles utilizing a wide range of steam conditions

were used with these combustion systems. The purpose of this study is to establish through

engineering analysis, the most cost-effective performance potential available through

improvement in the Rankine Cycle steam 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 Wyomissing, Pennsylvania and American Electric Power

(AEP), from its offices in Columbus, Ohio. The US Department of Energy National Energy

Technology Laboratory provided consultation and funding. ALSTOM provided cost share to this

project.

This report discusses the results of a coal fired steam power plant project, which is comprised of

two parts. The main part of the study was 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 (CMBTM) integrated with five different steam

cycles. The study explores the technical feasibility, thermal performance, environmental

performance, and economic 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 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 coal-fired steam power

plants. With respect to environmental performance, 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 NOx

• < 0.01 lbm/MM-Btu Particulate Matter

• > 90% Hg removal

Mercury control has not been considered in the investment costs or economic analysis for this

study to simplify the analysis. New mercury control technology is currently being developed. It is

believed that the investment and operating cost would be relatively small and approximately the

same for PC, CFB, and CMBTM boiler technologies.
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. xviii September 8, 2004

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. There are currently more than 1,400

coal-fired units in operation in the United States 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 service that could benefit from this repowering

technology. The study evaluates the technical feasibility, thermal performance, and economic

viability of this repowering concept.

Primary results for both parts of the study are summarized in terms of thermal efficiency,

environmental performance, investment costs, and cost of electricity (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 summarize the thermal efficiency, investment cost, and

COE results for all the cases.

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

For the ten Greenfield cases, the calculated thermal 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 CMBTM) 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 CMBTM systems which is due to only partial sulfation in the CMBTM

combustor. The effect of the increasing steam cycle parameters (Temperature and Pressure) is

also clearly illustrated.
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. xix September 8, 2004

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 Existing

Thermal Efficiency - HHV (fraction)

The specific investment cost results for the Greenfield cases are shown in the table above range

from about 1,018 to 1,168 $/kW-net. For the same steam conditions, the CMBTM combustion

system plants require the lowest investment costs as compared to PC or CFB plants. This cost

advantage increases as steam cycle conditions (Temperature and Pressure) are raised. The CFB

systems are about 70 $/kW lower in cost than the PC type combustion systems. This difference is

primarily attributable to the differences in the costs for the gas cleanup 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 Existing

Plant Investment Costs - EPC Basis ($/kW-net )
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. xx September 8, 2004

The levelized cost of electricity (COE) results for the Greenfield cases shown in the table above

range from about 3.4 to 4.0 Cents/kWh. These results indicate that Case CMBTM-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 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 CMBTM 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 the same steam conditions. The advantage of the

CFB systems is attributable to the investment cost savings discussed above. Because of the

additional reduction in investment cost associated with CMBTM based systems, the CMBTM

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 Existing

Cost of Electricity - (Cents/kwhr)

The cost of electricity is directly related to the 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 lowest COE among the power plant cycles analyzed.
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. xxi September 8, 2004

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

5.00

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

CFB-2CFB-3CFB-4

CMB-3CMB-5

Repower

Base

$1.25 per MMBtu

($1.27 per MMBtu for

Sporn Plant)

$1.80 per MMBtu

The following figure shows a comparison of specific CO2 emissions (lbm/kWh) for all the cases.

This figure, in combination with the thermal efficiency results shown above, shows the direct

correlation of CO2 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 CO2 per kWh of net output.

CO2 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 Existing

CO2 Emissions - (lbm/kwhr)

The study has also investigated the impact of potential taxes placed on CO2 emissions. The

figure below illustrates the changes in the COE as the potential 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. xxii September 8, 2004

Cost of Electricity for PC Power Plant Cases For Different CO2 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 technology 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 unit. This difference may quickly disappear if the

price of NOx 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. CO2

emissions are decreased from about 1.94 to 1.80 lbm/kWh, a reduction of about 8 percent.

In summary, from the results of the study the evaluated power plant 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 facilitate construction 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 CMBTM cycles in a 10 to

15 year timeframe. The very high steam temperatures of the ultra-supecritical steam cycle do not

appear to be practical for conventional CFB technology where combustion temperature is

generally limited to 1,5500

F. CMBTM technology with the combustion temperature of 20000F

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

CMBTM 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 require installation of the back end NOx and SOx 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 the 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 temperatures of approximately 1,2000

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. xxiii September 8, 2004

Such a design would fulfill the promise of high efficiency 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 advantage 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. 1 September 8, 2004

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 efficiency 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 improvements in conventional, pulverized, and

fluidized bed coal fired steam power plants, known as Rankine Cycles, that are also capable of

high efficiency and lower emission. A typical Rankine 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 Energy/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 (CMBTM). The purpose of this study

is to establish through engineering analysis, the most cost-effective performance potential

available through improvements in the steam conditions of the Rankine Cycle.

Specific project objectives are listed below:

• Determine the thermal efficiency, investment costs, and economic 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 700MW Rankine Cycle for the same steam

conditions applying PC, CFB, and CMBTM combustion technologies.
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 2 September 8, 2004

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 product 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 5,000psig throttle pressure and steam temperatures of

1,200/1,050/1,050°F at the Eddystone 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 reasons, advanced steam conditions have not been

pursued in the domestic market. There was little motivation to continue lowering heat rates of

fossil-fired plants because of the expected increase in nuclear power generation for base load

application and the availability of relatively inexpensive fossil fuels.

However, due to recent increases in fuel prices 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 friendly 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 have to be burned, there is a pound of coal that

doesn’t need to be purchased, transported, stored and pulverized. If that coal is not burned it is

not necessary to collect and dispose of combustion residues. As a direct function of efficiency,

CO2 emission, which is believed to be a contributor to global warming, is reduced in proportion to

improved efficiency, as are NOx and SOx 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-fired 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 the previous work and expanded it to include an

ultra-high steam conditions power plant cycle. Additionally, 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 parameters 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, CMBTM
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 3 September 8, 2004

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 combustion 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 systems 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 encompass 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 Greenfield 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 (CMBTM). 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

CMBTM), combined with a single number, which identifies the steam cycle used (i.e. 1, 2, 3, 4, or

5). For example, Case PC-3 indicates a pulverized coal combustion system combined with the #

3 steam cycle (i.e. 1,049°F/1,112°F/3,625 psia) as listed above.

Five of the ten Greenfield cases selected include pulverized coal (PC) fired steam generators

equipped with low NOx tangential firing systems. These five PC cases utilize all five of the above

identified steam cycles, which provide discretely different steam conditions, thermodynamic

performance, and equipment design. Additionally three cases are selected with CFB and two

cases are selected with CMBTM 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 selected 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 psia
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 4 September 8, 2004

The final two cases included in the first part of the study are two Greenfield cases with the

following steam conditions selected for plants equipped with advanced circulating moving bed

(CMBTM) steam generators:

• CMBTM-3; 1,049°F/1,112°F/3,625 psia

• CMBTM-5; 1,292°F/1,328°F/5,075 psia

ALSTOM has been pursuing the development of CMBTM technology for the past few years.

Significant progress has been made in understanding combustion and heat transfer processes

unique to the CMBTM technology.

All power plant cases examined in the first part of the study are designed for several common

parameters including the same boiler heat output, 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 require 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 subcritical 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 employed, the steam generator designs and their

auxiliary components will be different. The designs account for inherent differences in coal

combustion, NOx 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 Research Council) 2010 targets.

• > 98% sulfur removal

• < 0.05 lbm/MM-Btu NOx

• < 0.01 lbm/MM-Btu Particulate Matter

• > 90% Hg removal

Mercury control has not been considered in the investment costs or economic analysis for this

study to simplify the analysis. New mercury control technology is currently being developed. It is

believed that the investment and operating cost would be relatively small and approximately the

same for PC, CFB, and CMBTM boiler technologies.

Repowering Study:

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. 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 being analyzed for a repowering scenario.

The proposed repowering concept uses a number of new plant components integrated with the

existing plant components to the maximum extent practical. The repowered plant includes a new

CMBTM boiler. It also includes a new topping steam turbine that expands steam from the new

CMBTM 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. 5 September 8, 2004

The scope of this second part of the study is to determine the overall thermal performance,

investment cost, and incremental cost of electricity for repowering the plant to operate at these

higher steam conditions. The incremental cost of electricity is incremental 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 emission control system would be installed and at a

minimum, the current air emission standards would be maintained. However, the CMBTM boiler

produces inherently low NOx emissions. It is capable of 0.10 lbm/MM-Btu NOx emission without

SNCR as compared to the existing unit emission of 0.57 lbm/MM-Btu. Since NOx emissions are a

tradable commodity, particularly during the five-month ozone season when NOx emission is

limited to 0.15 lbm/MM-Btu, the economic analysis (Section 4) includes NOx trade allowances.
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 6 September 8, 2004

2. Case Studies; Plant Performance, Design and Equipment

This section of the report provides detailed descriptions 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 processes 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 effort of the study, is an evaluation 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 distinct groups, which utilize different Boiler Island

systems for combustion of the coal. The first group includes 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 (CMBTM) boilers and two of the same steam cycles used in the

PC group. One of the steam cycles used in the CMBTM 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 performance for the large fleet of existing older coal fired power

plants. The Philip Sporn plant, owned by American Electric Power (AEP), is being analyzed to

estimate the performance and cost of repowering the 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 repowering 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 the 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 designed for a constant heat input to the steam

cycles (i.e. boiler heat output). 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, 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. 7 September 8, 2004

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, capable of carrying AASHTO H-20 S-16 loads and with

overhead restriction of not less than 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 the site is rolling hills, with elevations within

2,000 yards not more than 300 feet above the site elevation. 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 plants 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 administration, 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 transformer, foundations, and standby equipment.

Additionally, the following utilities are assumed to be available at the site boundary.

• Communication lines

• Electrical power for plant construction

• Potable water and sanitary sewer connections

• Electrical transmission facilities and lines
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 8 September 8, 2004

Plant Ambient Design Conditions:

Table 2.1.1 lists ambient and other relevant characteristic 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 repowering 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 Value

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 CMBTM 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. 9 September 8, 2004

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

CaCO3 (wt. frac.) 83.71

Moisture " 1.00

Impurities " 7.08

MgCO3 " 8.21

Total " 100.00
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 10 September 8, 2004

Table 2.1. 4: Design Coal Analysis (High 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 Matter " 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 available 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 inverters, uninterruptible ac power for the integrated

control and monitoring system, intercommunication.

• 125 Vdc system for dc controls, emergency lighting, 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 corrosion 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 μm or lower.
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Hydrogen and Carbon Dioxide:

• H2 and CO2 for generator cooling and purging from storage.

Nitrogen:

• N2 for equipment blanketing against corrosion during shutdown and lay-up.

Raw Water:

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

Structures and Foundations:

Structures are provided to support and permit access to all plant components requiring support to

conform to the site criteria. The structure(s) are enclosed if deemed necessary to conform to the

environmental conditions.

Foundations are provided for the support structures, pumps, tanks, and other plant components.

A soil-bearing load of 5,000 lbm/ft 2 is used for foundation design.
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2.2 Steam Cycles for the Greenfield Cases

Five steam cycles were selected for the ten Greenfield cases. These cycles (~700-820 MWe

gross output) have discretely different steam conditions, thermodynamic performance, and

equipment design. Steam turbine design conditions 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 well, which is a receptacle for the condensed steam

from the exhaust of the steam turbine. The condensate flows to the suction of the condensate

pumps, which increase the pressure of the fluid 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 cycle) low-pressure feedwater heaters. Steam Cycle

#5 utilizes five LPFWH’s whereas all the other steam cycles use four. The heaters successively

increase the condensate temperature by condensing and partially sub-cooling steam extracted

from the LP steam turbine section. Each heater receives a separate extraction steam stream at

successively higher pressure and temperature. The condensed steam (now referred to as heater

drains) is progressively passed to the next lower pressure 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 heaters, 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 evaporated and finally superheated. The high-pressure

superheated steam leaving the finishing superheater 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 expands 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.
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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 CMBTM cases as indicated in the table above.
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Figure 2.2. 1: Steam Cycle #1 Schematic and Performance
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Figure 2.2. 2: Steam Cycle #2 Schematic and Performance
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Figure 2.2. 3: Steam Cycle #3 Schematic and Performance
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Figure 2.2. 4: Steam Cycle #4 Schematic and Performance
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Figure 2.2. 5: Steam Cycle #5 Schematic and Performance
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2.2.2 Steam Cycle Equipment

This section provides a brief description of the major equipment included with the steam cycle,

including the steam turbine generator, the condensate 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 passes through the stop valves and control valves

and enters the turbine. The steam initially enters the turbine near the middle of the high-pressure

span, flows through the turbine, and returns to the boiler for reheating. The reheated steam flows

through the reheat stop valves and intercept valves and enters the IP sections. After passing

through the IP sections, the steam enters a crossover pipe, which transports the steam to the two

LP sections. The steam is divided into two paths 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; two 50 percent capacity, motor-driven vertical

condensate 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 the recirculation flow. In addition, the suctions of

the boiler feed pumps are equipped with startup strainers, 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 designs 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 treatment 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 condensers. For this reason, once through designs

require a condensate polishing system. Steam purity requirements are the same regardless of the

type of boiler used.
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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 NOx emission control, an electrostatic 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 NOx tangential firing systems capable

of reducing furnace NOx emissions to 0.25 lbm/MM-Btu. All five PC fired cases are identical with

respect to the gas side energy and material balance. 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 Ash 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 percent 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 rate and thermal efficiency of 8,768 Btu/kWh and

38.93 percent respectively. The Case PC-4 supercritical plant produces a net output of about 677

MWe with a net plant heat rate and thermal efficiency of 8,580 Btu/kWh and 39.78 percent
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respectively. Finally, the Case PC-5 ultra-supercritical plant produces a net output of about 742

MWe with a net plant heat rate and thermal efficiency of 7,838 Btu/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 these 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 this group allows quantification of differences in

performance, investment costs, and economics (cost of electricity) as a function of steam

conditions. Several of these steam cycles are also used in the other combustion system groups

(CFB and CMBTM) which will provide a direct comparison of the effect of coal combustion system

changes. For example, the steam cycle used for Case PC-2 is identical to that used for Case

CFB-2 (Refer to Section 2.4). Other steam cycle 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 output. 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 selection 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 reheat systems of 10% of the turbine cold reheat

pressure. Half of this pressure 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 for 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 typical boiler arrangement of a once-through supercritical steam

generator. It is a two-pass gas design with pendant heating surfaces located in the upper furnace
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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. After leaving the lower furnace, the flue gas enters

the upper furnace where wide-spaced superheat division panels and superheat platens cool the

gases. Downstream of the platens and above the arch, there is a finishing reheater followed by a

finishing superheater pendant. To minimize the effect of a high radiant heat flux emitted by the

combustion process in the furnace, the final superheat 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 quantities are significantly larger than for the more

conventional steam temperature designs.
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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 Boiler
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Figure 2.3.3 shows a simplified high pressure main 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 tubes 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 designs 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 supercritical 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 integral part of the start-up system discussed in

the start-up system section of this paper.
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The waterwall construction for subcritical and supercritical designs is similar. Both use a rifled

tube, vertical wall configuration. The supercritical 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 they 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. These steels are relatively inexpensive, have satisfactory strength,

are easily fabricated, and are resistant to corrosion and oxidation from steam and furnace gases.

For subcritical designs, the waterwalls are constructed of carbon steel 210C. The supercritical

designs require application of conventional low chrome (Cr) ferritic steels T12 (1Cr-1/2Mo) and
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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, ultra 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. This 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 steels 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 strength 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 practical. 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 consideration. 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 following 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 ultra-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 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 and air for combustion, mixes the reactants, ignites the mixture,

and distributes the flame envelope and the products of combustion. The firing system is

comprised of several components or sub-systems including the windbox, the steam temperature

control system, the ignition system, 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 air compartments with dampers associated with each

compartment. One windbox is located in each corner of the rectangular furnace. Both the fuel
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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 they 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 flame 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 NOx control. The NOx 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 nozzle 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 capability 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 reduced. When tilted up the reverse occurs.

This tilting capability therefore gives the operator (or control system) the ability to control

superheater or reheater outlet temperature with 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 continuously 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 for the capability of igniting fuels ranging from No.

2 to No. 6 fuel oil. The system uses an electrical capacitor discharge device for producing a high

intensity spark. There is one elevation of HEA igniters for each elevation of light oil warm-up

guns. The warm-up guns are used to light 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 pulverizer feeds one windbox elevation of coal nozzles.

The pulverizers are of the HP configuration and include DynamicTM Classifiers and are designed

to provide fine grind (85% through 200 mesh) pulverized 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 force 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 mixture 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 classifier where secondary classification occurs. The

rotational speed of the dynamic classifier determines the ultimate fineness. The coal leaving the

dynamic classifier through the exhauster then enters the fuel piping system while oversized

particles return to the bowl for additional grinding.
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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 where 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 heaters were installed. The air heater system is used

for increasing the efficiency of the system by reducing the exit gas temperature 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 preheater design is a very efficient and cost effective

air heating system. The utilization of rotating modular elements with highly efficient heat transfer

surface makes these air heaters extremely compact and cost effective for a large amount of heat

transferred.

Sootblowers are used to clean the air heater heat transfer surfaces. The sootblower drive unit is

located externally and can be serviced while the unit 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 provide disturbance-free operation 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 pumps 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 water 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 all supercritical PC, CFB, and CMBTM designs in this study.
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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 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 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 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 NOx reduction, particulate removal, and sulfur removal.

Particulate removal is done with an electrostatic precipitator and sulfur (SO2) is removed with a

wet flue gas desulfurization (FGD) unit.

The selective catalytic reduction system uses a catalyst and a reductant (ammonia gas, NH3) to

dissociate NOx to nitrogen gas and water vapor. The SCR 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 with SCR operating temperatures of 575 to 750°F.

Upstream of the SCR chamber are the ammonia 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.
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Figure 2.3. 6: SCR Typical Arrangement Diagram

Boiler flue gas enters the spray tower and is contacted by the absorbent slurry where the SO2 is

absorbed reducing SO2 emissions by 98%. The spent sorbent drains 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 regenerated 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.
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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 stream 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. Make-up water is added to the system to replace

evaporated water and water carried with the waste 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 meeting 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 1.1
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Therefore, the industry needs mercury control technologies that can effectively meet regulations

on a wide variety of coal characteristics. Recent 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. However, mercury removal is difficult for lignite and

sub-bituminous coals compared to bituminous coals because of the high proportion of elemental

mercury in the flue gas. A fabric filter captures mercury to a higher degree compared to an ESP

due to enhanced gas-sorbent contact. However, it is capital intensive (~ $30 - 50/kWe). 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 ALSTOM (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/kWe, and sorbent consumption is expected to be comparable to a fabric filter

(~ 5 lbm/MM-acf). The Mer-Cure approach employs a sorbent preparation and injection system

that enhances sorbent performance by changing the 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 funded tests at the University of North Dakota – Energy and

Environmental Research Center. In these tests, the performance of this technology was

compared to current industry standard: Norit Darco FGDTM sorbent injection. Results are

presented in Figure 2.3.8 from the firing of a lignite 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-382

Hg (t) Concentration (

μg/Nm3 )

Sorbent Feed Rate X 4X X/4 X/2 X/4 X/4

 

41%

57%

69%

74%

88%

92%

Removal %

Baseline ALSTOM
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Comparison is also provided for standard sorbent injection 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 investment costs or economic analysis for this

study to simplify the analysis. New technology is currently being developed. It is believed that the

investment and operating cost would be small and approximately the same for PC, CFB, and

CMBTM boiler technologies.

2.3.3.2 Other BOP Systems for the PC Cases

The equipment in the category of other BOP equipment 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 SCR, 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, which disperses the flue gas 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 (temperature controlled) air to the pulverizers for

pulverized coal drying and transport of the pulverized coal to the furnace. It is preheated in a

steam coil air heater (during cold ambient conditions only) and a regenerative air preheater.

Temperature control for the pulverizers is achieved 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 sections. The flue gas leaving the convection pass

flows through the SCR and regenerative air pre-heaters and then exits 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 primary 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 units 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.
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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 CMBTM 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 criteria 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 Value

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 the repowering case, use the exact same equipment

for coal handling and preparation. This is possible because the heat output from the boiler is the

same for all cases. The function of the coal handling 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 unloading is done by a trestle bottom dumper, which

unloads the coal to two receiving hoppers. Coal from each hopper is fed directly into a vibratory

feeder. The 6" x 0 coal from the feeder is discharged 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 remove tramp iron and then to the reclaim pile.

Coal from the reclaim pile is fed by two vibratory 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-off collection, and treatment systems:
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− 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 Value

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 handling system is to receive and store prepared

limestone on an as-needed delivery basis. The system 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 discharged 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 solids (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 baghouse. Fly ash is removed from the stack gas

through an electrostatic precipitator.

Ash Handling:

The function of the ash handling system is to convey, prepare, store, and dispose of the flyash

and bottom ash produced on a daily basis by the boiler. 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, economizer, 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 telescopic 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 two 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 operation

at reduced load. The condenser cooling load varies significantly from case to case with Case PC1 being the highest (2,808 x 106

 Btu/hr) and Case PC-5 being the lowest (2,480 x 106 Btu/hr).
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Although the cooling load varies among the cases, the design of the system is similar for all

cases. Only capacity changes are required for the circulating water system equipment.

Waste Treatment System:

An onsite water treatment facility treats all runoff, 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 slurry makeup system with 50-ton lime silo, a 0 -

1,000 lbm/hour dry lime feeder, a 5,000-gallon lime slurry tank, slurry tank mixer, and 25 gpm

lime slurry feed pumps.

Miscellaneous systems:

Miscellaneous systems consisting of fuel oil, service air, instrument 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 cable trays, all wire and cable. It also includes

the main power transformer, all required 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 minimum load to 100 percent. Startup and shutdown

routines are implemented as supervised manual with operator selection of modular automation

routines available.

Buildings and Structures:

A soil-bearing load of 5,000 lb/ft2

 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 building
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• 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.
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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 cases. 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 (Controls, 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 0.4355
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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-5

Thermal Efficiency - HHV (fraction)

Figure 2.3. 9: Thermal Efficiency 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 constant fuel heat input and the same steam

temperatures leads to an increase in net plant 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 design (Case PC-5 vs. PC-1). This represents more

than 6.5 percentage points in thermal efficiency improvement and an 18% reduction in CO2

emissions.
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2.4 Circulating Fluidized Bed (CFB) Cases

The three Circulating Fluidized Bed (CFB) steam 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 CMBTM-3 (refer to Section

2.4). The steam cycle used for Case CFB-4 is identical to that used for Case PC-4. Thus there is

good comparability from group to group allowing identification of advantages and disadvantages

of one type combustion system as compared to another 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. NOx emissions are inherently low with CFB

boilers. The basic design of the furnace combined with high efficiency cyclones and intensive air

staging results in NOx emissions of 0.20 lbm/MM-Btu. Additional reduction to 0.05 lbm/MM-Btu

level is achieved by integration of the SNCR system with the furnace. All three CFB cases are

identical with respect to the gas side energy and material balance. Figure 2.4.1 shows a

simplified gas side process flow diagram for the 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 Cases
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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 Ash 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 rate 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 rate 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 cases (PC-2, PC-3, PC-4) and the description is not repeated here.

Additionally, the steam cycle used for Case CFB-3 is identical to that used for Case CMBTM-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 CMBTM units (CMBTM-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 which affect the ability to meet performance

requirements (emissions, Ca/S, and efficiency) are 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 pressure 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 added as required to maintain gas velocities at

optimum levels. Figure 2.4.2 illustrates this design 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).
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< 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 heat 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.
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Properly designed nozzles allow for proper air distribution in the lower combustor region, which

contributes to optimal residence time of the fuel, sorbent and ash in the primary loop. The

location of the secondary air along the front and rear walls of the combustor aids in combustion

as well as creates conditions to minimize NOx formation.

Cyclones in a CFB separate the entrained solid particles 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 capture 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 size 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 utilizing a modular approach, an increase in unit

size can be accommodated without developing a new FBHE design.

The backpass of the CFB boiler accommodates horizontal surfaces including the low temperature

superheater, low temperature reheater, and economizer. The arrangement is similar to that

utilized in a conventional pulverized 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 predictions, 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. Cyclones 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 the firing technology used, backpass sizing is a welldefined, low-risk procedure. Finally, modularized FBHE construction has been used in the

design. The resulting 700MW designs are essentially 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 are 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 sides ensuring appropriate

mixing of coal, air, and sorbent.
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The major difference between the subcritical and supercritical 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 installation of which necessitated increasing either the

size or the quantity of the FBHE’s. The decision 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.
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Figure 2.4. 4: Side View Elevation of a 700 MW Supercritical CFB Boiler
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Figure 2.4. 5: Isometric View of Second-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 predominate in the construction of the low temperature

reheat and superheat sections. The finishing reheater and superheater tubes are constructed of

stainless steels, TP304H, TP347, and HR3C.

The once-through supercritical CFB’s feature slightly higher-grade alloys. For the waterwalls the

vertical tubes require T12 and T23 alloys. The supercritical 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 finishing tubes. For the hottest metal temperature

surfaces, high strength stainless 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 the
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mixture. The firing system is comprised of several components or sub-systems including the

ignition system, the fuel feed system, 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 combustion air system, the fuel oil and atomizing media supply

systems, and controls.

Fuel Feed System:

The fuel feed system transports prepared coal from the storage silos to the lower combustor. The

system includes the storage silos, silo isolation valves, fuel feeders, 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 storage silos, silo isolation valves, rotary feeders,

blower, and piping from the blower to the furnace 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 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 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 and Appendix II for drawings.
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2.4.3.1 Gas Clean-up Systems for the CFB Cases

To achieve the NOx emissions of 0.05 lbm/MM-Btu the CFB combustor is integrated with the

SNCR system. The SNCR method requires the injection of ammonia in the upper region of the

combustor. With today’s technology such low NOx emissions are possible for relatively few coals.

However, new combustion arrangements, aided by CFD modeling, are being developed to

enlarge the range of coals that can be burned producing very low NOx 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 since

each 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 SO2 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 product 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 combustion 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 unit, capture of about one-third of the coal-derived

sulfur, as calcium sulfate, occurs. The gas discharge from the boiler to the FDA system thus

contains some SO2, and a burden of particulate matter consisting of reacted and unreacted

calcium compounds as well as fly ash. Approximately 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 fabric 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 individual filter bags. The particulate is retained

on the outside of the filter bags and the cleaned gas flows out the top of the bags and into the

clean-gas outlet ductwork. When the dust deposits 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 into
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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 filter that is a high-ratio, intermediate-pressure,

pulse-cleaning unit known as an LKP. The fabric 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 the 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 substantially to the overall SO2 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/conditioner 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 SO2 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 fabric filter compartment. The water added for gas

cooling and humidification is fully evaporated before the dust reaches the filter bags. Completion

of the SO2-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 small 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 commercially applied to utility coal-fired boilers. The process has been

tested on diesel engines as well as wastes-to-energy flue-gas cleaning applications. The process

entered the commercial market in mid-1997, after 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 equipment 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 description 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:
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• Primary air fans, which provide forced draft primary airflow to the combustor grate and fuel

feed chutes. 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 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 electric 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 units supplied with electric motor drives and inlet dampers. The

total electric power required for the electric motor drives is 10,924 kW. This power

requirement is the same for all three CFB cases.

• Fluidizing air blowers, which provide air to the 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 CMBTM 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 comparison 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 thermal efficiency for the CFB cases.

This plot visually illustrates the effect of steam cycle parameters (temperature, pressure) on plant

thermal efficiency. The thermal efficiency changes for the CFB cases are nearly identical to those

for the PC fired cases as would be expected.
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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 0.3983
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0.3803

0.3898

0.3983

0.37

0.38

0.39

0.40

CFB-2 CFB-3 CFB-4

Thermal Efficiency - HHV (fraction)

Figure 2.4. 7: Thermal Efficiency for CFB Cases
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2.5 Circulating Moving Bed (CMBTM) Cases

Two steam cycles (~736 & 821 MWe gross output) with the following steam conditions are

selected for plants equipped with advanced CMBTM steam generators. The CMBTM steam

generators both fire the same amount of fuel. These cases are designated CMBTM-3 and CMBTM5 as shown below.

• CMBTM-3: 1,049°F/1,112°F/3,625 psia

• CMBTM-5: 1,292°F/1,328°F/5,075 psia

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

The steam cycle used for Case CMBTM-5 is identical to that used for Case PC-5. This

commonality of steam cycles provides for comparative analysis of the various coal combustion

systems.

Each CMBTM case includes a fabric filter baghouse for particulate removal integrated with a flash

dryer absorber (FDA) system for sulfur capture. Both CMBTM 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 CMBTM 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 

Removal

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 CMBTM Cases
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Table 2.5. 1: Gas Side Material and Energy Balance for the CMBTM Cases

CMB Cases Point 1 Point 2 Point 3 Point 4 Point 5 Point 6 Point 7

Coal Limestone Ash 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 CMBTM cases, each of which consumes fuel at the same

rate, reveals the following information. The Case CMBTM -3 supercritical plant produces a net

output of about 665 MWe with a net plant heat rate and thermal efficiency of 8,781 Btu/kWh and

38.87 percent respectively. Similarly, the Case CMBTM -5 ultra-supercritical plant produces a net

output of about 744 MWe with a net plant heat rate and thermal efficiency of 7,853 Btu/kWh and

43.46 percent respectively. Detailed plant performance for the CMBTM cases is shown in Section

2.5.4.

2.5.1 Steam Cycles for the CMBTM Cases

The steam cycles for the two CMBTM cases (CMBTM -3, CMBTM -5) are identical to the two steam

cycles used for the cases PC-3, and PC-5 respectively, and the description is not repeated here.

Refer to Section 2.2.1 for a description of these steam cycles. Additionally, the case CMBTM -3

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

2.5.2 Steam Generator Designs for the CMBTM Cases

Two CMBTM steam generator units of a nominal capacity 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 CMBTM boiler. The two CMBTM units are directly comparable to the appropriate PC fired

units that utilize the identical steam cycle. One of the CMBTM units (CMBTM -3) is also directly

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

2.5.2.1 CMBTM Background

Circulating Moving Bed (CMBTM) combustion system technology (illustrated 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 CMBTM 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 bubbling 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 combustion (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 chemically inert, and are readily available.
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Figure 2.5. 2: CMBTM Combustion System Schematic

Once the solids have recuperated the heat of combustion, they collect at the bottom of the

combustor where they are fluidized and transferred to a lower chamber through standpipes. The

lower chamber consists of a counterflow, direct 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 particles 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 itself 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 rates higher than gas-only convection. The use of

extended heat transfer surfaces that have significant contact surface with the moving solids is a

key attribute that makes the CMBTM 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 N2O emissions, low carbon monoxide emissions, and hence,

increased combustion efficiency with reduced pollutant emission. A unique feature of the CMBTM

combustion system process is that combustion, heat transfer, and environmental control

processes are effectively de-coupled and can be optimized separately. The lower combustor is

staged for NOx 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

SO2 emissions will be controlled primarily by a backend cleanup system such as ALSTOM’s
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Flash Dry Absorber (FDA). Limestone is calcined in the combustor for use in the backend

desulfurization system and additional sulfur capture can be achieved in the combustor also.

Through an extensive test campaign that has been 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 CMBTM design have been characterized. The test campaign has

explored the issues related to combustion, carbon loss, NOx and SO2 emissions gas flow and bed

dynamics, gas to solids heat transfer, solids to tube heat transfer, heat transfer surface fouling,

and agglomeration. The information developed so far has been used in the conceptual design

and analysis of the two 700MWe CMBTM boilers shown in this study.

2.5.2.2 Heat Transfer Surfaces and Arrangement for the CMBTM Boilers

The two CMBTM designs, supercritical (Case CMBTM -3) and ultra-supercritical (Case CMBTM -5),

have many components in common and have the same general arrangement of heat transfer

surface and auxiliaries. Both are designed for the same firing rate and have the same size and

quantity of combustors, ductwork, and other boiler auxiliaries. Low NOx and SO2 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. Figure 2.5.3 shows a side view elevation of the

supercritical CMBTM design while Figure 2.5.4 shows a side view of the moving bed heat

exchanger showing the arrangement of the various heat exchanger sections within the moving

bed. Both these figures are for Case CMBTM -3 although as mentioned, Case CMBTM -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 hot 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 are progressively cooled while 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.
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Figure 2.5. 3: Side Elevation View of a 700MW Supercritical CMBTM Boiler (Case CMBTM -3)
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Figure 2.5. 4: Side Elevation of Moving Bed Heat Exchanger (Case CMBTM -3)

There is a refractory lined combustor constructed of three octagonal shaped and connected

modules. The overall approximate depth and width 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 are transported to the three MBHE’s via the

standpipes. The working fluid heat transfer surface is installed in the MBHE’s. The feedwater and

steam heat exchangers are arranged in countercurrent 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 and 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. The particles are then ready to restart the heat

recuperation process. The air streams leaving the small cyclones are used for combustion as part

of the secondary air.
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2.5.2.3 Materials for the CMBTM Boilers

Case CMBTM -3:

The materials of construction for the supercritical design (CMBTM -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 the economizer tubes to stainless steel for the

superheat and reheat finish tubes.

Case CMBTM -5:

The materials for the construction of tubing for the ultra-supercritical design (CMBTM -5) require

Ni-based alloys for high temperature sections. The 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 the 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 CMBTM Boilers

The firing system for the CMBTM 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 CMBTM Boilers

The air heater system for the CMBTM 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 Supercritical and Ultra-Supercritical CMBTM 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.
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2.5.3 Balance of Plant Equipment for the CMBTM Cases

The balance of plant equipment described 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 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 and Appendix II for drawings.

2.5.3.1 Gas Clean-up Systems for the CMBTM Cases

The gas cleanup systems (NOx control, particulate removal, and sulfur removal) for the CMBTM

cases are similar to those used for the CFB cases except that most of the SO2 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 description 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 CMBTM Cases

The equipment in the category of other BOP equipment 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 CMBTM cases are

identical to those for the PC cases and the descriptions 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 CMBTM cases are nearly identical to equipment used for the

CFB cases and the description is not repeated here. Refer to Section 2.4.3.2 for the description of

the other BOP equipment.

Draft System:

The draft system for the CMBTM 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

CMBTM cases. Furthermore, the pressure rises, flow rates, and power requirements for the

CMBTM cases fans are different than for the corresponding fans for the PC cases.

The following fans are provided for the CMBTM steam generators:

• Primary air fans, which provide forced draft primary airflow to the combustor grate and fuel

feed chutes. 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 14,037 kW. This power requirement is the same for both CMBTM

 cases.

• Secondary air fans, which provide forced draft secondary airflow to the combustor. 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 1,219 kW. This

power requirement is the same for both CMBTM

 cases.

• Induced draft fans, centrifugal units 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 CMBTM

 cases.

• Fluidizing air blowers, which provide air to the 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 840

kW. This power requirement is the same for both CMBTM

 cases.
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The total power requirement for the CMBTM 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.
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2.5.4 Overall Plant Performance Comparison for the CMBTM Cases

Table 2.5.2 shows a fairly detailed comparison 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 736–821 MWe with improved steam conditions, while total auxiliary power

ranges from about 9.4 - 9.6 percent of generator output. The resulting 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 CMBTM cases. This plot visually illustrates the effect of steam

cycle parameters (temperature, pressure) on plant thermal efficiency. The efficiency improvement

for the CMBTM cases is almost the same as was shown for the PC fired cases as would be

expected.
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Table 2.5. 2: Overall Plant Performance Comparison for CMBTM 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 0.4346
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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-5

Thermal Efficiency - HHV (fraction)

Figure 2.5. 5: Thermal Efficiency Comparison for CMBTM Cases
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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 power 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 higher 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 with 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 existing components to the maximum extent practical.

The repowered plant includes a new CMBTM boiler (refer to Section 2.5.2.1 for CMBTM

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 CMBTM 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. The topping turbine produces an output of about 32

MWe. The exhaust steam from the topping steam turbine, 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 CMBTM

boiler where it is reheated to 1,005°F. The reheated 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 CMBTM boiler minimizes the length of the very expensive high

temperature steam piping.
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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 precipitator 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.
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Figure 2.6. 2: Simplified Gas Side Process Flow Diagram for the Repowering Case

Air Heater

Secondary

Air Fan

Primary

Air Fan

Transport Air

Coal

Fluidizing

Air Blower

Limestone

Cooled

Solids

Falling

Solids

Combustor

Cyclone

CMBTM Steam Generator Unit

1

2

Moving

Bed

Heat

Exchanger

Induced

Draft Fan

FDA &

Particulate

Removal

3

Ash

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 Ash 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 approximately 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 CMBTM boiler is sized for the required additional firing rate that is about 9.8%

higher than in the existing boiler. The repowered 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 for 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 CMBTM 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 CMBTM 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 throttle conditions of the existing

steam turbine. The topping turbine steam flow is selected to provide the existing high-pressure
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turbine with the same flow as it would normally 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 CMBTM 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 turbine and the existing steam turbine is about 204

MWe.
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 69 September 8, 2004

H

H

GE

GS

5.4

SE

SE

HEAT BALANCE DIAGRAMPHILIP SPORN PLANTTopping SP 700C ,HP Flow as was

Drawn:Checked:Approved:

2003-04-09

Doc F L Sh.No. N.o.Sh.

E

PTHMTS

PressureTemperatureEnthalpyMassflowSaturation temperature

psia'FBtu/lblb/h'F

We reserve all rights in this document and in the information contained therein Reproduction use or disclosure to third parties without express authority is strictly forbidden Copyright © ALSTOM Power (Switzerland) Ltd 2003

S:\AEP\Final2\AEP

_

Philip_Sporn_Topping.alg

M59

H1338 M

174 H

1338 M

174 H

1338 M

59

H1338

P 14.94P 11.60

E

_KIN9.2 E

_KIN9.2

M60

H1521

P 11.60

M1

1 H

1521 M

16

H152

1

M59

H133

M 8101 H

1338

P14.94

M10

1 H

1338

5.3 5.2 5.4

M221 H

1354 M

283 H

1354

M20

H150

M 518

H150

5

M327 H

147

M 4-25

H1466

P11.60P14.94

P85.93

M48

3 H

1354 M

432 H

1505

G

Gland system sprayGland system excess steamGland sealing system excess

GSGESE

8.0 11.5 8.1 11.6 2.8

P 504.9T 699.0H 1356.8M 98929

P 196.4T 785.9H 1418.4M 6938

P 2522T 316.6H 291.3M 1077835

P 46.81T 276.9H 1147.8M 49843

P 20.74T 327.4H 1204.4M 19521

P 11.60T 794.9H 1430.7M 8929

P 9.671T 213.2H 1153.0M 39326

P 3.100T 142.8H 1086.5M 32499

P 310.0T 267.9H 237.3M 942566

T 366.3H 342.5

M 40340

T 310.7H 280.8

P 458.6T 1000.0H 1521.5M 964416 P 504.9

T 699.0H 1356.8M 1023005

P 4242T 1292.0H 1609.9M 1077835

P 9.671T 213.2H 1153.0M 826100

T 60.0H 28.2M 6239

M 1200

P T H M 

T 220.7H 189.6

T 197.5H 166.2

T 183.7H 152.4

T 134.4H 103.1

T 95.9H 64.7

P_EL 43886 

P 2016T 1050.0H 1505.0M 1039500

T 671.3H 1365.9M 52518

T 374.4H 351.6

T 312.0H 299.1

T 188.4H 168.4

T 200.3H 194.2

T 225.9H 242.2

P 0.781H 1024.0

M 795899

P 85.93T 979.0H 1521.5M 5476T 671.3H 1365.9M 16791

M15

H1503 M

197 H

1503

M42

H160

M 926

H1609

M10

H160

M 9140 H

1609

P11.60P14.94

P196.4

M199

H150

3 M

140

H160

9

G

P 196.4T 1034.4H 1547.3M 34015

P 4587T 460.0H 444.2M 1077835P 2522T 452.7H 434.5M 1077835

P_EL 31840

Figure 2.6. 3: Repowering Case Steam Cycle Schematic Diagram
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ALSTOM Power Inc. 70 September 8, 2004

Exhaust steam from the existing LP turbine is condensed in the existing condenser and also

utilizes the existing condensate and feedwater systems to provide preheated feedwater to the

new CMBTM boiler as described below.

The condensate leaving the existing condenser flows to the suction of the existing condensate

pumps, which increase the pressure of the fluid and transport it through the new condensate

polishing system, the existing low-pressure feedwater heaters, and the existing condensate

piping system which enables it to enter the existing 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 increase the condensate temperature

to 267.9°F by condensing and partially sub-cooling steam extracted from the existing LP steam

turbine section. Each heater receives a separate extraction steam stream at successively higher

pressure and temperature. The condensed steam (now referred to as heater drains) is

progressively passed to the next lower pressure heater.

The condensate entering the deaerator is further 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 deaerator 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 electric motor driven. The boosted condensate flows

through two existing high-pressure feedwater heaters, 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 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 high-pressure heater

draining to the deaerator.

Within the new CMBTM boiler, the feedwater is progressively 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 CMBTM Repowering Case

The CMBTM steam generator unit for the repowering case was designed for a nominal capacity of

204 MWe gross to match the repowered steam cycle described above. The basic description of

operation and CMBTM background information was provided previously for Cases CMBTM -3 and

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

2.6.2.1 Heat Transfer Surfaces and Arrangement for the CMBTM Repowering Boiler

The CMBTM combustor, shown on the general arrangement 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 burning 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 recycled 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 heat transfer surface, the Ljungstrom air preheater,

that captures heat from the flue gas to raise the temperature of the primary and secondary air
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entering the furnace. The flue gas exiting the air preheater proceeds to the existing ESP for the

final clean up.

Figure 2.6. 4: CMBTM Combustor General Arrangement Drawing (Side Elevation)

Figure 2.6. 5: CMBTM Combustor General Arrangement Drawing (Plan View)
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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, LTSH 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: CMBTM 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 leave 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 secondary combustion air for the furnace.

2.6.2.2 Materials for the CMBTM Repowering Boiler

The tubing materials for the construction of the superheater require Ni-based alloys for high

temperature sections. The primary alloy used for the superheat section are IN 740, Hayness 230,

and stainless steel 347H. The materials of construction for the reheater section are stainless steel

304H and 347H.

The once-through evaporator and economizer 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.
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The headers and piping, except for the superheat finishing header and main steam piping to the

topping turbine are made of conventional boiler alloys. Inconel 617was used for these higher

temperature components.

2.6.2.3 Firing System for the CMBTM Repowering Boiler

The firing system for the CMBTM repowering boiler is of the same basic design as was used for

the Greenfield CMBTM boilers. It is described previously in Section 2.5.2.4 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 CMBTM cases produce more than 730 MWe.

2.6.2.4 Air Heater System for the CMBTM Repowering Boiler

The air heater system for the CMBTM repowering boiler is of the same basic design as was used

for the Greenfield CMBTM 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 CMBTM cases produce more than 730 MWe.

2.6.2.5 Start up System for the CMBTM Repowering Case

The start-up system used for the CMBTM repowering is the same as was used for the Greenfield

CMBTM boilers. It was described previously in Section 2.5.2.6 and it is not repeated here.

2.6.3 Balance of Plant Equipment for the CMBTM Repowering Case

The CMBTM boiler inherently generates low NOx emissions. Compared to the existing boiler

emission of 0.57 lbm/MM-Btu, the predicted emission from the CMBTM boiler would be 0.10

lbm/MM-Btu. The balance of plant equipment described 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 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 and Appendix II for drawings.

2.6.3.1 Gas Clean-up Systems for the CMBTM 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 electrostatic precipitator for particulate removal. No

sulfur removal equipment is used for the existing plant. Because of the limited scope for this

repowering study, it was agreed with AEP that in the framework of this study, no additional

environmental control systems would be considered 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 CMBTM 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 plant, the increased firing rate should not be a

problem for many of the existing 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

• Transformer
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• Ductwork and dampers

• Feedwater and steam piping

Draft System:

The flue gas is moved through the new CMBTM 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 induced 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 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 air to the combustor 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 air 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 through the cyclones and convection pass of the unit,

which contains the economizer section. The flue gas leaving the convection pass flows through

the regenerative air preheater and then exits the unit and flows to the precipitator for final

particulate capture. The flue gas is drawn through 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 primary 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.
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• 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 plant. 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 Figure 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 Plan
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Unit #4 utilizes an electrostatic precipitator for particulate removal 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 gas 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 Ash 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 performance 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 boiler at 453°F. Figure 2.6.10 shows the existing

Sporn Plant Unit #4 steam cycle.
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 77 September 8, 2004

H

H

GE

GS

5.1

SE

SE

HEAT BALANCE DIAGRAMPHILIP SPORN PLANTAs Is

Drawn:Checked :App roved:

2003 -04 -09

Doc F L Sh.No. N.o.Sh.

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PressureTemperatureEnthalpyMassf lowSaturation temperature

psia'FBtu/lblb/h'F

We 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 2003

S:\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 1329.6

P 14.94P 11.60

E_KIN8.7

E_KIN8.7

M 604

H 1521.7

P 11.60

M 8

H 1521.7

M 166

H 1521.7

M 1032

H 1329.6

M 604

H 1329.6

P 14.94

M 1032

H 1329.6

5.0 5.0 5.1

M 2213

H 1353.3

M 2638

H 1353.3

M 183

H 1505.0

M 202

H 1505.0 M -2823

H 1363.2

M 3499

H 1390.6

P 11.60P 14.94

P 82.50

M 4938

H 1353.3

M 4301

H 1505.0G

Gland s ystem sprayGland s ystem ex ces s Gland s ealing s ystem e

GSGESE

Mis c. SteamLos ses & Blow dow n

7.9 12.0 7.8 12.0 4.8

P 499.7T 696.9H 1356.0M 98476

P 188.6T 779.3H 1415.4M 43329

P 2522T 451.6H 433.4M 1050334

P 2522T 313.7H 288.3M 1050334

P 44.90T 274.3H 975.8M 58046

P 19.90T 322.9H 1202.4M 18528

P 11.60T 696.9H 1382.5M 8496

P 9.300T 209.6H 1151.4M 36982

P 3.006T 141.5H 1085.6M 30590

P 310.0T 264.9H 234.3M 914367

T 363.2H 339.2

M 40340

T 307.8H 277.8

P 452.9T 1000.0H 1521.7M 965013 P 499.7

T 696.9H 1356.0M 1023148

P 2015T 1050.0H 1505.0M 1041594

P 9.300T 209.6H 1151.4M 795611

T 60.0H 28.2M 14979

M 1200

T 218.8H 187.7

T 195.5H 164.3

T 182.4H 151.1

T 133.7H 102.5

T 95.9H 64.8

M 8740

P_EL 44166 

P 2015T 1050.0H 1505.0M 1039500

T 669.7H 1365.3M 50719

T 371.0H 348.8

T 309.1H 296.5

T 186.7H 168.4

T 200.3H 192.1

T 223.8

H 238.9

P 0.7H 102M 767

P 82.50T 979.1H 1521.7M 5485T 669.7H 1365.3M 16216

Figure 2.6.10: Existing Sporn Plant Steam Cycle Schematic Diagram
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2.6.5 Overall Plant Performance for the CMBTM 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. The table compares plant 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 thermal efficiency improvement for the repowered

case. The improved steam conditions for the repowered case are shown to improve plant thermal

efficiency by about 2.7 percentage points or about 7.6 percent.
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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--
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ALSTOM Power Inc. 80 September 8, 2004

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 Existing

Thermal Efficiency - HHV (fraction)

Figure 2.6.11: Thermal Efficiency Comparison for the Repowered and Existing Unit
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2.7 Overall Plant Performance Comparison (all Cases)

Steam power production is based on a thermodynamic 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 (NPHR). Since, by definition, one kilowatt-hour of

electrical power is equivalent to 3412.7 Btu, to convert 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 factors. 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 requirements 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 steam cycle energy balances. The efficiency of the entire boiler

feed pump drive system, which comprises a mechanical 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 components and systems were then determined rigorously

for Case PC-1. Using the Case PC-1 as the basis, the auxiliary power requirements were
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determined for all other cases by linear interpolation. 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 consumption: 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, for all the cases, the primary plant performance parameters which

contribute to the plants overall thermal efficiency. 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 efficiency for all cases. The PC and CFB cases of

the Greenfield study are identical whereas the CMBTM case is about 0.5 percentage points lower.

The lower value for the CMBTM 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 total plant auxiliary power. The CMBTM 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.
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Finally, Figure 2.7.4 shows for all cases the comparison 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 CO2 emissions (lbm/kWh) for all the

cases. This figure in combination with Figure 2.7.4 shows the direct correlation of CO2 emissions

and plant thermal efficiency.
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IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 84 September 8, 2004

Table 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

Auxiliary Power Listing (units)

Feedwater Pumps (mechanical) (kw) 15606 15187 22799 25858 29316 15187 22799 25858 22799 293

Feedwater Pumps (electrical) (kw) 17340 16874 25332 28731 32573 16874 25332 28731 25332 325Main Condensate Extraction Pumps (kw) 1255 1197 1347 1317 1026 1197 1347 1317 1347 10

Main Cooling Water Pumps (kw) 4799 4728 4627 4521 4237 4728 4627 4521 4627 42Secondary Cooling Water Pumps (kw) 202 199 234 228 214 199 234 228 234 2

Closed Circuit Cooling Water Pumps (kw) 370 365 428 418 392 365 428 418 428 3Cooling Tower Fans (kw) 3300 3251 3182 3109 2914 3251 3182 3109 3182 29

Forced Draft Fans (kw) 1589 1589 1589 1589 1589 3876 3876 3876 1219 12Primary Air Fans (kw) 1322 1322 1322 1322 1322 7904 7904 7904 14037 140Induced Draft Fans (kw) 8950 8950 8950 8950 8950 10924 10924 10924 7740 77Fluidizing Air Blowers (kw) n/a n/a n/a n/a n/a 2875 2875 2875 840 8

Coal Handling (kw) 350 350 350 350 350 350 350 350 352 3

Pulverizers (kw) 1949 1949 1949 1949 1949 n/a n/a n/a n/a 

Ash Handling (kw) 2417 2417 2417 2417 2417 2783 2783 2783 2783 27Limestone Handling (kw) 741 741 741 741 741 1153 1153 1153 1159 11

Electrostatic Precipitator (kw) 1400 1400 1400 1400 1400 n/a n/a n/a n/a 

FGD or FDA System (kw) 13200 13200 13200 13200 13200 1260 1260 1260 1267 12

SCR or SNCR Auxiliary Power (kw) 200 200 200 200 200 106 106 106 106 1

Boiler Circulation Pumps (kw) 621 621 n/a n/a n/a n/a n/a n/a n/a Misc. Aux. Power (Controls, Lighting, HVAC, etc.) (kw) 3000 3000 3000 3000 3000 3000 3000 3000 3000 30

Transformer Loss (kw) 2785 2845 2945 3016 3285 2845 2945 3016 2945 32Total Auxiliary Power Consumption (kw) 65790 65198 73212 76458 79759 63690 72325 75571 70596 771

Fraction of Generator Output (fraction) 0.094 0.092 0.099 0.101 0.097 0.090 0.098 0.100 0.096 0.0

Fraction 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 0.0

Steam Cycle Parameters

Main Steam Pressure (psia) 2408 2408 3625 3915 5075 2408 3625 3915 3625 50

Main Steam Temperature (Deg F) 1000 1049 1049 1085 1292 1049 1049 1085 1049 12Reheat Steam Temperature (Deg F) 1000 1112 1112 1148 1328 1112 1112 1148 1112 13Feedwater Temperature (Deg F) 500 500 500 554 626 500 500 554 500 6

Number of Feedwater Heaters (no.) 777897787

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 0.89

Steam Cycle Efficiency (fraction) 0.4442 0.4543 0.4650 0.4745 0.5161 0.4543 0.4650 0.4745 0.4650 0.51

(Btu/kwhr) 7683 7512 7339 7193 6613 7512 7339 7193 7339 66

Generator Output (kw) 696316 711278 736148 753937 821374 711278 736148 753937 736148 8213

Net Plant Output (kw) 630526 646080 662936 677479 741615 647588 663823 678366 665552 7442Fuel Heat Input (HHV basis) (MM-Btu/hr) 5812 5812 5812 5812 5812 5812 5812 5812 5844 58

Net Plant Heat Rate (HHV basis) (Btu/kwhr) 9218 8997 8768 8580 7838 8976 8756 8568 8781 78Thermal Efficiency (HHV basis) (fraction) 0.3702 0.3794 0.3893 0.3978 0.4355 0.3803 0.3898 0.3983 0.3887 0.43
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 85 September 8, 2004

0.8975 0.8975 0.8975 0.8975 0.8975 0.8975 0.8975 0.8975

0.8926 0.8926

0.870.880.880.890.890.900.90

PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 

Boiler Efficiency - (Fraction of HHV)

Figure 2.7. 1: Boiler Efficiency Comparison for all Cases
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 86 September 8, 2004

0.4442

0.4543

0.4650

0.4745

0.5161

0.4543

0.4650

0.4745

0.4650

0.5161

0.400.420.440.460.480.500.520.54

PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 

Steam Cycle Thermal Efficiency - (Fraction )

Figure 2.7. 2: Steam Cycle Thermal Efficiency Comparison for all Cases
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IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 87 September 8, 2004

0.094

0.092

0.099

0.101

0.097

0.090

0.098

0.100

0.096

0.094

0.060.070.080.090.100.11

PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 R

Total Auxilliary Power - (Fraction of Generator Output)

Figure 2.7. 3: Total Auxiliary Power Comparison for all Cases
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IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 88 September 8, 2004

0.3702

0.3794

0.3893

0.3978

0.4355

0.3803

0.3898

0.3983

0.3887

0.4346

0.300.320.340.360.380.400.420.440.46

PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 

Plant Thermal Efficiency - HHV (fraction)

Figure 2.7. 4: Plant Thermal Efficiency Comparison for all Cases
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IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 89 September 8, 2004

1.893

1.847

1.800

1.762

1.609

1.843

1.798

1.759

1.803

1.612

1.501.551.601.651.701.751.801.851.901.952.00

PC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 

CO

2 Emissions - (lbm/kwhr)

Figure 2.7. 5: Plant CO2 Emission Comparison for all Cases
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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) pulverized coal (PC) fired power plants (Palkes,

Liljedahl, Kruger, Weirich; 1999). Similar results would be achieved for plants utilizing CFB and

CMBTM combustion systems since boiler efficiency and auxiliary power requirements for these

combustion systems are very comparable to pulverized coal firing.

Figure 2.7.6 is a three-dimensional plot depicting 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

9250

Heat 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 basis) for Subcritical (2,400 psia) Cycles
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

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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

8985 8983

894789328916

88778874 87688743

87158702

8681

8581

7838

7200

7400

7600

7800

8000

8200

8400

8600

8800

9000

Heat 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 CMBTM combustion

systems would be nearly identical. In general, the transition from a subcritical plant with 2,400

psia main steam pressure to a supercritical plant 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 approximately 2.4%. The ultra high steam conditions case

(Case PC-5 or Case 28 on Figure 2.7.2) offers almost 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 study; pulverized coal (PC), circulating fluidized

bed (CFB), and circulating moving bed (CMBTM). 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 CMBTM -3 indicates that the PC fired case

is essentially equivalent to the CFB case and the CMBTM 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

CMBTM -3 is 89.26%. The primary contributors to CFB and CMBTM boiler efficiency differences

are the calcination and sulfation reactions associated with the CFB and CMBTM cases. In the

CMBTM 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 CMBTM -3 is about 71 MWe or about 9.6 percent
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

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

-3 is due to the fans. The Case CMBTM -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 CMBTM) 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 power 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. CMBTM -5).

These additional comparisons indicate nearly the same differences described above and these

differences will not be repeated here.

2.7.5 Comparison of CO2 Emissions for All Cases:

The following figure shows a comparison of specific CO2 emissions (lbm/kWh) for all the cases.

This figure, in combination with the thermal efficiency results shown above, shows the direct

correlation of CO2 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 CO2 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 Existing

CO2 Emissions - (lbm/kwhr)

Figure 2.7. 8: CO2 Emissions (lbm/kWh) – All Cases
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3. Cost Analysis

The plant investment cost estimate summaries, including engineering, procurement, and

construction (EPC basis), are shown in this section 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 the 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, circulating 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, cooling, electrical, instrumentation and control, and

misc.).

The cost estimates include equipment, materials, labor, indirect construction costs, and

engineering. The labor cost to install the equipment 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 plus 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 include 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 scheduling and cost control services for the project;

providing engineering and design liaison during the construction period; and providing startup

support. Construction management (CM) services cost includes a field management staff

capable of performing all field contract administration; field inspection and quality assurance;

project construction control; safety and medical services as required; field and construction

insurance administration, field office clerical and administrative support. The “other costs”

category includes a cost allowance for freight 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 weights 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 (nth plant) commercial design
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• Owners costs (including interest during construction, 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 systems 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 charges for shutdown time have been charged against the project.

Other exclusions from the EPC investment 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 depending 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 analysis, design ambient conditions, plant location

and site conditions are described in Section 2.1 under 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 these studies, changing from Gulf Coast non-union to
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Ohio River Valley union basis, for example, would increase the EPC plant costs by about 20

percent.

Operating and Maintenance Costs Basis:

Operating and Maintenance (O&M) costs are calculated for each plant and are listed as either

fixed or variable. The fixed costs are those costs 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 fixed 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 labor 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 cases
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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 was first estimated for cases PC-3, CFB-3, and

CMBTM -3. The plant cost for each other case was determined by estimating new absolute costs

or cost differences from the Base Cases for the components that required modifications because

of changes in combustion system, gas cleanup system, steam cycle system, electrical, and

feedwater system design parameters. 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 unchanged for all cases.

• Within a given combustion system group (PC, CFB, or CMBTM), the locations of the terminal

points for pipe connections to the steam generator 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 steam 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 results 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.
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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 54 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 53 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 CFB-2 Case CFB-3 Case CFB-4 Case CMB-3 Case CMB-5

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-5

Specific Total Pant Cost ($/KW-net)

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

Specific investment costs for the entire spectrum 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 CMBTM) on specific investment cost ($/kW-net)

were as follows:

• There was about a 7% difference between the total 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.
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• The CMBTM combustion system was shown to have slightly lower total plant investment cost

than the CFB system (CMBTM -3 vs. CFB-3). It requires also about 8-11% less investment

cost than the PC power plant (CMBTM -3 vs. PC-3, CMBTM -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 CMBTM) 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 generally 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 the cases with ultra-supercritical steam conditions

(Cases PC-5 and CMBTM -5) where the higher temperature and pressure of these cases

increased the total plant specific investment cost significantly. It should be emphasized

however that the costs for the 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 sensitivity 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 otherwise 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 changes in cost) were not smoothed out; the results

would then be exact only for the particular 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, CMBTM -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 CMBTM), fuel, sorbent, air, and flue

gas dependent components were the same for all cases.

• Within a given combustion system group (PC, CFB, or CMBTM), the number of wallblowers

and sootblowers were the same for all cases.

• Steam loading per foot of drum length was 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 CMBTM).

• Potential changes in the circulation system design due to differences 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.
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For each case, in addition to the cost of the heat transfer surfaces, estimates were made to

account for changes in drum length (subcritical pressure), headers and connecting links

diameters and materials, and the steam cooled back - pass height.

Figure 3.1.2 shows the specific ($/kW) boiler costs (Account 4) for all Greenfield cases. Account 4

includes the boiler, boiler structure, boiler foundations, 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, CMBTM -5).

The costs of the PC-5 and CMBTM -5 boiler are not easily determined since both of these designs

require high strength Ni based alloys. These alloys 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 techniques, 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 was 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-5

Specific 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) causes 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, CMBTM -5).
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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-5

Specific 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 the 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 other 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 economic sensitivity study was performed at

$20.00/lbm and $32.90/lbm also (see Section 4.3.4).
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• 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 specific ($/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) causes 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 CMBTM -5 however were

shown to cause about a 35% and 28% increase in specific turbine cost as compared to cases

PC-3 and CMBTM -3 respectively. The smaller increase for the CMBTM case as compared to the

PC case is due to shorter steam piping runs for the CMBTM cases.

166

173 174 178

235

172 174 178 173

222

100

120

140

160

180

200

220

240

260

Specific Turbine Condenser & Piping Cost ($/KWPC-1 PC-2 PC-3 PC-4 PC-5 CFB-2 CFB-3 CFB-4 CMB-3 CMB-5 net) (Account 8)

Figure 3.1. 4: Specific Turbine Costs (Account 8)

Similarly, Figure 3.1.5 shows the specific Turbine 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 are compensated for by decreases in feedwater

system, cooling water system, and the accessory electrical equipment specific costs for all cases

except PC-5 and CMBTM -5. The ultra high steam conditions of cases PC-5 and CMBTM -5 were

shown to cause about a 13% and 10% increase in specific Turbine Island cost as compared to

cases PC-3 and CMBTM -3 respectively.
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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-5

Specific Turbine Island Cost ($/KW-net)

(Accounts 3,8,9,11)

Figure 3.1. 5: Specific Turbine Island Costs (Accounts 8, 3, 9, and 11)

3.1.4 Other Balance of Plant Equipment Costs:

Figure 3.1.6 shows the specific 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 instrumentation 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-5

Specific 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)
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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 expressed in July 2003 dollars. The following list indicates the major

items included in the equipment scope.

• CMBTM 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 CMBTM Boiler and new

topping steam turbine/generator. Lesser amounts 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 the 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 account 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 CMBTM 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 CMBTM boiler is located on available land adjacent to the

existing Unit #4 boiler building. ALSTOM estimated the cost for the new CMBTM boiler and new
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topping steam turbine. AEP estimated the balance of plant costs. Additional 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 obtain lifetime and availability goals consistent with

the new equipment was not included in the AEP estimate.

• Contingency was not included in the AEP estimate.
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3.3 Operating and Maintenance Costs

The production costs consist of plant operating 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 determined assuming an equivalent plant operating capacity

factor of 80 percent.

The operating and maintenance (O&M) results for the 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 15.3 9,639,466 18,326,741 0.0041 27,966,208 4,419 0.633

Case PC-2 15.0 9,683,793 18,369,295 0.0041 28,053,088 4,528 0.620

Case PC-3 14.7 9,722,038 18,406,010 0.0040 28,128,048 4,646 0.605

Case PC-4 14.4 9,766,944 18,449,120 0.0039 28,216,064 4,748 0.594

Case PC-5 14.0 10,379,154 19,036,841 0.0037 29,415,995 5,197 0.566

Case CFB-2 14.7 9,531,512 12,723,866 0.0028 22,255,378 4,538 0.490

Case CFB-3 14.4 9,572,495 12,763,210 0.0027 22,335,705 4,652 0.480

Case CFB-4 14.2 9,654,292 12,841,735 0.0027 22,496,027 4,754 0.473

Case CMB-3 14.3 9,516,360 12,724,400 0.0027 22,240,761 4,664 0.477

Case CMB-5 13.4 9,993,780 13,182,724 0.0025 23,176,504 5,216 0.444

Sporn #4 Repowering 30.0 5,543,775 2,512,502 0.0018 8,056,277 1,377 0.585

Sporn #4 Existing 35.4 5,543,775 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 

(106 kWh)

The range of O&M costs for the Greenfield cases is from 0.44 – 0.63 Cents/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 electricity for the repowering case. A more detailed

breakdown of the individual O&M costs for each case is shown in Appendix III.
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4. Economic Analysis

A comprehensive economic evaluation comparing the various Rankine cycle power plants was

performed. These comparisons were done for three types of plants (PC, CFB, and CMBTM). In

addition the economics of repowering an existing coal fired plant with a new CMBTM boiler and

supercritical topping steam turbine was also investigated. 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 coal fired plants including PC, CFB, and advanced

CMBTM type units. Additionally a comparison between all cases is also provided. The economic

evaluation results are presented as Costs of Electricity (levelized basis).

The model used to perform the economic evaluations is the proprietary ALSTOM Power Plant

Laboratories’ Project Economic Evaluation Pro-Forma Model. This cash flow model, developed

by the Company’s Project & Trade Finance group, has the capability to analyze the economic

effects of different technologies based on differing 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 electricity, net present value, 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 assumptions 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 cost, interest rate, and discount factor. All other

financial inputs are equivalent for all cases.

The 30-month construction period of the PC and CFB systems are known from the experience in

the industry. The construction period for the CMBTM systems is thought to be similar to the CFB

systems since the system complexity is very similar. The construction period for the repowering

case is 30-month based on a CMBTM 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 economic sensitivity study (Section 4.3.4).
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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 evaluation 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 constant value over the life of the

study.

The financial component of the COE represents the costs which are associated with payment of

the original engineered, procured and constructed (EPC) price, all associated owner’s costs,

custom’s and financing fees, and interests accrued both during construction and during operation.

The fixed O&M component represents the costs that occur regardless of whether the unit is in
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operation or not. The variable O&M component represents 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 systems are discussed in Section 4.3.1. The CFB and

CMBTM systems are discussed in Section 4.3.2. The Repowering system is discussed in Section

4.3.3. The case studies are compared using levelized cost of electricity (COE) evaluation

criterion.

4.3.1 Pulverized Coal Fired Cases

The levelized COE for the PC systems is summarized in Table 4.3.1. The supercritical cases PC3, PC-4and PC-5 have relatively low production 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 CMBTM Cases

The levelized COE values for the CFB and CMBTM systems are summarized in Table 4.3.2. Case

CMBTM -5 had the lowest production cost of the CFB and CMBTM systems because of its highest

net plant efficiency and the relatively low investment cost. Compared to the increase in the

investment cost for the PC-5, the incremental increase in the investment cost of CMBTM -5 was

not as high since the design required significantly less amounts of expensive Ni materials.

Table 4.3. 2: CFB and CMBTM Systems (CFB-2, CFB-3, CMBTM -3, CMBTM -4, CMBTM -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 3.41
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4.3.3 Repowering Case

The levelized incremental Cost of Electricity (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

NOx 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 Base

Levelized 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 NOx credits. For the existing unit, the NOx emission is 0.57 lbm/MM-Btu. During the five

months ozone season that limits NOx emission to 0.15 lbm/MM-Btu the plant is required to

purchase NOx credits which amount to a difference of 0.42 lbm/MM-Btu. For the repowered case,

since the NOx emission is only 0.1 lbm/MM-Btu, a credit 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.
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2.76

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/ton

Levelized COE (cents per kWh)

Figure 4.3. 2: Repowering versus Base Case – With NOx Credits

4.3.4 Economic Sensitivity Study Summary

Sensitivity analyses were conducted for all case 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 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). Selected sensitivity analysis “spider plots” for selected

cases are provided in the following section. The complete package of sensitivity results for all

case studies are provided in Appendix IV. In general, 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, CMBTM

-5, and the repowering case.

2) NOx emissions credit on the repowering case.

3) SOx emissions credit on the repowering case.
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4.3.4.1 Case PC-3

Results for the Case PC-3 COE sensitivity study are 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 Variable

Percent Change in COE

3.1

3.3

3.5

3.7

3.9

4.1

4.3

4.5

4.7

4.9

Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price

Equity Corporate Tax Discount Rate

Figure 4.3. 3: Case PC-3 - Economic Sensitivity Results
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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 Variable

Percent Change in COE

2.8

3.0

3.2

3.4

3.6

3.8

4.0

4.2

4.4

Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price

Equity Corporate Tax Discount Rate

Figure 4.3. 4: Case CFB-3 - Economic Sensitivity Results
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

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4.3.4.3 High Temperature Nickel Alloy Sensitivity Study

In general, the cost of Ni alloys affected the 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%

18.0 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

3.86

Levelized COE (cents / kWh)

Figure 4.3. 5: Case PC-5 – High Temperature Alloy Sensitivity Results
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Similarly, the results for the high temperature alloy Case CMBTM -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 ranges 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

3.48

Levelized COE (cents / kWh)

Figure 4.3. 6: Case CMBTM -5 – High Temperature Alloy Sensitivity Results

Results for the high temperature alloy repowering 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

2.87

Levelized COE (cents / kWh)

Figure 4.3. 7: Case Repowering – High Temperature Alloy Sensitivity Results
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4.3.4.4 NOx / SOx Credit Sensitivity Study for Repowering Case

Results for the NOx / SOx credit for the repowering Case COE sensitivity study are shown in

Figure 4.3.8 and tabulated in Appendix IV. The NOx credits are based on the reduction of NOx

emissions with repowering versus the base plant during the five month ozone season which the

base plant purchases NOx credits. The SOx credits are based on the reduction of SOx 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 equipment 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 cases selling emissions credits versus the base

plant purchasing credits, NOx credits of about $6,500 per ton NOx sold would produce a COE

similar to the COE of the base plant purchasing NOx credits at $5,000 per ton NOx.

2.78

2.29

2.75 2.73 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/ton

Levelized COE (cents per kWh)

Repowering

$200/ton SOx Credit

Figure 4.3. 8: Case Repowering – NOx Credit Sensitivity Results
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Figure 4.3.9 provides the breakdown of levelized COE for the scenarios shown in Figure 4.3.8.

NOX and SOx 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/ton

Levelized 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 NOx Credit Sensitivity Study
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

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4.4 Economic Study Summary and Conclusions

The economic study results are summarized by comparing the levelized COE results for the PC,

CFB, and CMBTM cases as shown in Figure 4.4.1. The ultra-supercritical case CMBTM -5 has the

lowest cost of electricity. The lower cost is directly 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

CMBTM 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 clean-up systems (SCR, ESP, and wet 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 costs. Similarly, there are no significant differences

in COE within the CFB and CMBTM 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 Study

Levelized 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/ CMBTM Cases
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

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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 how the cost of NOx credits impacts the COE. As the price of NOx 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 years and the existing boiler that is already fully

depreciated. It should be also noted that any major investment cost required to refurbish the

existing old boiler or potential decrease in future availability caused by the aging equipment has

not been considered in estimating the COE of the base case.

2.78

2.29

2.75 2.73 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/ton

Levelized COE (cents per kWh)

Repowering

$200/ton SOx Credit

Figure 4.4. 2: Levelized Cost of Electricity Comparison for Repowering versus Base Plant
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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 than 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/ CMBTM Cases are shown in Figure 4.4.4. Case

CMBTM -5 has the lowest COE over the entire coal 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/ CMBTM Cases
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The study has also investigated the impact of potential taxes placed on CO2 emissions. The

figure below illustrates the changes in the COE as the potential CO2 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.

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 CO2 Emissions Tax

Rate
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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 cost of electricity (COE). The table shown below

defines the case studies in terms of steam cycle 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 thermal 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 CMBTM) 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 CMBTM systems which is due to only partial sulfation in the CMBTM

combustor. The effect of the increasing steam cycle parameters (Temperature and Pressure) is

also clearly illustrated.

The specific investment cost results for the Greenfield cases shown in the table above range from

about 1,018 to 1,168 $/kW-net. For the same steam conditions, the CMBTM combustion system

plants require the lowest investment costs as compared to PC or CFB plants. This cost

advantage increases as steam cycle conditions (Temperature and Pressure) are raised. The CFB

systems are about 70 $/kW lower in cost than the PC type combustion systems. This difference is

primarily attributable to the differences in the costs for the gas cleanup system equipment.

The cost of electricity (COE) results for the Greenfield cases shown in the table above range from

about 3.4 to 4.0 Cents/kWh. These results indicate that Case CMBTM -5 is the most economical

from a COE basis. Compared to Case PC-5, it requires 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 CMBTM designs.
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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 Existing

Cost 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 the same steam conditions. The advantage of the

CFB systems is attributable to the investment cost savings discussed above. Because of the

additional reduction in investment cost associated with CMBTM based systems, the CMBTM

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 the 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 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 lowest 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

5.00

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

CFB-2CFB-3CFB-4

CMB-3CMB-5

Repower

Base

$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

Cases
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Repowering Case:

For the Repowering case, 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 is calculated relative to

the unmodified existing unit. This difference may quickly disappear if the price of NOx credits

continues to increase and/or a major capital investment is required to refurbish the existing boiler

of if there is loss of availability caused by the aging equipment.

Recommendations:

In summary, from the results of the study the evaluated power plant 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 facilitate construction 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 CMBTM cycles in a 10 to

15 year timeframe. The very high steam temperatures of the ultra-supecritical steam cycle do not

appear to be practical for conventional CFB technology where combustion temperature is

generally limited to 1,5500

F. CMBTM technology with the combustion temperature of 20000F

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

CMBTM 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 require installation of the back end NOx and SOx 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 the 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 temperatures of approximately 1,2000

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 efficiency 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 advantage over future IGCC plants with advanced gas

turbines. (MARION,10)
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6. Bibliography

Bustard et al., DOE Full Scale Data, Air Quality III Conference, September 2002.

Coal Utilization Research Council - CURC (www.coal.org).

Jukkola, G.; Turek, D.; Levasseur, A.; Teigen, B.; “Operating Experience with ALSTOM’s

Circulating Moving Bed Combustor”, Proceedings of FBC-2003, 17th International Fluidized Bed

Combustion Conference, Jacksonville, Florida USA, May 18-21, 2003.

Marchetti, M.; Semedard, J.; Devroe, S.; Czarnecki, T.; Lemasle, J.; “ ALSTOM’s Large CFB’s

and Results” Proceedings of FBC-2003, 17th 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” 29th International Technical Conference on Coal

Utilization and Fuel Science, Clearwater, Florida USA, April 18-22, 2004.

Palkes, M.; “Boiler Materials for Ultra Supercritical Coal Power Plants”, Task 1A, Conceptual

Design, ALSTOM Approach, Topical Report, Prepared 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 Proprietary 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

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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 results
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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 cases is subdivided by combustion system type

(i.e. PC, CFB, and CMBTM).

Balance of Plant Equipment for the Greenfield cases 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 example, the Coal Receiving and Handling equipment

(Account 1) is the same for all cases ant 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 (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 case (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.
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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 associated 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 Furnace Superheater Pendants/Headers/Piping

(panels and platens)

- PC-3,-4,-5 In Tunnel Superheat 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 Burners, 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 Piping
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- 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/Silencer 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 platforms, 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. 129 September 8, 2004

- 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 Site
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 130 September 8, 2004

7.1.1.2 CFB Cases Boiler Island Equipment

This section contains a list of all equipment associated with the boiler scope of supply for the CFB

boilers for cases CFB-2, CFB-3, and CFB-4. Case 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 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

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 Pendants/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 Burners, 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 Horizontal Reheater/Economizer

CFB-4 Horizontal Superheater/Reheater/Economizer
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 131 September 8, 2004

- 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/Silencer 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 platforms, 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. 132 September 8, 2004

- 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 Site
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 133 September 8, 2004

7.1.1.3 CMBTM Cases Boiler Island Equipment

This section contains a list of all equipment associated with the boiler scope of supply for the

CMBTM boilers for cases CMBTM -3, and CMBTM -5. Cases CMBTM -3 and CMBTM -5 are

supercritical and ultra-supercritical pressure designs. A large portion of the equipment is common

to both boilers and therefore a single equipment list 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 Including Air Nozzles & Drain Tubes

- Ash Drain Valve(s)

- Start-up Burner System (Including Burners, 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
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 134 September 8, 2004

- Safety Valves/Discharge Piping/Silencers

- Electro. Relief Valve/Silencer and Discharge Piping

Particle Return System:

-Particle Removal Cyclones

-Ductwork

PA Fan to MBHE Outlet

Particle transport pipes from MBHE 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 platforms, 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
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 135 September 8, 2004

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 Site
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 136 September 8, 2004

7.1.2 Balance of Plant Equipment for Greenfield Cases

This section contains the balance of plant equipment 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 the Greenfield plants, a single list is used with

differences among the cases indicated where necessary. For example, the Coal Receiving and

Handling equipment (Account 1) is the same for all 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 (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.
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 137 September 8, 2004

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 1
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 138 September 8, 2004

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 2
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 139 September 8, 2004

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 centrifugal800,000 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

1
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 140 September 8, 2004

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 centrifugal800,000 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

1
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 141 September 8, 2004

FEEDWATER SYSTEMS (Steam Cycle #3; Cases PC-3, CFB-3, CMBTM -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 centrifugal800,000 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

1
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 142 September 8, 2004

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 centrifugal800,000 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

1
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 143 September 8, 2004

FEEDWATER SYSTEMS (Steam Cycle #5; Cases PC-5, CMBTM -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 centrifugal800,000 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 1
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 144 September 8, 2004

554°F to 617°F

18 Topping de-superheater Horizontal U Tube 4,300,000 lbm/hr

617°F to 626°F

1
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 145 September 8, 2004

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 1
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 146 September 8, 2004

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 106 lbm/hr

2,400psi

1,000°F/1,000°F

1

1 Power Boiler Pulverized Coal Fired

Case PC-2

4.4 x 106 lbm/hr

2,400psi

1,049°F/1,112°F

1

1 Power Boiler Pulverized Coal Fired

Case PC-3

4.3 x 106 lbm/hr

3,625 psi

1,049°F/1,112°F

1

1 Power Boiler Pulverized Coal Fired

Case PC-4

4.6 x 106 lbm/hr

3,915 psi

1,085°F/1,148°F

1

1 Power Boiler Pulverized Coal Fired

Case PC-5

4.3 x 106 lbm/hr

5,075 psi

1,292°F/1,328°F

1

1 Power Boiler Circulating Fluidized

Bed Case CFB-2

4.4 x 106 lbm/hr

2,400 psi

1,049°F/1,112°F

1

1 Power Boiler Circulating Fluidized

Bed Case CFB-3

4.3 x 106 lbm/hr

3,625 psi

1,049°F/1,112°F

1

1 Power Boiler Circulating Fluidized

Bed Case CFB-4

4.6 x 106 lbm/hr

3,915 psi

1,085°F/1,148°F

1

1 Power Boiler Circulating Moving

Bed Case CMBTM -3

4.6 x 106

 lbm/hr

3,915 psi

1,085°F/1,148°F

1

1 Power Boiler Circulating Moving

Bed Case CMBTM -5

4.3 x 106

 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

1
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 147 September 8, 2004

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 CMBTM -3,

CMBTM -5)

1,165,000 pph,

281,000 acfm,

98" wg, 1,219 kW

1

3 Secondary Air Fan Centrifugal

(Cases CMBTM -3,

CMBTM -5)

677,000 pph,

163,000 acfm,

78" wg, 3,182 kW

1

4 ID Fan Centrifugal

(Cases CMBTM -3,

CMBTM -5)

2,168,000 pph,

724,000 acfm,

39" wg, 7,740kW

1

5 Fluidizing Air Blower Centrifugal

(Cases CMBTM -3,

CMBTM -5)

16,000 acfm,

25 psig, 840 kW

2
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 148 September 8, 2004

ACCOUNT 5 FLUE GAS CLEANUP

ACCOUNT 5A PARTICULATE CONTROL

Equipment No. Description Type Design Condition Qty

1 Bag Filter for CFB and

CMBTM cases as part of

FDA system (Cases

CFB-2, CFB-3, CFB-4,

CMBTM -3, and CMBTM -

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

CMBTM cases (Cases

CFB-2, CFB-3, CFB-4,

CMBTM -3, and CMBTM -

5)

N/A ~6,100,000 lbm/hr,

total removal

efficiency = 98%

1

1 Wet FGD System for PC

Cases (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 1
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 149 September 8, 2004

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, CMBTM -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, CMBTM -

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

- 1
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 150 September 8, 2004

ACCOUNT 9 COOLING WATER SYSTEM (Note: 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,

CMBTM -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

6
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 151 September 8, 2004

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

1
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 152 September 8, 2004

7.1.3 Sporn Repowering Case Equipment List

This section provides a listing of all major plant 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 associated with the boiler scope of supply for the

CMBTM 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 Including Air Nozzles & Drain Tubes

- Ash Drain Valve(s)

- Start-up Burner System (Including Burners, 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/Silencer and Discharge Piping

Particle Return System:

-Particle Removal Cyclones

-Ductwork

PA Fan to MBHE Particle Outlet

Particle transport pipes from MBHE outlet to Cyclone separator
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 153 September 8, 2004

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 platforms, 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 Site
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 154 September 8, 2004

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 costs 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 lines 
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 155 September 8, 2004

7.2 Appendix II - Drawings

This appendix shows drawings of the various Greenfield case boilers (PC, CFB, and CMBTM)

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 700MW 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 CMBTM Steam Generator

Figure 7.2. 8 Side Arrangement of 700MW Supercritical CMBTM Steam Generator

Figure 7.2. 9 Plan Arrangement of 700MW Supercritical CMBTM 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 Elevation of Steam Generator Repowering Case

Figure 7.2. 13 Philip Sporn Sectional Side Elevation of Steam Generator Repowering Case

Figure 7.2. 14 Philip Sporn Plan View of Steam Generator Repowering Case
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 156 September 8, 2004

Figure 7.2. 1 Front Arrangement of 700MW Supercritical CFB Steam Generator
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 157 September 8, 2004

Figure 7.2. 2 Side Arrangement of 700MW Supercritical CFB Steam Generator
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 158 September 8, 2004

Figure 7.2. 3 Plan Arrangement of 700MW Supercritical CFB Steam Generator
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 159 September 8, 2004

Figure 7.2. 4 Front Arrangement of 700MW Subcritical CFB Steam Generator
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 160 September 8, 2004

Figure 7.2. 5 Side Arrangement of 700MW Subcritical CFB Steam Generator
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 161 September 8, 2004

Figure 7.2. 6 Side Arrangement of 700MW Subcritical CFB Steam Generator
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 162 September 8, 2004

Figure 7.2. 7 Front Arrangement of 700MW Supercritical CMB Steam Generator
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 163 September 8, 2004

Figure 7.2. 8 Side Arrangement of 700MW Supercritical CMB Steam Generator
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 164 September 8, 2004

Figure 7.2. 9 Plan Arrangement of 700MW Supercritical CMB Steam Generator
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 165 September 8, 2004

Figure 7.2.10:Philip Sporn Plant - Plan View of Existing Site
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 166 September 8, 2004

Figure 7.2.11:Topping Steam Turbine for Sporn Unit #4 Repowering Case
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 167 September 8, 2004

Figure 7.2.12: Philip Sporn Sectional Side Elevation of Steam Generator Repowering Cas
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 168 September 8, 2004

Figure 7.2.13:Philip Sporn Front Elevation of Steam Generator Repowering Case
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 169 September 8, 2004

Figure 7.2. 14: Philip Sporn Plan View of Steam Generator Repowering Case
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 170 September 8, 2004

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 plants 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, CMBTM -3, and

finally Case CMBTM -5.

Additionally, the investment cost breakdown for the Sporn Unit #4 repowering 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 CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 171 September 8, 2004

Table 7.3. 1: Case PC-1 Investment Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 172 September 8, 2004

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) 7.81 4,926,449

Maintenance Labor Costs (calc'd) 4.42 2,785,124

Administrative & Support Labor (calc'd) 3.06 1,927,893

TOTAL FIXED OPERATING COSTS 15.29 9,639,466

$/kWh-net

Maintenance Material Cost (calc'd) 0.00076 3,342,149

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) 0.0013 5,840,000

 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 & ANNUAL O&M EXPENSES

Consumption

Table 7.3. 2: Case PC-1 Operating and Maintenance Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 173 September 8, 2004

Table 7.3. 3: Case PC-2 Investment Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 174 September 8, 2004

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) 7.63 4,926,449

Maintenance Labor Costs (calc'd) 4.37 2,820,586

Administrative & Support Labor (calc'd) 3.00 1,936,759

TOTAL FIXED OPERATING COSTS 14.99 9,683,793

$/kWh-net

Maintenance Material Cost (calc'd) 0.00075 3,384,703

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) 0.0013 5,840,000

 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 & ANNUAL O&M EXPENSES

Consumption

Table 7.3. 4: Case PC-2 Operating and Maintenance Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 175 September 8, 2004

Table 7.3. 5: Case PC-3 Investment Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 176 September 8, 2004

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) 7.43 4,926,449

Maintenance Labor Costs (calc'd) 4.30 2,851,182

Administrative & Support Labor (calc'd) 2.93 1,944,408

TOTAL FIXED OPERATING COSTS 14.67 9,722,038

$/kWh-net

Maintenance Material Cost (calc'd) 0.00074 3,421,418

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) 0.0013 5,840,000

 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 & ANNUAL O&M EXPENSES

Consumption

Table 7.3. 6: Case PC-3 Operating and Maintenance Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 177 September 8, 2004

Table 7.3. 7: Case PC-4 Investment Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 178 September 8, 2004

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) 7.27 4,926,449

Maintenance Labor Costs (calc'd) 4.26 2,887,106

Administrative & Support Labor (calc'd) 2.88 1,953,389

TOTAL FIXED OPERATING COSTS 14.4 9,766,944 2

$/kWh-net

Maintenance Material Cost (calc'd) 0.00073 3,464,528

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) 0.0012 5,840,000

 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 & ANNUAL O&M EXPENSES

Consumption

Table 7.3. 8: Case PC-4 Operating and Maintenance Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 179 September 8, 2004

Table 7.3. 9: Case PC-5 Investment Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 180 September 8, 2004

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) 6.64 4,926,449

Maintenance Labor Costs (calc'd) 4.55 3,376,874

Administrative & Support Labor (calc'd) 2.80 2,075,831

TOTAL FIXED OPERATING COSTS 14.00 10,379,154

$/kWh-net

Maintenance Material Cost (calc'd) 0.00078 4,052,249

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) 0.0011 5,840,000

 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 & ANNUAL O&M EXPENSES

Consumption

Table 7.3.10: Case PC-5 Operating and Maintenance Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 181 September 8, 2004

Table 7.3.11: Case CFB-2 Investment Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 182 September 8, 2004

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) 7.61 4,926,449

Maintenance Labor Costs (calc'd) 4.17 2,698,760

Administrative & Support Labor (calc'd) 2.94 1,906,302

TOTAL FIXED OPERATING COSTS 14.72 9,531,512

$/kWh-net

Maintenance Material Cost (calc'd) 0.00071 3,238,513

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 & ANNUAL O&M EXPENSES

Consumption

Table 7.3.12: Case CFB-2 Operating and Maintenance Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 183 September 8, 2004

Table 7.3.13: Case CFB-3 Investment Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 184 September 8, 2004

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) 7.42 4,926,449

Maintenance Labor Costs (calc'd) 4.11 2,731,547

Administrative & Support Labor (calc'd) 2.88 1,914,499

TOTAL FIXED OPERATING COSTS 14.4 9,572,495 2

$/kWh-net

Maintenance Material Cost (calc'd) 0.00070 3,277,857

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 COST 0.0027 12,763,210

Annual Generation 4652 (MM-kwhr/yr)

Total O&M Cost 0.48 (Cents/kwhr)

INITIAL & ANNUAL O&M EXPENSES

Consumption

Table 7.3.14: Case CFB-3 Operating and Maintenance Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 185 September 8, 2004

Table 7.3.15: Case CFB-4 Investment Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 186 September 8, 2004

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) 7.26 4,926,449

Maintenance Labor Costs (calc'd) 4.12 2,796,985

Administrative & Support Labor (calc'd) 2.85 1,930,858

TOTAL FIXED OPERATING COSTS 14.23 9,654,292

$/kWh-net

Maintenance Material Cost (calc'd) 0.00071 3,356,382

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 Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 187 September 8, 2004

Table 7.3.17: Case CMB-3 Investment Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 188 September 8, 2004

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) 7.40 4,926,449

Maintenance Labor Costs (calc'd) 4.04 2,686,639

Administrative & Support Labor (calc'd) 2.86 1,903,272

TOTAL FIXED OPERATING COSTS 14.30 9,516,360

$/kWh-net

Maintenance Material Cost (calc'd) 0.00069 3,223,967

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 Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 189 September 8, 2004

Table 7.3.19: Case CMB-5 Investment Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 190 September 8, 2004

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) 6.62 4,926,449

Maintenance Labor Costs (calc'd) 4.12 3,068,575

Administrative & Support Labor (calc'd) 2.69 1,998,756

TOTAL FIXED OPERATING COSTS 13.43 9,993,780

$/kWh-net

Maintenance Material Cost (calc'd) 0.00071 3,682,290

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 EXPENSES

Consumption

Table 7.3.20: Case CMB-5 Operating and Maintenance Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS ALSTOM Power Inc. 191 September 8, 2004

Equipment Description Measures Installed Cost Comments & Issues Boiler: ~186 MWe-net (1,080,000 lbm/hr steam) 54,182,000

Circulating Moving Bed (4,500Psia/1,292F/1,000F) 

Topping Turbine/Generator: ~32 MWe, 1,080,000 lbm/hr, no extraction 10,725,000

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 500,000 Single pump 

Full flow condensate polishing system 950,000 lb/hr condensate flow 1,067,000 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) 1,510,000

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 1,700,000

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 830,000

Includes foundations and crane rental for installation 

Piping: 

Link to Demin. from condensate 1 x 275 ft 37,000 Link from Demin. to #1 Feedwater Heater 1 x 275 ft 29,000 Main Steam to Topping Turbine 1 x 100 ft 4,180,000 Insulated, 1 line, 4,242 psi, 1,292F Topping Turbine to Existing Turbine 1 x 200 ft 615,000 Insulated, 1 line R.H. Inlet Link 2 x 200 ft 331,000 Insulated, 2 lines R.H. Outlet Link 2 x 200 ft 396,000 Insulated, 2 lines Economizer Inlet Link from new Feedwater Booster Pump 2 x 300 ft 242,000 Insulated, 2 lines 

TOTAL COST 76,344,000 

Table 7.3.21: Sporn Unit #4 Repowering Case Investment Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 192 September 8, 2004

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) 19.03 3,518,892

Maintenance Labor Costs (calc'd) 4.96 916,128

Administrative & Support Labor (calc'd) 6.00 1,108,755

TOTAL FIXED OPERATING COSTS 29.98 5,543,775

$/kWh-net

Maintenance Material Cost (New Equipment) 0.00028 389,354

Maintenance Material Cost (Existing Equipment) 0.00057 778,709

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 0.0018 2

Annual Generation 1377 (MM-kwhr/yr)

Total O&M Cost 0.59 (Cents/kwhr)

INITIAL & ANNUAL O&M EXPENSES

Consumption

Table 7.3.22: Sporn Unit #4 Repowering Case Operating and Maintenance Costs
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 193 September 8, 2004

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) 22.48 3,518,892

Maintenance Labor Costs (calc'd) 5.85 916,128

Administrative & Support Labor (calc'd) 7.08 1,108,755

TOTAL FIXED OPERATING COSTS 35.4 5,543,775 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 & ANNUAL O&M EXPENSES

Consumption

Table 7.3.23: Existing Sporn Unit #4 Operating and Maintenance Costs
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7.4 Appendix IV - Economic Sensitivity Study Results

Sensitivity analyses were conducted for all PC and CFB/ CMBTM case 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 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, CMBTM -5, and the

repowering case.

2) NOx 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 parameter 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 Fired Steam Plant with SCR Economic Sensitivity

Results
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

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Table 7.4. 1: Case PC-1 – 1 x 630 MW PC Fired 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

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 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

Financing 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 Electricity (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 4.34
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

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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 parameter 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 Variable

Percent Change in COE

3.1

3.3

3.5

3.7

3.9

4.1

4.3

4.5

4.7

4.9

Levelized 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

Results
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

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Table 7.4. 2: Case PC-2 – 1 x 650 MW PC Fired 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

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 Electricity (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

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

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

Financing 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 Electricity (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 4.27
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

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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 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 Variable

Percent Change in COE

3.1

3.3

3.5

3.7

3.9

4.1

4.3

4.5

4.7

4.9

Levelized 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

Results
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 199 September 8, 2004

Table 7.4. 3: Case PC-3 – 1 x 660 MW PC Fired 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

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 Electricity (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

Financing 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 Electricity (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 4.20
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

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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 parameter 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 Variable

Percent Change in COE

3.0

3.2

3.4

3.6

3.8

4.0

4.2

4.4

4.6

4.8

Levelized 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

Results
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 201 September 8, 2004

Table 7.4. 4: Case PC-4 – 1 x 680 MW PC Fired 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

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 Electricity (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

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

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

Financing 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 Electricity (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 4.13
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 202 September 8, 2004

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 parameter 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 Variable

Percent Change in COE

3.0

3.2

3.4

3.6

3.8

4.0

4.2

4.4

4.6

4.8

Levelized 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 Results
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 203 September 8, 2004

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 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 0.20 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

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

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 1,139 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

Financing 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 Electricity (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 4.10
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 204 September 8, 2004

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 parameter 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 Variable

Percent Change in COE

3.0

3.2

3.4

3.6

3.8

4.0

4.2

4.4

4.6

4.8

Levelized 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 Results
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 205 September 8, 2004

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 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

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 Electricity (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

Financing 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 Electricity (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 4.17
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 206 September 8, 2004

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 parameter 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 Variable

Percent Change in COE

3.0

3.2

3.4

3.6

3.8

4.0

4.2

4.4

4.6

4.8

Levelized 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 Results
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 207 September 8, 2004

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

Parameter 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

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 Electricity (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

Parameter 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

Financing 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 Electricity (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 4.21
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

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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 study are shown in Figure 7.4.8 and summarized in

Table 7.4.8. 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 4.4 cents per kWh.

-20%

-15%

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

-30% -20% -10% 0% 10% 20% 30%

Percent Change in Variable

Percent Change in COE

2.9

3.1

3.3

3.5

3.7

3.9

4.1

4.3

4.5

4.7

Levelized 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

Results
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 209 September 8, 2004

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

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 Electricity (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

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

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

Financing 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 Electricity (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 3.98
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

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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 study are shown in Figure 7.4.9 and summarized in

Table 7.4.9. 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.

-20%

-15%

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

-30% -20% -10% 0% 10% 20% 30%

Percent Change in Variable

Percent Change in COE

2.8

3.0

3.2

3.4

3.6

3.8

4.0

4.2

4.4

Levelized 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

Results
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

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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

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 Electricity (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

Financing 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 Electricity (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 3.91
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

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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 parameter 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 Variable

Percent Change in COE

2.8

3.0

3.2

3.4

3.6

3.8

4.0

4.2

4.4

Levelized 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 Results
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 213 September 8, 2004

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

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 Electricity (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

Financing 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 Electricity (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 3.88
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7.4.11 Case CMB-3 - 1 x 670 MW CMB Steam Plant with SNCR Economic Sensitivity

Results

Results for the Case CMBTM -3 COE sensitivity study are shown 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 Variable

Percent Change in COE

2.8

3.0

3.2

3.4

3.6

3.8

4.0

4.2

4.4

Levelized 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 Results
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

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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

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 Electricity (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

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

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

Financing 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 Electricity (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 3.87
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

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7.4.12 Case CMB-5 20 Alloy - 1 x 750 MW CMB Steam Plant with SNCR and $20 per Pound

High Temperature Alloy Economic Sensitivity Results

Results for the Case CMBTM -5 COE sensitivity study are shown 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 Variable

Percent Change in COE

2.7

2.9

3.1

3.3

3.5

3.7

3.9

4.1

4.3

Levelized 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 Results
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

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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

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 Electricity (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

Financing 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 Electricity (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 3.75
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

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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

Results for the Case CMBTM -5 COE sensitivity study are shown 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 Variable

Percent Change in COE

2.7

2.9

3.1

3.3

3.5

3.7

3.9

4.1

4.3

Levelized 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 Results
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 219 September 8, 2004

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

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 Electricity (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

Financing 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 Electricity (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 3.74
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 220 September 8, 2004

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 CMBTM -5 COE sensitivity study are shown 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 Variable

Percent Change in COE

2.7

2.9

3.1

3.3

3.5

3.7

3.9

4.1

4.3

Levelized 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 Results
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 221 September 8, 2004

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

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 Electricity (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

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

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

Financing 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 Electricity (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 3.78
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 222 September 8, 2004

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 sensitivity 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 Variable

Percent Change in COE

1.5

1.6

1.7

1.8

1.9

2.0

2.1

2.2

2.3

2.4

Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price

Equity Corporate Tax Discount Rate

Figure 7.4.15: Case Base Phillip Sporn Unit 4 – Base Phillip Sporn Unit 4 Economic

Sensitivity Results
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 223 September 8, 2004

Table 7.4.15: Case Base Phillip Sporn Unit 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

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 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

Financing 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 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 0.48 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 1.87
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 224 September 8, 2004

7.4.16 Case Base Phillip Sporn Unit 4 Purchase NOx Credits – Base Phillip Sporn Unit 4

with Purchase of $5k per Ton NOx Credits Economic Sensitivity Results

Results for the Base Case Phillip Sporn plant with NOx credits purchased at $5k per ton COE

sensitivity study are shown in Figure 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 Variable

Percent Change in COE

1.8

2.0

2.2

2.4

2.6

2.8

Levelized 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 NOx Credits – Base Phillip

Sporn Unit 4 with Purchase of $5k per Ton NOx Credits Economic Sensitivity Results
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 225 September 8, 2004

Table 7.4.16: Case Base Phillip Sporn Unit 4 Purchase NOx Credits – Base Phillip Sporn

Unit 4 with Purchase of $5k per Ton NOx 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

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 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

Financing 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 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 0.48 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 2.29
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 226 September 8, 2004

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 Case COE sensitivity study are shown in Figure

7.4.17 and summarized in Table 7.4.17. The levelized 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 Variable

Percent Change in COE

2.2

2.4

2.6

2.8

3.0

3.2

3.4

Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price

Equity Corporate Tax Discount Rate

Figure 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
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 227 September 8, 2004

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

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 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

Financing 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 Electricity (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 2.97
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 228 September 8, 2004

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 Case COE sensitivity study are shown in Figure

7.4.18 and summarized in Table 7.4.18. The levelized 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 Variable

Percent Change in COE

2.2

2.4

2.6

2.8

3.0

3.2

3.4

3.6

Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price

Equity Corporate Tax Discount Rate

Figure 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
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 229 September 8, 2004

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

Parameter 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

Parameter 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 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

Financing 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 Electricity (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 3.02
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 230 September 8, 2004

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 Case COE sensitivity study are shown in Figure

7.4.19 and summarized in Table 7.4.19. The levelized 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 Variable

Percent Change in COE

2.3

2.5

2.7

2.9

3.1

3.3

3.5

3.7

Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price

Equity Corporate Tax Discount Rate

Figure 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
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 231 September 8, 2004

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 Sporn Unit #4 - Repowering; $32.90 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 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 30.11 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

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 1.13 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 Sporn Unit #4 - Repowering; $32.90 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 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

Financing 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 Electricity (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 3.04
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 232 September 8, 2004

7.4.20 Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with $2k

per Ton NOx and $200 per Ton SOx Emissions Credits Sold and $28 per Pound High

Temperature Alloy Economic Sensitivity Results

Results for the Phillip Sporn Unit 4 Repowering Case COE sensitivity study are shown in Figure

9.4.20 and summarized in Table 9.4.20. The levelized 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 Variable

Percent Change in COE

2.2

2.4

2.6

2.8

3.0

3.2

3.4

Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price

Equity Corporate Tax Discount Rate

Figure 7.4.20: Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4

with $2k per Ton NOx and $200 per Ton SOx Emissions Credits Sold and $28 per Pound

High Temperature Alloy Economic Sensitivity Results
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 233 September 8, 2004

Table 7.4.20: Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with

$2k per Ton NOx and $200 per Ton SOx Emissions Credits Sold and $28 per Pound High

Temperature Alloy Economic Sensitivity Results

Parameter Units Sporn Unit #4 - Repowering; $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 29.98 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

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 1.13 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 Sporn Unit #4 - Repowering; $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

Financing 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 Electricity (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 2.77 2.80 2.82 2.59 2.68 2.89 3.00
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 234 September 8, 2004

7.4.21 Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with $5k

per Ton NOx and $200 per Ton SOx Emissions Credits Sold and $28 per Pound High

Temperature Alloy Economic Sensitivity Results

Results for the Phillip Sporn Unit 4 Repowering Case COE sensitivity study are shown in Figure

9.4.21 and summarized in Table 9.4.21. The levelized 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 Variable

Percent Change in COE

2.2

2.4

2.6

2.8

3.0

3.2

3.4

Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price

Equity Corporate Tax Discount Rate

Figure 7.4.21: Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4

with $5k per Ton NOx and $200 per Ton SOx Emissions Credits Sold and $28 per Pound

High Temperature Alloy Economic Sensitivity Results
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 235 September 8, 2004

Table 7.4.21: Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with

$5k per Ton NOx and $200 per Ton SOx Emissions Credits Sold and $28 per Pound High

Temperature Alloy Economic Sensitivity Results

Parameter Units Sporn Unit #4 - Repowering; $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 29.98 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

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 1.13 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 Sporn Unit #4 - Repowering; $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

Financing 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 Electricity (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 2.74 2.77 2.79 2.56 2.66 2.86 2.97
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 236 September 8, 2004

7.4.22 Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with $8k

per Ton NOx and $200 per Ton SOx Emissions Credits Sold and $28 per Pound High

Temperature Alloy Economic Sensitivity Results

Results for the Phillip Sporn Unit 4 Repowering Case COE sensitivity study are shown in Figure

9.4.22 and summarized in Table 9.4.22. The levelized 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 Variable

Percent Change in COE

2.2

2.4

2.6

2.8

3.0

3.2

3.4

Levelized COE (cents / kWh)

Capacity Factor EPC Price Coal Price

Equity Corporate Tax Discount Rate

Figure 7.4.22: Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4

with $8k per Ton NOx and $200 per Ton SOx Emissions Credits Sold and $28 per Pound

High Temperature Alloy Economic Sensitivity Results
ECONOMICS AND FEASIBILITY OF RANKINE CYCLE

IMPROVEMENTS FOR COAL FIRED POWER PLANTS 

ALSTOM Power Inc. 237 September 8, 2004

Table 7.4.22: Case Repowering Phillip Sporn Unit 4 – Repowering Phillip Sporn Unit 4 with

$8k per Ton NOx and $200 per Ton SOx Emissions Credits Sold and $28 per Pound High

Temperature Alloy Economic Sensitivity Results

Parameter Units Sporn Unit #4 - Repowering; $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 29.98 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

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 1.13 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 Sporn Unit #4 - Repowering; $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

Financing 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 Electricity (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 2.71 2.75 2.77 2.54 2.63 2.83 2.94