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Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity Revision 2
	ML12170A423
Person / Time
Site:	Watts Bar
Issue date:	11/01/2010
From:	; US Dept of Energy, National Energy Technology Lab
To:	Justin Poole; Watts Bar Special Projects Branch
References
	DOE/2010/1397 DOE/NETL-2010/1397, Rev 2
	Download: ML12170A423 (626)
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Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity Revision 2, November 2010 DOE/NETL-2010/1397

Disclaimer This report was prepared as an account of work sponsored by an agency of the United States 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 therein 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 therein do not necessarily state or reflect those of the United States Government or any agency thereof.

COST AND PERFORMANCE BASELINE FOR FOSSIL ENERGY PLANTS VOLUME 1: BITUMINOUS COAL AND NATURAL GAS TO ELECTRICITY DOE/2010/1397 Final Report (Original Issue Date, May 2007)

Revision 1, August 2007 Revision 2, November 2010 NETL

Contact:

James Black Combustion Systems Lead Office of Systems, Analysis and Planning National Energy Technology Laboratory www.netl.doe.gov

This page intentionally left blank NETL Viewpoint

Background

The goal of Fossil Energy Research, Development, and Demonstration (RD&D) is to ensure the availability of ultra-clean (zero emissions), abundant, low-cost, domestic electricity and energy (including hydrogen) to fuel economic prosperity and strengthen energy security. A broad portfolio of technologies is being developed within the Clean Coal Program to accomplish this objective. Ever increasing technological enhancements are in various stages of the research pipeline, and multiple paths are being pursued to create a portfolio of promising technologies for development, demonstration, and eventual deployment. The technological progress of recent years has created a remarkable new opportunity for coal. Advances in technology are making it possible to generate power from fossil fuels with great improvements in the efficiency of energy use while at the same time significantly reducing the impact on the environment, including the long-term impact of fossil energy use on the Earths climate. The objective of the Clean Coal RD&D Program is to build on these advances and bring these building blocks together into a new, revolutionary concept for future coal-based power and energy production.

Objective To establish baseline performance and cost estimates for todays fossil energy plants, it is necessary to look at the current state of technology. Such a baseline can be used to benchmark the progress of the Fossil Energy RD&D portfolio. This study provides an accurate, independent assessment of the cost and performance for Pulverized Coal (PC) Combustion, Integrated Gasification Combined Cycles (IGCC), and Natural Gas Combined Cycles (NGCC), all with and without carbon dioxide (CO2) capture and sequestration assuming that the plants use technology available today.

Approach The power plant configurations analyzed in this study were modeled using the ASPEN Plus (Aspen) modeling program. Performance and process limits were based upon published reports, information obtained from vendors and users of the technology, cost and performance data from design/build utility projects, and/or best engineering judgment. Capital and operating costs were estimated by WorleyParsons based on simulation results and through a combination of existing vendor quotes, scaled estimates from previous design/build projects, or a combination of the two.

Operation and maintenance (O&M) costs and the cost for transporting, storing, and monitoring (TS&M) carbon dioxide (CO2) in the cases with carbon capture were also estimated based on reference data and scaled estimates. The cost of electricity (COE) was determined for all plants assuming investor-owned utility (IOU) financing. The initial results of this analysis were subjected to a significant peer review by industry experts, academia and government research and regulatory agencies. Based on the feedback from these experts, the report was updated both in terms of technical content and revised costs.

Results This independent analysis of fossil energy plant cost and performance is considered to be the most comprehensive set of publicly available data to date. While input was sought from technology vendors, the final assessment of performance and cost was determined independently, and may not represent the views of the technology vendors. The extent of collaboration with technology vendors varied from case to case, with minimal or no input from some vendors. Selection of system components and plant configurations from potential options and the rapid escalation in labor and material costs made it a challenge to develop state-of-the-art configurations and cost estimates. The rigorous expert technical review and systematic use of existing vendor quotes and project design/build data to develop the cost estimates in this report are believed to provide the most up-to-date performance and costs available in the public literature. The main purpose of publishing Revision 2 is to update performance and economic results. New data from technology vendors was incorporated into the modeling approach, owners costs were added to the financial model, and supplemental chapters were added that extend beyond the original report scope. The following are highlights of the study:

Coal-based plants using todays technology are capable of producing electricity at relatively high efficiencies of about 39 percent, higher heating value ([HHV], without CO2 capture) on bituminous coal while meeting or exceeding current environmental requirements for criteria pollutants.

Total overnight cost (TOC) for the non-capture plants are as follows: NGCC, $718/kW; PC, $2,010/kW (average); IGCC, $2,505/kW (average). With CO2 capture, capital costs are: NGCC, $1,497/kW; PC, $3,590/kW (average); IGCC, $3,568/kW (average).

At fuel costs of $1.64/MMBtu of coal and $6.55/MMBtu of natural gas, the COE for the non-capture plants is: 59 mills/kWh for NGCC, 59 mills/kWh for PC (average), and 77 mills/kWh (average) for IGCC.

When todays technology for CO2 capture and sequestration (CCS) is integrated into these new power plants, the resultant COE, including the cost of CO2 TS&M, is: 86 mills/kWh for NGCC; 108 mills/kWh (average) for PC; and 112 mills/kWh (average) for IGCC. The cost of transporting CO2 50 miles for storage in a geologic formation with over 30 years of monitoring is estimated to add about 3 to 6 mills/kWh. This represents less than 5.5 percent of the COE for each CO2 capture case.

A sensitivity study on natural gas price shows that at a coal price of $1.64/MMBtu, the average COE for IGCC with capture equals that of NGCC with CO2 capture at a gas price of $9.80/MMBtu. The average COE for PC with capture equals that of NGCC with capture at a gas price of $9.25/MMBtu. In terms of capacity factor (CF), when non-capture NGCC drops to 40 percent, such as in a peaking application, the COE is comparable to non-capture IGCC operating at base load (80 percent CF).

Fossil Energy RD&D aims at improving the performance and cost of clean coal power systems including the development of new approaches to capture and sequester greenhouse gases (GHGs). Improved efficiencies and reduced costs are required to improve the competitiveness of these systems in todays market and regulatory environment as well as in a carbon constrained scenario. The results of this analysis provide a starting point from which to measure the progress of RD&D achievements.

Cost and Performance Baseline for Fossil Energy Plants Table of Contents TABLE OF CONTENTS ..........................................................................................................VII LIST OF EXHIBITS................................................................................................................... XI PREPARED BY ....................................................................................................................... XIX ACKNOWLEDGMENTS ......................................................................................................... XX LIST OF ACRONYMS AND ABBREVIATIONS ............................................................... XXI EXECUTIVE

SUMMARY

...........................................................................................................1 PERFORMANCE..............................................................................................................................3 ENERGY EFFICIENCY ..................................................................................................................3 WATER USE................................................................................................................................7 COST RESULTS ..............................................................................................................................9 TOTAL OVERNIGHT COST............................................................................................................9 COST OF ELECTRICITY ..............................................................................................................11 CO2 EMISSION PRICE IMPACT ..................................................................................................16 COST OF CO2 AVOIDED ............................................................................................................19 ENVIRONMENTAL PERFORMANCE ...............................................................................................21

1. INTRODUCTION................................................................................................................27

2. GENERAL EVALUATION BASIS ...................................................................................31 2.1 SITE CHARACTERISTICS ..................................................................................................31 2.2 COAL CHARACTERISTICS ................................................................................................32 2.3 NATURAL GAS CHARACTERISTICS ..................................................................................34 2.4 ENVIRONMENTAL TARGETS ............................................................................................34 2.4.1 IGCC ..........................................................................................................................37 2.4.2 PC ..............................................................................................................................38 2.4.3 NGCC.........................................................................................................................39 2.4.4 CARBON DIOXIDE ........................................................................................................40 2.5 CAPACITY FACTOR .........................................................................................................41 2.6 RAW WATER WITHDRAWAL AND CONSUMPTION ............................................................41 2.7 COST ESTIMATING METHODOLOGY ................................................................................42 2.7.1 CAPITAL COSTS ............................................................................................................42 2.7.2 OPERATIONS AND MAINTENANCE COSTS .......................................................................52 2.7.3 CO2 TRANSPORT, STORAGE AND MONITORING ..............................................................53 2.7.4 FINANCE STRUCTURE, DISCOUNTED CASH FLOW ANALYSIS, AND COE ..........................56 2.8 IGCC STUDY COST ESTIMATES COMPARED TO INDUSTRY ESTIMATES ..........................63

3. IGCC POWER PLANTS ....................................................................................................67 3.1 IGCC COMMON PROCESS AREAS ...................................................................................67 3.1.1 COAL RECEIVING AND STORAGE ...................................................................................67 3.1.2 AIR SEPARATION UNIT (ASU) CHOICE AND INTEGRATION .............................................68 3.1.3 WATER GAS SHIFT REACTORS .......................................................................................72 3.1.4 MERCURY REMOVAL ....................................................................................................72 3.1.5 ACID GAS REMOVAL (AGR) PROCESS SELECTION .........................................................73 3.1.6 SULFUR RECOVERY/TAIL GAS CLEANUP PROCESS SELECTION .......................................81 3.1.7 SLAG HANDLING ..........................................................................................................84 3.1.8 POWER ISLAND ............................................................................................................84 3.1.9 STEAM GENERATION ISLAND .........................................................................................88 VII

Cost and Performance Baseline for Fossil Energy Plants 3.1.10 ACCESSORY ELECTRIC PLANT ...................................................................................92 3.1.11 INSTRUMENTATION AND CONTROL ............................................................................92 3.2 GENERAL ELECTRIC ENERGY IGCC CASES ....................................................................93 3.2.1 GASIFIER BACKGROUND ...............................................................................................94 3.2.2 PROCESS DESCRIPTION ................................................................................................96 3.2.3 KEY SYSTEM ASSUMPTIONS.........................................................................................103 3.2.4 SPARING PHILOSOPHY ................................................................................................105 3.2.5 CASE 1 PERFORMANCE RESULTS ................................................................................105 3.2.6 CASE 1 - MAJOR EQUIPMENT LIST ..............................................................................116 3.2.7 CASE 1 - COST ESTIMATING ........................................................................................124 3.2.8 CASE 2 - GEE IGCC WITH CO2 CAPTURE ..................................................................131 3.2.9 CASE 2 PERFORMANCE RESULTS ................................................................................135 3.2.10 CASE 2 - MAJOR EQUIPMENT LIST ..........................................................................146 3.2.11 CASE 2 - COST ESTIMATING ....................................................................................155 3.3 CONOCOPHILLIPS E-GASTM IGCC CASES.....................................................................162 3.3.1 GASIFIER BACKGROUND .............................................................................................162 3.3.2 PROCESS DESCRIPTION ..............................................................................................164 3.3.3 KEY SYSTEM ASSUMPTIONS.........................................................................................170 3.3.4 SPARING PHILOSOPHY ................................................................................................170 3.3.5 CASE 3 PERFORMANCE RESULTS ................................................................................172 3.3.6 CASE 3 - MAJOR EQUIPMENT LIST ..............................................................................182 3.3.7 CASE 3 - COSTS ESTIMATING RESULTS ........................................................................191 3.3.8 CASE 4 - E-GAS' IGCC POWER PLANT WITH CO2 CAPTURE .....................................198 3.3.9 CASE 4 PERFORMANCE RESULTS ................................................................................202 3.3.10 CASE 4 - MAJOR EQUIPMENT LIST ..........................................................................214 3.3.11 CASE 4 - COST ESTIMATING RESULTS ......................................................................222 3.4 SHELL GLOBAL SOLUTIONS IGCC CASES.....................................................................229 3.4.1 GASIFIER BACKGROUND .............................................................................................229 3.4.2 PROCESS DESCRIPTION ..............................................................................................231 3.4.3 KEY SYSTEM ASSUMPTIONS.........................................................................................237 3.4.4 SPARING PHILOSOPHY ................................................................................................239 3.4.5 CASE 5 PERFORMANCE RESULTS ................................................................................239 3.4.6 CASE 5 - MAJOR EQUIPMENT LIST ..............................................................................250 3.4.7 CASE 5 - COST ESTIMATING ........................................................................................258 3.4.8 CASE 6 - SHELL IGCC POWER PLANT WITH CO2 CAPTURE .........................................265 3.4.9 CASE 6 PERFORMANCE RESULTS ................................................................................271 3.4.10 CASE 6 - MAJOR EQUIPMENT LIST ..........................................................................282 3.4.11 CASE 6 - COST ESTIMATING ....................................................................................290 3.5 IGCC CASE

SUMMARY

.................................................................................................297

4. PULVERIZED COAL RANKINE CYCLE PLANTS ...................................................305 4.1 PC COMMON PROCESS AREAS ......................................................................................306 4.1.1 COAL AND SORBENT RECEIVING AND STORAGE ...........................................................306 4.1.2 STEAM GENERATOR AND ANCILLARIES ........................................................................306 4.1.3 NOX CONTROL SYSTEM...............................................................................................309 4.1.4 PARTICULATE CONTROL .............................................................................................310 4.1.5 MERCURY REMOVAL ..................................................................................................310 VIII

Cost and Performance Baseline for Fossil Energy Plants 4.1.6 FLUE GAS DESULFURIZATION.....................................................................................310 4.1.7 CARBON DIOXIDE RECOVERY FACILITY .......................................................................313 4.1.8 POWER GENERATION..................................................................................................318 4.1.9 BALANCE OF PLANT ...................................................................................................318 4.1.10 ACCESSORY ELECTRIC PLANT .................................................................................322 4.1.11 INSTRUMENTATION AND CONTROL ..........................................................................322 4.2 SUBCRITICAL PC CASES ...............................................................................................322 4.2.1 PROCESS DESCRIPTION ..............................................................................................323 4.2.2 KEY SYSTEM ASSUMPTIONS.........................................................................................327 4.2.3 SPARING PHILOSOPHY ................................................................................................329 4.2.4 CASE 9 PERFORMANCE RESULTS ................................................................................329 4.2.5 CASE 9 - MAJOR EQUIPMENT LIST .............................................................................338 4.2.6 CASE 9 - COST ESTIMATING .......................................................................................346 4.2.7 CASE 10 - PC SUBCRITICAL UNIT WITH CO2 CAPTURE ...............................................353 4.2.8 CASE 10 PERFORMANCE RESULTS ..............................................................................353 4.2.9 CASE 10 - MAJOR EQUIPMENT LIST ...........................................................................364 4.2.10 CASE 10 - COST ESTIMATING .................................................................................373 4.3 SUPERCRITICAL PC CASES ............................................................................................380 4.3.1 PROCESS DESCRIPTION ..............................................................................................380 4.3.2 KEY SYSTEM ASSUMPTIONS.........................................................................................384 4.3.3 SPARING PHILOSOPHY ................................................................................................385 4.3.4 CASE 11 PERFORMANCE RESULTS ..............................................................................385 4.3.5 CASE 11 - MAJOR EQUIPMENT LIST ...........................................................................394 4.3.6 CASE 11 - COSTS ESTIMATING RESULTS......................................................................402 4.3.7 CASE 12 - SUPERCRITICAL PC WITH CO2 CAPTURE ....................................................409 4.3.8 CASE 12 PERFORMANCE RESULTS ..............................................................................409 4.3.9 CASE 12 - MAJOR EQUIPMENT LIST ...........................................................................420 4.3.10 CASE 12 - COST ESTIMATING BASIS ........................................................................429 4.4 PC CASE

SUMMARY

......................................................................................................436

5. NATURAL GAS COMBINED CYCLE PLANTS .........................................................443 5.1 NGCC COMMON PROCESS AREAS ................................................................................443 5.1.1 NATURAL GAS SUPPLY SYSTEM ...................................................................................443 5.1.2 COMBUSTION TURBINE ...............................................................................................443 5.1.3 HEAT RECOVERY STEAM GENERATOR .........................................................................445 5.1.4 NOX CONTROL SYSTEM ..............................................................................................445 5.1.5 CARBON DIOXIDE RECOVERY FACILITY .......................................................................446 5.1.6 STEAM TURBINE .........................................................................................................448 5.1.7 WATER AND STEAM SYSTEMS ......................................................................................449 5.1.8 ACCESSORY ELECTRIC PLANT .....................................................................................451 5.1.9 INSTRUMENTATION AND CONTROL ..............................................................................451 5.2 NGCC CASES ...............................................................................................................452 5.2.1 PROCESS DESCRIPTION ..............................................................................................452 5.2.2 KEY SYSTEM ASSUMPTIONS.........................................................................................455 5.2.3 SPARING PHILOSOPHY ................................................................................................456 5.2.4 CASE 13 PERFORMANCE RESULTS ..............................................................................457 5.2.5 CASE 13 - MAJOR EQUIPMENT LIST ...........................................................................464 IX

Cost and Performance Baseline for Fossil Energy Plants 5.2.6 CASE 13 - COST ESTIMATING .....................................................................................469 5.2.7 CASE 14 - NGCC WITH CO2 CAPTURE .......................................................................476 5.2.8 CASE 14 PERFORMANCE RESULTS ..............................................................................476 5.2.9 CASE 14 MAJOR EQUIPMENT LIST ..............................................................................486 5.2.10 CASE 14 - COST ESTIMATING .................................................................................492 5.3 NGCC CASE

SUMMARY

...............................................................................................499

6. EFFECT OF HIGHER NATURAL GAS PRICES AND DISPATCH-BASED CAPACITY FACTORS ............................................................................................................505 6.1 INCREASING NATURAL GAS PRICES ..............................................................................505 6.2 PRICE METHODOLOGY ..................................................................................................505 6.3 COST OF ELECTRICITY ..................................................................................................506 6.4 DISPATCH-BASED CAPACITY FACTORS ........................................................................513 6.5 DISPATCH MODELING RESULTS WITHIN PJM...............................................................516 6.6 PJM INDEPENDENT SYSTEM OPERATOR .......................................................................522 6.6.1 PJM ROLES AND RESPONSIBILITIES ............................................................................523 6.6.2 GENERATION MIX.......................................................................................................524 6.6.3 PJM MARKETS...........................................................................................................524 6.6.4 PJM ENERGY MARKETS .............................................................................................525 6.6.5 DAY-AHEAD MARKET .................................................................................................525 6.6.6 PRICES AND DEMAND .................................................................................................527

6.7 DESCRIPTION

OF THE PJM REGIONAL MODELING ........................................................529 6.8 WPLANET MODEL INPUTS ...........................................................................................530

7. DRY AND PARALLEL COOLING ................................................................................533 7.1 STUDY RESULTS ...........................................................................................................535 7.2 SENSITIVITY CASE ........................................................................................................542

7.3 CONCLUSION

S ...............................................................................................................543

8. GEE IGCC IN QUENCH-ONLY CONFIGURATION WITH CO2 CAPTURE ........545 8.1 CASE 2A - GEE IGCC IN QUENCH ONLY MODE WITH CO2 CAPTURE .........................546 8.1.1 KEY SYSTEM ASSUMPTIONS.........................................................................................550 8.1.2 CASE 2A PERFORMANCE RESULTS ..............................................................................552 8.1.3 CASE 2A - MAJOR EQUIPMENT LIST ...........................................................................561 8.1.4 CASE 2A - COST ESTIMATING .....................................................................................570

9. SENSITIVITY TO MEA SYSTEM PERFORMANCE AND COST BITUMINOUS BASELINE CASE 12A ..............................................................................................................577 9.1 BASIS FOR SENSITIVITY ANALYSIS ...............................................................................577 9.2 PERFORMANCE ..............................................................................................................577 9.3 COST ESTIMATING ........................................................................................................583

10. REVISION CONTROL.................................................................................................591

11. REFERENCES ...............................................................................................................595 X

Cost and Performance Baseline for Fossil Energy Plants List of Exhibits Exhibit ES-1 Case Descriptions ..................................................................................................... 2 Exhibit ES-2 Cost and Performance Summary and Environmental Profile for All Cases ............ 5 Exhibit ES-3 Net Plant Efficiency (HHV Basis) ........................................................................... 6 Exhibit ES-4 Raw Water Withdrawal and Consumption .............................................................. 8 Exhibit ES-5 Plant Capital Costs ................................................................................................. 10 Exhibit ES-6 Economic Parameters Used to Calculate COE ...................................................... 12 Exhibit ES-7 COE by Cost Component ....................................................................................... 13 Exhibit ES-8 COE Sensitivity to Fuel Costs in Non-Capture Cases ........................................... 14 Exhibit ES-9 COE Sensitivity to Fuel Costs in CO2 Capture Cases............................................ 15 Exhibit ES-10 COE Sensitivity to Capacity Factor ..................................................................... 16 Exhibit ES-11 Impact of Carbon Emissions Price on Study Technologies ................................. 17 Exhibit ES-12 Lowest Cost Power Generation Options Comparing NGCC and Coal................ 18 Exhibit ES-13 First Year CO2 Avoided Costs ............................................................................. 20 Exhibit ES-14 Study Environmental Targets ............................................................................... 21 Exhibit ES-15 SO2, NOx, and Particulate Emission Rates .......................................................... 23 Exhibit ES-16 Mercury Emission Rates ...................................................................................... 24 Exhibit ES-17 CO2 Emissions Normalized By Net Output ......................................................... 26 Exhibit 1-1 Case Descriptions ..................................................................................................... 29 Exhibit 2-1 Site Ambient Conditions........................................................................................... 31 Exhibit 2-2 Site Characteristics ................................................................................................... 31 Exhibit 2-3 Design Coal............................................................................................................... 33 Exhibit 2-4 Natural Gas Composition.......................................................................................... 34 Exhibit 2-5 Standards of Performance for Electric Utility Steam Generating Units ................... 35 Exhibit 2-6 NSPS Mercury Emission Limits ............................................................................... 36 Exhibit 2-7 Probability Distribution of Mercury Concentration in the Illinois No. 6 Coal ......... 36 Exhibit 2-8 Environmental Targets for IGCC Cases ................................................................... 37 Exhibit 2-9 Environmental Targets for PC Cases ........................................................................ 38 Exhibit 2-10 Environmental Targets for NGCC Cases................................................................ 39 Exhibit 2-11 Capital Cost Levels and their Elements .................................................................. 43 Exhibit 2-12 Features of an AACE Class 4 Cost Estimate .......................................................... 44 Exhibit 2-13 AACE Guidelines for Process Contingency ........................................................... 48 Exhibit 2-14 TASC/TOC Factors ................................................................................................. 49 Exhibit 2-15 Owners Costs Included in TOC ............................................................................. 50 Exhibit 2-16 CO2 Pipeline Specification ..................................................................................... 53 Exhibit 2-17 Deep, Saline Aquifer Specification ........................................................................ 54 Exhibit 2-18 Global Economic Assumptions .............................................................................. 57 Exhibit 2-19 Financial Structure for Investor Owned Utility High and Low Risk Projects ........ 58 Exhibit 2-20 Illustration of COE Solutions using DCF Analysis ................................................ 60 Exhibit 2-21 PC with CCS in Current 2007 Dollars .................................................................... 61 Exhibit 2-22 Capital Charge Factors for COE Equation ............................................................. 62 Exhibit 2-23 COE and LCOE Summary...................................................................................... 63 Exhibit 3-1 Air Extracted from the Combustion Turbine and Supplied to the ASU in Non-Carbon Capture Cases ........................................................................................................... 70 Exhibit 3-2 Typical ASU Process Schematic .............................................................................. 71 XI

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-3 Flow Diagram for a Conventional AGR Unit ........................................................... 75 Exhibit 3-4 Common Chemical Reagents Used in AGR Processes ............................................ 76 Exhibit 3-5 Physical Solvent AGR Process Simplified Flow Diagram ....................................... 77 Exhibit 3-6 Common Physical Solvents Used in AGR Processes ............................................... 78 Exhibit 3-7 Common Mixed Solvents Used in AGR Processes .................................................. 79 Exhibit 3-8 Equilibrium Solubility Data on H2S and CO2 in Various Solvents .......................... 79 Exhibit 3-9 Typical Three-Stage Claus Sulfur Plant ................................................................... 82 Exhibit 3-10 Advanced F Class Combustion Turbine Performance Characteristics Using Natural Gas ........................................................................................................................................ 85 Exhibit 3-11 Typical Fuel Specification for F-Class Machines................................................... 86 Exhibit 3-12 Allowable Gas Fuel Contaminant Level for F-Class Machines ............................. 87 Exhibit 3-13 Case 1 Block Flow Diagram, GEE IGCC without CO2 Capture ............................ 98 Exhibit 3-14 Case 1 Stream Table, GEE IGCC without CO2 Capture ........................................ 99 Exhibit 3-15 GEE IGCC Plant Study Configuration Matrix ..................................................... 103 Exhibit 3-16 Balance of Plant Assumptions .............................................................................. 104 Exhibit 3-17 Case 1 Plant Performance Summary .................................................................... 106 Exhibit 3-18 Case 1 Emissions .................................................................................................. 107 Exhibit 3-19 Case 1 Carbon Balance ......................................................................................... 108 Exhibit 3-20 Case 1 Sulfur Balance ........................................................................................... 108 Exhibit 3-21 Case 1 Water Balance ........................................................................................... 109 Exhibit 3-22 Case 1 Coal Gasification and Air Separation Units Heat and Mass Balance Schematic ............................................................................................................................ 111 Exhibit 3-23 Case 1 Syngas Cleanup Heat and Mass Balance Schematic ................................ 112 Exhibit 3-24 Case 1 Combined-Cycle Power Generation Heat and Mass Balance Schematic . 113 Exhibit 3-25 Case 1 Overall Energy Balance (0°C [32°F] Reference)...................................... 115 Exhibit 3-26 Case 1 Total Plant Cost Summary ........................................................................ 125 Exhibit 3-27 Case 1 Total Plant Cost Details ............................................................................ 126 Exhibit 3-28 Case 1 Initial and Annual O&M Costs ................................................................. 130 Exhibit 3-29 Case 2 Block Flow Diagram, GEE IGCC with CO2 Capture ............................... 132 Exhibit 3-30 Case 2 Stream Table, GEE IGCC with CO2 Capture ........................................... 133 Exhibit 3-31 Case 2 Plant Performance Summary .................................................................... 136 Exhibit 3-32 Case 2 Air Emissions ............................................................................................ 137 Exhibit 3-33 Case 2 Carbon Balance ......................................................................................... 138 Exhibit 3-34 Case 2 Sulfur Balance ........................................................................................... 138 Exhibit 3-35 Case 2 Water Balance ........................................................................................... 139 Exhibit 3-36 Case 2 Coal Gasification and Air Separation Units Heat and Mass Balance Schematic ............................................................................................................................ 141 Exhibit 3-37 Case 2 Syngas Cleanup Heat and Mass Balance Schematic ................................ 142 Exhibit 3-38 Case 2 Combined-Cycle Power Generation Heat and Mass Balance Schematic . 143 Exhibit 3-39 Case 2 Overall Energy Balance (0°C [32°F] Reference)...................................... 145 Exhibit 3-40 Case 2 Total Plant Cost Summary ........................................................................ 156 Exhibit 3-41 Case 2 Total Plant Cost Details ............................................................................ 157 Exhibit 3-42 Case 2 Initial and Annual Operating and Maintenance Costs .............................. 161 Exhibit 3-43 Case 3 Block Flow Diagram, E-Gas' IGCC without CO2 Capture.................... 165 Exhibit 3-44 Case 3 Stream Table, E-Gas' IGCC without CO2 Capture ................................ 166 Exhibit 3-45 CoP IGCC Plant Study Configuration Matrix ...................................................... 171 XII

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-46 Case 3 Plant Performance Summary .................................................................... 173 Exhibit 3-47 Case 3 Air Emissions ............................................................................................ 174 Exhibit 3-48 Case 3 Carbon Balance ......................................................................................... 175 Exhibit 3-49 Case 3 Sulfur Balance ........................................................................................... 175 Exhibit 3-50 Case 3 Water Balance ........................................................................................... 176 Exhibit 3-51 Case 3 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic ............................................................................................................................ 177 Exhibit 3-52 Case 3 Syngas Cleanup Heat and Mass Balance Schematic ................................ 178 Exhibit 3-53 Case 3 Combined Cycle Power Generation Heat and Mass Balance Schematic . 179 Exhibit 3-54 Case 3 Overall Energy Balance (0°C [32°F] Reference)...................................... 181 Exhibit 3-55 Case 3 Total Plant Cost Summary ........................................................................ 192 Exhibit 3-56 Case 3 Total Plant Cost Details ............................................................................ 193 Exhibit 3-57 Case 3 Initial and Annual Operating and Maintenance Costs .............................. 197 Exhibit 3-58 Case 4 Block Flow Diagram, E-Gas' IGCC with CO2 Capture ......................... 199 Exhibit 3-59 Case 4 Stream Table, E-Gas' IGCC with CO2 Capture ..................................... 200 Exhibit 3-60 Case 4 Plant Performance Summary .................................................................... 204 Exhibit 3-61 Case 4 Air Emissions ............................................................................................ 205 Exhibit 3-62 Case 4 Carbon Balance ......................................................................................... 206 Exhibit 3-63 Case 4 Sulfur Balance ........................................................................................... 206 Exhibit 3-64 Case 4 Water Balance ........................................................................................... 207 Exhibit 3-65 Case 4 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic ............................................................................................................................ 209 Exhibit 3-66 Case 4 Syngas Cleanup Heat and Mass Balance Schematic ................................ 210 Exhibit 3-67 Case 4 Combined Cycle Power Generation Heat and Mass Balance Schematic . 211 Exhibit 3-68 Case 4 Overall Energy Balance (0°C [32°F] Reference)...................................... 213 Exhibit 3-69 Case 4 Total Plant Cost Summary ........................................................................ 223 Exhibit 3-70 Case 4 Total Plant Cost Details ............................................................................ 224 Exhibit 3-71 Case 4 Initial and Annual Operating and Maintenance Costs .............................. 228 Exhibit 3-72 Case 5 Block Flow Diagram, Shell IGCC without CO2 Capture ......................... 232 Exhibit 3-73 Case 5 Stream Table, Shell IGCC without CO2 Capture...................................... 233 Exhibit 3-74 Shell IGCC Plant Study Configuration Matrix ..................................................... 238 Exhibit 3-75 Case 5 Plant Performance Summary .................................................................... 240 Exhibit 3-76 Case 5 Air Emissions ............................................................................................ 241 Exhibit 3-77 Case 5 Carbon Balance ......................................................................................... 242 Exhibit 3-78 Case 5 Sulfur Balance ........................................................................................... 242 Exhibit 3-79 Case 5 Water Balance ........................................................................................... 243 Exhibit 3-80 Case 5 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic ............................................................................................................................ 245 Exhibit 3-81 Case 5 Syngas Cleanup Heat and Mass Balance Schematic ................................ 246 Exhibit 3-82 Case 5 Combined Cycle Power Generation Heat and Mass Balance Schematic . 247 Exhibit 3-83 Case 5 Overall Energy Balance (0°C [32°F] Reference)...................................... 249 Exhibit 3-84 Case 5 Total Plant Cost Summary ........................................................................ 259 Exhibit 3-85 Case 5 Total Plant Cost Details ............................................................................ 260 Exhibit 3-86 Case 5 Initial and Annual Operating and Maintenance Costs .............................. 264 Exhibit 3-87 Case 6 Block Flow Diagram, Shell IGCC with CO2 Capture .............................. 268 Exhibit 3-88 Case 6 Stream Table, Shell IGCC with CO2 Capture ........................................... 269 XIII

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-89 Case 6 Plant Performance Summary .................................................................... 272 Exhibit 3-90 Case 6 Air Emissions ............................................................................................ 273 Exhibit 3-91 Case 6 Carbon Balance ......................................................................................... 274 Exhibit 3-92 Case 6 Sulfur Balance ........................................................................................... 274 Exhibit 3-93 Case 6 Water Balance ........................................................................................... 275 Exhibit 3-94 Case 6 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic ............................................................................................................................ 277 Exhibit 3-95 Case 6 Syngas Cleanup Heat and Mass Balance Schematic ................................ 278 Exhibit 3-96 Case 6 Combined Cycle Power Generation Heat and Mass Balance Schematic . 279 Exhibit 3-97 Case 6 Overall Energy Balance (0°C [32°F] Reference)...................................... 281 Exhibit 3-98 Case 6 Total Plant Cost Summary ........................................................................ 291 Exhibit 3-99 Case 6 Total Plant Cost Details ............................................................................ 292 Exhibit 3-100 Case 6 Initial and Annual Operating and Maintenance Costs ............................ 296 Exhibit 3-101 Estimated Performance and Cost Results for IGCC Cases................................. 297 Exhibit 3-102 Plant Capital Cost for IGCC Cases ..................................................................... 298 Exhibit 3-103 COE for IGCC Cases .......................................................................................... 299 Exhibit 3-104 Capacity Factor Sensitivity of IGCC Cases ........................................................ 300 Exhibit 3-105 Coal Price Sensitivity of IGCC Cases ................................................................ 301 Exhibit 3-106 Cost of CO2 Avoided in IGCC Cases ................................................................. 301 Exhibit 3-107 Carbon Conversion Efficiency and Slag Carbon Content .................................. 302 Exhibit 3-108 Raw Water Withdrawal and Consumption in IGCC Cases ................................ 304 Exhibit 4-1 Fluor Econamine FG PlusSM Typical Flow Diagram ............................................. 314 Exhibit 4-2 CO2 Compressor Interstage Pressures .................................................................... 317 Exhibit 4-3 Case 9 Block Flow Diagram, Subcritical Unit without CO2 Capture ..................... 324 Exhibit 4-4 Case 9 Stream Table, Subcritical Unit without CO2 Capture ................................. 325 Exhibit 4-5 Subcritical PC Plant Study Configuration Matrix .................................................. 327 Exhibit 4-6 Balance of Plant Assumptions ................................................................................ 328 Exhibit 4-7 Case 9 Plant Performance Summary ...................................................................... 330 Exhibit 4-8 Case 9 Air Emissions .............................................................................................. 331 Exhibit 4-9 Case 9 Carbon Balance ........................................................................................... 332 Exhibit 4-10 Case 9 Sulfur Balance ........................................................................................... 332 Exhibit 4-11 Case 9 Water Balance ........................................................................................... 333 Exhibit 4-12 Case 9 Heat and Mass Balance, Subcritical PC Boiler without CO2 Capture ...... 335 Exhibit 4-13 Case 9 Heat and Mass Balance, Subcritical Steam Cycle .................................... 336 Exhibit 4-14 Case 9 Overall Energy Balance (0°C [32°F] Reference)...................................... 337 Exhibit 4-15 Case 9 Total Plant Cost Summary ........................................................................ 347 Exhibit 4-16 Case 9 Total Plant Cost Details ............................................................................ 348 Exhibit 4-17 Case 9 Initial and Annual Operating and Maintenance Costs .............................. 352 Exhibit 4-18 Case 10 Block Flow Diagram, Subcritical Unit with CO2 Capture ...................... 354 Exhibit 4-19 Case 10 Stream Table, Subcritical Unit with CO2 Capture ................................... 355 Exhibit 4-20 Case 10 Plant Performance Summary ................................................................... 357 Exhibit 4-21 Case 10 Air Emissions .......................................................................................... 358 Exhibit 4-22 Case 10 Carbon Balance ....................................................................................... 359 Exhibit 4-23 Case 10 Sulfur Balance ......................................................................................... 359 Exhibit 4-24 Case 10 Water Balance ......................................................................................... 359 Exhibit 4-25 Case 10 Heat and Mass Balance, Subcritical PC Boiler with CO2 Capture ......... 361 XIV

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-26 Case 10 Heat and Mass Balance, Subcritical Steam Cycle .................................. 362 Exhibit 4-27 Case 10 Overall Energy Balance (0°C [32°F] Reference).................................... 363 Exhibit 4-28 Case 10 Total Plant Cost Summary ...................................................................... 374 Exhibit 4-29 Case 10 Total Plant Cost Details .......................................................................... 375 Exhibit 4-30 Case 10 Initial and Annual Operating and Maintenance Costs ............................ 379 Exhibit 4-31 Case 11 Block Flow Diagram, Supercritical Unit without CO2 Capture.............. 381 Exhibit 4-32 Case 11 Stream Table, Supercritical Unit without CO2 Capture .......................... 382 Exhibit 4-33 Supercritical PC Plant Study Configuration Matrix ............................................. 384 Exhibit 4-34 Case 11 Plant Performance Summary .................................................................. 386 Exhibit 4-35 Case 11 Air Emissions .......................................................................................... 387 Exhibit 4-36 Case 11 Carbon Balance ....................................................................................... 387 Exhibit 4-37 Case 11 Sulfur Balance ......................................................................................... 388 Exhibit 4-38 Case 11 Water Balance ......................................................................................... 388 Exhibit 4-39 Case 11 Heat and Mass Balance, Supercritical PC Boiler without CO2 Capture . 391 Exhibit 4-40 Case 11 Heat and Mass Balance, Supercritical Steam Cycle ............................... 392 Exhibit 4-41 Case 11 Overall Energy Balance (0°C [32°F] Reference).................................... 393 Exhibit 4-42 Case 11 Total Plant Cost Summary ...................................................................... 403 Exhibit 4-43 Case 11 Total Plant Cost Details .......................................................................... 404 Exhibit 4-44 Case 11 Initial and Annual Operating and Maintenance Costs ............................ 408 Exhibit 4-45 Case 12 Block Flow Diagram, Supercritical Unit with CO2 Capture ................... 410 Exhibit 4-46 Case 12 Stream Table, Supercritical Unit with CO2 Capture ............................... 411 Exhibit 4-47 Case 12 Plant Performance Summary .................................................................. 413 Exhibit 4-48 Case 12 Air Emissions .......................................................................................... 414 Exhibit 4-49 Case 12 Carbon Balance ....................................................................................... 415 Exhibit 4-50 Case 12 Sulfur Balance ......................................................................................... 415 Exhibit 4-51 Case 12 Water Balance ......................................................................................... 415 Exhibit 4-52 Case 12 Heat and Mass Balance, Supercritical PC Boiler with CO2 Capture ...... 417 Exhibit 4-53 Case 12 Heat and Mass Balance, Supercritical Steam Cycle ............................... 418 Exhibit 4-54 Case 12 Overall Energy Balance (0°C [32°F] Reference).................................... 419 Exhibit 4-55 Case 12 Total Plant Cost Summary ...................................................................... 430 Exhibit 4-56 Case 12 Total Plant Cost Details .......................................................................... 431 Exhibit 4-57 Case 12 Initial and Annual Operating and Maintenance Costs ............................ 435 Exhibit 4-58 Estimated Performance and Cost Results for Pulverized Coal Cases .................. 436 Exhibit 4-59 Plant Capital Cost for PC Cases ........................................................................... 437 Exhibit 4-60 COE for PC Cases................................................................................................. 438 Exhibit 4-61 Sensitivity of COE to Capacity Factor for PC Cases ........................................... 439 Exhibit 4-62 Sensitivity of COE to Coal Price for PC Cases .................................................... 440 Exhibit 4-63 First Year Cost of CO2 Avoided in PC Cases ....................................................... 440 Exhibit 4-64 Raw Water Withdrawal and Consumption in PC Cases ....................................... 442 Exhibit 5-1 Combustion Turbine Typical Scope of Supply....................................................... 444 Exhibit 5-2 CO2 Compressor Interstage Pressures .................................................................... 449 Exhibit 5-3 Case 13 Block Flow Diagram, NGCC without CO2 Capture ................................. 453 Exhibit 5-4 Case 13 Stream Table, NGCC without CO2 Capture ............................................. 454 Exhibit 5-5 NGCC Plant Study Configuration Matrix .............................................................. 455 Exhibit 5-6 NGCC Balance of Plant Assumptions .................................................................... 456 Exhibit 5-7 Case 13 Plant Performance Summary .................................................................... 457 XV

Cost and Performance Baseline for Fossil Energy Plants Exhibit 5-8 Case 13 Air Emissions ............................................................................................ 458 Exhibit 5-9 Case 13 Carbon Balance ......................................................................................... 458 Exhibit 5-10 Case 13 Water Balance ......................................................................................... 459 Exhibit 5-11 Case 13 Heat and Mass Balance, NGCC without CO2 Capture ........................... 461 Exhibit 5-12 Case 13 Overall Energy Balance (0°C [32°F] Reference).................................... 463 Exhibit 5-13 Case 13 Total Plant Cost Summary ...................................................................... 470 Exhibit 5-14 Case 13 Total Plant Cost Details .......................................................................... 471 Exhibit 5-15 Case 13 Initial and Annual Operating and Maintenance Cost Summary ............. 475 Exhibit 5-16 Case 14 Block Flow Diagram, NGCC with CO2 Capture .................................... 477 Exhibit 5-17 Case 14 Stream Table, NGCC with CO2 Capture ................................................ 478 Exhibit 5-18 Case 14 Plant Performance Summary .................................................................. 479 Exhibit 5-19 Case 14 Air Emissions .......................................................................................... 480 Exhibit 5-20 Case 14 Carbon Balance ....................................................................................... 480 Exhibit 5-21 Case 14 Water Balance ......................................................................................... 481 Exhibit 5-22 Case 14 Heat and Mass Balance, NGCC with CO2 Capture ................................ 483 Exhibit 5-23 Case 14 Overall Energy Balance (0°C [32°F] Reference).................................... 485 Exhibit 5-24 Case 14 Total Plant Cost Summary ...................................................................... 493 Exhibit 5-25 Case 14 Total Plant Cost Details .......................................................................... 494 Exhibit 5-26 Case 14 Initial and Annual Operating and Maintenance Cost Summary ............. 498 Exhibit 5-27 Estimated Performance and Cost Results for NGCC Cases ................................. 499 Exhibit 5-28 Plant Capital Cost for NGCC Cases ..................................................................... 500 Exhibit 5-29 COE of NGCC Cases ............................................................................................ 501 Exhibit 5-30 Sensitivity of COE to Capacity Factor in NGCC Cases ....................................... 502 Exhibit 5-31 Sensitivity of COE to Fuel Price in NGCC Cases ................................................ 502 Exhibit 5-32 Raw Water Withdrawal and Consumption in NGCC Cases................................. 504 Exhibit 6-1 COE By Cost Component ....................................................................................... 508 Exhibit 6-2 First Year CO2 Avoided Costs ................................................................................ 509 Exhibit 6-3 COE Sensitivity to Fuel Costs in Non-Capture Cases ............................................ 510 Exhibit 6-4 COE Sensitivity to Fuel Costs in CO2 Capture Cases ............................................ 511 Exhibit 6-5 COE Sensitivity to Capacity Factor in Non-Capture Cases ................................... 512 Exhibit 6-6 COE Sensitivity to Capacity Factor in Capture Cases ............................................ 513 Exhibit 6-7 Dispatch Based Capacity Factors for Cases without CO2 Capture ......................... 514 Exhibit 6-8 Estimated Stacking Order in PJM for Year 2010 Based on First Year Production Costs .................................................................................................................................... 517 Exhibit 6-9 Capacity Factors of Replacement Units Dispatched into PJM ............................... 518 Exhibit 6-10 Dispatch Based Capacity Factors Assuming No CO2 Capture ............................. 518 Exhibit 6-11 Summary of Prospective Facility Parameters for Modeling ................................. 519 Exhibit 6-12 Comparison of COE as a Function of Capacity Factor ........................................ 520 Exhibit 6-13 Impact of Dispatched Based Capacity Factors on the Cost of Electricity ............ 521 Exhibit 6-14 The PJM Operating Territory ............................................................................... 523 Exhibit 6-15 PJM Installed Capacity by Fuel Type ................................................................... 524 Exhibit 6-16 PJM East Day-Ahead LMP for 2006 .................................................................... 526 Exhibit 6-17 PJM Load and Day-Ahead LMP for 2006 ............................................................ 527 Exhibit 6-18 PJM Day-Ahead LMP vs. Demand for 2006 ........................................................ 528 Exhibit 6-19 PJM Price/Load Distribution for 2006.................................................................. 528 Exhibit 6-20 Data Sources for Electricity Generation in the PJM Region in Year 2006 .......... 530 XVI

Cost and Performance Baseline for Fossil Energy Plants Exhibit 6-21 Assumptions for Projecting PJM Year 2006 into 2010 ........................................ 531 Exhibit 6-22 Breakdown of Additional Generation in the PJM ISO by Fuel Type ................... 531 Exhibit 6-23 Summary of Prospective Facility Parameters ....................................................... 532 Exhibit 7-1 Cost Accounts Affected by Change in Cooling System ......................................... 534 Exhibit 7-2 Normalized Raw Water Withdrawal for Baseline, Parallel and Dry Cooling Cases

............................................................................................................................................. 536 Exhibit 7-3 Absolute Decrease in Raw Water Withdrawal for Parallel and Dry Cooling Cases

............................................................................................................................................. 537 Exhibit 7-4 Net Output Reduction Relative to the Baseline (Wet Cooling) Case ..................... 538 Exhibit 7-5 Total Overnight Cost for Baseline, Parallel and Dry Cooling Cases...................... 540 Exhibit 7-6 COE for Baseline, Parallel and Dry Cooling Systems............................................ 541 Exhibit 7-7 Design Ambient Conditions for SC PC Sensitivity Case ........................................ 542 Exhibit 8-1 Case 2A Block Flow Diagram, GEE Quench Only IGCC with CO2 Capture........ 547 Exhibit 8-2 Case 2A Stream Table, GEE Quench Only IGCC with CO2 Capture .................... 548 Exhibit 8-3 GEE IGCC Plant Study Configuration Matrix ....................................................... 551 Exhibit 8-4 Case 2A Plant Performance Summary.................................................................... 553 Exhibit 8-5 Case 2A Air Emissions ........................................................................................... 554 Exhibit 8-6 Case 2A Carbon Balance ........................................................................................ 555 Exhibit 8-7 Case 2A Sulfur Balance .......................................................................................... 555 Exhibit 8-8 Case 2A Water Balance .......................................................................................... 556 Exhibit 8-9 Case 2A Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic ............................................................................................................................ 557 Exhibit 8-10 Case 2A Syngas Cleanup Heat and Mass Balance Schematic.............................. 558 Exhibit 8-11 Case 2A Combined Cycle Power Generation Heat and Mass Balance Schematic

............................................................................................................................................. 559 Exhibit 8-12 Case 2A Overall Energy Balance ......................................................................... 561 Exhibit 8-13 Case 2A Total Plant Cost Summary ..................................................................... 571 Exhibit 8-14 Case 2A Total Plant Cost Details ......................................................................... 572 Exhibit 8-15 Case 2A Initial and Annual Operating and Maintenance Costs ........................... 576 Exhibit 9-1 Case 12A Block Flow Diagram, Supercritical Unit with CO2 Capture (MEA Sensitivity) .......................................................................................................................... 579 Exhibit 9-2 Case 12A Stream Table, Supercritical Unit with CO2 Capture .............................. 580 Exhibit 9-3 Case 12A Plant Performance Summary.................................................................. 582 Exhibit 9-4 Case 12A Total Plant Cost Summary ..................................................................... 584 Exhibit 9-5 Case 12A Total Plant Cost Details ......................................................................... 585 Exhibit 9-6 Case 12A Initial and Annual Operating and Maintenance Costs ........................... 589 Exhibit 10-1 Record of Revisions .............................................................................................. 591 XVII

Cost and Performance Baseline for Fossil Energy Plants This page intentionally left blank XVIII

Cost and Performance Baseline for Fossil Energy Plants PREPARED BY:

Research and Development Solutions, LLC (RDS)

UPDATED BY:

Energy Sector Planning and Analysis (ESPA)

John L. Haslbeck Booz Allen Hamilton Norma J. Kuehn Booz Allen Hamilton Eric G. Lewis Booz Allen Hamilton Lora L. Pinkerton WorleyParsons Group, Inc.

James Simpson WorleyParsons Group, Inc.

Marc J. Turner Booz Allen Hamilton Elsy Varghese WorleyParsons Group, Inc.

Mark C. Woods Booz Allen Hamilton DOE Contract # DE-FE0004001 XIX

Cost and Performance Baseline for Fossil Energy Plants Acknowledgments This report was initially prepared by Research and Development Solutions, LLC (RDS) for the United States Department of Energys (DOE) National Energy Technology Laboratory (NETL) under DOE NETL Contract Number DE-AM26-04NT41817; Subtask 41817-401.01.04. The report was updated by Booz Allen Hamilton Inc. under DOE NETL Contract Number DE-FE0004001, Energy Sector Planning and Analysis.

The authors wish to acknowledge the excellent guidance, contributions, and cooperation of the NETL staff and other past contributors, particularly:

John Wimer, Director of OSAP Systems Division James Black Daniel Cicero Jared Ciferno Kristin Gerdes Eric Grol Jeffrey Hoffmann Julianne Klara Patrick Le Michael Matuszewski Sean Plasynski Larry Rath Wally Shelton Gary Stiegel William Summers Thomas Tarka Maria Vargas Pamela Capicotto formerly of Parsons Corporation Michael Rutkowski formerly of Parsons Corporation Ronald Schoff formerly of Parsons Corporation Vladimir Vaysman WorleyParsons Group, Inc.

XX

Cost and Performance Baseline for Fossil Energy Plants LIST OF ACRONYMS AND ABBREVIATIONS AACE Association for the Advancement of Cost Engineering ADIP Aqueous di-isoproponal AEO Annual Energy Outlook AGR Acid gas removal ANSI American National Standards Institute Aspen Aspen Plus ASU Air separation unit BACT Best available control technology BEC Bare erected cost BFD Block flow diagram BFW Boiler feedwater Btu British thermal unit Btu/hr British thermal unit per hour Btu/kWh British thermal unit per kilowatt-hour Btu/lb British thermal unit per pound Btu/scf British thermal unit per standard cubic foot m3/d Cubic meters per day CAMR Clean Air Mercury Rule CCF Capital Charge Factor CCS Carbon capture and sequestration CDR Carbon Dioxide Recovery CF Capacity factor CGE Cold gas efficiency CL Closed-loop cm Centimeter CMU Carnegie Mellon University CO Carbon monoxide CO2 Carbon dioxide COE Cost of electricity CoP ConocoPhillips COS Carbonyl sulfide CRT Cathode ray tube CS Carbon steel CT Combustion turbine CTG Combustion Turbine-Generator CWP Circulating water pump CWS Circulating water system DCS Distributed control system DI De-ionized DIPA Diisopropanolamine DLN Dry low NOx DOE Department of Energy XXI

Cost and Performance Baseline for Fossil Energy Plants EAF Equivalent availability factor E-GasTM ConocoPhillips gasifier technology EIA Energy Information Administration EM Electromagnetic EMF Emission modification factors EPA Environmental Protection Agency EPC Engineer/Procure/Construct EPRI Electric Power Research Institute EPCM Engineering/Procurement/Construction Management EU European Union ESP Electrostatic precipitator FD Forced draft FERC Federal Energy Regulatory Commission FG Flue gas FGD Flue gas desulfurization FOAK First-of-a-kind FRP Fiberglass-reinforced plastic ft Foot, feet FW Feedwater ft, w.g. Feet of water gauge GADS Generating Availability Data System gal Gallon gal/MWh Gallon per megawatt hour GCV Gross calorific value GDP Gross domestic product GEE General Electric Energy GHG Greenhouse gas gpd Gallons per day gpm Gallons per minute gr/100 scf grains per one hundred standard cubic feet GSU Generator step-up transformers GT Gas turbine GWh Gigawatt-hour h Hour H2 Hydrogen H2S Hydrogen sulfide H2SO4 Sulfuric acid Hg Mercury HDPE High-density polyethylene HHV Higher heating value hp Horsepower HP High-pressure HRSG Heat recovery steam generator XXII

Cost and Performance Baseline for Fossil Energy Plants HSS Heat stable salts HVAC Heating, ventilating, and air conditioning ICR Information Collection Request ID Induced draft IEA International Energy Agency IGCC Integrated gasification combined cycle IGVs Inlet guide vanes In. H2O Inches water In. Hga Inches mercury (absolute pressure)

In. W.C. Inches water column IOU Investor-owned utility IP Intermediate pressure IPM Integrated Planning Model IPP Independent power producer ISO International Standards Organization kg/GJ Kilogram per gigajoule kg/hr Kilogram per hour kJ Kilojoules kJ/hr Kilojoules per hour kJ/kg Kilojoules per kilogram km Kilometer KO Knockout kPa Kilopascal absolute kV Kilovolt kW Kilowatt kWe Kilowatt-electric kWh Kilowatt-hour LAER Lowest Achievable Emission Rate LF Levelization factor lb Pound lb/gal Pound per gallon lb/hr Pounds per hour 2

lb/ft Pounds per square foot lb/MMBtu Pounds per million British thermal units lb/MWh Pounds per megawatt-hour lb/TBtu Pounds per trillion British thermal units LCOE Levelized cost of electricity LGTI Louisiana Gasification Technology, Inc.

LHV Lower heating value LMP Locational Marginal Price LNB Low NOx burner LNG Liquified natural gas LP Low-pressure XXIII

Cost and Performance Baseline for Fossil Energy Plants lpm Liters per minute LSE Load-serving entities m Meters m/min Meters per minute 3

m /min Cubic meter per minute MAC Main Air Compressor MAF Moisture/Ash-Free MCR Maximum continuous rating md Millidarcy MDEA Methyldiethanolamine MEA Monoethanolamine MHz Megahertz Mills/kWh Tenths of a cent per kilowatt hour MJ/Nm3 Megajoule per normal cubic meter MMBtu Million British thermal units (also shown as 106 Btu)

MMBtu/hr Million British thermal units (also shown as 106 Btu) per hour MMkJ Million kilojoules (also shown as 106 kJ)

MMkJ/hr Million kilojoules (also shown as 106 kJ) per hour MNQC Multi Nozzle Quiet Combustor mol% Mole percent MPa Megapascals MVA Mega volt-amps MW Megawatt MWe Megawatts electric MWh Megawatt-hour N2 Nitrogen N/A Not applicable NaOH Sodium hydroxide NEMA National Electrical Manufacturers Association NERC North American Electric Reliability Council NETL National Energy Technology Laboratory NGCC Natural gas combined cycle NH3 Ammonia Nm3 Normal cubic meter 3

Nm /hr Normal cubic meter per hour NMP N-methyl-2-pyrrolidone NOAK Nth-of-a-kind NOx Oxides of nitrogen NSPS New Source Performance Standards NSR New Source Review O&GJ Oil & Gas Journal O2 Oxygen O&M Operation and maintenance XXIV

Cost and Performance Baseline for Fossil Energy Plants OCFn Category n fixed operating cost for the initial year of operation OD Outside diameter OEM Original equipment manufacturers OFA Overfire air OP/VWO Over pressure/valves wide open PA Primary air PC Pulverized coal PECO Philadelphia Electric Company PJM Pennsylvania-New Jersey-Maryland Interconnection PM Particulate matter PO Purchase order POTW Publicly Owned Treatment Works PP&L Pennsylvania Power & Light Company ppm Parts per million ppmv Parts per million volume ppmvd Parts per million volume, dry PPS Polyphenylensulfide PRB Powder River Basin coal region PSD Prevention of Significant Deterioration PSE&G Public Service Electric & Gas Company psi Pounds per square inch psia Pounds per square inch absolute psig Pounds per square inch gage PTFE Teflon (Polytetrafluoroethylene)

PSFM Power systems financial model RD&D Research, Development, and Demonstration RDS Research and Development Solutions, LLC RH Reheater RTO Regional transmission organization SC Supercritical scf Standard cubic feet scfh Standard cubic feet per hour scfm Standard cubic feet per minute Sch Schedule scmh Standard cubic meter per hour SCOT Shell Claus Off-gas Treating SC PC Supercritical Pulverized Coal SCR Selective catalytic reduction SEP Samenwerkende Electriciteits-Productiebedrijven NV SG Specific gravity SFC Synthetic Fuels Corporation SGC Synthesis gas cooler SGS Sour gas shift XXV

Cost and Performance Baseline for Fossil Energy Plants Shell Shell Global Solutions SNCR Selective non-catalytic reduction SNG Synthetic natural gas SO2 Sulfur dioxide SOx Oxides of sulfur SRU Sulfur recovery unit SS Stainless steel SS Amine SS Specialty Amine STG Steam turbine generator Syngas Synthetic gas TASC Total as-spent cost TOC Total overnight cost TPC Total plant cost TEWAC Totally Enclosed Water-to-Air-Cooled TGTU Tail gas treating unit Tonne Metric ton (1000 kg)

TPC Total plant cost TPD Tons per day TPH Tons per hour TPI Total plant investment TS&M Transport, storage, and monitoring U.S. United States vol% Volume percent WB Wet bulb WGS Water-gas shift wg Water gauge WTI West Texas Intermediate wt% Weight percent yr Year

$/kW Dollars per kilowatt

$/MMBtu Dollars per million British thermal units

$/MMkJ Dollars per million kilojoule

$/MW Dollars per megawatt

$/MWh Dollars per megawatt-hour

°C Degrees Celsius

°F Degrees Fahrenheit 5-10s Fifty hour work weeks XXVI

Cost and Performance Baseline for Fossil Energy Plants EXECUTIVE

SUMMARY

The objective of this report is to present an accurate, independent assessment of the cost and performance of fossil energy power systems, specifically integrated gasification combined cycle (IGCC), pulverized coal (PC), and natural gas combined cycle (NGCC) plants, using a consistent technical and economic approach that accurately reflects current market conditions. This is Volume 1 of a four volume report. The four volume series consists of the following:

Volume 1: Bituminous Coal and Natural Gas to Electricity

Volume 2: Coal to Synthetic Natural Gas and Ammonia (Various Coal Ranks)

Volume 3: Low Rank Coal and Natural Gas to Electricity

Volume 4: Bituminous Coal to Liquid Fuels with Carbon Capture The cost and performance of the various fossil fuel-based technologies will most likely determine which combination of technologies will be utilized to meet the demands of the power market. Selection of new generation technologies will depend on many factors, including:

Capital and operating costs

Overall energy efficiency

Fuel prices

Cost of electricity (COE)

Availability, reliability, and environmental performance

Current and potential regulation of air, water, and solid waste discharges from fossil-fueled power plants

Market penetration of clean coal technologies that have matured and improved as a result of recent commercial-scale demonstrations under the Department of Energys (DOE)

Clean Coal Programs Twelve power plant configurations were analyzed as listed in Exhibit ES-1. The list includes six IGCC cases utilizing General Electric Energy (GEE), ConocoPhillips (CoP), and Shell Global Solutions (Shell) gasifiers each with and without carbon dioxide (CO2) capture; four PC cases, two subcritical and two supercritical (SC), each with and without CO2 capture; and two NGCC plants with and without CO2 capture. Two additional cases were originally included in this study and involve production of synthetic natural gas (SNG) and the repowering of an existing NGCC facility using SNG. The two SNG cases were subsequently moved to Volume 2 of this report resulting in the discontinuity of case numbers (1-6 and 9-14).

While input was sought from various technology vendors, the final assessment of performance and cost was determined independently and has not been reviewed by individual vendors. Thus, portions of this report may not represent the views of the technology vendors. The extent of collaboration with technology vendors varied from case to case, with minimal or no collaboration obtained from some vendors.

The methodology included performing steady-state simulations of the various technologies using the ASPEN Plus (Aspen) modeling program. The resulting mass and energy balance data from 1

Cost and Performance Baseline for Fossil Energy Plants the Aspen model were used to size major pieces of equipment. These equipment sizes formed the basis for cost estimating. Performance and process limits were based upon published reports, information obtained from vendors and users of the technology, performance data from design/build utility projects, and/or best engineering judgment. Capital and operating costs were estimated by WorleyParsons based on simulation results and through a combination of vendor quotes, scaled estimates from previous design/build projects, or a combination of the two.

Baseline fuel costs for this analysis were determined using data from the Energy Information Administrations (EIA) Annual Energy Outlook (AEO) 2008. The first year of capital expenditure (2007) costs used are $1.55/MMkJ ($1.64/MMBtu) for coal (Illinois No. 6) and

$6.21/MMkJ ($6.55 /MMBtu) for natural gas, both on a HHV basis and in 2007 United States (U.S.) dollars.

Exhibit ES-1 Case Descriptions H2S Sulfur CO2 Unit Steam Cycle, Combustion Gasifier/Boiler Case Oxidant Separation/ Removal/ Separa-Cycle psig/°F/°F Turbine Technology Removal Recovery tion 2 x Advanced GEE Radiant 95 mol%

1 IGCC 1800/1050/1050 Selexol Claus Plant F Class Only O2 2 x Advanced GEE Radiant 95 mol% Selexol 2 IGCC 1800/1000/1000 Selexol Claus Plant nd F Class Only O2 2 stage 2 x Advanced 95 mol% Refrigerated 3 IGCC 1800/1050/1050 CoP E-Gas' Claus Plant F Class O2 MDEA 2 x Advanced 95 mol% Selexol 4 IGCC 1800/1000/1000 CoP E-Gas' Selexol Claus Plant nd F Class O2 2 stage 2 x Advanced 95 mol%

5 IGCC 1800/1050/1050 Shell Sulfinol-M Claus Plant F Class O2 2 x Advanced 95 mol% Selexol 6 IGCC 1800/1000/1000 Shell Selexol Claus Plant nd F Class O2 2 stage Wet Flue gas desulfuri-9 PC 2400/1050/1050 Subcritical PC Air zation (FGD)/

Gypsum Wet FGD/ Amine 10 PC 2400/1050/1050 Subcritical PC Air Gypsum Absorber Wet FGD/

11 PC 3500/1100/1100 Supercritical PC Air Gypsum Wet FGD/ Amine 12 PC 3500/1100/1100 Supercritical PC Air Gypsum Absorber 2 x Advanced 13 NGCC 2400/1050/1050 HRSG Air F Class 2 x Advanced Amine 14 NGCC 2400/1050/1050 HRSG Air F Class Absorber All plant configurations are evaluated based on installation at a greenfield site. Since these are state-of-the-art plants, they will have higher efficiencies than the average power plant population.

Consequently, these plants would be expected to be near the top of the dispatch list and the study 2

Cost and Performance Baseline for Fossil Energy Plants capacity factor (CF) is chosen to reflect the maximum availability demonstrated for the specific plant type, i.e., 80 percent for IGCC and 85 percent for PC and NGCC configurations. Since variations in fuel costs and other factors can influence dispatch order and CF, sensitivity of the cost of electricity (COE) to CF is evaluated and presented later in this Executive Summary (Exhibit ES-10) and in the body of the report.

The nominal net plant output for this study is set at 550 megawatt (MW). The actual net output varies between technologies because the combustion turbines (CTs) in the IGCC and NGCC cases are manufactured in discrete sizes, but the boilers and steam turbines in the PC cases are readily available in a wide range of capacities. The result is that all of the PC cases have a net output of 550 MW, but the IGCC cases have net outputs ranging from 497 (Case 6) to 629 MW (Case 5). The range in IGCC net output is caused by the much higher auxiliary load imposed in the CO2 capture cases, primarily due to CO2 compression, and the need for extraction steam in the water-gas shift (WGS) reactions, which reduces steam turbine output. Higher auxiliary load and extraction steam requirements can be accommodated in the PC cases (larger boiler and steam turbine) but not in the IGCC cases where it is impossible to maintain a constant net output from the steam cycle given the fixed input (CT). Likewise, the two NGCC cases have a net output of 555 and 474 MW because of the CT constraint.

Exhibit ES-2 shows the cost, performance, and environmental profile summary for all cases.

The results are discussed below in the following order:

Performance (efficiency and raw water consumption)

Cost (plant capital costs and COE)

Environmental profile PERFORMANCE Energy Efficiency The net plant efficiency (HHV basis) for all twelve cases is shown in Exhibit ES-3. The primary conclusions that can be drawn are:

The NGCC with no CO2 capture has the highest net efficiency of the technologies modeled in this study with an efficiency of 50.2 percent.

The NGCC case with CO2 capture results in the highest efficiency (42.8 percent) among all of the capture technologies.

The NGCC with CO2 capture results in a relative efficiency penalty of 14.7 percent (7.4 absolute percent), compared to the non-capture case. The NGCC penalty is less than for the PC cases because natural gas is less carbon intensive than coal, and there is less CO2 to capture and to compress for equal net power outputs.

The energy efficiency of the IGCC non-capture cases is as follows: the dry-fed Shell gasifier (42.1 percent), the slurry-fed, two-stage CoP gasifier (39.7 percent) and the slurry-fed, single-stage GEE gasifier (39.0 percent).

3

Cost and Performance Baseline for Fossil Energy Plants

When CO2 capture is added to the IGCC cases, the energy efficiency of all three cases is more nearly equal than the non-capture cases, ranging from 31.0 percent for CoP to 32.6 percent for GEE, with Shell intermediate at 31.2 percent.

The relative efficiency penalty for adding CO2 capture to the IGCC cases is 21.4 percent on average. The relative penalty for subcritical and SC PC is 28.9 and 27.6 percent, respectively. The relative penalty for NGCC is 14.7 percent.

SC PC without CO2 capture has an efficiency of 39.3 percent. Subcritical PC has an efficiency of 36.8 percent, which is the lowest of all the non-capture cases in the study.

The addition of CO2 capture to the PC cases via the Fluor Econamine FG PlusSM (Econamine) process has the highest relative efficiency penalties out of all the cases studied. This is primarily because the low partial pressure of CO2 in the flue gas (FG) from a PC plant requires a chemical absorption process rather than physical absorption. For chemical absorption processes, the regeneration requirements are more energy intensive. The relative efficiency impact on NGCC is less because of the lower carbon intensity of natural gas relative to coal as mentioned above.

4

Cost and Performance Baseline for Fossil Energy Plants Exhibit ES-2 Cost and Performance Summary and Environmental Profile for All Cases Integrated Gasification Combined Cycle Pulverized Coal Boiler NGCC GEE R+Q CoP E-Gas FSQ Shell PC Subcritical PC Supercritical Advanced F Class PERFORMANCE Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 Case 9 Case 10 Case 11 Case 12 Case 13 Case 14 CO2 Capture 0% 90% 0% 90% 0% 90% 0% 90% 0% 90% 0% 90%

Gross Power Output (kWe) 747,800 734,000 738,200 703,700 737,000 673,400 582,600 672,700 580,400 662,800 564,700 511,000 Auxiliary Power Requirement (kWe) 125,750 190,750 113,140 190,090 108,020 176,540 32,580 122,740 30,410 112,830 9,620 37,430 Net Power Output (kWe) 622,050 543,250 625,060 513,610 628,980 496,860 550,020 549,960 549,990 549,970 555,080 473,570 Coal Flowrate (lb/hr) 466,901 487,011 459,958 484,212 436,646 465,264 437,378 614,994 409,528 565,820 N/A N/A Natural Gas Flowrate (lb/hr) N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 167,333 167,333 HHV Thermal Input (kWth) 1,596,320 1,665,074 1,572,582 1,655,503 1,492,878 1,590,722 1,495,379 2,102,643 1,400,162 1,934,519 1,105,812 1,105,812 Net Plant HHV Efficiency (%) 39.0% 32.6% 39.7% 31.0% 42.1% 31.2% 36.8% 26.2% 39.3% 28.4% 50.2% 42.8%

Net Plant HHV Heat Rate (Btu/kWh) 8,756 10,458 8,585 10,998 8,099 10,924 9,277 13,046 8,687 12,002 6,798 7,968 Raw Water Withdrawal (gpm/MW net) 7.6 10.7 7.0 11.1 6.6 11.3 10.7 20.4 9.7 18.3 4.3 8.4 Process Water Discharge (gpm/MW net) 1.6 2.0 1.4 2.1 1.2 2.0 2.2 4.7 2.0 4.3 1.0 2.1 Raw Water Consumption (gpm/MW net) 6.0 8.7 5.5 9.0 5.3 9.3 8.5 15.7 7.7 14.1 3.3 6.3 CO2 Emissions (lb/MMBtu) 197 20 199 20 197 20 204 20 204 20 118 12 CO2 Emissions (lb/MWhgross) 1,434 152 1,448 158 1,361 161 1,783 217 1,675 203 790 87 CO2 Emissions (lb/MWhnet) 1,723 206 1,710 217 1,595 218 1,888 266 1,768 244 804 94 SO2 Emissions (lb/MMBtu) 0.0012 0.0022 0.0117 0.0022 0.0042 0.0021 0.0858 0.0017 0.0858 0.0016 Negligible Negligible SO2 Emissions (lb/MWhgross) 0.0090 0.0166 0.0852 0.0173 0.0290 0.0171 0.7515 0.0176 0.7063 0.0162 Negligible Negligible NOx Emissions (lb/MMBtu) 0.059 0.049 0.060 0.049 0.059 0.049 0.070 0.070 0.070 0.070 0.009 0.008 NOx Emissions (lb/MWhgross) 0.430 0.376 0.434 0.396 0.409 0.396 0.613 0.747 0.576 0.697 0.060 0.061 PM Emissions (lb/MMBtu) 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0130 0.0130 0.0130 0.0130 Negligible Negligible PM Emissions (lb/MWhgross) 0.052 0.055 0.052 0.057 0.049 0.057 0.114 0.139 0.107 0.129 Negligible Negligible Hg Emissions (lb/TBtu) 0.571 0.571 0.571 0.571 0.571 0.571 1.143 1.143 1.143 1.143 Negligible Negligible Hg Emissions (lb/MWhgross) 4.16E-06 4.42E-06 4.15E-06 4.59E-06 3.95E-06 4.61E-06 1.00E-05 1.22E-05 9.41E-06 1.14E-05 Negligible Negligible COST Total Plant Cost (2007$/kW) 1,987 2,711 1,913 2,817 2,217 3,181 1,622 2,942 1,647 2,913 584 1,226 Total Overnight Cost (2007$/kW) 2,447 3,334 2,351 3,466 2,716 3,904 1,996 3,610 2,024 3,570 718 1,497 Bare Erected Cost 1,528 2,032 1,470 2,113 1,695 2,385 1,317 2,255 1,345 2,239 482 926 Home Office Expenses 144 191 138 199 156 221 124 213 127 211 40 78 Project Contingency 265 369 256 385 302 444 182 369 176 362 62 162 Process Contingency 50 119 50 120 63 131 0 105 0 100 0 60 Owner's Costs 460 623 438 649 500 723 374 667 377 657 133 271 Total Overnight Cost (2007$ x 1,000) 1,521,880 1,811,411 1,469,577 1,780,290 1,708,524 1,939,878 1,098,124 1,985,432 1,113,445 1,963,644 398,290 709,039 Total As Spent Capital (2007$/kW) 2,789 3,801 2,680 3,952 3,097 4,451 2,264 4,115 2,296 4,070 771 1,614 COE (mills/kWh, 2007$)1,2 76.3 105.6 74.0 110.3 81.3 119.4 59.4 109.6 58.9 106.5 58.9 85.9 CO2 TS&M Costs 0.0 5.2 0.0 5.5 0.0 5.6 0.0 5.8 0.0 5.6 0.0 3.2 Fuel Costs 14.3 17.1 14.0 18.0 13.3 17.9 15.2 21.3 14.2 19.6 44.5 52.2 Variable Costs 7.3 9.3 7.2 9.8 7.8 9.9 5.1 9.2 5.0 8.7 1.3 2.6 Fixed Costs 11.3 14.8 11.1 15.5 12.1 16.7 7.8 13.1 8.0 13.0 3.0 5.7 Capital Costs 43.4 59.1 41.7 61.5 48.2 69.2 31.2 60.2 31.7 59.6 10.1 22.3 LCOE (mills/kWh, 2007$)1,2 96.7 133.9 93.8 139.9 103.1 151.4 75.3 139.0 74.7 135.2 74.7 108.9 1

CF is 80% for IGCC cases and 85% for PC and NGCC cases 2

COE and Levelized COE are defined in Section 2.7.

5

Cost and Performance Baseline for Fossil Energy Plants Exhibit ES-3 Net Plant Efficiency (HHV Basis) 60.0%

50.2%

50.0%

42.1% 42.8%

39.0% 39.7% 39.3%

40.0%

36.8%

Efficiency, % (HHV Basis) 32.6%

31.0% 31.2%

28.4%

30.0%

26.2%

20.0%

10.0%

0.0%

GEE GEE w/CO2 CoP CoP w/ CO2 Shell Shell w/ CO2 Subcritical Subcritical PC Supercritical Supercritical NGCC NGCC w/

Capture Capture Capture PC w/ CO2 PC PC w/ CO2 CO2 Capture Capture Capture 6

Cost and Performance Baseline for Fossil Energy Plants Water Use Three water values are presented for each technology in Exhibit ES-4: raw water withdrawal, process discharge, and raw water consumption. Each value is normalized by net output. Raw water withdrawal is the difference between demand and internal recycle. Demand is the amount of water required to satisfy a particular process (slurry, quench, flue gas desulfurization [FGD]

makeup, etc.) and internal recycle is water available within the process (boiler feedwater [BFW]

blowdown, condensate, etc.). Raw water withdrawal is the water removed from the ground or diverted from a surface-water source for use in the plant. Raw water consumption is the portion of the raw water withdrawn that is evaporated, transpired, incorporated into products or otherwise not returned to the water source it was withdrawn from. Raw water consumption is the difference between withdrawal and process discharge, and it represents the overall impact of the process on the water source, which in this study is considered to be 50 percent from groundwater (wells) and 50 percent from a municipal source. All plants are equipped with evaporative cooling towers, and all process blowdown streams are assumed to be treated and recycled to the cooling tower. The primary conclusions that can be drawn are:

In all cases the primary water consumer is cooling tower makeup, which ranges from 73 to 99 percent of the total raw water consumption.

Among non-capture cases, NGCC requires the least amount of raw water withdrawal, followed by IGCC and PC. If an average raw water consumption for the three IGCC cases and two PC cases is used, the relative normalized raw water consumption for the technologies is 2.5:1.7:1.0 (PC:IGCC:NGCC). The relative results are as expected given the much higher steam turbine output in the PC cases, which results in higher condenser duties, higher cooling water flows, and ultimately higher cooling water makeup. The IGCC cases and the NGCC case have comparable steam turbine outputs, but IGCC requires additional water for coal slurry (GEE and CoP), syngas quench (GEE), humidification (CoP and Shell), gasifier steam (Shell), and slag handling (all cases), which increases the IGCC water withdrawal over NGCC.

Among capture cases, raw water withdrawal requirements increase (relative to non-capture cases) more dramatically for the PC and NGCC cases than for IGCC cases because of the large cooling water demand of the Econamine process, which results in greater cooling water makeup requirements. If average water consumption values are used for IGCC and PC cases, the relative normalized raw water consumption for the technologies in CO2 capture cases is 2.4:1.4:1.0 (PC:IGCC:NGCC). The NGCC CO2 capture case still has the lowest water consumption.

CO2 capture increases the average raw water consumption for all three technologies evaluated, but the increase is lowest for the IGCC cases. The average normalized raw water consumption for the three IGCC cases increases by about 58 percent due primarily to the need for additional water in the syngas to accomplish the WGS reaction. With the addition of CO2 capture, PC normalized raw water consumption increases by 83 percent and NGCC by 91 percent. The large cooling water demand of the Econamine process drives this substantial increase for PC and NGCC.

7

Cost and Performance Baseline for Fossil Energy Plants Exhibit ES-4 Raw Water Withdrawal and Consumption 25.0 Raw Water Withdrawal Process Discharge Raw Water Consumption 20.4 20.0 18.3 15.7 Water, gpm/MWnet 15.0 14.1 11.3 11.1 10.7 10.7 9.3 9.7 10.0 8.7 9.0 8.5 8.4 7.6 7.7 7.0 6.6 6.0 6.3 5.5 5.3 4.3 5.0 3.3 0.0 GEE GEE w/CO2 CoP CoP w/ CO2 Shell Shell w/ CO2 Subcritical Subcritical PC Supercritical Supercritical NGCC NGCC w/

Capture Capture Capture PC w/ CO2 PC PC w/ CO2 CO2 Capture Capture Capture 8

Cost and Performance Baseline for Fossil Energy Plants COST RESULTS Total Overnight Cost The Total Overnight Cost (TOC) for each plant was calculated by adding owners costs to the Total Plant Cost (TPC). The TPC for each technology was determined through a combination of vendor quotes, scaled estimates from previous design/build projects, or a combination of the two.

TPC includes all equipment (complete with initial chemical and catalyst loadings), materials, labor (direct and indirect), engineering and construction management, and contingencies (process and project). Escalation and interest on debt during the capital expenditure period were estimated and added to the TOC to provide the Total As-Spent Cost (TASC).

The cost estimates carry an accuracy of -15%/+30%, consistent with a feasibility study level of design engineering applied to the various cases in this study. The value of the study lies not in the absolute accuracy of the individual case results but in the fact that all cases were evaluated under the same set of technical and economic assumptions. This consistency of approach allows meaningful comparisons among the cases evaluated.

Project contingencies were added to the Engineering/Procurement/Construction Management (EPCM) capital accounts to cover project uncertainty and the cost of any additional equipment that would result from a detailed design. The contingencies represent costs that are expected to occur. Each bare erected cost (BEC) account was evaluated against the level of estimate detail and field experience to determine project contingency. Process contingency was added to cost account items that were deemed to be first-of-a-kind (FOAK) or posed significant risk due to lack of operating experience. The cost accounts that received a process contingency include:

Slurry Prep and Feed - 5 percent on GE IGCC cases - systems are operating at approximately 800 psia as compared to 600 psia for the other IGCC cases.

Gasifiers and Syngas Coolers - 15 percent on all IGCC cases - next-generation commercial offering and integration with the power island.

Two Stage Selexol - 20 percent on all IGCC capture cases - lack of operating experience at commercial scale in IGCC service.

Mercury Removal - 5 percent on all IGCC cases - minimal commercial scale experience in IGCC applications.

CO2 Removal System - 20 percent on all PC/NGCC capture cases - post-combustion process unproven at commercial scale for power plant applications.

Combustion Turbine-Generator (CTG) - 5 percent on all IGCC non-capture cases -

syngas firing and air separation unit (ASU) integration; 10 percent on all IGCC capture cases - high hydrogen firing.

Instrumentation and Controls - 5 percent on all IGCC accounts and 5 percent on the PC and NGCC capture cases - integration issues.

The normalized components of TOC and overall TASC are shown for each technology in Exhibit ES-5. The following conclusions can be drawn:

Among the non-capture cases, NGCC has the lowest TOC at $718 kW followed by PC with an average cost of $2,010/kW and IGCC with an average cost of $2,505/kW.

9

Cost and Performance Baseline for Fossil Energy Plants Exhibit ES-5 Plant Capital Costs 6,000 TASC Owner's Cost 5,000 Process Contingency 4,451 Project Contingency 4,115 4,070 Home Office Expense 3,952 3,904 4,000 3,801 Bare Erected Cost 3,610 3,570 3,466 TOC or TASC, $/kW 3,334 3,097 3,000 2,789 2,680 2,716 2,447 2,351 2,296 2,264 1,996 2,024 2,000 1,614 1,497 1,000 718 771 0

TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC GEE GEE w/ CO2 CoP CoP w/ CO2 Shell Shell w/ CO2 Subcritical PC Subcritical PC w/ Supercritical PC Supercritical PC NGCC NGCC w/ CO2 Capture Capture Capture CO2 Capture w/ CO2 Capture Capture Note: TOC expressed in 2007 dollars. TASC expressed in mixed-year 2007 to 2011 year dollars for coal plants and 2007 to 2009 mixed-year dollars for NGCC.

10

Cost and Performance Baseline for Fossil Energy Plants The average IGCC cost is 25 percent greater than the average PC cost. The process contingency for the IGCC cases ranges from $50-63/kW while there is zero process contingency for the PC and NGCC non-capture cases. The differential between IGCC and PC is reduced to 22 percent when process contingency is eliminated.

The three IGCC non-capture cases have a TOC ranging from $2,351/kW (CoP) to

$2,716/kW (Shell) with GEE intermediate at $2,447/kW.

Among the capture cases, NGCC has the lowest TOC, despite the fact that the TOC of the NGCC capture case is more than double the cost of the non-capture case at

$1,497kW.

Among the capture cases, the PC cases have the highest TOC at an average of

$3,590/kW. The average TOC for IGCC CO2 capture cases is $3,568/kW, which is less than one percent lower than the average of the PC cases. The process contingency for the IGCC capture cases ranges from $119-131/kW, for the PC cases from $100-105/kW and $60/kW for the NGCC case.

Cost of Electricity The cost metric used in this study is the COE, which is the revenue received by the generator per net megawatt-hour during the power plants first year of operation, assuming that the COE escalates thereafter at a nominal annual rate equal to the general inflation rate, i.e., that it remains constant in real terms over the operational period of the power plant. To calculate the COE, the Power Systems Financial Model (PSFM) [2] was used to determine a base-year (2007) COE that, when escalated at an assumed nominal annual general inflation rate of 3 percent 1, provided the stipulated internal rate of return on equity over the entire economic analysis period (capital expenditure period plus thirty years of operation). The first year capital charge factor (CCF) shown in Exhibit ES-6, which was derived using the PSFM, can also be used to calculate COE using a simplified equation as detailed in Section 2.7.4.

The project financial structure varies depending on the type of project (high risk or low risk) and the length of the capital expenditure period (3 year or 5 year). All cases were assumed to be undertaken at investor owned utilities (IOUs). High risk projects are those in which commercial scale operating experience is limited. The IGCC cases (with and without CO2 capture) and the PC and NGCC cases with CO2 capture were considered to be high risk. The non-capture PC and NGCC cases were considered to be low risk. Coal based cases were assumed to have a 5 year capital expenditure period and natural gas cases a 3 year period. The current-dollar, 30-year levelized cost of electricity (LCOE) was also calculated and is shown in Exhibit 2-23, but the primary metric used in the balance of this study is COE. A more detailed discussion of the two metrics is provided in Section 2.7 of the report.

1 This nominal escalation rate is equal to the average annual inflation rate between 1947 and 2008 for the U.S.

Department of Labors Producer Price Index for Finished Goods. This index was used instead of the Producer Price Index for the Electric Power Generation Industry because the Electric Power Index only dates back to December 2003 and the Producer Price Index is considered the headline index for all of the various Producer Price Indices.

11

Cost and Performance Baseline for Fossil Energy Plants Exhibit ES-6 Economic Parameters Used to Calculate COE High Risk Low Risk High Risk Low Risk (5 year capital (5 year capital (3 year capital (3 year capital expenditure expenditure expenditure expenditure period) period) period) period)

First Year Capital 0.1243 0.1165 0.1111 0.1048 Charge Factor Commodity prices fluctuate over time based on overall economic activity and general supply and demand curves. While the cost basis for this study is June 2007, many price indices had similar values in January 2010 compared to June 2007. For example, the Chemical Engineering Plant Cost Index was 532.7 in June 2007 and 532.9 in January 2010, and the Gross Domestic Product Chain-type Price Index was 106.7 on July 1, 2007 and 110.0 on January 1, 2010. Hence the June 2007 dollar cost base used in this study is expected to be representative of January 2010 costs.

The COE results are shown in Exhibit ES-7 with the capital cost, fixed operating cost, variable operating cost, and fuel cost shown separately. In the capture cases, the CO2 transport, storage, and monitoring (TS&M) costs are also shown as a separate bar segment. The following conclusions can be drawn:

In non-capture cases, NGCC plants have the lowest COE (58.9 mills/kWh), followed by PC (average 59.2 mills/kWh) and IGCC (average 77.2 mills/kWh).

In capture cases, NGCC plants have the lowest COE (85.9 mills/kWh), followed by PC (average 108.2 mills/kWh) and IGCC (average 111.8 mills/kWh).

The COE for the three IGCC non-capture cases ranges from 74.0 mills/kWh (CoP) to 81.3 mills/kWh (Shell) with GEE intermediate at 76.3 mills/kWh. The study level of accuracy is insufficient to definitively quantify the differences in COE of the three IGCC technologies.

Non-capture SC PC has a COE of 58.9 mills/kWh and subcritical PC is 59.4 mills/kWh, an insignificant difference given the level of accuracy of the study estimate.

IGCC is the most expensive technology with CO2 capture, 3 percent higher than PC and 30 percent higher than NGCC.

The capital cost component of COE is between 56 and 59 percent in all IGCC and PC cases. It represents only 17 percent of COE in the NGCC non-capture case and 26 percent in the CO2 capture case.

The fuel component of COE ranges from 15-19 percent for the IGCC cases and the PC CO2 capture cases. For the PC non-capture cases the fuel component varies from 24-26 percent. The fuel component is 76 percent of the total in the NGCC non-capture case and 61 percent in the CO2 capture case.

CO2 TS&M is estimated to add 3 to 6 mills/kWh to the COE, which is less than 5.5 percent of the total for all capture cases.

12

Cost and Performance Baseline for Fossil Energy Plants Exhibit ES-7 COE by Cost Component CO2 TS&M Costs 160 Fuel Costs Variable Costs 140 Fixed Costs 119.46 Capital Costs 120 110.39 5.7 109.69 105.66 106.63 5.6 5.9 5.3 17.9 5.7 100 COE, mills/kWh (2007$)

18.0 17.1 21.3 9.9 19.6 85.93 81.31 3.2 80 76.28 9.8 9.3 74.02 16.7 9.2 8.7 13.3 14.3 15.5 14.8 14.0 13.1 13.0 7.8 59.40 58.91 58.90 60 7.3 7.2 52.2 12.1 15.2 14.2 11.3 11.1 40 5.1 5.0 69.2 7.8 8.0 44.5 59.1 61.5 60.2 59.6 2.6 48.2 5.7 20 43.4 41.7 31.2 31.7 1.3 3.0 22.3 10.1 0

GEE GEE w/CO2 CoP CoP w/ CO2 Shell Shell w/ Subcritical Subcritical SupercriticalSupercritical NGCC NGCC w/

Capture Capture CO2 PC PC w/ CO2 PC PC w/ CO2 CO2 Capture Capture Capture Capture 13

Cost and Performance Baseline for Fossil Energy Plants Exhibit ES-8 shows the COE sensitivity to fuel costs for the non-capture cases. The solid line is the COE of NGCC as a function of natural gas cost. The points on the line represent the natural gas cost that would be required to make the COE of NGCC equal to PC or IGCC at a given coal cost. The coal prices shown ($1.23, $1.64, and $2.05/MMBtu) represent the baseline cost and a range of +/-25 percent around the baseline. As an example, at a coal cost of $1.64/MMBtu, the COE of PC equals NGCC at a natural gas price of $6.59/MMBtu.

Another observation from Exhibit ES-8 is that the COE of IGCC at a coal price of $1.23/MMBtu is greater than PC at a coal price of $2.05/MMBtu, due to the higher capital cost of IGCC and its relative insensitivity to fuel price. For example, a decrease in coal cost of 40 percent (from $2.05 to $1.23/MMBtu) results in an IGCC COE decrease of only nine percent (80.7 to 73.7 mills/kWh).

Fuel cost sensitivity is presented for the CO2 capture cases in Exhibit ES-9. Even at the lowest coal cost shown, the COE of NGCC is less than IGCC and PC at the baseline natural gas price of

$6.55/MMBtu. For the coal-based technologies at the baseline coal cost of $1.64/MMBtu to be equal to NGCC, the cost of natural gas would have to be $9.34/MMBtu (PC) or $9.80/MMBtu (IGCC). Alternatively, for the COE of coal-based technologies to be equal to NGCC at the high end coal cost of $2.05/MMBtu, natural gas prices would have to be $9.98/MMBtu for PC and

$10.35/MMBtu for IGCC.

Exhibit ES-8 COE Sensitivity to Fuel Costs in Non-Capture Cases 100 90 80 COE, mills/kWh (2007$)

70 NGCC PC w/ coal at $1.23/MMBtu 60 PC w/ coal at $1.64/MMBtu PC w/ coal at $2.05/MMBtu IGCC w/ coal at $1.23/MMBtu 50 IGCC w/ coal at $1.64/MMBtu IGCC w/ coal at $2.05/MMBtu 40 3 4 5 6 7 8 9 10 11 12 13 Natural Gas Price, $/MMBtu 14

Cost and Performance Baseline for Fossil Energy Plants Exhibit ES-9 COE Sensitivity to Fuel Costs in CO2 Capture Cases 140 130 120 110 100 COE, mills/kWh (2007$)

90 NGCC 80 PC w/ coal at $1.23/MMBtu PC w/ coal at $1.64/MMBtu 70 PC w/ coal at $2.05/MMBtu 60 IGCC w/ coal at $1.23/MMBtu IGCC w/ coal at $1.64/MMBtu 50 IGCC w/ coal at $2.05/MMBtu 40 3 4 5 6 7 8 9 10 11 12 13 Natural Gas Price, $/MMBtu The sensitivity of COE to CF is shown for all technologies in Exhibit ES-10. The subcritical and SC PC cases with no CO2 capture are nearly identical so that the two curves appear as a single curve on the graph. The CF is plotted from 30 to 90 percent. The baseline CF is 80 percent for IGCC cases with no spare gasifier and is 85 percent for PC and NGCC cases. The curves plotted in Exhibit ES-10 for the IGCC cases assume that the CF could be extended to 90 percent with no spare gasifier. Similarly, the PC and NGCC curves assume that the CF could reach 90 percent with no additional capital equipment.

Technologies with high capital cost (PC and IGCC with CO2 capture) show a greater increase in COE with decreased CF. Conversely, NGCC with no CO2 capture is relatively flat because the COE is dominated by fuel charges, which decrease as the CF decreases. Conclusions that can be drawn from Exhibit ES-10 include:

At a CF at or below 85 percent, NGCC has the lowest COE out of the non-capture cases.

The COE of NGCC with CO2 capture is the lowest of the capture technologies in the baseline study, and the advantage increases as CF decreases. The relatively low capital cost component of NGCC accounts for the increased cost differential with decreased CF.

In non-capture cases, NGCC at 40 percent CF has approximately the same COE as the average of the three IGCC cases at base load (80 percent CF) further illustrating the relatively small impact of CF on NGCC COE.

15

Cost and Performance Baseline for Fossil Energy Plants Exhibit ES-10 COE Sensitivity to Capacity Factor 300 250 Coal = $1.64/MMBtu Shell w/CO2 capture Natural Gas = $6.55/MMBtu Sub PC w/CO2 capture 200 SC PC w/CO2 capture COE, mills/kWh (2007$)

CoP w/CO2 capture GEE w/CO2 capture 150 Shell no capture GEE no capture CoP no capture 100 Sub PC no capture NGCC w/CO2 capture SC PC no capture 50 NGCC no capture 0

0 10 20 30 40 50 60 70 80 90 100 Capacity Factor, %

CO2 Emission Price Impact In the event that future legislation assigns a cost to carbon emissions, all of the technologies examined in this study will become more expensive. The technologies without carbon capture will be impacted to a larger extent than those with carbon capture, and coal-based technologies will be impacted more than natural gas-based technologies. The most economically favored option for each technology is shown in Exhibit ES-11. Hence the IGCC non-capture case is based on the CoP gasifier, the IGCC capture case is based on the GEE technology, and the PC technology is based on supercritical steam conditions.

The curves represent the study design conditions (capacity factor) and fuel prices used for each technology; namely 80 percent capacity factor for IGCC plants and 85 percent for PC and NGCC plants, and $1.64/MMBtu for coal and $6.55/MMBtu for natural gas. Natural gas fuel prices are more volatile than coal and tend to fluctuate over a fairly large range. The two black lines shown in Exhibit ES-11 represent NGCC at a fuel price of $9.50/MMBtu and are shown for reference.

The dispatch-based capacity factor for NGCC plants, addressed in Section 6.4 of this report, is significantly less than 85 percent and would result in a higher COE as shown in Exhibit ES-10.

16

Cost and Performance Baseline for Fossil Energy Plants Exhibit ES-11 Impact of Carbon Emissions Price on Study Technologies 160 140 120 COE, mills/kWh (2007$)

100 80 NGCC w/Cap ($9.50/MMBtu) 60 NGCC ($9.50/MMBtu)

IGCC (GEE) w/Capture 40 IGCC (CoP)

SCPC w/Capture SCPC 20 NGCC w/Capture ($6.55/MMBtu)

NGCC ($6.55/MMBtu) 0 0 10 20 30 40 50 60 70 80 90 100 First Year CO2 Emission Price, $/tonne The intersection of the capture and non-capture curves for a given technology gives the cost of CO2 avoided for that technology, except for the IGCC cases which use different gasifier technologies for the capture and non-capture cases. For example, the cost of CO2 avoided is

$69/tonne ($63/ton) for SC PC and $84/tonne ($76/ton) for NGCC. These values can be compared to those shown in Exhibit ES-13.

The following conclusions can be drawn from the carbon emissions price graph:

At the baseline study conditions any cost applied to carbon emissions favors NGCC technology. While PC and NGCC with no capture start at essentially equivalent COEs, they diverge rapidly as the CO2 emission cost increases. The lower carbon intensity of natural gas relative to coal and the greater efficiency of the NGCC technology account for this effect.

Capture for NGCC systems is only justified economically at CO2 emissions prices greater than $83/tonne ($75/ton) at the baseline natural gas price of $6.55/MMBtu and $95/tonne ($86/ton) at the higher natural gas price of $9.50/MMBtu.

The SC PC and IGCC non-capture curves are nearly parallel indicating that the CO2 emission price impacts the two technologies nearly equally. The two lines gradually converge due to the slightly lower efficiency of SC PC relative to the CoP IGCC technology (39.3 versus 39.7 percent net efficiency). The SC PC and GEE IGCC cases with CO2 capture start at nearly equivalent COE values and slowly diverge.

The COE of the SC PC case increases slightly faster than the GEE IGCC case 17

Cost and Performance Baseline for Fossil Energy Plants because of the lower efficiency (28.4 versus 32.6 percent net efficiency) and slightly lower capture efficiency (90.2 versus 90.3 percent).

Comparing only the coal-based technologies, IGCC or PC with capture become the favored technology compared to SC PC with no capture at an emission price of

$67/tonne ($61/ton).

At a natural gas price of $9.50/MMBtu, NGCC with capture has nearly the same COE as IGCC and SC PC with capture at a CO2 emission price of $30/tonne ($27/ton).

At a natural gas price of $9.50/MMBtu, SC PC without capture has a lower COE than NGCC without capture until the CO2 emissions price exceeds $46/tonne ($42/ton).

The relationship between technologies and CO2 emission pricing can also be considered in a phase diagram type plot as shown in Exhibit ES-12. The lines in the plot represent cost parity between different pairs of technologies.

Exhibit ES-12 Lowest Cost Power Generation Options Comparing NGCC and Coal 20 COE parity between 18 Supercritical PC IGCC Supercritical PC without CCS 16 without CCS with CCS has lowest COE has lowest COE Natural Gas Price, $/MMBtu 14 12 and IGCC with CCS 10 COE parity between 8 NGCC with CCS and IGCC with CCS 6

4 NGCC NGCC without CCS with CCS 2 has lowest COE has lowest COE 0

0 10 20 30 40 50 60 70 80 90 100 110 First Year CO2 Emission Price, $/tonne The plot demonstrates the following points:

Non-capture plants are the low cost option below a first year CO2 price of $60/tonne

($54/ton).

18

Cost and Performance Baseline for Fossil Energy Plants

At natural gas prices below $6.50/MMBtu (and a capacity factor of 85 percent)

NGCC is always preferred.

At natural gas prices above $11/MMBtu coal plants are always preferred.

Cost of CO2 Avoided The first year cost of CO2 avoided was calculated as illustrated in Equation ES-1:

{COE with removal COE reference } $ / MWh Avoided Cost = (ES-1)

{CO2 Emissions reference CO2 Emissions with removal } tons / MWh The COE with CO2 removal includes the costs of capture and compression as well as TS&M costs. The resulting avoided costs are shown in Exhibit ES-13 for each of the six technologies modeled. The avoided costs for each capture case are calculated using the analogous non-capture plant as the reference and again with SC PC without CO2 capture as the reference. The following conclusions can be drawn:

The total first year cost of CO2 avoided is $52.9/tonne ($48/ton) (average IGCC),

$68.3/tonne ($62/ton) (average PC), and $83.8/tonne ($76/ton) (NGCC) using analogous non-capture plants as the reference and $75/tonne ($68/ton) (average IGCC), $71.6/tonne ($65/ton) (average PC), and $35.3/tonne ($32/ton) (NGCC) using SC PC without capture as the reference.

CO2 avoided costs for IGCC plants using analogous non-capture plants as reference are substantially less than for PC and NGCC because the IGCC CO2 removal is accomplished prior to combustion and at elevated pressure using physical absorption.

CO2 avoided costs for IGCC plants using analogous non-capture as reference are less than NGCC plants because the baseline CO2 emissions for NGCC plants are 44 percent less than for IGCC plants. Consequently, the normalized removal cost for NGCC plants is divided by a smaller amount of CO2.

CO2 avoided costs for the GEE IGCC plant are less than for the CoP and Shell IGCC plants. This is consistent with the efficiency changes observed when going from a non-capture to capture configuration for the GEE IGCC plant. The GEE plant started with the lowest efficiency of the IGCC plants but realized the smallest reduction in efficiency between the non-capture and capture configurations.

CO2 avoided costs for NGCC using SC PC as the reference are 53 percent lower than IGCC and 50 percent lower than PC because of the relatively low COE of the NGCC capture plant compared to IGCC and PC.

19

Cost and Performance Baseline for Fossil Energy Plants Exhibit ES-13 First Year CO2 Avoided Costs 100 Avoided Cost (Analogous Technology w/o Capture Reference)

Avoided Cost (SC PC w/o Capture Reference) 90 86 84 80 73 75 70 68 69 69 66 First Year CO2 Avoided Cost, $/tonne (2007$)

61 60 54 50 43 40 36 30 20 10 0

GEE CoP Shell Subcritical PC Supercritical PC NGCC 20

Cost and Performance Baseline for Fossil Energy Plants ENVIRONMENTAL PERFORMANCE The environmental targets for each technology are summarized in Exhibit ES-14. Emission rates of sulfur dioxide (SO2), nitrogen oxide (NOx), and particulate matter (PM) are shown graphically in Exhibit ES-15, and emission rates of mercury (Hg) are shown separately in Exhibit ES-16 because of the orders of magnitude difference in emission rate values.

Exhibit ES-14 Study Environmental Targets Technology Pollutant IGCC PC NGCC SO2 0.0128 lb/MMBtu 0.085 lb/MMBtu Negligible 15 ppmv (dry) @ 2.5 ppmv (dry) @

NOx 0.070 lb/MMBtu 15% O2 15% O2 PM (Filterable) 0.0071 lb/MMBtu 0.013 lb/MMBtu Negligible Hg >90% capture 1.14 lb/TBtu N/A Environmental targets were established for each of the technologies as follows:

IGCC cases use the EPRI targets established in their CoalFleet for Tomorrow work as documented in the CoalFleet User Design Basis Specification for Coal-Based Integrated Gasification Combined Cycle (IGCC) Power Plants, EPRI, Palo Alto, CA, 2009.

PC and NGCC cases are based on best available control technology (BACT)

The primary conclusions that can be drawn are:

The NGCC baseline plant generates the lowest emissions, followed by IGCC and then PC.

In NGCC cases, study assumptions result in zero emissions of SO2, PM, and Hg. If the pipeline natural gas contained the maximum amount of sulfur allowed by Environmental Protection Agency (EPA) definition (0.6 gr/100 scf), SO2 emissions would be 0.000839 kg/GJ (0.00195 lb/MMBtu).

Based on vendor data it was assumed that dry low NOx (DLN) burners could achieve 25 ppmv (dry) at 15 percent O2 and, coupled with a selective catalytic reduction (SCR) unit that achieves 90 percent NOx reduction efficiency, would result in the environmental target of 2.5 ppmv (dry) at 15 percent O2 for both NGCC cases.

Based on vendor data it was assumed that Selexol, Sulfinol-M, and refrigerated methyldiethanolamine (MDEA) could all meet the sulfur environmental target, hence emissions of approximately 0.0128 lb/MMBtu in each of the IGCC non-capture cases. In the CO2 capture cases, to achieve 95 percent CO2 capture from the syngas, the sulfur 21

Cost and Performance Baseline for Fossil Energy Plants removal is greater than in the non-capture cases resulting in emissions of approximately 0.0009 kg/GJ (0.0022 lb/MMBtu).

It was a study assumption that each IGCC technology could meet the filterable particulate emission limit with the combination of technologies employed. In the case of Shell and CoP, this consists of cyclones, candle filters, and the syngas scrubber. In the case of GEE particulate control consists of a water quench and syngas scrubber.

Based on vendor data it was assumed that a combination of low NOx burners (LNBs) and nitrogen (N2) dilution could limit IGCC NOx emissions to the environmental target of 15 ppmvd at 15 percent O2. The small variations in NOx emissions are due to small variations in CT gas volumes.

Based on vendor data it was assumed that 95 percent Hg removal could be achieved using carbon beds thus meeting the environmental target. The Hg emissions are reported in Exhibit ES-16 as lb per trillion Btu to make the values the same order of magnitude as the other reported values.

It was a study assumption that the PC FGD unit would remove 98 percent of the inlet SO2, resulting in the environmental target of 0.037 kg/GJ (0.085 lb/MMBtu). In the CO2 capture cases, the Econamine system employs a polishing scrubber to reduce emissions to 10 ppmv entering the CO2 absorber. Nearly all of the remaining SO2 is absorbed by the Econamine solvent resulting in negligible emissions of SO2 in those cases.

In PC cases, it was a study assumption that a fabric filter would remove 99.8 percent of the entering particulate and that there is an 80/20 split between fly ash and bottom ash.

The result is the environmental target of 0.006 kg/GJ (0.013 lb/MMBtu) of filterable particulate.

In PC cases, it was a study assumption that NOx emissions exiting the boiler equipped with LNBs and overfire air (OFA) would be 0.22 kg/GJ (0.50 lb/MMBtu) and that an SCR unit would further reduce the NOx by 86 percent, resulting in the environmental target of 0.030 kg/GJ (0.070 lb/MMBtu).

In PC cases, it was a study assumption that the environmental target of 90 percent of the incoming Hg would be removed by the combination of SCR, fabric filter and wet FGD thus eliminating the need for activated carbon injection. The resulting Hg emissions for each of the PC cases are 4.92 x 10-7 kg/GJ (1.14 lb/TBtu).

CO2 emissions are not currently regulated. However, since there is increasing momentum for establishing carbon limits, it was an objective of this study to examine the relative amounts of CO2 capture achievable among the six technologies. CO2 emissions are presented in Exhibit ES-17 for each case, normalized by net output. In the body of the report CO2 emissions are presented on both a net and gross MWh basis. New Source Performance Standards (NSPS) contain emission limits for SO2 and NOx on a lb/(gross) MWh basis. However, since CO2 emissions are not currently regulated, the potential future emission limit basis is not known and CO2 emissions are presented in both ways. The following conclusions can be drawn:

22

Cost and Performance Baseline for Fossil Energy Plants Exhibit ES-15 SO2, NOx, and Particulate Emission Rates 0.12 SO2 0.10 NOx Particulate Matter 0.08 Emissions, lb/MMBtu 0.06 0.04 0.02 0.00 GEE GEE w/CO2 CoP CoP w/ CO2 Shell Shell w/ CO2 Subcritical Subcritical Supercritical Supercritical NGCC NGCC w/

Capture Capture Capture PC PC w/ CO2 PC PC w/ CO2 CO2 Capture Capture Capture 23

Cost and Performance Baseline for Fossil Energy Plants Exhibit ES-16 Mercury Emission Rates 1.4 1.2 1.0 Hg Emissions, lb/TBtu 0.8 0.6 0.4 0.2 0.0 GEE GEE w/CO2 CoP CoP w/ CO2 Shell Shell w/ CO2 Subcritical Subcritical PC Supercritical Supercritical NGCC NGCC w/ CO2 Capture Capture Capture PC w/ CO2 PC PC w/ CO2 Capture Capture Capture 24

Cost and Performance Baseline for Fossil Energy Plants

In cases with no CO2 capture, NGCC emits 56 percent less CO2 than PC and 52 percent less CO2 than IGCC per unit of net output. The lower NGCC CO2 emissions reflect the lower carbon intensity of natural gas relative to coal and the higher cycle efficiency of NGCC relative to IGCC and PC. Based on the fuel compositions used in this study, natural gas contains 41 lb carbon/MMBtu of heat input and coal contains 55 lb/MMBtu.

The CO2 reduction goal in this study was a nominal 90 percent in all cases. The result is that the controlled CO2 emissions follow the same trend as the uncontrolled, i.e., the NGCC case emits less CO2 than the IGCC cases, which emit less than the PC cases.

In the IGCC cases the nominal 90 percent CO2 reduction was accomplished by using two sour gas shift (SGS) reactors to convert carbon monoxide (CO) to CO2. A two-stage Selexol process with a second stage CO2 removal efficiency of 92 percent, a number that was supported by vendor quotes, was used in the GEE and Shell cases. The GEE CO2 capture case resulted in 90.3 percent reduction of CO2 in the syngas. The Shell capture case resulted in 90.1 percent reduction of CO2 in the syngas. In the CoP case, in order for the capture target of 90 percent to be achieved, the Selexol efficiency was increased to 95 percent. This was done because of the high syngas methane content (1.5 vol% compared to 0.10 vol% in the GEE gasifier and 0.06 vol% in the Shell gasifier). The CoP capture case resulted in 90.4 percent reduction of CO2 in the syngas.

Among the three non-capture IGCC cases the Shell process has slightly lower emissions primarily because it is the most efficient. The emissions in the CO2 capture cases are nearly identical for each case.

The PC and NGCC cases both assume that all of the carbon in the fuel is converted to CO2 in the FG and that 90 percent is subsequently removed in the Econamine process, which was also supported by a vendor quote.

25

Cost and Performance Baseline for Fossil Energy Plants Exhibit ES-17 CO2 Emissions Normalized By Net Output 2,500 2,000 1,888 1,768 1,723 1,710 1,595 CO2 Emissions, lb/net-MWh 1,500 1,000 804 500 206 217 218 266 244 94 0

GEE GEE w/CO2 CoP CoP w/ CO2 Shell Shell w/ CO2 Subcritical Subcritical PC Supercritical Supercritical NGCC NGCC w/

Capture Capture Capture PC w/ CO2 PC PC w/ CO2 CO2 Capture Capture Capture 26

Cost and Performance Baseline for Fossil Energy Plants

1. INTRODUCTION The objective of this report is to present an accurate, independent assessment of the cost and performance of fossil energy power systems, specifically IGCC, PC, and NGCC plants, in a consistent technical and economic manner that accurately reflects current market conditions.

This is Volume 1 of a four volume report. The four volume series consists of the following:

Volume 1: Bituminous Coal and Natural Gas to Electricity

Volume 2: Coal to Synthetic Natural Gas and Ammonia (Various Coal Ranks)

Volume 3: Low Rank Coal and Natural Gas to Electricity

Volume 4: Bituminous Coal to Liquid Fuels with Carbon Capture The cost and performance of the various fossil fuel-based technologies will largely determine which technologies will be utilized to meet the demands of the power market. Selection of new generation technologies will depend on many factors, including:

Capital and operating costs

Overall energy efficiency

Fuel prices

Cost of electricity (COE)

Availability, reliability, and environmental performance

Current and potential regulation of air, water, and solid waste discharges from fossil-fueled power plants

Market penetration of clean coal technologies that have matured and improved as a result of recent commercial-scale demonstrations under the DOEs Clean Coal Programs Twelve different power plant design configurations were analyzed. The configurations are listed in Exhibit 1-1. The list includes six IGCC cases utilizing the GEE, CoP, and Shell gasifiers each with and without CO2 capture, and six cases representing conventional technologies: PC-subcritical, PC-SC, and NGCC plants, with and without CO2 capture. While input was sought from various technology vendors, the final assessment of performance and cost was determined independently, and may not represent the views of the technology vendors. Individual vendors have not reviewed this report and the extent of collaboration with technology vendors varied from case to case, with minimal or no collaboration obtained from some vendors.

Cases 7 and 8 were originally included in this study and involve production of SNG and the repowering of an existing NGCC facility using SNG. The two SNG cases were subsequently moved to Volume 2 of this report resulting in the discontinuity of case numbers (1-6 and 9-14).

GENERATING UNIT CONFIGURATIONS A summary of plant configurations considered in this study is presented in Exhibit 1-1.

Components for each plant configuration are described in more detail in the corresponding report sections for each case.

27

Cost and Performance Baseline for Fossil Energy Plants The IGCC cases have different gross and net power outputs because of the gas turbine (GT) size constraint. The advanced F-class turbine used to model the IGCC cases comes in a standard size of 232 MW when operated on syngas at International Standards Organization (ISO) conditions.

Each case uses two CTs for a combined gross output of 464 MW. In the combined cycle a heat recovery steam generator (HRSG) extracts heat from the CT exhaust to power a steam turbine.

However, the CO2 capture cases consume more extraction steam than the non-capture cases, thus reducing the steam turbine output. In addition, the capture cases have a higher auxiliary load requirement than non-capture cases, which serves to further reduce net plant output. While the two CTs provide 464 MW gross output in all six cases, the overall combined cycle gross output ranges from 673 to 748 MW, which results in a range of net output from 497 (case 6) to 629 MW (case 5). The coal feed rate required to achieve the gross power output is also different between the six cases, ranging from 198,220 to 220,899 kg/hr (437,000 to 487,000 lb/hr).

Similar to the IGCC cases, the NGCC cases do not have a common net power output. The NGCC system is again constrained by the available CT size, which is 181 MW at ISO conditions for both cases (based on the same advanced F class turbine used in the IGCC cases). Since the CO2 capture case requires both a higher auxiliary power load and a significant amount of extraction steam, which significantly reduces the steam turbine output, the net output in the NGCC case is also reduced.

All four PC cases have a net output of 550 MW. The boiler and steam turbine industrys ability to match unit size to a custom specification has been commercially demonstrated enabling a common net output comparison of the PC cases in this study. The coal feed rate was increased in the CO2 capture cases to increase the gross steam turbine output and account for the higher auxiliary load, resulting in a constant net output.

The balance of this report is organized as follows:

Chapter 2 provides the basis for technical, environmental, and cost evaluations.

Chapter 3 describes the IGCC technologies modeled and presents the results for the six IGCC cases.

Chapter 4 describes the PC technologies modeled and presents the results for the four PC cases.

Chapter 5 describes the NGCC technologies modeled and presents the results for the two NGCC cases.

Chapter 6 is a supplemental chapter examining the impact of dry and parallel cooling systems.

Chapter 7 is a supplemental chapter examining the cost and performance of a GEE gasifier in a quench-only configuration with CO2 capture.

Chapter 8 is a supplemental chapter examining the COE sensitivity to monoethanolamine (MEA) system performance and cost.

Chapter 9 includes a record of report revisions.

Chapter 10 contains the reference list.

28

Cost and Performance Baseline for Fossil Energy Plants Exhibit 1-1 Case Descriptions Sulfur CO2 CO2 Unit Steam Cycle, Combustion Gasifier/Boiler H2S Separation/ NOx CO2 Case Oxidant Removal/ PM Control Separa- Sequestra-Cycle psig/°F/°F Turbine Technology Removal Control Capture Recovery tion tion 2 x Advanced F Single-Stage Quench, scrubber 1 IGCC 1800/1050/1050 GEE Radiant Only 95 mol% O2 Claus Plant N2 dilution Class Selexol and AGR adsorber 2 x Advanced F Quench, scrubber Selexol 2nd 2 IGCC 1800/1000/1000 GEE Radiant Only 95 mol% O2 Two-Stage Selexol Claus Plant N2 dilution 90%1 Off-Site Class and AGR adsorber stage 2 x Advanced F Refrigerated Cyclone, barrier filter 3 IGCC 1800/1050/1050 CoP E-Gas' 95 mol% O2 Claus Plant N2 dilution Class MDEA and scrubber 2 x Advanced F Cyclone, barrier filter Selexol 2nd 4 IGCC 1800/1000/1000 CoP E-Gas' 95 mol% O2 Selexol Claus Plant N2 dilution 90%1 Off-Site Class and scrubber stage 2 x Advanced F Cyclone, barrier filter 5 IGCC 1800/1050/1050 Shell 95 mol% O2 Sulfinol-M Claus Plant N2 dilution Class and scrubber 2 x Advanced F Cyclone, barrier filter Selexol 2nd 6 IGCC 1800/1000/1000 Shell 95 mol% O2 Selexol Claus Plant N2 dilution 90%1 Off-Site Class and scrubber stage Wet FGD/ LNB w/OFA 9 PC 2400/1050/1050 Subcritical PC Air Baghouse Gypsum and SCR Wet FGD/ LNB w/OFA Amine 10 PC 2400/1050/1050 Subcritical PC Air Baghouse 90% Off-Site Gypsum and SCR Absorber Wet FGD/ LNB w/OFA 11 PC 3500/1100/1100 Supercritical PC Air Baghouse Gypsum and SCR Wet FGD/ LNB w/OFA Amine 12 PC 3500/1100/1100 Supercritical PC Air Baghouse 90% Off-Site Gypsum and SCR Absorber 2 x Advanced F LNB and 13 NGCC 2400/1050/1050 HRSG Air Class SCR 2 x Advanced F LNB and Amine 14 NGCC 2400/1050/1050 HRSG Air 90% Off-Site Class SCR Absorber 1

Defined as the percentage of carbon in the syngas that is captured; differences are explained in Chapter 3.

29

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Cost and Performance Baseline for Fossil Energy Plants

2. GENERAL EVALUATION BASIS For each of the plant configurations in this study an Aspen model was developed and used to generate material and energy balances, which in turn were used to provide a design basis for items in the major equipment list. The equipment list and material balances were used as the basis for generating the capital and operating cost estimates. Performance and process limits were based upon published reports, information obtained from vendors and users of the technology, performance data from design/build utility projects, and/or best engineering judgment. Capital and operating costs were estimated by WorleyParsons based on simulation results and through a combination of vendor quotes, scaled estimates from previous design/build projects, or a combination of the two. Ultimately a COE was calculated for each of the cases and is reported as the revenue requirement figure-of-merit.

The balance of this chapter documents the design basis common to all technologies, as well as environmental targets and cost assumptions used in the study. Technology specific design criteria are covered in subsequent chapters.

2.1 SITE CHARACTERISTICS All plants in this study are assumed to be located at a generic plant site in Midwestern U.S., with ambient conditions and site characteristics as presented in Exhibit 2-1 and Exhibit 2-2. The ambient conditions are the same as ISO conditions.

Exhibit 2-1 Site Ambient Conditions Elevation, (ft) 0 Barometric Pressure, MPa (psia) 0.10 (14.696)

Design Ambient Temperature, Dry Bulb, °C (°F) 15 (59)

Design Ambient Temperature, Wet Bulb,°C, (°F) 11 (51.5)

Design Ambient Relative Humidity, % 60 Exhibit 2-2 Site Characteristics Location Greenfield, Midwestern USA Topography Level Size, acres 300 (PC/IGCC), 100 (NGCC)

Transportation Rail Ash/Slag Disposal Off Site Water Municipal (50%) / Groundwater (50%)

Access Land locked, having access by rail and highway Compressed to 15.3 MPa (2,215 psia), transported 80 CO2 Storage kilometers (50 miles) and sequestered in a saline formation at a depth of 1,239 m (4,055 ft) 31

Cost and Performance Baseline for Fossil Energy Plants The land area for PC and IGCC cases assumes 30 acres are required for the plant proper and the balance provides a buffer of approximately 0.25 miles to the fence line. The extra land could also provide for a rail loop if required. In the NGCC cases it was assumed the plant proper occupies about 10 acres leaving a buffer of 0.15 miles to the plant fence line.

In all cases it was assumed that the steam turbine is enclosed in a turbine building and in the PC cases the boiler is also enclosed. The gasifier in the IGCC cases and the CTs in the IGCC and NGCC cases are not enclosed.

The following design parameters are considered site-specific, and are not quantified for this study. Allowances for normal conditions and construction are included in the cost estimates.

Flood plain considerations

Existing soil/site conditions

Water discharges and reuse

Rainfall/snowfall criteria

Seismic design

Buildings/enclosures

Local code height requirements

Noise regulations - Impact on site and surrounding area 2.2 COAL CHARACTERISTICS The design coal is Illinois No. 6 with characteristics presented in Exhibit 2-3. The coal properties are from NETLs Coal Quality Guidelines [1].

The Power Systems Financial Model (PSFM) was used to derive the capital charge factors (CCF) and levelization factors (LF) for this study [ 2]. The PSFM requires that all cost inputs have a consistent cost year basis. Because the capital and operating cost estimates are in June 2007 dollars, the fuel costs must also be in June 2007 dollars.

The coal cost used in this study is $1.55/GJ ($1.64/MMBtu) (2007 cost of coal in June 2007 dollars). This cost was determined using the following information from the EIA 2008 AEO:

The 2007 minemouth cost of Illinois No. 6 in 2006 dollars, $32.66/tonne

($29.63/ton), was obtained from Supplemental Table 112 of the EIAs 2008 AEO for eastern interior high-sulfur bituminous coal.

The cost of Illinois No. 6 coal was escalated to 2007 dollars using the gross domestic product (GDP) chain-type price index from AEO 2008, resulting in a price of

$33.67/tonne ($30.55/ton) [3].

Transportation costs for Illinois No. 6 were estimated to be 25 percent of the minemouth cost based on the average transportation rate of the respective coals to the surrounding regions [ 4]. The final delivered costs for Illinois No. 6 coal used in the calculations is $42.09/tonne ($38.18/ton) or $1.55/GJ ($1.64/MMBtu). (Note: The Illinois No. 6 coal cost of $1.6366/MMBtu was used in calculations, but only two decimal places are shown in the report.)

32

Cost and Performance Baseline for Fossil Energy Plants Exhibit 2-3 Design Coal Rank Bituminous Seam Illinois No. 6 (Herrin)

Source Old Ben Mine Proximate Analysis (weight %) (Note A)

As Received Dry Moisture 11.12 0.00 Ash 9.70 10.91 Volatile Matter 34.99 39.37 Fixed Carbon 44.19 49.72 Total 100.00 100.00 Sulfur 2.51 2.82 HHV, kJ/kg 27,113 30,506 HHV, Btu/lb 11,666 13,126 LHV, kJ/kg 26,151 29,544 LHV, Btu/lb 11,252 12,712 Ultimate Analysis (weight %)

As Received Dry Moisture 11.12 0.00 Carbon 63.75 71.72 Hydrogen 4.50 5.06 Nitrogen 1.25 1.41 Chlorine 0.29 0.33 Sulfur 2.51 2.82 Ash 9.70 10.91 Oxygen (Note B) 6.88 7.75 Total 100.00 100.00 Notes: A. The proximate analysis assumes sulfur as volatile matter B. By difference 33

Cost and Performance Baseline for Fossil Energy Plants 2.3 NATURAL GAS CHARACTERISTICS Natural gas is utilized as the main fuel in Cases 13 and 14 (NGCC with and without CO2 capture), and its composition is presented in Exhibit 2-4 [5].

Exhibit 2-4 Natural Gas Composition Component Volume Percentage Methane CH4 93.1 Ethane C2H6 3.2 Propane C3H8 0.7 n-Butane C4H10 0.4 Carbon Dioxide CO2 1.0 Nitrogen N2 1.6 Total 100.0 LHV HHV kJ/kg 47,454 52,581 MJ/scm 34.71 38.46 Btu/lb 20,410 22,600 Btu/scf 932 1,032 Note: Fuel composition is normalized and heating values are calculated The first year cost of natural gas used in this study is $6.21/MMkJ ($6.55/MMBtu) (2007 cost of natural gas in 2007 dollars). The cost was determined using the following information from the EIAs 2008 AEO:

The 2007 East North Central region delivered cost of natural gas to electric utilities in 2006 dollars, $231.47/1000 m3 ($6.55/1000 ft3), was obtained from the AEO 2008 reference case Table 108 and converted to an energy basis, $6.02/MMkJ

($6.35/MMBtu).

The 2007 cost was escalated to 2007 dollars using the GDP chain-type price index from AEO 2008, resulting in a delivered 2007 price in 2007 dollars of $6.21/MMkJ

($6.55/MMBtu) [3]. (Note: The natural gas cost of $6.5478/MMBtu was used in calculations, but only two decimal places are shown in the report.)

2.4 ENVIRONMENTAL TARGETS The environmental targets for the study were considered on a technology- and fuel-specific basis.

In setting the environmental targets a number of factors were considered, including current emission regulations, regulation trends, results from recent permitting activities and the status of current BACT.

The current federal regulation governing new fossil-fuel fired electric utility steam generating units is the NSPS as amended in February 2006 and shown in Exhibit 2-5, which represents the 34

Cost and Performance Baseline for Fossil Energy Plants minimum level of control that would be required for a new fossil energy plant [6]. Stationary CT emission limits are further defined in 40 CFR Part 60, Subpart KKKK.

Exhibit 2-5 Standards of Performance for Electric Utility Steam Generating Units Built, Reconstructed, or Modified After February 28, 2005 New Units Reconstructed Units Modified Units Emission Emission Emission % %

Limit % Reduction Limit Limit Reduction Reduction (lb/MMBtu) (lb/MMBtu) 0.015 PM 99.9 0.015 99.9 0.015 99.8 lb/MMBtu SO2 1.4 lb/MWh 95 0.15 95 0.15 90 NOx 1.0 lb/MWh N/A 0.11 N/A 0.15 N/A The new NSPS standards apply to units with the capacity to generate greater than 73 MW of power by burning fossil fuels, as well as cogeneration units that sell more than 25 MW of power and more than one-third of their potential output capacity to any utility power distribution system. The rule also applies to combined cycle, including IGCC plants, and combined heat and power CTs that burn 75 percent or more synthetic-coal gas. In cases where both an emission limit and a percent reduction are presented, the unit has the option of meeting one or the other.

All limits with the unit lb/MWh are based on gross power output.

Other regulations that could affect emissions limits from a new plant include the New Source Review (NSR) permitting process and Prevention of Significant Deterioration (PSD). The NSR process requires installation of emission control technology meeting either BACT determinations for new sources being located in areas meeting ambient air quality standards (attainment areas),

or Lowest Achievable Emission Rate (LAER) technology for sources being located in areas not meeting ambient air quality standards (non-attainment areas). Environmental area designation varies by county and can be established only for a specific site location. Based on the EPA Green Book Non-attainment Area Map relatively few areas in the Midwestern U.S. are classified as non-attainment so the plant site for this study was assumed to be in an attainment area [7].

In addition to federal regulations, state and local jurisdictions can impose even more stringent regulations on a new facility. However, since each new plant has unique environmental requirements, it was necessary to apply some judgment in setting the environmental targets for this study.

As of October 2009, no active legislation establishes acceptable mercury emission levels. The levels previously established by the Clean Air Mercury Rule (CAMR) have been vacated through the D.C Circuit Court. Until new limits are established, the previously established CAMR levels are used in this report. The CAMR established NSPS limits for Hg emissions from new PC-fired boilers based on coal type as well as for IGCC units independent of coal type.

The NSPS limits, based on gross output, are shown in Exhibit 2-6 [8]. The applicable limit in this study is 20 x 10-6 lb/MWh for both bituminous coal-fired PC boilers and for IGCC units.

35

Cost and Performance Baseline for Fossil Energy Plants Exhibit 2-6 NSPS Mercury Emission Limits Coal Type / Technology Hg Emission Limit Bituminous 20 x 10-6 lb/MWh Subbituminous (wet units) 66 x 10-6 lb/MWh Subbituminous (dry units) 97 x 10-6 lb/MWh Lignite 175 x 10-6 lb/MWh Coal refuse 16 x 10-6 lb/MWh IGCC 20 x 10-6 lb/MWh The mercury content of 34 samples of Illinois No. 6 coal has an arithmetic mean value of 0.09 ppm (dry basis) with standard deviation of 0.06 based on coal samples shipped by Illinois mines [9]. Hence, as illustrated in Exhibit 2-7, there is a 50 percent probability that the mercury content in the Illinois No. 6 coal would not exceed 0.09 ppm (dry basis). The coal mercury content for this study was assumed to be 0.15 ppm (dry) for all IGCC and PC cases, which corresponds to the mean plus one standard deviation and encompasses about 84 percent of the samples. It was further assumed that all of the coal Hg enters the gas phase and none leaves with the bottom ash or slag.

The current NSPS emission limits are provided below for each technology along with the environmental targets for this study and the control technologies employed to meet the targets.

In some cases, application of the control technology results in emissions that are less than the target, but in no case are the emissions greater than the target.

Exhibit 2-7 Probability Distribution of Mercury Concentration in the Illinois No. 6 Coal P:\X_GEMSET\0_GEMSET Fuels Price Database\Rev.0 Fuels\[IllinoisNo6 Mercury.xls] Rev. 00 11/21/05 10:

100%

90%

Arithmetic Mean = 0.09 ppm db Probability Illinois #6 Sample Will Be At or Below Value Standard Deviation = 0.06 ppm db 80%

70%

60%

50%

40%

30%

20%

10%

0%

0.00 ppm Hg 0.05 ppm Hg 0.10 ppm Hg 0.15 ppm Hg 0.20 ppm Hg 0.25 ppm Hg 0.30 ppm Hg Mercury Concentraion in Coal, ppm db 36

Cost and Performance Baseline for Fossil Energy Plants 2.4.1 IGCC The IGCC environmental targets were chosen to match the EPRIs design basis for their CoalFleet for Tomorrow Initiative and are shown in Exhibit 2-8 [10]. EPRI notes that these are design targets and are not to be used for permitting values.

Exhibit 2-8 Environmental Targets for IGCC Cases Environmental Pollutant NSPS Limit1 Control Technology Target 15 ppmv (dry) 1.0 lb/MWh Low NOx burners and NOx

@ 15% O2 (0.091 lb/MMBtu) syngas nitrogen dilution Selexol, MDEA or Sulfinol 1.4 lb/MWh SO2 0.0128 lb/MMBtu (depending on gasifier (0.127 lb/MMBtu) technology)

Quench, water scrubber, Particulate and/or cyclones and candle Matter 0.0071 lb/MMBtu 0.015 lb/MMBtu filters (depending on (Filterable) gasifier technology) 20 x 10-6 lb/MWh Mercury > 90% capture Carbon bed (1.8 lb/TBtu) 1 The value in parentheses is calculated based on the highest IGCC heat rate in this study of 10,998 Btu/kWh, CoP E-Gas with CO2 capture.

Based on published vendor literature, it was assumed that LNBs and nitrogen dilution can achieve 15 ppmvd at 15 percent O2, and that value was used for all IGCC cases [11,12].

To achieve an environmental target of 0.0128 lb/MMBtu of SO2 requires approximately 28 ppmv sulfur in the sweet syngas. The acid gas removal (AGR) process must have a sulfur capture efficiency of about 99.7 percent to reach the environmental target. Vendor data on each of the three AGR processes used in the non-capture cases indicate that this level of sulfur removal is possible. In the CO2 capture cases, the two-stage Selexol process was designed for 95 percent CO2 removal, which results in a sulfur capture of greater than 99.7 percent, hence the lower sulfur emissions in the CO2 capture cases.

Most of the coal ash is removed from the gasifier as slag. The ash that remains entrained in the syngas is captured in the downstream equipment, including the syngas scrubber and a cyclone and either ceramic or metallic candle filters (CoP and Shell). The environmental target of 0.0071 lb/MMBtu filterable particulates can be achieved with each combination of particulate control devices so that in each IGCC case it was assumed the environmental target was met exactly.

The environmental target for mercury capture is greater than 90 percent. Based on experience at the Eastman Chemical plant, where syngas from a GEE gasifier is treated, the actual mercury removal efficiency used is 95 percent. Sulfur-impregnated activated carbon is used by Eastman as the adsorbent in the packed beds operated at 30°C (86°F) and 6.2 MPa (900 psig). Mercury removal between 90 and 95 percent has been reported with a bed life of 18 to 24 months.

Removal efficiencies may be even higher, but at 95 percent the measurement precision limit was 37

Cost and Performance Baseline for Fossil Energy Plants reached. Eastman has yet to experience any mercury contamination in its product [13]. Mercury removals of greater than 99 percent can be achieved by the use of dual beds, i.e., two beds in series. However, this study assumes that the use of sulfur-impregnated carbon in a single carbon bed achieves 95 percent reduction of mercury emissions, which meets the environmental target and NSPS limits in all cases.

2.4.2 PC BACT was applied to each of the PC cases and the resulting emissions compared to NSPS limits and recent permit averages. Since the BACT results met or exceeded the NSPS requirements and the average of recent permits, they were used as the environmental targets as shown in Exhibit 2-9. The average of recent permits is comprised of 8 units at 5 locations. The 5 plants include Elm Road Generating Station, Longview Power, Prairie State, Thoroughbred, and Cross.

It was assumed that LNBs and staged OFA would limit NOx emissions to 0.5 lb/MMBtu and that SCR technology would be 86 percent efficient, resulting in emissions of 0.07 lb/MMBtu for all cases.

The wet limestone scrubber was assumed to be 98 percent efficient, which results in SO2 emissions of 0.085 lb/MMBtu. Current technology allows FGD removal efficiencies in excess of 99 percent, but based on NSPS requirements and recent permit averages, such high removal efficiency is not necessary.

The fabric filter used for particulate control was assumed to be 99.8 percent efficient. The result is particulate emissions of 0.013 lb/MMBtu in all cases, which also exceeds NSPS and recent permit average requirements.

Exhibit 2-9 Environmental Targets for PC Cases Average of Environmental Control Pollutant NSPS Limit Recent Target Technology Permits 1.0 lb/MWh Low NOx 0.08 NOx 0.07 lb/MMBtu (0.111 burners, overfire lb/MMBtu lb/MMBtu) air and SCR 1.4 lb/MWh 0.085 0.16 Wet limestone SO2 (0.156 lb/MMBtu lb/MMBtu scrubber lb/MMBtu)

Particulate 0.013 0.017 Matter 0.015 lb/MMBtu Fabric filter lb/MMBtu lb/MMBtu (Filterable) 20 x 10-6 lb/MWh Co-benefit Mercury 1.14 lb/TBtu 2.49 lb/TBtu (2.2 lb/TBtu) capture 38

Cost and Performance Baseline for Fossil Energy Plants Mercury control for PC cases was assumed to occur through 90 percent co-benefit capture in the fabric filter and the wet FGD scrubber. EPA used a statistical method to calculate the Hg co-benefit capture from units using a best demonstrated technology approach, which for bituminous coals was considered to be a combination of a fabric filter and an FGD system. The statistical analysis resulted in a co-benefit capture estimate of 86.7 percent with an efficiency range of 83.8 to 98.8 percent [14]. EPAs documentation for their Integrated Planning Model (IPM) provides mercury emission modification factors (EMF) based on 190 combinations of boiler types and control technologies. The EMF is simply one minus the removal efficiency.

For PC boilers (as opposed to cyclones, stokers, fluidized beds, and others) with a fabric filter, SCR and wet FGD, the EMF is 0.1, which corresponds to a removal efficiency of 90 percent

[15]. The average reduction in total Hg emissions developed from EPAs Information Collection Request (ICR) data on U.S. coal-fired boilers using bituminous coal, fabric filters, and wet FGD is 98 percent [16]. The referenced sources bound the co-benefit Hg capture for bituminous coal units employing SCR, a fabric filter and a wet FGD system between 83.8 and 98 percent. Ninety percent was chosen as near the mid-point of this range and it also matches the value used by EPA in their IPM.

Since co-benefit capture alone exceeds the requirements of NSPS and recent permit averages, no activated carbon injection is included in this study.

2.4.3 NGCC BACT was applied to the NGCC cases and the resulting emissions compared to NSPS limits.

The NGCC environmental targets were chosen based on reasonably obtainable limits given the control technologies employed and are presented in Exhibit 2-10.

Exhibit 2-10 Environmental Targets for NGCC Cases 40 CFR Part 60, Environmental Control Pollutant Subpart KKKK Target Technology Limits Low NOx burners NOx 2.5 ppmv @ 15% O2 15 ppmv @ 15% O2 and SCR 0.9 lb/MWh Low sulfur content SO2 Negligible (0.134 lb/MMBtu)1 fuel Particulate Matter N/A N/A N/A (Filterable)

Mercury N/A N/A N/A 1

Assumes a heat rate of 6,719 Btu/kWh from the NGCC non-capture case.

Published vendor literature indicates that 25 ppmv NOx at 15 percent O2 is achievable using natural gas and DLN technology [17,18]. The application of SCR with 90 percent efficiency further reduces NOx emissions to 2.5 ppmv, which was selected as the environmental target.

39

Cost and Performance Baseline for Fossil Energy Plants For the purpose of this study, natural gas was assumed to contain a negligible amount of sulfur compounds, and therefore generate negligible sulfur emissions. The EPA defines pipeline natural gas as containing >70 percent methane by volume or having a gross calorific value (GCV) of between 35.4 and 40.9 MJ/Nm3 (950 and 1,100 Btu/scf) and having a total sulfur content of less than 13.7 mg/Nm3 (0.6 gr/100 scf) [19]. Assuming a sulfur content equal to the EPA limit for pipeline natural gas, resulting SO2 emissions for the two NGCC cases in this study would be approximately 21 tonnes/yr (23.2 tons/yr) at 85 percent CF or 0.00084 kg/GJ (0.00195 lb/MMBtu). Thus, for the purpose of this study, SO2 emissions were considered negligible.

The pipeline natural gas was assumed to contain no particulate matter (PM) and no mercury resulting in no emissions of either.

2.4.4 Carbon Dioxide CO2 is not currently regulated nationally. However, the possibility exists that federal carbon limits will be imposed in the future and this study examines cases that include a reduction in CO2 emissions. Because the form of emission limits, should they be imposed, is not known, CO2 emissions are reported on both a lb/(gross) MWh and lb/(net) MWh basis in each capture case emissions table.

For the IGCC cases that have CO2 capture, the basis is a nominal 90 percent removal based on carbon input from the coal and excluding carbon that exits the gasifier with the slag. In the GEE and Shell cases, this was accomplished by using two SGS reactors, to convert CO to CO2, and a two-stage Selexol process with a second stage CO2 removal efficiency of 92 percent, a number that was supported by vendor quotes. The GEE CO2 capture case resulted in 90.3 percent reduction of CO2 in the syngas. The Shell capture case resulted in 90.1 percent reduction of CO2 in the syngas. In the CoP case, in order for the capture target of 90 percent to be achieved, a third SGS reactor was added and the Selexol efficiency was increased to 95 percent (the maximum removal efficiency supported by vendor quotes). This was done because of the high syngas methane content (1.5 vol% compared to 0.10 vol% in the GEE gasifier and 0.06 vol% in the Shell gasifier). The CoP capture case resulted in 90.4 percent reduction of CO2 in the syngas.

For PC and NGCC cases that have CO2 capture, it is assumed that all of the fuel carbon is converted to CO2 in the FG. CO2 is also generated from limestone in the FGD system, and 90 percent of the CO2 exiting the FGD absorber is subsequently captured using the Econamine technology.

The cost of CO2 capture was calculated as an avoided cost as illustrated in the equation below.

Analogous non-capture technologies and SC non-capture PC were chosen as separate reference cases. The COE in the CO2 capture cases includes TS&M as well as capture and compression.

{COE with removal COE reference } $ / MWh Avoided Cost =

{CO2 Emissions reference CO2 Emissions with removal } tons / MWh 40

Cost and Performance Baseline for Fossil Energy Plants 2.5 CAPACITY FACTOR This study assumes that each new plant would be dispatched any time it is available and would be capable of generating maximum capacity when online. Therefore, CF and availability are equal. The availability for PC and NGCC cases was determined using the Generating Availability Data System (GADS) from the North American Electric Reliability Council (NERC) [20]. Since there are only two operating IGCC plants in North America, the same database was not useful for determining IGCC availability. Rather, input from EPRI and their work on the CoalFleet for Tomorrow Initiative was used.

NERC defines an equivalent availability factor (EAF), which is essentially a measure of the plant CF assuming there is always a demand for the output. The EAF accounts for planned and scheduled derated hours as well as seasonal derated hours. As such, the EAF matches this studys definition of CF.

The average EAF for coal-fired plants in the 400-599 MW size range was 84.9 percent in 2004 and averaged 83.9 percent from 2000-2004. Given that many of the plants in this size range are older, the EAF was rounded up to 85 percent and that value was used as the PC plant CF.

The average EAF for NGCC plants in the 400-599 MW size range was 84.7 percent in 2004 and averaged 82.7 percent from 2000-2004. Using the same rationale as for PC plants, the EAF was rounded up to 85 percent and that value was also used as the NGCC plant CF.

EPRI examined the historical forced and scheduled outage times for IGCCs and concluded that the reliability factor (which looks at forced or unscheduled outage time only) for a single train IGCC (no spares) would be about 90 percent [21]. To get the availability factor, one has to deduct the scheduled outage time. In reality the scheduled outage time differs from gasifier technology-to-gasifier technology, but the differences are relatively small and would have minimal impact on the CF, so for this study it was assumed to be constant at a 30-day planned outage per year (or two 15-day outages). The planned outage would amount to 8.2 percent of the year, so the availability factor would be (90 percent - 8.2 percent), or 81.2 percent.

There are four operating IGCCs worldwide that use a solid feedstock and are primarily power producers (Polk, Wabash, Buggenum, and Puertollano). A 2006 report by Higman et al.

examined the reliability of these IGCC power generation units and concluded that typical annual on-stream times are around 80 percent [ 22]. The CF would be somewhat less than the on-stream time since most plants operate at less than full load for some portion of the operating year.

Given the results of the EPRI study and the Higman paper, a CF of 80 percent was chosen for IGCC with no spare gasifier required.

The addition of CO2 capture to each technology was assumed not to impact the CF. This assumption was made to enable a comparison based on the impact of capital and variable operating costs only. Any reduction in assumed CF would further increase the COE for the CO2 capture cases.

2.6 RAW WATER WITHDRAWAL AND CONSUMPTION A water balance was performed for each case on the major water consumers in the process. The total water demand for each subsystem was determined and internal recycle water available from various sources like BFW blowdown and condensate from syngas or FG (in CO2 capture cases) was applied to offset the water demand. The difference between demand and recycle is raw 41

Cost and Performance Baseline for Fossil Energy Plants water withdrawal. Raw water withdrawal is the water removed from the ground or diverted from a surface-water source for use in the plant. Raw water consumption is also accounted for as the portion of the raw water withdrawn that is evaporated, transpired, incorporated into products or otherwise not returned to the water source it was withdrawn from.

Raw water makeup was assumed to be provided 50 percent by a publicly owned treatment works (POTW) and 50 percent from groundwater. Raw water withdrawal is defined as the water metered from a raw water source and used in the plant processes for any and all purposes, such as cooling tower makeup, BFW makeup, slurry preparation makeup, ash handling makeup, syngas humidification, quench system makeup, and FGD system makeup. The difference between withdrawal and process water returned to the source is consumption. Consumption represents the net impact of the process on the water source.

BFW blowdown and a portion of the sour water stripper blowdown were assumed to be treated and recycled to the cooling tower. The cooling tower blowdown and the balance of the SWS blowdown streams were assumed to be treated and 90 percent returned to the water source with the balance sent to the ash ponds for evaporation.

The largest consumer of raw water in all cases is cooling tower makeup. It was assumed that all cases utilized a mechanical draft, evaporative cooling tower, and all process blowdown streams were assumed to be treated and recycled to the cooling tower. The design ambient wet bulb temperature of 11°C (51.5°F) (Exhibit 2-1) was used to achieve a cooling water temperature of 16°C (60°F) using an approach of 5°C (8.5°F). The cooling water range was assumed to be 11°C (20°F). The cooling tower makeup rate was determined using the following:[23]

Evaporative losses of 0.8 percent of the circulating water flow rate per 10°F of range

Drift losses of 0.001 percent of the circulating water flow rate

Blowdown losses were calculated as follows:

o Blowdown Losses = Evaporative Losses / (Cycles of Concentration - 1)

Where cycles of concentration is a measure of water quality, and a mid-range value of 4 was chosen for this study.

The water balances presented in subsequent sections include the water demand of the major water consumers within the process, the amount provided by internal recycle, the amount of raw water withdrawal by difference, the amount of process water returned to the source and the raw water consumption, again by difference.

2.7 COST ESTIMATING METHODOLOGY The estimating methodology for capital costs, operations and maintenance costs, and CO2 TS&M costs are described below. The finance structure, basis for the discounted cash flow analysis, and first-year COE cost calculations are also described.

2.7.1 Capital Costs As illustrated in Exhibit 2-11, this study reports capital cost at four levels: Bare Erected Cost (BEC), Total Plant Cost (TPC), Total Overnight Cost (TOC) and Total As-spent Capital (TASC).

BEC, TPC and TOC are overnight costs and are expressed in base-year dollars. The base year is the first year of capital expenditure, which for this study is assumed to be 2007. TASC is 42

Cost and Performance Baseline for Fossil Energy Plants expressed in mixed-year, current-year dollars over the entire capital expenditure period, which is assumed to last five years coal plants (2007 to 2011) and three years for natural gas plants (2007 to 2009).

Exhibit 2-11 Capital Cost Levels and their Elements process equipment Bare Erected Cost supporting facilities BEC Total Plant Cost Total Overnight Cost direct and indirect labor TPC Total As-Spent Cost EPC contractor services process contingency TOC project contingency TASC preproduction costs inventory capital BEC, TPC and TOC are all financing costs overnight costs expressed other owners costs in base-year dollars.

TASC is expressed in mixed-escalation during capital expenditure period year current dollars, spread over the capital expenditure interest on debt during capital expenditure period period.

The BEC comprises the cost of process equipment, on-site facilities and infrastructure that support the plant (e.g., shops, offices, labs, road), and the direct and indirect labor required for its construction and/or installation. The cost of EPC services and contingencies is not included in BEC. BEC is an overnight cost expressed in base-year (2007) dollars.

The TPC comprises the BEC plus the cost of services provided by the engineering, procurement and construction (EPC) contractor and project and process contingencies. EPC services include:

detailed design, contractor permitting (i.e., those permits that individual contractors must obtain to perform their scopes of work, as opposed to project permitting, which is not included here),

and project/construction management costs. TPC is an overnight cost expressed in base-year (2007) dollars.

The TOC comprises the TPC plus owners costs. TOC is an overnight cost, expressed in base-year (2007) dollars and as such does not include escalation during construction or interest during construction. TOC is an overnight cost expressed in base-year (2007) dollars.

The TASC is the sum of all capital expenditures as they are incurred during the capital expenditure period including their escalation. TASC also includes interest during construction.

43

Cost and Performance Baseline for Fossil Energy Plants Accordingly, TASC is expressed in mixed, current-year dollars over the capital expenditure period.

Cost Estimate Basis and Classification The TPC and Operation and Maintenance (O&M) costs for each of the cases in the study were estimated by WorleyParsons using an in-house database and conceptual estimating models.

Costs were further calibrated using a combination of adjusted vendor-furnished and actual cost data from recent design projects.

Recommended Practice 18R-97 of the Association for the Advancement of Cost Engineering International (AACE) describes a Cost Estimate Classification System as applied in Engineering, Procurement and Construction for the process industries [24].

Most techno-economic studies completed by NETL feature cost estimates intended for the purpose of a Feasibility Study (AACE Class 4). Exhibit 2-12 describes the characteristics of an AACE Class 4 Cost Estimate. Cost estimates in this study have an expected accuracy range of -15%/+30%.

Exhibit 2-12 Features of an AACE Class 4 Cost Estimate Project Typical Engineering Completed Expected Accuracy Definition plant capacity, block schematics, indicated

-15% to -30% on the low layout, process flow diagrams for main process 1 to 15% side, and +20% to +50% on systems, and preliminary engineered process and the high side utility equipment lists System Code-of-Accounts The costs are grouped according to a process/system oriented code of accounts. This type of code-of-account structure has the advantage of grouping all reasonably allocable components of a system or process so they are included in the specific system account. (This would not be the case had a facility, area, or commodity account structure been chosen instead).

Non-CO2 Capture Plant Maturity The case estimates provided include technologies at different commercial maturity levels. The estimates for the non-CO2-capture PC and NGCC cases represent well-developed commercial technology or nth plants. The non-capture IGCC cases are also based on commercial offerings, however, there have been very limited sales of these units so far. These non-CO2-capture IGCC plant costs are less mature in the learning curve, and the costs listed reflect the next commercial offering level of cost rather than mature nth-of-a-kind (NOAK) cost. Thus, each of these cases reflects the expected cost for the next commercial sale of each of these respective technologies.

CO2 Removal Maturity The post-combustion CO2 removal technology for the PC and NGCC capture cases is immature technology. This technology remains unproven at commercial scale in power generation applications.

44

Cost and Performance Baseline for Fossil Energy Plants The pre-combustion CO2 removal technology for the IGCC capture cases has a stronger commercial experience base. Pre-combustion CO2 removal from syngas streams has been proven in chemical processes with similar conditions to that in IGCC plants, but has not been demonstrated in IGCC applications. While no commercial IGCC plant yet uses CO2 removal technology in commercial service, there are currently IGCC plants with CO2 capture well along in the planning stages.

Contracting Strategy The estimates are based on an EPCM approach utilizing multiple subcontracts. This approach provides the Owner with greater control of the project, while minimizing, if not eliminating most of the risk premiums typically included in an Engineer/Procure/Construct (EPC) contract price.

In a traditional lump sum EPC contract, the Contractor assumes all risk for performance, schedule, and cost. However, as a result of current market conditions, EPC contractors appear more reluctant to assume that overall level of risk. Rather, the current trend appears to be a modified EPC approach where much of the risk remains with the Owner. Where Contractors are willing to accept the risk in EPC type lump-sum arrangements, it is reflected in the project cost.

In todays market, Contractor premiums for accepting these risks, particularly performance risk, can be substantial and increase the overall project costs dramatically.

The EPCM approach used as the basis for the estimates here is anticipated to be the most cost effective approach for the Owner. While the Owner retains the risks, the risks become reduced with time, as there is better scope definition at the time of contract award(s).

Estimate Scope The estimates represent a complete power plant facility on a generic site. The plant boundary limit is defined as the total plant facility within the fence line including coal receiving and water supply system, but terminating at the high voltage side of the main power transformers.

TS&M cost is not included in the reported capital cost or O&M costs, but is treated separately and added to the COE.

Capital Cost Assumptions WorleyParsons developed the capital cost estimates for each plant using the companys in-house database and conceptual estimating models for each of the specific technologies. This database and the respective models are maintained by WorleyParsons as part of a commercial power plant design base of experience for similar equipment in the companys range of power and process projects. A reference bottoms-up estimate for each major component provides the basis for the estimating models.

Other key estimate considerations include the following:

Labor costs are based on Midwest, Merit Shop. The estimating models are based on U.S.

Gulf Coast and the labor has been factored to Midwest. The basis for the factors is the PAS, Inc. (PAS) Merit Shop Wage & Benefit Survey, which is published annually.

Based on the data provided in PAS, WorleyParsons used the weighted average payroll plus fringe rate for a standard craft distribution as developed for the estimating models.

PAS presents information for eight separate regions. For this study, Region 5 (IL, IN, MI, MN, OH, and WI) was selected.

45

Cost and Performance Baseline for Fossil Energy Plants

The estimates are based on a competitive bidding environment, with adequate skilled craft labor available locally.

Labor is based on a 50-hour work-week (5-10s). No additional incentives such as per-diems or bonuses have been included to attract craft labor.

While not included at this time, labor incentives may ultimately be required to attract and retain skilled labor depending on the amount of competing work in the region, and the availability of skilled craft in the area at the time the projects proceed to construction.

The estimates are based on a greenfield site.

The site is considered to be Seismic Zone 1, relatively level, and free from hazardous materials, archeological artifacts, or excessive rock. Soil conditions are considered adequate for spread footing foundations. The soil bearing capability is assumed adequate such that piling is not needed to support the foundation loads.

Costs are limited to within the fence line, terminating at the high voltage side of the main power transformers with the exception of costs included for TS&M, which are treated as an addition to COE.

Engineering and Construction Management are estimated at 8-10 percent of BEC. These costs consist of all home office engineering and procurement services as well as field construction management costs. Site staffing generally includes a construction manager, resident engineer, scheduler, and personnel for project controls, document control, materials management, site safety, and field inspection.

Price Fluctuations During the course of this study, the prices of equipment and bulk materials fluctuated quite substantially. Some reference quotes pre-dated the 2007 year cost basis while others were received post-2007. All vendor quotes used to develop these estimates were adjusted to June 2007 dollars accounting for the price fluctuations. Adjustments of costs pre-dating 2007 benefitted from a vendor survey of actual and projected pricing increases from 2004 through mid-2007 that WorleyParsons conducted for another project. The results of that survey were used to validate/recalibrate the corresponding escalation factors used in the conceptual estimating models. The more recent economic down turn has resulted in a reduction of commodity prices such that many price indices have similar values in January 2010 compared to June 2007. For example, the Chemical Engineering Plant Cost Index was 532.7 in June 2007 and 532.9 in January 2010, and the Gross Domestic Product Chain-type Price Index was 106.7 on July 1, 2007 and 110.0 on January 1, 2010. While these overall indices are nearly constant, it should be noted that the cost of individual equipment types may still deviate from the June 2007 reference point.

Cross-comparisons In all technology comparison studies, the relative differences in costs are often more significant than the absolute level of TPC. This requires cross-account comparison between technologies to review the consistency of the direction of the costs.

In performing such a comparison, it is important to reference the technical parameters for each specific item, as these are the basis for establishing the costs. Scope or assumption differences 46

Cost and Performance Baseline for Fossil Energy Plants can quickly explain any apparent anomalies. There are a number of cases where differences in design philosophy occur. Some key examples are:

The CT account in the GEE IGCC cases includes a syngas expander, which is not required for the CoP or Shell cases.

The CTs for the IGCC capture cases include an additional cost for firing a high hydrogen content fuel.

The Shell gasifier syngas cooling configuration is different between the CO2-capture and non-CO2-capture cases, resulting in a significant differential in thermal duty between the syngas coolers for the two cases.

Exclusions The capital cost estimate includes all anticipated costs for equipment and materials, installation labor, professional services (Engineering and Construction Management), and contingency. The following items are excluded from the capital costs:

All taxes, with the exception of payroll and property taxes (property taxes are included with the fixed O&M costs)

Site specific considerations - including, but not limited to, seismic zone, accessibility, local regulatory requirements, excessive rock, piles, laydown space, etc.

Labor incentives in excess of 5-10s

Additional premiums associated with an EPC contracting approach Contingency Process and project contingencies are included in estimates to account for unknown costs that are omitted or unforeseen due to a lack of complete project definition and engineering.

Contingencies are added because experience has shown that such costs are likely, and expected, to be incurred even though they cannot be explicitly determined at the time the estimate is prepared.

Capital cost contingencies do not cover uncertainties or risks associated with

scope changes

changes in labor availability or productivity

delays in equipment deliveries

changes in regulatory requirements

unexpected cost escalation

performance of the plant after startup (e.g., availability, efficiency)

Process Contingency Process contingency is intended to compensate for uncertainty in cost estimates caused by performance uncertainties associated with the development status of a technology. Process contingencies are applied to each plant section based on its current technology status.

47

Cost and Performance Baseline for Fossil Energy Plants As shown in Exhibit 2-13, AACE International Recommended Practice 16R-90 provides guidelines for estimating process contingency based on EPRI philosophy [25].

Process contingencies have been applied to the estimates in this study as follows:

Slurry Prep and Feed - 5 percent on GE IGCC cases - systems are operating at approximately 800 psia as compared to 600 psia for the other IGCC cases

Gasifiers and Syngas Coolers - 15 percent on all IGCC cases - next-generation commercial offering and integration with the power island

Two Stage Selexol - 20 percent on all IGCC capture cases - unproven technology at commercial scale in IGCC service

Mercury Removal - 5 percent on all IGCC cases - minimal commercial scale experience in IGCC applications

CO2 Removal System - 20 percent on all PC/NGCC capture cases - post-combustion process unproven at commercial scale for power plant applications

CTG - 5 percent on all IGCC non-capture cases - syngas firing and ASU integration; 10 percent on all IGCC capture cases - high hydrogen firing.

Instrumentation and Controls - 5 percent on all IGCC accounts and 5 percent on the PC and NGCC capture cases - integration issues Exhibit 2-13 AACE Guidelines for Process Contingency Process Contingency Technology Status

(% of Associated Process Capital)

New concept with limited data 40+

Concept with bench-scale data 30-70 Small pilot plant data 20-35 Full-sized modules have been operated 5-20 Process is used commercially 0-10 Process contingency is typically not applied to costs that are set equal to a research goal or programmatic target since these values presume to reflect the total cost.

Project Contingency AACE 16R-90 states that project contingency for a budget-type estimate (AACE Class 4 or 5) should be 15 to 30 percent of the sum of BEC, EPC fees and process contingency. This was used as a general guideline, but some project contingency values outside of this range occur based on WorleyParsons in-house experience.

48

Cost and Performance Baseline for Fossil Energy Plants Owners Costs Exhibit 2-15 explains the estimation method for owners costs. With some exceptions, the estimation method follows guidelines in Sections 12.4.7 to 12.4.12 of AACE International Recommended Practice No. 16R-90 [25]. The Electric Power Research Institutes Technical Assessment Guide (TAG) - Power Generation and Storage Technology Options also has guidelines for estimating owners costs. The EPRI and AACE guidelines are very similar. In instances where they differ, this study has sometimes adopted the EPRI approach.

Interest during construction and escalation during construction are not included as owners costs but are factored into the COE and are included in TASC. These costs vary based on the capital expenditure period and the financing scenario. Ratios of TASC/TOC determined from the PSFM are used to account for escalation and interest during construction. Given TOC, TASC can be determined from the ratios given in Exhibit 2-14.

Exhibit 2-14 TASC/TOC Factors Finance Structure High Risk IOU Low Risk IOU Capital Expenditure Period Three Years Five Years Three Years Five Years TASC/TOC 1.078 1.140 1.075 1.134 49

Cost and Performance Baseline for Fossil Energy Plants Exhibit 2-15 Owners Costs Included in TOC Owners Estimate Basis Cost Prepaid Any technology royalties are assumed to be included in the associated equipment cost, and thus are not included as an Royalties owners cost.

6 months operating labor

1 month maintenance materials at full capacity

1 month non-fuel consumables at full capacity

1 month waste disposal Preproduction (Start-Up)

25% of one months fuel cost at full capacity Costs

2% of TPC Compared to AACE 16R-90, this includes additional costs for operating labor (6 months versus 1 month) to cover the cost of training the plant operators, including their participation in startup, and involving them occasionally during the design and construction. AACE 16R-90 and EPRI TAG differ on the amount of fuel cost to include; this estimate follows EPRI.

Working Although inventory capital (see below) is accounted for, no additional costs are included for working capital.

Capital

0.5% of TPC for spare parts

60 day supply (at full capacity) of fuel. Not applicable for natural gas.

Inventory

60 day supply (at full capacity) of non-fuel consumables (e.g., chemicals and catalysts) that are stored on site. Does Capital not include catalysts and adsorbents that are batch replacements such as WGS, COS, and SCR catalysts and activated carbon.

AACE 16R-90 does not include an inventory cost for fuel, but EPRI TAG does.

Land * $3,000/acre (300 acres for IGCC and PC, 100 acres for NGCC)

2.7% of TPC Financing This financing cost (not included by AACE 16R-90) covers the cost of securing financing, including fees and closing costs Cost but not including interest during construction (or AFUDC). The rule of thumb estimate (2.7% of TPC) is based on a 2008 private communication with a capital services firm.

50

Cost and Performance Baseline for Fossil Energy Plants Owners Estimate Basis Cost

15% of TPC This additional lumped cost is not included by AACE 16R-90 or EPRI TAG. The rule of thumb estimate (15% of TPC) is based on a 2009 private communication with WorleyParsons. Significant deviation from this value is possible as it is very site and owner specific. The lumped cost includes:

Preliminary feasibility studies, including a Front-End Engineering Design (FEED) study Economic development (costs for incentivizing local collaboration and support)

Construction and/or improvement of roads and/or railroad spurs outside of site boundary Legal fees Permitting costs Owners engineering (staff paid by owner to give third-party advice and to help the owner oversee/evaluate the work of the EPC contractor and other contractors)

Other Owners contingency (Sometimes called management reserve, these are funds to cover costs relating to delayed Owners startup, fluctuations in equipment costs, unplanned labor incentives in excess of a five-day/ten-hour-per-day work Costs week. Owners contingency is NOT a part of project contingency.)

This lumped cost does NOT include:

EPC Risk Premiums (Costs estimates are based on an Engineering Procurement Construction Management approach utilizing multiple subcontracts, in which the owner assumes project risks for performance, schedule and cost)

Transmission interconnection: the cost of interconnecting with power transmission infrastructure beyond the plant busbar.

Taxes on capital costs: all capital costs are assumed to be exempt from state and local taxes.

Unusual site improvements: normal costs associated with improvements to the plant site are included in the bare erected cost, assuming that the site is level and requires no environmental remediation. Unusual costs associated with the following design parameters are excluded: flood plain considerations, existing soil/site conditions, water discharges and reuse, rainfall/snowfall criteria, seismic design, buildings/enclosures, fire protection, local code height requirements, noise regulations.

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Cost and Performance Baseline for Fossil Energy Plants 2.7.2 Operations and Maintenance Costs The production costs or operating costs and related maintenance expenses (O&M) pertain to those charges associated with operating and maintaining the power plants over their expected life. These costs include:

Operating labor

Maintenance - material and labor

Administrative and support labor

Consumables

Fuel

Waste disposal

Co-product or by-product credit (that is, a negative cost for any by-products sold)

There are two components of O&M costs; fixed O&M, which is independent of power generation, and variable O&M, which is proportional to power generation.

Operating Labor Operating labor cost was determined based on of the number of operators required for each specific case. The average base labor rate used to determine annual cost is $34.65/hour. The associated labor burden is estimated at 30 percent of the base labor rate. Taxes and insurance are included as fixed O&M costs totaling 2 percent of the TPC.

Maintenance Material and Labor Maintenance cost was evaluated on the basis of relationships of maintenance cost to initial capital cost. This represents a weighted analysis in which the individual cost relationships were considered for each major plant component or section.

Administrative and Support Labor Labor administration and overhead charges are assessed at rate of 25 percent of the burdened O&M labor.

Consumables The cost of consumables, including fuel, was determined on the basis of individual rates of consumption, the unit cost of each specific consumable commodity, and the plant annual operating hours.

Quantities for major consumables such as fuel and sorbent were taken from technology-specific heat and mass balance diagrams developed for each plant application. Other consumables were evaluated on the basis of the quantity required using reference data.

The quantities for initial fills and daily consumables were calculated on a 100 percent operating capacity basis. The annual cost for the daily consumables was then adjusted to incorporate the annual plant operating basis, or CF.

Initial fills of the consumables, fuels and chemicals, are different from the initial chemical loadings, which are included with the equipment pricing in the capital cost.

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Cost and Performance Baseline for Fossil Energy Plants Waste Disposal Waste quantities and disposal costs were determined/evaluated similarly to the consumables. In this study both slag from the IGCC cases and fly ash and bottom ash from the PC cases are considered a waste with a disposal cost of $17.89/tonne ($16.23/ton). The carbon used for mercury control in the IGCC cases is considered a hazardous waste with disposal cost of

$926/tonne ($840/ton).

Co-Products and By-Products By-product quantities were also determined similarly to the consumables. However, due to the variable marketability of these by-products, specifically gypsum and sulfur, no credit was taken for their potential salable value.

It should be noted that by-product credits and/or disposal costs could potentially be an additional determining factor in the choice of technology for some companies and in selecting some sites.

A high local value of the product can establish whether or not added capital should be included in the plant costs to produce a particular co-product. Ash and slag are both potential by-products in certain markets, and in the absence of activated carbon injection in the PC cases, the fly ash would remain uncontaminated and have potential marketability. However, as stated above, the ash and slag are considered wastes in this study with a concomitant disposal cost.

2.7.3 CO2 Transport, Storage and Monitoring For those cases that feature carbon sequestration, the capital and operating costs for CO2 TS&M were independently estimated by NETL. Those costs were converted to a TS&M COE increment that was added to the plant COE.

CO2 TS&M was modeled based on the following assumptions:

CO2 is supplied to the pipeline at the plant fence line at a pressure of 15.3 MPa (2,215 psia). The CO2 product gas composition varies in the cases presented, but is expected to meet the specification described in Exhibit 2-16 [26]. A glycol dryer located near the mid-point of the compression train is used to meet the moisture specification.

Exhibit 2-16 CO2 Pipeline Specification Parameter Units Parameter Value Inlet Pressure MPa (psia) 15.3 (2,215)

Outlet Pressure MPa (psia) 10.4 (1,515)

Inlet Temperature °C (°F) 35 (95)

N2 Concentration ppmv < 300 O2 Concentration ppmv < 40 Ar Concentration ppmv < 10 H2O Concentration ppmv < 150 53

Cost and Performance Baseline for Fossil Energy Plants

The CO2 is transported 80 km (50 miles) via pipeline to a geologic sequestration field for injection into a saline formation.

The CO2 is transported and injected as a SC fluid in order to avoid two-phase flow and achieve maximum efficiency [27]. The pipeline is assumed to have an outlet pressure (above the SC pressure) of 8.3 MPa (1,200 psia) with no recompression along the way.

Accordingly, CO2 flow in the pipeline was modeled to determine the pipe diameter that results in a pressure drop of 6.9 MPa (1,000 psi) over an 80 km (50 mile) pipeline length

[28]. (Although not explored in this study, the use of boost compressors and a smaller pipeline diameter could possibly reduce capital costs for sufficiently long pipelines.) The diameter of the injection pipe will be of sufficient size that frictional losses during injection are minimal and no booster compression is required at the well-head in order to achieve an appropriate down-hole pressure, with hydrostatic head making up the difference between the injection and reservoir pressure.

The saline formation is at a depth of 1,236 m (4,055 ft) and has a permeability of 22 millidarcy (md) (22 m2) and formation pressure of 8.4 MPa (1,220 psig) [ 29]. This is considered an average storage site and requires roughly one injection well for each 9,360 tonnes (10,320 short tons) of CO2 injected per day [29]. The assumed aquifer characteristics are tabulated in Exhibit 2-17.

The cost metrics utilized in this study provide a best estimate of TS&M costs for a favorable sequestration project, and may vary significantly based on variables such as terrain to be crossed by the pipeline, reservoir characteristics, and number of land owners from which sub-surface rights must be acquired. Raw capital and operating costs are derived from detailed cost metrics found in the literature, escalated to June 2007-year dollars using appropriate price indices. These costs were then verified against values quoted by industrial sources where possible. Where regulatory uncertainty exists or costs are undefined, such as liability costs and the acquisition of underground pore volume, analogous existing policies were used for representative cost scenarios.

Exhibit 2-17 Deep, Saline Aquifer Specification Parameter Units Base Case Pressure MPa (psi) 8.4 (1,220)

Thickness m (ft) 161 (530)

Depth m (ft) 1,236 (4,055)

Permeability Md 22 Pipeline Distance km (miles) 80 (50)

Injection Rate per Well tonne (ton) CO2/day 9,360 (10,320)

The following sections describe the sources and methodology used for each metric.

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Cost and Performance Baseline for Fossil Energy Plants TS&M Captial Costs TS&M capital costs include both a 20 percent process contingency and 30 percent project contingency.

In several areas, such as Pore Volume Acquisition, Monitoring, and Liability, cost outlays occur over a longer time period, up to 100 years. In these cases a capital fund is established based on the net present value of the cost outlay, and this fund is then levelized similar to the other costs.

Transport Costs CO2 transport costs are broken down into three categories: pipeline costs, related capital expenditures, and O&M costs.

Pipeline costs are derived from data published in the Oil and Gas Journals (O&GJ) annual Pipeline Economics Report for existing natural gas, oil, and petroleum pipeline project costs from 1991 to 2003. These costs are expected to be analogous to the cost of building a CO2 pipeline, as noted in various studies [27, 29, 30]. The University of California performed a regression analysis to generate cost curves from the O&GJ data: (1) Pipeline Materials, (2)

Direct Labor, (3) Indirect Costs, and (4) Right-of-way acquisition, with each represented as a function of pipeline length and diameter [30]. These cost curves were escalated to the June 2007 year dollars used in this study.

Related capital expenditures were based on the findings of a previous study funded by DOE/NETL, Carbon Dioxide Sequestration in Saline Formations - Engineering and Economic Assessment [29]. This study utilized a similar basis for pipeline costs (O&GJ Pipeline cost data up to the year 2000) but added a CO2 surge tank and pipeline control system to the project.

Transport O&M costs were assessed using metrics published in a second DOE/NETL sponsored report entitled Economic Evaluation of CO2 Storage and Sink Enhancement Options [27]. This study was chosen due to the reporting of O&M costs in terms of pipeline length, whereas the other studies mentioned above either (a) do not report operating costs, or (b) report them in absolute terms for one pipeline, as opposed to as a length- or diameter-based metric.

Storage Costs Storage costs were divided into five categories: (1) Site Screening and Evaluation, (2) Injection Wells, (3) Injection Equipment, (4) O&M Costs, and (5) Pore Volume Acquisition. With the exception of Pore Volume Acquisition, all of the costs were obtained from Economic Evaluation of CO2 Storage and Sink Enhancement Options [27]. These costs include all of the costs associated with determining, developing, and maintaining a CO2 storage location, including site evaluation, well drilling, and the capital equipment required for distributing and injecting CO2.

Pore Volume Acquisition costs are the costs associated with acquiring rights to use the sub-surface volume where the CO2 will be stored, i.e., the pore space in the geologic formation.

These costs were based on recent research by Carnegie Mellon University, which examined existing sub-surface rights acquisition as it pertains to natural gas storage [31]. The regulatory uncertainty in this area combined with unknowns regarding the number and type (private or government) of property owners, require a number of best engineering judgment decisions to be made. In this study it was assumed that long-term lease rights were acquired from the property owners in the projected CO2 plume growth region for a nominal fee, and that an annual rent was paid when the plume reached each individual acre of their property for a period of up 55

Cost and Performance Baseline for Fossil Energy Plants to 100 years from the injection start date. The present value of the life cycle pore volume costs are assessed at a 10 percent discount rate and a capital fund is set up to pay for these costs over the 100 year rent scenario.

Liability Protection Liability Protection addresses the fact that if damages are caused by injection and long-term storage of CO2, the injecting party may bear financial liability. Several types of liability protection schemes have been suggested for CO2 storage, including Bonding, Insurance, and Federal Compensation Systems combined with either tort law (as with the Trans-Alaska Pipeline Fund), or with damage caps and preemption, as is used for nuclear energy under the Price Anderson Act [32]. However, at present, a specific liability regime has yet to be dictated either at a Federal or (to our knowledge) State level. However, certain state governments have enacted legislation, which assigns liability to the injecting party, either in perpetuity (Wyoming) or until ten years after the cessation of injection operations, pending reservoir integrity certification, at which time liability is turned over to the state (North Dakota and Louisiana) [33,34,35]. In the case of Louisiana, a trust fund totaling five million dollars is established over the first ten years (120 months) of injection operations for each injector. This fund is then used by the state for CO2 monitoring and, in the event of an at-fault incident, damage payments.

Liability costs assume that a bond must be purchased before injection operations are permitted in order to establish the ability and good will of an injector to address damages where they are deemed liable. A figure of five million dollars was used for the bond based on the Louisiana fund level. This bond level may be conservatively high, in that the Louisiana fund covers both liability and monitoring, but that fund also pertains to a certified reservoir where injection operations have ceased, having a reduced risk compared to active operations. The bond cost was not escalated.

Monitoring Costs Monitoring costs were evaluated based on the methodology set forth in the International Energy Agency (IEA) Greenhouse Gas (GHG) R&D Programmes Overview of Monitoring Projects for Geologic Storage Projects report [36]. In this scenario, operational monitoring of the CO2 plume occurs over 30 years (during plant operation) and closure monitoring occurs for the following fifty years (for a total of eighty years). Monitoring is via electromagnetic (EM) survey, gravity survey, and periodic seismic survey; EM and gravity surveys are ongoing while seismic survey occurs in years 1, 2, 5, 10, 15, 20, 25, and 30 during the operational period, then in years 40, 50, 60, 70, and 80 after injection ceases.

2.7.4 Finance Structure, Discounted Cash Flow Analysis, and COE The global economic assumptions are listed in Exhibit 2-18.

Finance structures were chosen based on the assumed type of developer/owner (investor-owned utility (IOU) or independent power producer) and the assumed risk profile of the plant being assessed (low-risk or high-risk). For this study the owner/developer was assumed to be an IOU.

All IGCC cases as well as PC and NGCC cases with CO2 capture were considered high risk.

The non-capture PC and NGCC cases were considered low risk. Exhibit 2-19 describes the low-risk IOU and high-risk IOU finance structures that were assumed for this study. These finance 56

Cost and Performance Baseline for Fossil Energy Plants structures were recommended in a 2008 NETL report based on interviews with project developers/owners, financial organizations and law firms [37].

Exhibit 2-18 Global Economic Assumptions Parameter Value TAXES Income Tax Rate 38% (Effective 34% Federal, 6% State)

Capital Depreciation 20 years, 150% declining balance Investment Tax Credit 0%

Tax Holiday 0 years CONTRACTING AND FINANCING TERMS Engineering Procurement Construction Contracting Strategy Management (owner assumes project risks for performance, schedule and cost)

Non-Recourse (collateral that secures debt is Type of Debt Financing limited to the real assets of the project)

Repayment Term of Debt 15 years Grace Period on Debt Repayment 0 years Debt Reserve Fund None ANALYSIS TIME PERIODS Natural Gas Plants: 3 Years Capital Expenditure Period Coal Plants: 5 Years Operational Period 30 years 33 or 35 Years (capital expenditure period plus Economic Analysis Period (used for IRROE) operational period)

TREATMENT OF CAPITAL COSTS Capital Cost Escalation During Capital 3.6% 2 Expenditure Period (nominal annual rate)

Distribution of Total Overnight Capital over the 3-Year Period: 10%, 60%, 30%

Capital Expenditure Period (before escalation) 5-Year Period: 10%, 30%, 25%, 20%, 15%

Working Capital zero for all parameters 100% (this assumption introduces a very small

% of Total Overnight Capital that is Depreciated error even if a substantial amount of TOC is actually non-depreciable)

ESCALATION OF OPERATING REVENUES AND COSTS Escalation of COE (revenue), O&M Costs, and 3.0% 3 Fuel Costs (nominal annual rate) 2 A nominal average annual rate of 3.6 percent is assumed for escalation of capital costs during construction. This rate is equivalent to the nominal average annual escalation rate for process plant construction costs between 1947 and 2008 according to the Chemical Engineering Plant Cost Index.

3 An average annual inflation rate of 3.0 percent is assumed. This rate is equivalent to the average annual escalation rate between 1947 and 2008 for the U.S. Department of Labor's Producer Price Index for Finished Goods, the so-called "headline" index of the various Producer Price Indices. (The Producer Price Index for the Electric Power Generation Industry may be more applicable, but that data does not provide a long-term historical perspective since it only dates back to December 2003.)

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Cost and Performance Baseline for Fossil Energy Plants Exhibit 2-19 Financial Structure for Investor Owned Utility High and Low Risk Projects Current Weighted After Tax Type of

% of Total (Nominal) Dollar Current Weighted Cost of Security Cost (Nominal) Cost Capital Low Risk Debt 50 4.5% 2.25%

Equity 50 12% 6%

Total 8.25% 7.39%

High Risk Debt 45 5.5% 2.475%

Equity 55 12% 6.6%

Total 9.075% 8.13%

DCF Analysis and Cost of Electricity The NETL Power Systems Financial Model (PSFM) is a nominal-dollar 4 (current dollar) discounted cash flow (DCF) analysis tool. As explained below, the PSFM was used to calculate COE 5 in two ways: a COE and a levelized COE (LCOE). To illustrate how the two are related, COE solutions are shown in Exhibit 2-20 for a generic pulverized coal (PC) power plant and a generic natural gas combined cycle (NGCC) power plant, each with carbon capture and sequestration installed.

The COE is the revenue received by the generator per net megawatt-hour during the power plants first year of operation, assuming that the COE escalates thereafter at a nominal annual rate equal to the general inflation rate, i.e., that it remains constant in real terms over the operational period of the power plant. To calculate the COE, the PSFM was used to determine a base-year (2007) COE that, when escalated at an assumed nominal annual general inflation rate of 3 percent 6, provided the stipulated internal rate of return on equity over the entire economic analysis period (capital expenditure period plus thirty years of operation). The COE solutions are shown as curved lines in the upper portion of Exhibit 2-20 for a PC power plant and a NGCC power plant. Since this analysis assumes that COE increases over the economic analysis period at the nominal annual general inflation rate, it remains constant in real terms and the first-year COE is equivalent to the base-year COE when expressed in base-year (2007) dollars.

4 Since the analysis takes into account taxes and depreciation, a nominal dollar basis is preferred to properly reflect the interplay between depreciation and inflation.

5 For this calculation, cost of electricity is somewhat of a misnomer because from the power plants perspective it is actually the price received for the electricity generated to achieve the stated IRROE. However, since the price paid for generation is ultimately charged to the end user, from the customers perspective it is part of the cost of electricity.

6 This nominal escalation rate is equal to the average annual inflation rate between 1947 and 2008 for the U.S.

Department of Labors Producer Price Index for Finished Goods. This index was used instead of the Producer Price Index for the Electric Power Generation Industry because the Electric Power Index only dates back to December 2003 and the Producer Price Index is considered the headline index for all of the various Producer Price Indices.

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Cost and Performance Baseline for Fossil Energy Plants

The LEVELIZED COE is the revenue received by the generator per net megawatt-hour during the power plants first year of operation, assuming that the COE escalates thereafter at a nominal annual rate of 0 percent, i.e., that it remains constant in nominal terms over the operational period of the power plant. This study reports LCOE on a current-dollar basis over thirty years. Current dollar refers to the fact that levelization is done on a nominal, rather than a real, basis 7. Thirty-years refers to the length of the operational period assumed for the economic analysis. To calculate the LCOE, the PSFM was used to calculate a base-year COE that, when escalated at a nominal annual rate of 0 percent, provided the stipulated return on equity over the entire economic analysis period. For the example PC and NGCC power plant cases, the LCOE solutions are shown as horizontal lines in the upper portion of Exhibit 2-20.

Exhibit 2-20 also illustrates the relationship between COE and the assumed developmental and operational timelines for the power plants. As shown in the lower portion of Exhibit 2-20, the capital expenditure period is assumed to start in 2007 for all cases in this report. All capital costs included in this analysis, including project development and construction costs, are assumed to be incurred during the capital expenditure period. Coal-fueled plants are assumed to have a capital expenditure period of five years and natural gas-fueled plants are assumed to have a capital expenditure period of three years. Since both types of plants begin expending capital in the base year (2007), this means that the analysis assumes that they begin operating in different years: 2012 for coal plants and 2010 for natural gas plants in this study. Note that, according to the Chemical Engineering Plant Cost Index, June-2007 dollars are nearly equivalent to January-2010 dollars.

7 For this current-dollar analysis, the LCOE is uniform in current dollars over the analysis period. In contrast, a constant-dollar analysis would yield an LCOE that is uniform in constant dollars over the analysis period.

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Cost and Performance Baseline for Fossil Energy Plants Exhibit 2-20 Illustration of COE Solutions using DCF Analysis In addition to the capital expenditure period, the economic analysis considers thirty years of operation for both coal and natural gas plants.

Since 2007 is the first year of the capital expenditure period, it is also the base year for the economic analysis. Accordingly, it is convenient to report the results of the economic analysis in base-year (June 2007) dollars, except for TASC, which is expressed in mixed-year, current dollars over the capital expenditure period.

Consistent with our nominal-dollar discounted cash flow methodology, the COEs shown on Exhibit 2-20 are expressed in current dollars. However, they can also be expressed in constant, base year dollars (June 2007) as shown in Exhibit 2-21 by adjusting them with the assumed nominal annual general inflation rate (3 percent).

Exhibit 2-21 illustrates the same information as in Exhibit 2-20 for a PC plant with CCS only on a constant 2007 dollar basis. With an assumed nominal COE escalation rate equal to the rate of inflation, the COE line now becomes horizontal and the LCOE decreases at a rate of 3 percent per year.

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Cost and Performance Baseline for Fossil Energy Plants Exhibit 2-21 PC with CCS in Current 2007 Dollars Estimating COE with Capital Charge Factors For scenarios that adhere to the global economic assumptions listed in Exhibit 2-18 and utilize one of the finance structures listed in Exhibit 2-19, the following simplified equation can be used to estimate COE as a function of TOC 8, fixed O&M, variable O&M (including fuel), capacity factor and net output. The equation requires the application of one of the capital charge factors (CCF) listed in Exhibit 2-22. These CCFs are valid only for the global economic assumptions listed in Exhibit 2-18, the stated finance structure, and the stated capital expenditure period.

8 Although TOC is used in the simplified COE equation, the CCF that multiplies it accounts for escalation during construction and interest during construction (along with other factors related to the recovery of capital costs).

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Cost and Performance Baseline for Fossil Energy Plants Exhibit 2-22 Capital Charge Factors for COE Equation Finance High Risk IOU Low Risk IOU Structure Capital Expenditure Period Three Years Five Years Three Years Five Years Capital Charge Factor (CCF) 0.111 0.124 0.105 0.116 All factors in the COE equation are expressed in base-year dollars. The base year is the first year of capital expenditure, which for this study is assumed to be 2007. As shown in Exhibit 2-18, all factors (COE, O&M and fuel) are assumed to escalate at a nominal annual general inflation rate of 3.0 percent. Accordingly, all first-year costs (COE and O&M) are equivalent to base-year costs when expressed in base-year (2007) dollars.

where:

COE = revenue received by the generator ($/MWh, equivalent to mills/kWh) during the power plants first year of operation (but expressed in base-year dollars), assuming that the COE escalates thereafter at a nominal annual rate equal to the general inflation rate, i.e., that it remains constant in real terms over the operational period of the power plant.

CCF = capital charge factor taken from Exhibit 2-22 that matches the applicable finance structure and capital expenditure period TOC = total overnight capital, expressed in base-year dollars OCFIX = the sum of all fixed annual operating costs, expressed in base-year dollars OCVAR = the sum of all variable annual operating costs, including fuel at 100 percent capacity factor, expressed in base-year dollars CF = plant capacity factor, assumed to be constant over the operational period MWH = annual net megawatt-hours of power generated at 100 percent capacity factor 62

Cost and Performance Baseline for Fossil Energy Plants The primary cost metric in this study is the COE, which is the base-year cost presented in base-year dollars. Exhibit 2-23 presents this cost metric along with the COE escalated to the first year of operation (2010 for NGCC cases and 2012 for coal cases) using the average annual inflation rate of 3 percent. Similarly, the LCOE is presented in both base-year dollars and first year of operation dollars. Using a similar methodology, the reader may generate either metric in the desired cost year basis.

Exhibit 2-23 COE and LCOE Summary COE LCOE Case Base-Year First Operational Year Base-Year First Operational Year 2007$ 2010$ 2012$ 2007$ 2010$ 2012$

(all cases) (NGCC cases) (coal cases) (all cases) (NGCC cases) (coal cases) 1 76.28 N/A 88.43 96.70 N/A 112.10 2 105.66 N/A 122.49 133.94 N/A 155.27 3 74.02 N/A 85.81 93.83 N/A 108.77 4 110.39 N/A 127.97 139.93 N/A 162.22 5 81.31 N/A 94.26 103.07 N/A 119.48 6 119.46 N/A 138.49 151.43 N/A 175.55 9 59.40 N/A 68.86 75.29 N/A 87.29 10 109.69 N/A 127.16 139.05 N/A 161.20 11 58.91 N/A 68.29 74.67 N/A 86.56 12 106.63 N/A 123.61 135.16 N/A 156.69 13 58.90 64.36 N/A 74.65 81.58 N/A 14 85.93 93.89 N/A 108.93 119.03 N/A 2.8 IGCC STUDY COST ESTIMATES COMPARED TO INDUSTRY ESTIMATES The estimated TOC for IGCC cases in this study ranges from $2,351 to $2,716/kW for non- CO2 capture cases and $3,334/kW to $3,904/kW for capture cases. Plant size ranges from 622 - 629 MW (net) for non-capture cases and 497 - 543 MW (net) for capture cases.

Within the power industry there are several power producers interested in pursuing construction of an IGCC plant. While these projects are still in the relatively early stages of development, some cost estimates have been published. Published estimates tend to be limited in detail, leaving it to the reader to speculate as to what is contained within the estimate. In November 2007, the Indiana Utility Regulatory Commission approved Duke Energys proposal to build an IGCC plant in Edwardsport, Indiana. The estimated cost to build the 630 MW plant is

$4,472/kW in June 2007 dollars. Duke expects the plant to begin operation in 2012. Other published estimates for similar proposed non-CO2 capture gasification plants range from

$2,483/kW to $3,122/kW in June 2007 dollars. Corresponding plant sizes range form 770 - 600 63

Cost and Performance Baseline for Fossil Energy Plants MW, respectively. Published estimates from similar CO2 capture facilities range from

$4,581/kW to $5,408/kW, in June 2007 dollars, with sizes ranging from 400 to 580 MW

[38,39,40,41]. 9 Differences in Cost Estimates Project Scope For this report, the scope of work is generally limited to work inside the project fence line. For outgoing power, the scope stops at the high side terminals of the Generator Step-up Transformers (GSUs).

Some typical examples of items outside the fenceline include:

New access roads and railroad tracks

Upgrades to existing roads to accommodate increased traffic

Makeup water pipe outside the fenceline

Landfill for on-site waste (slag) disposal

Natural gas line for backup fuel provisions

Plant switchyard

Electrical transmission lines & substation Estimates in this report are based on a generic mid-western greenfield site having normal characteristics. Accordingly, the estimates do not address items such as:

Piles or caissons

Rock removal

Excessive dewatering

Expansive soil considerations

Excessive seismic considerations

Extreme temperature considerations

Hazardous or contaminated soils

Demolition or relocation of existing structures

Leasing of offsite land for parking or laydown

Busing of craft to site

Costs of offsite storage This report is based on a reasonably standard plant. No unusual or extraordinary process equipment is included such as:

Excessive water treatment equipment

Air-cooled condenser

Automated coal reclaim

Zero Liquid Discharge equipment

SCR catalyst (IGCC cases only) 9 Costs were adjusted to June 2007 using the Chemical Engineering Plant Cost Index 64

Cost and Performance Baseline for Fossil Energy Plants For non-capture cases, which are likely the most appropriate comparison against industry published estimates, this report is based on plant equipment sized for non-capture only. None of the equipment is sized to accommodate a future conversion to CO2 capture.

Labor This report is based on Merit Shop (non-union) labor. If a project is to use Union labor, there is a strong likelihood that overall labor costs will be greater than those estimated in this report.

This report is based on a 50 hour5.787037e-4 days 0.0139 hours 8.267196e-5 weeks 1.9025e-5 months work week, with an adequate local supply of skilled craft labor.

No additional incentives such as per-diems or bonuses have been included to attract and retain skilled craft labor.

Contracting Methodology The estimates in this report are based on a competitively bid, multiple subcontract approach, often referred to as EPCM. Accordingly, the estimates do not include premiums associated with an EPC approach. It is believed that, given current market conditions, the premium charged by an EPC contractor could be as much as 30 percent or more over an EPCM approach.

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Cost and Performance Baseline for Fossil Energy Plants

3. IGCC POWER PLANTS Six IGCC power plant configurations were evaluated and the results are presented in this section.

Each design is based on a market-ready technology that is assumed to be commercially available to support startup.

The six cases are based on the GEE gasifier, the CoP E-Gas' gasifier and the Shell gasifier, each with and without CO2 capture. As discussed in Section 1, the net output for the six cases varies because of the constraint imposed by the fixed GT output and the high auxiliary loads imparted by the CO2 capture process.

The CT is based on an advanced F-class design. The HRSG/steam turbine cycle varies based on the CT exhaust conditions. Steam conditions range from 12.4 MPa/559°C/559°C (1800 psig/1038°F/1038°F) to 12.4 MPa/562°C/562°C (1800 psig/1043°F/1043°F) for all of the non-CO2 capture cases and 12.4 MPa/534°C/534°C (1800 psig/993°F/993°F) to 12.4 MPa/534°C/534°C (1800 psig/994°F/994°F) for all of the CO2 capture cases. The capture cases have a lower main and reheat steam temperature primarily because the turbine firing temperature is reduced to allow for a parts life equivalent to NGCC operation with a high-hydrogen content fuel, which results in a lower turbine exhaust temperature.

The evaluation scope included developing heat and mass balances and estimating plant performance. Equipment lists were developed for each design to support plant capital and operating cost estimates. The evaluation basis details, including site ambient conditions, fuel composition and environmental targets, were provided in Section 2. Section 3.1 covers general information that is common to all IGCC cases, and case specific information is subsequently presented in Sections 3.2, 3.3 and 3.4.

3.1 IGCC COMMON PROCESS AREAS The IGCC cases have process areas, which are common to each plant configuration such as coal receiving and storage, oxygen supply, gas cleanup, power generation, etc. As detailed descriptions of these process areas for each case would be burdensome and repetitious, they are presented in this section for general background information. Where there is case-specific performance information, the performance features are presented in the relevant case sections.

3.1.1 Coal Receiving and Storage The function of the Coal Receiving and Storage 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 and including the slide gate valves at the outlet of the coal storage silos. Coal receiving and storage is identical for all six IGCC cases; however, coal preparation and feed are gasifier-specific.

Operation Description - The coal is delivered to the site by 100-car unit trains comprised of 91 tonne (100 ton) rail cars. The unloading is done by a trestle bottom dumper, which unloads the coal into two receiving hoppers. Coal from each hopper is fed directly into a vibratory feeder.

The 8 cm x 0 (3" x 0) coal from the feeder is discharged onto a belt conveyor. Two conveyors with an intermediate transfer tower are assumed to convey the coal to the coal stacker, which transfer the coal to either the long-term storage pile or to the reclaim area. The conveyor passes under a magnetic plate separator to remove tramp iron and then to the reclaim pile.

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Cost and Performance Baseline for Fossil Energy Plants The reclaimer loads the coal into two vibratory feeders located in the reclaim hopper under the pile. The feeders transfer the coal onto a belt conveyor that transfers the coal to the coal surge bin located in the crusher tower. The coal is reduced in size to 3 cm x 0 (11/4" x 0) by the crusher. A conveyor then transfers the coal to a transfer tower. In the transfer tower the coal is routed to the tripper, which loads the coal into one of three silos. Two sampling systems are supplied: the as-received sampling system and the as-fired sampling system. Data from the analyses are used to support the reliable and efficient operation of the plant.

3.1.2 Air Separation Unit (ASU) Choice and Integration In order to economically and efficiently support IGCC projects, air separation equipment has been modified and improved in response to production requirements and the consistent need to increase single train output. Elevated pressure air separation designs have been implemented that result in distillation column operating pressures that are about twice as high as traditional plants. In this study, the main air compressor discharge pressure was set at 1.3 MPa (190 psia) compared to a traditional ASU plant operating pressure of about 0.7 MPa (105 psia) [ 42]. For IGCC designs the elevated pressure ASU process minimizes power consumption and decreases the size of some of the equipment items. When the air supply to the ASU is integrated with the GT, the ASU operates at or near the supply pressure from the GTs air compressor.

Residual Nitrogen Injection The residual nitrogen that is available after gasifier oxygen and nitrogen requirements have been met is often compressed and sent to the GT. Since all product streams are being compressed, the ASU air feed pressure is optimized to reduce the total power consumption and to provide a good match with available compressor frame sizes.

Increasing the diluent flow to the GT by injecting residual nitrogen from the ASU can have a number of benefits, depending on the design of the GT:

Increased diluent increases mass flow through the turbine, thus increasing the power output of the GT while maintaining optimum firing temperatures for syngas operation.

This is particularly beneficial for locations where the ambient temperature and/or elevation are high and the GT would normally operate at reduced output.

By mixing with the syngas or by being injected directly into the combustor, the diluent nitrogen lowers the firing temperature (relative to natural gas) and reduces the formation of thermal NOx.

In this study, the ASU nitrogen product was used as the primary diluent with a design target of reducing the syngas lower heating value (LHV) to 4.4-4.7 MJ/Nm3 (119-125 Btu/scf). If the amount of available nitrogen was not sufficient to meet this target, additional dilution was provided through syngas humidification, and if still more dilution was required, the third option was steam injection.

Air Integration Integration between the ASU and the CT can be practiced by extracting some, or all, of the ASUs air requirement from the GT. Medium British thermal unit (Btu) syngas streams result in a higher mass flow than natural gas to provide the same heat content to the GT. Some GT designs may need to extract air to maintain stable compressor or turbine operation in response to increased fuel flow rates. Other GTs may balance air extraction against injection of all of the 68

Cost and Performance Baseline for Fossil Energy Plants available nitrogen from the ASU. The amount of air extracted can also be varied as the ambient temperature changes at a given site to optimize year-round performance.

An important aspect of air-integrated designs is the need to efficiently recover the heat of compression contained in the air extracted from the GT. Extraction air temperature is normally in the range 399 - 454°C (750 - 850°F), and must be cooled to the last stage main air compressor discharge temperature prior to admission to the ASU. High-level recovery from the extracted air occurs by transferring heat to the nitrogen stream to be injected into the GT with a gas-to-gas heat exchanger.

Elevated Pressure ASU Experience in Gasification The Buggenum, Netherlands unit built for Demkolec was the first elevated-pressure, fully integrated ASU to be constructed. It was designed to produce up to 1,796 tonnes/day (1,980 tons per day [TPD]) of 95 percent purity oxygen for a Shell coal-based gasification unit that fuels a Siemens V94.2 GT. In normal operation at the Buggenum plant the ASU receives all of its air supply from and sends all residual nitrogen to the GT.

The Polk County, Florida ASU for the Tampa Electric IGCC is also an elevated-pressure, 95 percent purity oxygen design that provides 1,832 tonnes/day (2,020 TPD) of oxygen to a GEE coal-based gasification unit, which fuels a General Electric 7FA GT. All of the nitrogen produced in the ASU is used in the GT. The original design did not allow for air extraction from the CT. After a CT air compressor failure in January, 2005, a modification was made to allow air extraction, which in turn eliminated a bottleneck in ASU capacity and increased overall power output [43].

ASU Basis For this study, air integration is used for the non-carbon capture cases only. In the CO2 capture cases, once the syngas is diluted to the target heating value, all of the available combustion air is required to maintain mass flow through the turbine and hence maintain power output.

The amount of air extracted from the GT in the non-capture cases is determined through a process that includes the following constraints:

The CT output must be maintained at 232 MW.

The diluted syngas must meet heating value requirements specified by a CT vendor, which ranged from 4.4-4.7 MJ/Nm3 (119-125 Btu/scf).

Meeting the above constraints resulted in different levels of air extraction in the three non-carbon capture cases as shown in Exhibit 3-1. It was not a goal of this project to optimize the integration of the CT and the ASU, although several recent papers have shown that providing 25-30 percent of the ASU air from the turbine compressor provides the best balance between maximizing plant output and efficiency without compromising plant availability or reliability

[44,45].

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Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-1 Air Extracted from the Combustion Turbine and Supplied to the ASU in Non-Carbon Capture Cases Case No. 1 3 5 Gasifier GEE CoP Shell Air Extracted from Gas Turbine, % 4.0 4.0 4.0 Air Provided to ASU, % of ASU Total 16.8 18.9 19.4 Air Separation Plant Process Description[46]

The air separation plant is designed to produce 95 mole percent (mol%) O2 for use in the gasifier.

The plant is designed with two production trains, one for each gasifier. The air compressor is powered by an electric motor. Nitrogen is also recovered, compressed, and used as dilution in the GT combustor. A process schematic of a typical ASU is shown in Exhibit 3-2.

The air feed to the ASU is supplied from two sources. A portion of the air is extracted from the compressor of the GT (non-CO2 capture cases only). The remaining air is supplied from a stand-alone compressor. Air to the stand-alone compressor is first filtered in a suction filter upstream of the compressor. This air filter removes particulate, which may tend to cause compressor wheel erosion and foul intercoolers. The filtered air is then compressed in the centrifugal compressor, with intercooling between each stage.

Air from the stand-alone compressor is combined with the extraction air, and the combined stream is cooled and fed to an adsorbent-based pre-purifier system. The adsorbent removes water, CO2, and C4+ saturated hydrocarbons in the air. After passing through the adsorption beds, the air is filtered with a dust filter to remove any adsorbent fines that may be present.

Downstream of the dust filter a small stream of air is withdrawn to supply the instrument air requirements of the ASU.

Regeneration of the adsorbent in the pre-purifiers is accomplished by passing a hot nitrogen stream through the off-stream bed(s) in a direction countercurrent to the normal airflow. The nitrogen is heated against extraction steam (1.7 MPa [250 psia]) in a shell and tube heat exchanger. The regeneration nitrogen drives off the adsorbed contaminants. Following regeneration, the heated bed is cooled to near normal operating temperature by passing a cool nitrogen stream through the adsorbent beds. The bed is re-pressurized with air and placed on stream so that the current on-stream bed(s) can be regenerated.

The air from the pre-purifier is then split into three streams. About 70 percent of the air is fed directly to the cold box. About 25 percent of the air is compressed in an air booster compressor.

This boosted air is then cooled in an aftercooler against cooling water in the first stage and against chilled water in the second stage before it is fed to the cold box. The chiller utilizes low-pressure (LP) process steam at 0.3 MPa (50 psia) to drive the absorption refrigeration cycle. The remaining five percent of the air is fed to a turbine-driven, single-stage, centrifugal booster compressor. This stream is cooled in a shell and tube aftercooler against cooling water before it is fed to the cold box.

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Cost and Performance Baseline for Fossil Energy Plants All three air feeds are cooled in the cold box to cryogenic temperatures against returning product oxygen and nitrogen streams in plate-and-fin heat exchangers. The large air stream is fed directly to the first distillation column to begin the separation process. The second largest air stream is liquefied against boiling liquid oxygen before it is fed to the distillation columns. The third, smallest air stream is fed to the cryogenic expander to produce refrigeration to sustain the cryogenic separation process.

Inside the cold box the air is separated into oxygen and nitrogen products. The oxygen product is withdrawn from the distillation columns as a liquid and is pressurized by a cryogenic pump.

The pressurized liquid oxygen is then vaporized against the high-pressure (HP) air feed before being warmed to ambient temperature. The gaseous oxygen exits the cold box and is fed to the centrifugal compressor with intercooling between each stage of compression. The compressed oxygen is then fed to the gasification unit.

Nitrogen is produced from the cold box at two pressure levels. LP nitrogen is split into two streams. The majority of the LP nitrogen is compressed and fed to the GT as diluent nitrogen. A small portion of the nitrogen is used as the regeneration gas for the pre-purifiers and recombined with the diluent nitrogen. A HP nitrogen stream is also produced from the cold box and is further compressed before it is also supplied to the GT.

Exhibit 3-2 Typical ASU Process Schematic HP Oxygen Oxygen Compressor Cryogenic Air Separation Unit Regeneration Single Train GT Nitrogen Nitrogen Compressor Steam Regen. N2 Regen Blower Heater Booster Air Compressor Cond.

Air from Gas Turbine Prepurifiers GT Nitrogen Turbine Air Booster Chiller Turbine Liq. Oxygen CWS Pump 2nd Stage DCA Cond. Steam Main Air CWR Air Filter Compressor 1st Stage DCA CWS Air CWR 71

Cost and Performance Baseline for Fossil Energy Plants 3.1.3 Water Gas Shift Reactors Selection of Technology - In the cases with CO2 separation and capture, the gasifier product must be converted to hydrogen-rich syngas. The first step is to convert most of the syngas CO to hydrogen (H2) and CO2 by reacting the CO with water over a bed of catalyst. The H2O:CO molar ratio in the shift reaction, shown below, is adjusted to approximately 2: 1 by the addition of steam to the syngas stream thus promoting a high conversion of CO. In the cases without CO2 separation and capture, CO shift convertors are not required.

Water Gas Shift: CO + H2O CO2 + H2 The CO shift converter can be located either upstream of the AGR step (SGS) or immediately downstream (sweet gas shift). If the CO converter is located downstream of the AGR, then the metallurgy of the unit is less stringent but additional equipment must be added to the process.

Products from the gasifier are humidified with steam or water and contain a portion of the water vapor necessary to meet the water-to-gas criteria at the reactor inlet. If the CO converter is located downstream of the AGR, then the gasifier product would first have to be cooled and the free water separated and treated. Then additional steam would have to be generated and re-injected into the CO converter feed to meet the required water-to-gas ratio. If the CO converter is located upstream of the AGR step, no additional equipment is required. This is because the CO converter promotes carbonyl sulfide (COS) hydrolysis without a separate catalyst bed.

Therefore, for this study the CO converter was located upstream of the AGR unit and is referred to as SGS.

Process Description - The SGS consists of two paths of parallel fixed-bed reactors arranged in series. Two reactors in series are used in each parallel path to achieve sufficient conversion to meet the 90 percent CO2 capture target. In the CoP case, a third shift reactor is added to each path to increase the CO conversion because of the relatively high amount of CH4 present in the syngas. With the third reactor added, CO2 capture is 90.4 percent in the CoP case.

Cooling is provided between the series of reactors to control the exothermic temperature rise.

The parallel set of reactors is required due to the high gas mass flow rate. In all three CO2 capture cases the heat exchanger after the first SGS reactor is used to vaporize water that is then used to adjust the syngas H2O:CO ratio to 2:1 on a molar basis. The heat exchanger after the second SGS reactor is used to raise intermediate pressure (IP) steam, which then passes through the reheater (RH) section of the HRSG in the GEE and CoP cases, and is used to preheat the syngas prior to the first SGS reactor in the Shell case. Approximately 97 percent conversion of the CO is achieved in the GEE and Shell cases, and about 98 percent conversion is achieved in the CoP case.

3.1.4 Mercury Removal An IGCC power plant has the potential of removing mercury in a more simple and cost-effective manner than conventional PC plants. This is because mercury can be removed from the syngas at elevated pressure and prior to combustion so that syngas volumes are much smaller than FG volumes in comparable PC cases. A conceptual design for an activated, sulfur-impregnated, carbon bed adsorption system was developed for mercury control in the IGCC plants being studied. Data on the performance of carbon bed systems were obtained from the Eastman Chemical Company, which uses carbon beds at its syngas facility in Kingsport, Tennessee [13].

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Cost and Performance Baseline for Fossil Energy Plants The coal mercury content (0.15 ppm dry) and carbon bed removal efficiency (95 percent) were discussed previously in Section 2.4. IGCC-specific design considerations are discussed below.

Carbon Bed Location - The packed carbon bed vessels are located upstream of the sulfur recovery unit (SRU) and syngas enters at a temperature near 38°C (100°F). Consideration was given to locating the beds further upstream before the COS hydrolysis unit (in non-CO2 capture cases) at a temperature near 204°C (400°F). However, while the mercury removal efficiency of carbon has been found to be relatively insensitive to pressure variations, temperature adversely affects the removal efficiency [47]. Eastman Chemical also operates their beds ahead of their SRU at a temperature of 30°C (86°F) [13].

Consideration was also given to locating the beds downstream of the SRU. However, it was felt that removing the mercury and other contaminants before the SRU would enhance the performance of the SRU and increase the life of the various solvents.

Process Parameters - An empty vessel basis gas residence time of approximately 20 seconds was used based on Eastman Chemicals experience [13]. Allowable gas velocities are limited by considerations of particle entrainment, bed agitation, and pressure drop. One-foot-per-second superficial velocity is in the middle of the range normally encountered [47] and was selected for this application.

The bed density of 30 lb/ft3 was based on the Calgon Carbon Corporation HGR-P sulfur-impregnated pelletized activated carbon [48]. These parameters determined the size of the vessels and the amount of carbon required. Each gasifier train has one mercury removal bed and there are two gasifier trains in each IGCC case, resulting in two carbon beds per case.

Carbon Replacement Time - Eastman Chemicals replaces its bed every 18 to 24 months [13].

However, bed replacement is not because of mercury loading, but for other reasons including:

A buildup in pressure drop

A buildup of water in the bed

A buildup of other contaminants For this study a 24 month carbon replacement cycle was assumed. Under these assumptions, the mercury loading in the bed would build up to 0.6 - 1.1 weight percent (wt%). Mercury capacity of sulfur-impregnated carbon can be as high as 20 wt% [49]. The mercury laden carbon is considered to be a hazardous waste, and the disposal cost estimate reflects this categorization.

3.1.5 Acid Gas Removal (AGR) Process Selection Gasification of coal to generate power produces a syngas that must be treated prior to further utilization. A portion of the treatment consists of AGR and sulfur recovery. The environmental target for these IGCC cases is 0.0128 lb SO2/MMBtu, which requires that the total sulfur content of the syngas be reduced to less than 30 ppmv. This includes all sulfur species, but in particular the total of COS and H2S, thereby resulting in stack gas emissions of less than 4 ppmv SO2.

COS Hydrolysis The use of COS hydrolysis pretreatment in the feed to the AGR process provides a means to reduce the COS concentration. This method was first commercially proven at the Buggenum plant, and was also used at both the Tampa Electric and Wabash River IGCC projects. Several 73

Cost and Performance Baseline for Fossil Energy Plants catalyst manufacturers including Haldor Topsoe and Porocel offer a catalyst that promotes the COS hydrolysis reaction. The non-carbon capture COS hydrolysis reactor designs are based on information from Porocel. In cases with CO2 capture, the SGS reactors reduce COS to H2S as discussed in Section 3.1.3.

The COS hydrolysis reaction is equimolar with a slightly exothermic heat of reaction. The reaction is represented as follows.

COS + H2O CO2 + H2S Since the reaction is exothermic, higher conversion is achieved at lower temperatures. However, at lower temperatures the reaction kinetics are slower. Based on the feed gas for this evaluation, Porocel recommended a temperature of 177 to 204°C (350 to 400°F). Since the exit gas COS concentration is critical to the amount of H2S that must be removed with the AGR process, a retention time of 50-75 seconds was used to achieve 99.5 percent conversion of the COS. The Porocel activated alumina-based catalyst, designated as Hydrocel 640 catalyst, promotes the COS hydrolysis reaction without promoting reaction of H2S and CO to form COS and H2.

Although the reaction is exothermic, the heat of reaction is dissipated among the large amount of non-reacting components. Therefore, the reaction is essentially isothermal. The product gas, now containing less than 4 ppmv of COS, is cooled prior to entering the mercury removal process and the AGR.

Sulfur Removal H2S removal generally consists of absorption by a regenerable solvent. The most commonly used technique is based on countercurrent contact with the solvent. Acid-gas-rich solution from the absorber is stripped of its acid gas in a regenerator, usually by application of heat. The regenerated lean solution is then cooled and recirculated to the top of the absorber, completing the cycle. Exhibit 3-3 is a simplified diagram of the AGR process [50].

There are well over 30 AGR processes in common commercial use throughout the oil, chemical, and natural gas industries. However, in a 2002 report by SFA Pacific a list of 42 operating and planned gasifiers shows that only six AGR processes are represented: Rectisol, Sulfinol, MDEA, Selexol, aqueous di-isoproponal (ADIP) amine, and FLEXSORB [52]. These processes can be separated into three general types: chemical reagents, physical solvents, and hybrid solvents.

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Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-3 Flow Diagram for a Conventional AGR Unit Condenser Treated Gas Acid Gas Cooler Absorber L/R Lean Exchanger Stripper Solvent Feed Gas Reboiler Rich Solvent Lean Solvent Pump Chemical Solvents Frequently used for AGR, chemical solvents are more suitable than physical or hybrid solvents for applications at lower operating pressures. The chemical nature of acid gas absorption makes solution loading and circulation less dependent on the acid gas partial pressure. Because the solution is aqueous, co-absorption of hydrocarbons is minimal. In a conventional amine unit, the chemical solvent reacts exothermically with the acid gas constituents. They form a weak chemical bond that can be broken, releasing the acid gas and regenerating the solvent for reuse.

In recent years MDEA, a tertiary amine, has acquired a much larger share of the gas-treating market. Compared with primary and secondary amines, MDEA has superior capabilities for selectively removing H2S in the presence of CO2, is resistant to degradation by organic sulfur compounds, has a low tendency for corrosion, has a relatively low circulation rate, and consumes less energy. Commercially available are several MDEA-based solvents that are formulated for high H2S selectivity.

Chemical reagents are used to remove the acid gases by a reversible chemical reaction of the acid gases with an aqueous solution of various alkanolamines or alkaline salts in water. Exhibit 3-4 lists commonly used chemical reagents along with principal licensors that use them in their processes. The process consists of an absorber and regenerator, which are connected by a circulation of the chemical reagent aqueous solution. The absorber contacts the lean solution with the main gas stream (at pressure) to remove the acid gases by absorption/ reaction with the chemical solution. The acid-gas-rich solution is reduced to LP and heated in the stripper to reverse the reactions and strip the acid gas. The acid-gas-lean solution leaves the bottom of the regenerator stripper and is cooled, pumped to the required pressure and recirculated back to the absorber. For some amines, a filter and a separate reclaiming section (not shown) are needed to remove undesirable reaction byproducts.

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Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-4 Common Chemical Reagents Used in AGR Processes Chemical Reagent Acronym Process Licensors Using the Reagent Monoethanolamine MEA Dow, Exxon, Lurgi, Union Carbide Diethanolamine DEA Elf, Lurgi Diglycolamine DGA Texaco, Fluor Triethanolamine TEA AMOCO Diisopropanolamine DIPA Shell BASF, Dow, Elf, Snamprogetti, Shell, Methyldiethanolamine MDEA Union Carbide, Coastal Chemical Hindered amine Exxon Eickmeyer, Exxon, Lurgi, Potassium carbonate hot pot Union Carbide Typically, the absorber temperature is 27 to 49°C (80 to 120°F) for amine processes, and the regeneration temperature is the boiling point of the solutions, generally 104 to 127°C (220 to 260°F). The liquid circulation rates can vary widely, depending on the amount of acid gas being captured. However, the most suitable processes are those that will dissolve 2 to 10 standard cubic feet (scf) acid gas per gallon of solution circulated. Steam consumption can vary widely also: 0.7 to 1.5 pounds per gallon (lb/gal) of liquid is typical, with 0.8 to 0.9 being a typical good value. CoP non-capture, which utilizes the chemical solvent MDEA, uses 0.88 pounds of steam per gallon of liquid. The steam conditions are 0.45 MPa (65 psia) and 151°C (304°F).

The major advantage of these systems is the ability to remove acid gas to low levels at low to moderate H2S partial pressures.

Physical Solvents Physical solvents involve absorption of acid gases into certain organic solvents that have a high solubility for acid gases. As the name implies, physical solvents involve only the physical solution of acid gas - the acid gas loading in the solvent is proportional to the acid gas partial pressure (Henrys Law). Physical solvent absorbers are usually operated at lower temperatures than is the case for chemical solvents. The solution step occurs at HP and at or below ambient temperature while the regeneration step (dissolution) occurs by pressure letdown and indirect stripping with LP 0.45 MPa (65 psia) steam. It is generally accepted that physical solvents become increasingly economical, and eventually superior to amine capture, as the partial pressure of acid gas in the syngas increases.

The physical solvents are regenerated by multistage flashing to LPs. Because the solubility of acid gases increases as the temperature decreases, absorption is generally carried out at lower temperatures, and refrigeration is often required.

Most physical solvents are capable of removing organic sulfur compounds. Exhibiting higher solubility of H2S than CO2, they can be designed for selective H2S or total AGR. In applications where CO2 capture is desired the CO2 is flashed off at various pressures, which reduces the compression work and parasitic power load associated with sequestration.

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Cost and Performance Baseline for Fossil Energy Plants Physical solvents co-absorb heavy hydrocarbons from the feed stream. Since heavy hydrocarbons cannot be recovered by flash regeneration, they are stripped along with the acid gas during heated regeneration. These hydrocarbon losses result in a loss of valuable product and may lead to CO2 contamination.

Several physical solvents that use anhydrous organic solvents have been commercialized. They include the Selexol process, which uses dimethyl ether of polyethylene glycol as a solvent; Rectisol, with methanol as the solvent; Purisol, which uses N-methyl-2-pyrrolidone (NMP) as a solvent; and the propylene-carbonate process.

Exhibit 3-5 is a simplified flow diagram for a physical reagent type AGR process [50]. Common physical solvent processes, along with their licensors, are listed in Exhibit 3-6.

Exhibit 3-5 Physical Solvent AGR Process Simplified Flow Diagram Condenser Treated Gas Acid Gas Cooler Rich Solvent Absorber L/R Lean Exchanger Stripper Solvent Feed Gas Flash Reboiler Gas Lean Solvent Pump Hybrid Solvents Hybrid solvents combine the high treated-gas purity offered by chemical solvents with the flash regeneration and lower energy requirements of physical solvents. Some examples of hybrid solvents are Sulfinol, Flexsorb PS, and Ucarsol LE.

Sulfinol is a mixture of sulfolane (a physical solvent), diisopropanolamine (DIPA) or MDEA (chemical solvent), and water. DIPA is used when total AGR is specified, while MDEA provides for selective removal of H2S.

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Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-6 Common Physical Solvents Used in AGR Processes Solvent/Process Process Solvent Trade Name Licensors Dimethyl ether of poly-Selexol UOP ethylene glycol Linde AG and Methanol Rectisol Lurgi Methanol and toluene Rectisol II Linde AG Nmethyl pyrrolidone Purisol Lurgi Polyethylene glycol and Sepasolv MPE BASF dialkyl ethers Propylene carbonate Fluor Solvent Fluor Tetrahydrothiophenedioxide Sulfolane Shell Tributyl phosphate Estasolvan Uhde and IFP Flexsorb PS is a mixture of a hindered amine and an organic solvent. Physically similar to Sulfinol, Flexsorb PS is very stable and resistant to chemical degradation. High treated-gas purity, with less than 50 ppmv of CO2 and 4 ppmv of H2S, can be achieved. Both Ucarsol LE-701, for selective removal, and LE-702, for total AGR, are formulated to remove mercaptans from feed gas.

Mixed chemical and physical solvents combine the features of both systems. The mixed solvent allows the solution to absorb an appreciable amount of gas at HP. The amine portion is effective as a reagent to remove the acid gas to low levels when high purity is desired.

Mixed solvent processes generally operate at absorber temperatures similar to those of the amine-type chemical solvents and do not require refrigeration. They also retain some advantages of the lower steam requirements typical of the physical solvents. Common mixed chemical and physical solvent processes, along with their licensors, are listed in Exhibit 3-7. The key advantage of mixed solvent processes is their apparent ability to remove H2S and, in some cases, COS to meet very stringent purified gas specifications.

Exhibit 3-8 shows reported equilibrium solubility data for H2S and CO2 in various representative solvents [50]. The solubility is expressed as scf of gas per gallon liquid per atmosphere gas partial pressure.

The figure illustrates the relative solubilities of CO2 and H2S in different solvents and the effects of temperature. More importantly, it shows an order of magnitude higher solubility of H2S over CO2 at a given temperature, which gives rise to the selective absorption of H2S in physical solvents. It also illustrates that the acid gas solubility in physical solvents increases with lower solvent temperatures.

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Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-7 Common Mixed Solvents Used in AGR Processes Solvent/Chemical Solvent/Process Process Reagent Trade Name Licensors Methanol/MDEA or Amisol Lurgi diethylamine Sulfolane/MDEA or DIPA Sulfinol Shell Methanol and toluene Selefining Snamprogetti (Unspecified) /MDEA FLEXSORB PS Exxon Exhibit 3-8 Equilibrium Solubility Data on H2S and CO2 in Various Solvents 79

Cost and Performance Baseline for Fossil Energy Plants The ability of a process to selectively absorb H2S may be further enhanced by the relative absorption rates of H2S and CO2. Thus, some processes, besides using equilibrium solubility differences, will use absorption rate differences between the two acid gases to achieve selectivity. This is particularly true of the amine processes where the CO2 and H2S absorption rates are very different.

AGR used in CO2 Capture Cases A two-stage Selexol process is used for all IGCC CO2 capture cases in this study. A brief process description follows.

Untreated syngas enters the first of two absorbers where H2S is preferentially removed using loaded solvent from the CO2 absorber. The gas exiting the H2S absorber passes through the second absorber where CO2 is removed using first flash regenerated, chilled solvent followed by thermally regenerated solvent added near the top of the column. The treated gas exits the absorber and is sent either directly to the CT or is partially humidified prior to entering the CT.

A portion of the gas can also be used for coal drying, when required.

The amount of hydrogen recovered from the syngas stream is dependent on the Selexol process design conditions. In this study, hydrogen recovery is 99.4 percent. The minimal hydrogen slip to the CO2 sequestration stream maximizes the overall plant efficiency. The Selexol plant cost estimates are based on a plant designed to recover this high percentage of hydrogen.

The CO2 loaded solvent exits the CO2 absorber, and a portion is sent to the H2S absorber, a portion is sent to a reabsorber and the remainder is sent to a series of flash drums for regeneration. The CO2 product stream is obtained from the three flash drums, and after flash regeneration the solvent is chilled and returned to the CO2 absorber.

The rich solvent exiting the H2S absorber is combined with the rich solvent from the reabsorber and the combined stream is heated using the lean solvent from the stripper. The hot, rich solvent enters the H2S concentrator and partially flashes. The remaining liquid contacts nitrogen from the ASU and a portion of the CO2 along with lesser amounts of H2S and COS are stripped from the rich solvent. The stripped gases from the H2S concentrator are sent to the reabsorber where the H2S and COS that were co-stripped in the concentrator are transferred to a stream of loaded solvent from the CO2 absorber. The clean gas from the reabsorber is combined with the clean gas from the H2S absorber and sent to the CT.

The solvent exiting the H2S concentrator is sent to the stripper where the absorbed gases are liberated by hot gases flowing up the column from the steam heated reboiler. Water in the overhead vapor from the stripper is condensed and returned as reflux to the stripper or exported as necessary to maintain the proper water content of the lean solvent. The acid gas from the stripper is sent to the Claus plant for further processing. The lean solvent exiting the stripper is first cooled by providing heat to the rich solvent, then further cooled by exchange with the product gas and finally chilled in the lean chiller before returning to the top of the CO2 absorber.

AGR/Gasifier Pairings There are numerous commercial AGR processes that could meet the sulfur environmental target of this study. The most frequently used AGR systems (Selexol, Sulfinol, MDEA, and Rectisol) have all been used with the Shell and GEE gasifiers in various applications. Both existing E-Gas gasifiers use MDEA, but could in theory use any of the existing AGR technologies [50]. The following selections were made for the AGR process in non-CO2 capture cases:

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Cost and Performance Baseline for Fossil Energy Plants

GEE gasifier: Selexol was chosen based on the GE gasifier operating at the highest pressure (815 psia versus 615 psia for CoP and Shell), which favors the physical solvent used in the Selexol process.

CoP gasifier: Refrigerated MDEA was chosen because the two operating E-Gas gasifiers use MDEA and because CoP lists MDEA as the selected AGR process on their website

[51]. Refrigerated MDEA was chosen over conventional MDEA because the sulfur emissions environmental target chosen is just outside of the range of conventional (higher temperature) MDEA.

Shell gasifier: The Sulfinol process was chosen for this case because it is a Shell owned technology. While the Shell gasifier can and has been used with other AGR processes, it was concluded the most likely pairing would be with the Sulfinol process.

The two-stage Selexol process is used in all three cases that require CO2 capture. According to the previously referenced SFA Pacific report, For future IGCC with CO2 removal for sequestration, a two-stage Selexol process presently appears to be the preferred AGR process -

as indicated by ongoing engineering studies at EPRI and various engineering firms with IGCC interests.[52]

3.1.6 Sulfur Recovery/Tail Gas Cleanup Process Selection Currently, most of the worlds sulfur is produced from the acid gases coming from gas treating.

The Claus process remains the mainstay for sulfur recovery. Conventional three-stage Claus plants, with indirect reheat and feeds with a high H2S content, can approach 98 percent sulfur recovery efficiency. However, since environmental regulations have become more stringent, sulfur recovery plants are required to recover sulfur with over 99.8 percent efficiency. To meet these stricter regulations, the Claus process underwent various modifications and add-ons.

The add-on modification to the Claus plant selected for this study can be considered a separate option from the Claus process. In this context, it is often called a tail gas treating unit (TGTU) process.

The Claus Process The Claus process converts H2S to elemental sulfur via the following reactions:

H2S + 3/2 O2 H2O + SO2 2H2S + SO2 2H2O + 3S The second reaction, the Claus reaction, is equilibrium limited. The overall reaction is:

3H2S + 3/2 O2 3H2O + 3S The sulfur in the vapor phase exists as S2, S6, and S8 molecular species, with the S2 predominant at higher temperatures, and S8 predominant at lower temperatures.

A simplified process flow diagram of a typical three-stage Claus plant is shown in Exhibit 3-9

[52]. One-third of the H2S is burned in the furnace with oxygen from the air to give sufficient SO2 to react with the remaining H2S. Since these reactions are highly exothermic, a waste heat boiler that recovers this heat to generate HP steam usually follows the furnace. Sulfur is condensed in a condenser that follows the HP steam recovery section. LP steam is raised in the condenser. The tail gas from the first condenser then goes to several catalytic conversion stages, 81

Cost and Performance Baseline for Fossil Energy Plants usually 2 to 3, where the remaining sulfur is recovered via the Claus reaction. Each catalytic stage consists of gas preheat, a catalytic reactor, and a sulfur condenser. The liquid sulfur goes to the sulfur pit, while the tail gas proceeds to the incinerator or for further processing in a TGTU.

Claus Plant Sulfur Recovery Efficiency The Claus reaction is equilibrium limited, and sulfur conversion is sensitive to the reaction temperature. The highest sulfur conversion in the thermal zone is limited to about 75 percent.

Typical furnace temperatures are in the range from 1093 to 1427°C (2000 to 2600°F), and as the temperature decreases, conversion increases dramatically.

Exhibit 3-9 Typical Three-Stage Claus Sulfur Plant Claus plant sulfur recovery efficiency depends on many factors:

H2S concentration of the feed gas

Number of catalytic stages

Gas reheat method In order to keep Claus plant recovery efficiencies approaching 94 to 96 percent for feed gases that contain about 20 to 50 percent H2S, a split-flow design is often used. In this version of the Claus plant, part of the feed gas is bypassed around the furnace to the first catalytic stage, while the rest of the gas is oxidized in the furnace to mostly SO2. This results in a more stable temperature in the furnace.

Oxygen-Blown Claus Large diluent streams in the feed to the Claus plant, such as N2 from combustion air, or a high CO2 content in the feed gas, lead to higher cost Claus processes and any add-on or tail gas units.

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Cost and Performance Baseline for Fossil Energy Plants One way to reduce diluent flows through the Claus plant and to obtain stable temperatures in the furnace for dilute H2S streams is the oxygen-blown Claus process.

The oxygen-blown Claus process was originally developed to increase capacity at existing conventional Claus plants and to increase flame temperatures of low H2S content gases. The process has also been used to provide the capacity and operating flexibility for sulfur plants where the feed gas is variable in flow and composition such as often found in refineries. The application of the process has now been extended to grass roots installations, even for rich H2S feed streams, to provide operating flexibility at lower costs than would be the case for conventional Claus units. At least four of the recently built gasification plants in Europe use oxygen enriched Claus units.

Oxygen enrichment results in higher temperatures in the front-end furnace, potentially reaching temperatures as high as 1593 to 1649°C (2900 to 3000°F) as the enrichment moves beyond 40 to 70 vol% O2 in the oxidant feed stream. Although oxygen enrichment has many benefits, its primary benefit for lean H2S feeds is a stable furnace temperature. Sulfur recovery is not significantly enhanced by oxygen enrichment. Because the IGCC process already requires an ASU, the oxygen-blown Claus plant was chosen for all cases.

Tail Gas Treating In many refinery and other conventional Claus applications, tail gas treating involves the removal of the remaining sulfur compounds from gases exiting the SRU. Tail gas from a typical Claus process, whether a conventional Claus or one of the extended versions of the process, usually contains small but varying quantities of COS, CS2, H2S, SO2, and elemental sulfur vapors. In addition, there may be H2, CO, and CO2 in the tail gas. In order to remove the rest of the sulfur compounds from the tail gas, all of the sulfur-bearing species must first be converted to H2S. Then, the resulting H2S is absorbed into a solvent and the clean gas vented or recycled for further processing. The clean gas resulting from the hydrolysis step can undergo further cleanup in a dedicated absorption unit or be integrated with an upstream AGR unit. The latter option is particularly suitable with physical absorption solvents. The approach of treating the tail gas in a dedicated amine absorption unit and recycling the resulting acid gas to the Claus plant is the one used by the Shell Claus Off-gas Treating (SCOT) process. With tail gas treatment, Claus plants can achieve overall removal efficiencies in excess of 99.9 percent.

In the case of IGCC applications, the tail gas from the Claus plant can be catalytically hydrogenated and then recycled back into the system with the choice of location being technology dependent, or it can be treated with a SCOT-type process. In the each of the six IGCC cases the Claus plant tail gas is hydrogenated, water is separated, the tail gas is compressed and then returned to the AGR process for further treatment.

Flare Stack A self-supporting, refractory-lined, carbon steel (CS) flare stack is typically provided to combust and dispose of unreacted gas during startup, shutdown, and upset conditions. However, in all six IGCC cases a flare stack was provided for syngas dumping during startup, shutdown, etc. This flare stack eliminates the need for a separate Claus plant flare.

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Cost and Performance Baseline for Fossil Energy Plants 3.1.7 Slag Handling The slag handling system conveys, stores, and disposes of slag removed from the gasification process. Spent material drains from the gasifier bed into a water bath in the bottom of the gasifier vessel. A slag crusher receives slag from the water bath and grinds the material into pea-sized fragments. A slag/water slurry that is between 5 and 10 percent solids leaves the gasifier pressure boundary through either a proprietary pressure letdown device (CoP) or through the use of lockhoppers (GEE and Shell) to a series of dewatering bins.

The general aspects of slag handling are the same for all three technologies. The slag is dewatered, the water is clarified and recycled and the dried slag is transferred to a storage area for disposal. The specifics of slag handling vary among the gasification technologies regarding how the water is separated and the end uses of the water recycle streams.

In this study the slag bins were sized for a nominal holdup capacity of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months of full-load operation. At periodic intervals, a convoy of slag-hauling trucks will transit the unloading station underneath the hopper and remove a quantity of slag for disposal. Approximately ten truckloads per day are required to remove the total quantity of slag produced by the plant operating at nominal rated power. While the slag is suitable for use as a component of road paving mixtures, it was assumed in this study that the slag would be landfilled at a specified cost just as the ash from the PC boiler cases is assumed to be landfilled at the same per ton cost.

3.1.8 Power Island Combustion Turbine The GT generator selected for this application is representative of the advanced F Class turbines.

This machine is an axial flow, single spool, and constant speed unit, with variable inlet guide vane (IGV). The turbine includes advanced bucket cooling techniques, compressor aerodynamic design and advanced alloys, enabling a higher firing temperature than the previous generation machines. The standard production version of this machine is fired with natural gas and is also commercially offered for use with IGCC derived syngas, although only earlier versions of the turbine are currently operating on syngas. For the purposes of this study, it was assumed that the advanced F Class turbine will be commercially available for use on both conventional and high hydrogen content syngas representative of the cases with CO2 capture. High H2 fuel combustion issues like flame stability, flashback, and NOx formation were assumed to be solved in the time frame needed to support deployment. However, because these are FOAK applications, process contingencies were included in the cost estimates as described in Section 2.7. Performance typical of an advanced F class turbine on natural gas at ISO conditions is presented in Exhibit 3-10.

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Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-10 Advanced F Class Combustion Turbine Performance Characteristics Using Natural Gas Advanced F Class Firing Temperature Class, °C (°F) 1371+ (2500+)

Airflow, kg/s (lb/s) 431 (950)

Pressure Ratio 18.5 NOx Emissions, ppmv 25 Simple Cycle Output, MW 185 Combined cycle performance Net Output, MW 280 Net Efficiency (LHV), % 57.5 Net Heat Rate (LHV), kJ/kWh 6,256 (5,934)

(Btu/kWh)

In this service, with syngas from an IGCC plant, the machine requires some modifications to the burner and turbine nozzles in order to properly combust the low-Btu gas and expand the combustion products in the turbine section of the machine.

The modifications to the machine include some redesign of the original can-annular combustors.

A second modification involves increasing the nozzle areas of the turbine to accommodate the mass and volume flow of low-Btu fuel gas combustion products, which are increased relative to those produced when firing natural gas. Other modifications include rearranging the various auxiliary skids that support the machine to accommodate the spatial requirements of the plant general arrangement. The generator is a standard hydrogen-cooled machine with static exciter.

Combustion Turbine Package Scope of Supply The CT is typically supplied in several fully shop-fabricated modules, complete with all mechanical, electrical, and control systems as required for CT operation. Site CT installation involves module inter-connection, and linking CT modules to the plant systems.

CT Firing Temperature Control Issue for Low Calorific Value Fuel A GT when fired on LCV syngas has the potential to increase power output due to the increase in flow rate through the turbine. The higher turbine flow and moisture content of the combustion products can contribute to overheating of turbine components, affect rating criteria for the parts lives, and require a reduction in syngas firing temperatures (compared to the natural gas firing) to maintain design metal temperature [ 53]. Uncontrolled syngas firing temperature could result in more than 50 percent life cycle reduction of stage 1 buckets. Control systems for syngas applications include provisions to compensate for these effects by maintaining virtually constant generation output for the range of the specified ambient conditions. IGVs and firing temperature are used to maintain the turbine output at the maximum torque rating, producing a flat rating up to the IGV full open position. Beyond the IGV full open position, flat output may be extended to higher ambient air temperatures by steam/nitrogen injection.

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Cost and Performance Baseline for Fossil Energy Plants In this study the firing temperature (defined as inlet rotor temperature) using natural gas in NGCC applications is 1371°C (2500°F) while the firing temperature in the non-capture IGCC cases is 1333-1343°C (2432-2449°F) and in the CO2 capture cases is 1317-1322°C (2402-2412°F). The further reduction in firing temperature in the CO2 capture cases is done to maintain parts life as the H2O content of the combustion products increases from 6-9 vol% in the non-capture cases to 12-14 vol% in the capture cases. The decrease in temperature also results in the lower temperature steam cycle in the CO2 capture cases, ranging from 12.4 MPa/534°C/534°C (1800 psig/993°F/993°F) to 12.4 MPa/534°C/534°C (1800 psig/994°F/994°F) for all of the CO2 capture cases versus 12.4 MPa/559°C/559°C (1800 psig/1038°F/1038°F) to 12.4 MPa/562°C/562°C (1800 psig/1043°F/1043°F) for all of the non-CO2 capture cases.

Combustion Turbine Syngas Fuel Requirements Typical fuel specifications and contaminant levels for successful CT operation are provided in reference [ 54] and presented for F Class machines in Exhibit 3-11 and Exhibit 3-12. The vast majority of published CT performance information is specific to natural gas operation. Turbine performance using syngas requires vendor input as was obtained for this study.

Exhibit 3-11 Typical Fuel Specification for F-Class Machines Max Min LHV, kJ/m3 (Btu/scf) None 3.0 (100)

Gas Fuel Pressure, MPa (psia) 3.1 (450)

Varies with gas Gas Fuel Temperature, °C (°F) (1) pressure (2)

Flammability Limit Ratio, Rich-to-Lean, (3) 2:2.1 Volume Basis Sulfur (4)

Notes:

1. The maximum fuel temperature is defined in reference [55]

2. To ensure that the fuel gas supply to the GT is 100 percent free of liquids the minimum fuel gas temperature must meet the required superheat over the respective dew point. This requirement is independent of the hydrocarbon and moisture concentration. Superheat calculation shall be performed as described in GEI-4140G [54].

3. Maximum flammability ratio limit is not defined. Fuel with flammability ratio significantly larger than those of natural gas may require start-up fuel

4. The quantity of sulfur in syngas is not limited by specification. Experience has shown that fuel sulfur levels up to one percent by volume do not significantly affect oxidation/corrosion rates.

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Cost and Performance Baseline for Fossil Energy Plants Normal Operation Inlet air is compressed in a single spool compressor to a pressure ratio of approximately 16:1.

This pressure ratio was vendor specified and less than the 18.5:1 ratio used in natural gas applications. The majority of compressor discharge air remains on-board the machine and passes to the burner section to support combustion of the syngas. Compressed air is also used in burner, transition, and film cooling services. About 4-7 percent of the compressor air is extracted and integrated with the air supply of the ASU in non-carbon capture cases. It may be technically possible to integrate the CT and ASU in CO2 capture cases as well; however, in this study integration was considered only for non-carbon capture cases.

Exhibit 3-12 Allowable Gas Fuel Contaminant Level for F-Class Machines Fuel Limit, ppmw Turbine Inlet Limit, Turbine Inlet Flow/Fuel Flow ppbw 50 12 4 Lead 20 1.0 0.240 .080 Vanadium 10 0.5 0.120 0.040 Calcium 40 2.0 0.480 0.160 Magnesium 40 2.0 0.480 0.160 Sodium + Potassium Na/K = 28 (1) 20 1.0 0.240 0.080 Na/K = 3 10 0.5 0.120 0.40 Na/K 1 6 0.3 0.072 0.024 Particulates Total (2) 600 30 7.2 2.4 Above 10 microns 6 0.3 0.072 0.024 Notes:

1. Na/K=28 is nominal sea salt ratio

2. The fuel gas delivery system shall be designed to prevent generation or admittance of solid particulate to the GT gas fuel system Pressurized syngas is combusted in several (14) parallel diffusion combustors and syngas dilution is used to limit NOx formation. As described in Section 3.1.2 nitrogen from the ASU is used as the primary diluent followed by syngas humidification and finally by steam dilution, if necessary, to achieve an LHV of 4.4-4.7 MJ/Nm3 (119-125 Btu/scf). The advantages of using nitrogen as the primary diluent include:

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Cost and Performance Baseline for Fossil Energy Plants

Nitrogen from the ASU is already partially compressed and using it for dilution eliminates wasting the compression energy.

Limiting the water content reduces the need to de-rate firing temperature, particularly in the high-hydrogen (CO2 capture) cases.

There are some disadvantages to using nitrogen as the primary diluent, and these include:

There is a significant auxiliary power requirement to further compress the large nitrogen flow from the ASU pressures of 0.4 and 1.3 MPa (56 and 182 psia) to the CT pressure of 3.2 MPa (465 psia).

Low quality heat not otherwise useful for other applications can be used to preheat water for the syngas humidification process.

Nitrogen is not as efficient as water in limiting NOx emissions It is not clear that one dilution method provides a significant advantage over the other. However, in this study nitrogen was chosen as the primary diluent based on suggestions by turbine industry experts during peer review of the report.

Hot combustion products are expanded in the three-stage turbine-expander. Given the assumed ambient conditions, back-end loss, and HRSG pressure drop, the CT exhaust temperature is nominally 588°C (1090°F) for non-CO2 capture cases and 562°C (1044°F) for capture cases.

Gross turbine power, as measured prior to the generator terminals, is 232 MW. The CT generator is a standard hydrogen-cooled machine with static exciter.

3.1.9 Steam Generation Island Heat Recovery Steam Generator The HRSG is a horizontal gas flow, drum-type, multi-pressure design that is matched to the characteristics of the GT exhaust gas when firing medium-Btu gas. High-temperature FG exiting the CT is conveyed through the HRSG to recover the large quantity of thermal energy that remains. Flue gas (FG) travels through the HRSG gas path and exits at 132°C (270°F) for all six IGCC cases.

The HP drum produces steam at main steam pressure, while the IP drum produces process steam and turbine dilution steam, if required. The HRSG drum pressures are nominally 12.4/3.1 MPa (1800/443 psia) for the HP/IP turbine sections, respectively. In addition to generating and superheating steam, the HRSG performs reheat duty for the cold/hot reheat steam for the steam turbine, provides condensate and feedwater (FW) heating, and also provides deaeration of the condensate.

Natural circulation of steam is accomplished in the HRSG by utilizing differences in densities due to temperature differences of the steam. The natural circulation HRSG provides the most cost-effective and reliable design.

The HRSG drums include moisture separators, internal baffles, and piping for FW/steam. All tubes, including economizers, superheaters, and headers and drums, are equipped with drains.

Safety relief valves are furnished in order to comply with appropriate codes and ensure a safe work place.

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Cost and Performance Baseline for Fossil Energy Plants Superheater, boiler, and economizer sections are supported by shop-assembled structural steel.

Inlet and outlet duct is provided to route the gases from the GT outlet to the HRSG inlet and the HRSG outlet to the stack. A diverter valve is included in the inlet duct to bypass the gas when appropriate. Suitable expansion joints are also included.

Steam Turbine Generator and Auxiliaries The steam turbine consists of an HP section, an IP section, and one double-flow LP section, all connected to the generator by a common shaft. The HP and IP sections are contained in a single-span, opposed-flow casing, with the double-flow LP section in a separate casing. The LP turbine has a last stage bucket length of 76 cm (30 in).

Main steam from the HRSG and gasifier island is combined in a header, and then passes through the stop valves and control valves and enters the turbine at either 12.4 MPa/559°C to 562°C (1800 psig/1038°F to 1043°F) for the non-carbon capture cases, or 12.4 MPa/534°C (1800 psig/993°F to 994°F) for the carbon capture cases. The steam initially enters the turbine near the middle of the HP span, flows through the turbine, and returns to the HRSG for reheating. The reheat steam flows through the reheat stop valves and intercept valves and enters the IP section at 3.1 MPa/558°C to 561°C (443 psig/1036°F to 1041°F) for the non-carbon capture cases or 3.1 MPa/532°C to 533°C (443 psig/990°F to 992°F) for the carbon capture cases. After passing through the IP section, the steam enters a crossover pipe, which transports the steam to the LP section. The steam divides into two paths and flows through the LP sections, exhausting downward into the condenser.

Turbine bearings are lubricated by a closed-loop (CL), water-cooled, pressurized oil system. The oil is contained in a reservoir located below the turbine floor. During startup or unit trip an emergency oil pump mounted on the reservoir pumps the oil. When the turbine reaches 95 percent of synchronous speed, the main pump mounted on the turbine shaft pumps oil. The oil flows through water-cooled heat exchangers prior to entering the bearings. The oil then flows through the bearings and returns by gravity to the lube oil reservoir.

Turbine shafts are sealed against air in-leakage or steam blowout using a modern positive pressure variable clearance shaft sealing design arrangement connected to a LP steam seal system. During startup, seal steam is provided from the main steam line. As the unit increases load, HP turbine gland leakage provides the seal steam. Pressure-regulating valves control the gland header pressure and dump any excess steam to the condenser. A steam packing exhauster maintains a vacuum at the outer gland seals to prevent leakage of steam into the turbine room.

Any steam collected is condensed in the packing exhauster and returned to the condensate system.

The generator is a hydrogen-cooled synchronous type, generating power at 24 kV. A static, transformer type exciter is provided. The generator is cooled with a hydrogen gas recirculation system using fans mounted on the generator rotor shaft. The heat absorbed by the gas is removed as it passes over finned tube gas coolers mounted in the stator frame. Gas is prevented from escaping at the rotor shafts by a CL oil seal system. The oil seal system consists of storage tank, pumps, filters, and pressure controls, all skid-mounted.

The STG is controlled by a triple-redundant, microprocessor-based electro-hydraulic control system. The system provides digital control of the unit in accordance with programmed control 89

Cost and Performance Baseline for Fossil Energy Plants algorithms, color cathode ray tube (CRT) operator interfacing, and datalink interfaces to the balance-of-plant DCS, and incorporates on-line repair capability.

Condensate System The condensate system transfers condensate from the condenser hotwell to the deaerator, through the gland steam condenser, gasifier, and the low-temperature economizer section in the HRSG.

The system consists of one main condenser; two 50 percent capacity, motor-driven, vertical condensate pumps; one gland steam condenser; and a low-temperature tube bundle in the HRSG.

Condensate is delivered to a common discharge header through 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.

Feedwater System The function of the FW system is to pump the various FW streams from the deaerator storage tank in the HRSG to the respective steam drums. Two 50 percent capacity boiler feed pumps are provided for each of three pressure levels, HP, IP, and LP. Each pump is provided with inlet and outlet isolation valves, and outlet check valve. Minimum flow recirculation to prevent overheating and cavitation of the pumps during startup and low loads is provided by an automatic recirculation valve and associated piping that discharges back to the deaerator storage tank. Pneumatic flow control valves control the recirculation flow.

The FW pumps are supplied with instrumentation to monitor and alarm on low oil pressure, or high bearing temperature. FW pump suction pressure and temperature are also monitored. In addition, the suction of each boiler feed pump is equipped with a startup strainer.

Main and Reheat Steam Systems The function of the main steam system is to convey main steam generated in the synthesis gas cooler (SGC) and HRSG from the HRSG superheater outlet to the HP turbine stop valves. The function of the reheat system is to convey steam from the HP turbine exhaust to the HRSG RH, and to the turbine reheat stop valves.

Main steam at approximately 12.4 MPa/559°C to 562°C (1800 psig/1038°F to 1043°F) (non-CO2 capture cases) or 12.4 MPa/534°C (1800 psig/993°F to 994°F) (CO2 capture cases) exits the HRSG superheater through a motor-operated stop/check valve and a motor-operated gate valve, and is routed to the HP turbine. Cold reheat steam at approximately 3.5 MPa/349°C to 372°C (501 psia/661°F to 702°F) exits the HP turbine, flows through a motor-operated isolation gate valve, to the HRSG reheater. Hot reheat steam at approximately 3.1 MPa/558 to 561°C (443 psig/1036°F to 1041°F) for the non-carbon capture cases and 3.1 MPa/532°C to 533°C (443 psig/990°F to 992°F) for the CO2 capture cases exits the HRSG RH through a motor-operated gate valve and is routed to the IP turbines.

Steam piping is sloped from the HRSG to the drip pots located near the steam turbine for removal of condensate from the steam lines. Condensate collected in the drip pots and in low-point drains is discharged to the condenser through the drain system.

Steam flow is measured by means of flow nozzles in the steam piping. The flow nozzles are located upstream of any branch connections on the main headers.

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Cost and Performance Baseline for Fossil Energy Plants Safety valves are installed to comply with appropriate codes and to ensure the safety of personnel and equipment.

Circulating Water System The circulating water system (CWS) is a closed-cycle cooling water system that supplies cooling water to the condenser to condense the main turbine exhaust steam. The system also supplies cooling water to the AGR plant as required, and to the auxiliary cooling system. The auxiliary cooling system is a CL process that utilizes a higher quality water to remove heat from compressor intercoolers, oil coolers and other ancillary equipment and transfers that heat to the main circulating cooling water system in plate and frame heat exchangers. The heat transferred to the circulating water in the condenser and other applications is removed by a mechanical draft cooling tower.

The system consists of two 50 percent capacity vertical CWPs, a mechanical draft evaporative cooling tower, and CS cement-lined interconnecting piping. The pumps are single-stage vertical pumps. The piping system is equipped with butterfly isolation valves and all required expansion joints. The cooling tower is a multi-cell wood frame counterflow mechanical draft cooling tower.

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 the condenser can be removed from service for cleaning or for plugging tubes. This can be done during normal operation at reduced load.

The condenser is equipped with an air extraction system to evacuate the condenser steam space for removal of non-condensable gases during steam turbine operation and to rapidly reduce the condenser pressure from atmospheric pressure before unit startup and admission of steam to the condenser.

Raw Water, Fire Protection, and Cycle Makeup Water Systems The raw water system supplies cooling tower makeup, cycle makeup, service water and potable water requirements. The water source is 50 percent from a POTW and 50 percent from groundwater. Booster pumps within the plant boundary provide the necessary pressure.

The fire protection system provides water under pressure to the fire hydrants, hose stations, and fixed water suppression system within the buildings and structures. The system consists of pumps, underground and aboveground supply piping, distribution piping, hydrants, hose stations, spray systems, and deluge spray systems. One motor-operated booster pump is supplied on the intake structure of the cooling tower with a diesel engine backup pump installed on the water inlet line.

The cycle makeup water system provides high quality demineralized water for makeup to the HRSG cycle, for steam injection ahead of the WGS reactors in CO2 capture cases, and for injection steam to the auxiliary boiler for control of NOx emissions, if required.

The cycle makeup system consists of two 100 percent trains, each with a full-capacity activated carbon filter, primary cation exchanger, primary anion exchanger, mixed bed exchanger, recycle pump, and regeneration equipment. The equipment is skid-mounted and includes a control panel and associated piping, valves, and instrumentation.

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Cost and Performance Baseline for Fossil Energy Plants 3.1.10 Accessory Electric Plant The accessory electric plant consists of switchgear and control equipment, generator equipment, station service equipment, conduit and cable trays, and wire and cable. It also includes the main power transformer, all required foundations, and standby equipment.

3.1.11 Instrumentation and Control An integrated plant-wide distributed control system (DCS) is provided. The DCS is a redundant microprocessor-based, functionally DCS. 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 be operational and accessible 99.5 percent of the time it is required (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 manually implemented, with operator selection of modular automation routines available. The exception to this, and an important facet of the control system for gasification, is the critical controller system, which is a part of the license package from the gasifier supplier and is a dedicated and distinct hardware segment of the DCS.

This critical controller system is used to control the gasification process. The partial oxidation of the fuel feed and oxygen feed streams to form a syngas product is a stoichiometric, temperature-and pressure-dependent reaction. The critical controller utilizes a redundant microprocessor executing calculations and dynamic controls at 100- to 200-millisecond intervals. The enhanced execution speeds as well as evolved predictive controls allow the critical controller to mitigate process upsets and maintain the reactor operation within a stable set of operating parameters.

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Cost and Performance Baseline for Fossil Energy Plants 3.2 GENERAL ELECTRIC ENERGY IGCC CASES This section contains an evaluation of plant designs for Cases 1 and 2, which are based on the GEE gasifier in the radiant only configuration. GEE offers three design configurations:[56]

Quench: In this configuration, the hot syngas exiting the gasifier passes through a pool of water to quench the temperature to 289°C (550°F) before entering the syngas scrubber. It is the simplest and lowest capital cost design, but also the least efficient. This configuration is examined in Section 8.

Radiant Only: In this configuration, the hot syngas exiting the gasifier passes through a radiant syngas cooler where it is cooled from about 1316°C (2400°F) to 677°C (1250°F),

then through a water quench where the syngas is further cooled to about 232°C (450°F) prior to entering the syngas scrubber. Relative to the quench configuration, the radiant only design offers increased output, higher efficiency, improved reliability/availability, and results in the lowest COE. This configuration was chosen by GEE and Bechtel for the design of their reference plant.

Radiant-Convective: In this configuration, the hot syngas exiting the gasifier passes through a radiant syngas cooler where it is cooled from about 1316°C (2400°F) to 760°C (1400°F), then passes over a pool of water where particulate is removed but the syngas is not quenched, then through a convective syngas cooler where the syngas is further cooled to about 371°C (700°F) prior to entering additional heat exchangers or the scrubber. This configuration has the highest overall efficiency, but at the expense of highest capital cost and the lowest availability. This is the configuration used at Tampa Electrics Polk Power Station.

Note that the radiant only configuration includes a water quench and, based on functionality, would be more appropriately named radiant-quench. The term radiant only is used to distinguish it from the radiant-convective configuration. Since radiant only is the terminology used by GEE, it will be used throughout this report.

The balance of Section 3.2 is organized as follows:

Gasifier Background provides information on the development and status of the GEE gasification technology.

Process and System Description provides an overview of the technology operation as applied to Case 1. The systems that are common to all gasifiers were covered in Section 3.1 and only features that are unique to Case 1 are discussed further in this section.

Key Assumptions is a summary of study and modeling assumptions relevant to Cases 1 and 2.

Sparing Philosophy is provided for both Cases 1 and 2.

Performance Results provides the main modeling results from Case 1, including the performance summary, environmental performance, carbon balance, sulfur balance, water balance, mass and energy balance diagrams, and mass and energy balance tables.

Equipment List provides an itemized list of major equipment for Case 1 with account codes that correspond to the cost accounts in the Cost Estimates section.

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Cost Estimates provides a summary of capital and operating costs for Case 1.

Process and System Description, Performance Results, Equipment List and Cost Estimates are repeated for Case 2.

3.2.1 Gasifier Background Development and Current Status[ 57] - Initial development of the GEE gasification technology (formerly licensed by Texaco and then ChevronTexaco) was conducted in the 1940s at Texacos Montebello, California laboratories. From 1946 to 1954 the Montebello pilot plant produced syngas (hydrogen and carbon monoxide) by partial oxidation of a variety of feedstocks, including natural gas, oil, asphalt, coal tar, and coal. From 1956 to 1958, coal was gasified in a 91 tonne/day (100 TPD) Texaco coal gasifier at the Olin Mathieson Chemical Plant in Morgantown, West Virginia, for the production of ammonia.

The oil price increases and supply disruptions of the 1970s renewed interest in the Texaco partial-oxidation process for gasification of coal or other solid opportunity fuels. Three 14 tonne/day (15 TPD) pilot plants at the Montebello laboratories have been used to test numerous coals. Two larger pilot plants were also built. The first gasified 150 tonne/day (165 TPD) of coal and was built to test syngas generation by Rührchemie and Rührkohle at Oberhausen, Germany, and included a SGC. The second gasified 172 tonne/day (190 TPD) of coal using a quench-only gasifier cooler and was built to make hydrogen at an existing TVA ammonia plant at Muscle Shoals, Alabama. These two large-scale pilot plants successfully operated for several years during the 1980s and tested a number of process variables and numerous coals.

The first commercial Texaco coal gasification plant was built for Tennessee Eastman at Kingsport, Tennessee, and started up in 1983. To date, 24 gasifiers have been built in 12 plants for coal and petroleum coke. Several of the plants require a hydrogen-rich gas and therefore directly water quench the raw gas to add the water for shifting the CO to H2, and have no SGCs.

The Cool Water plant was the first commercial-scale Texaco coal gasification project for the electric utility industry. This facility gasified 907 tonne/day (1,000 TPD) (dry basis) of bituminous coal and generated 120 MW of electricity by IGCC operation. In addition, the plant was the first commercial-sized Texaco gasifier used with a SGC. The Cool Water plant operated from 1984 to 1989 and was a success in terms of operability, availability, and environmental performance.

The Tampa Electric IGCC Clean Coal Technology Demonstration Project built on the Cool Water experience to demonstrate the use of the Texaco coal gasification process in an IGCC plant. The plant utilizes approximately 2,268 tonne/day (2,500 TPD) of coal in a single Texaco gasifier to generate a net of approximately 250 megawatts electric (MWe). The syngas is cooled in a high-temperature radiant heat exchanger, generating HP steam, and further cooled in convective heat exchangers (the radiant-convective configuration). The particles in the cooled gas are removed in a water-based scrubber. The cleaned gas then enters a hydrolysis reactor where COS is converted to H2S. After additional cooling, the syngas is sent to a conventional AGR unit, where H2S is absorbed by reaction with an amine solvent. H2S is removed from the amine by steam stripping and sent to a sulfuric acid (H2SO4) plant. The cleaned gas is sent to a General Electric MS 7001FA CT.

94

Cost and Performance Baseline for Fossil Energy Plants The Delaware Clean Energy Project is a coke gasification and CT repowering of an existing 130 MW coke-fired boiler cogeneration power plant at the Motiva oil refinery in Delaware City, Delaware. The Texaco coal gasification process was modified to gasify 1,814 tonne/day (2,000 TPD) of this low-quality petroleum coke. The plant is designed to use all the fluid petroleum coke generated at Motivas Delaware City Plant and produce a nominal 238,136 kg/hr (525,000 lb/hr) of 8.6 MPa (1250 psig) steam, and 120,656 kg/hr (266,000 lb/hr) of 1.2 MPa (175 psig) steam for export to the refinery and the use/sale of 120 MW of electrical power.

Environmentally, these new facilities help satisfy tighter NOx and SO2 emission limitations at the Delaware City Plant.

Gasifier Capacity - The largest GEE gasifier is the unit at Tampa Electric, which consists of the radiant-convective configuration. The daily coal-handling capacity of this unit is 2,268 tonnes (2,500 tons) of bituminous coal. The dry gas production rate is 0.19 million Nm3/hr (6.7 million scfh) with an energy content of about 1,897 million kJ/hr (HHV) (1,800 million Btu/hr). This size matches the F Class CTs that are used at Tampa.

Distinguishing Characteristics - A key advantage of the GEE coal gasification technology is the extensive operating experience at full commercial scale. Furthermore, Tampa Electric is an IGCC power generation facility, operated by conventional electric utility staff, and is environmentally one of the cleanest coal-fired power plants in the world. The GEE gasifier also operates at the highest pressure of the three gasifiers in this study, 5.6 MPa (815 psia) compared to 4.2 MPa (615 psia) for CoP and Shell.

Entrained-flow gasifiers have fundamental environmental advantages over fluidized-bed and moving-bed gasifiers. They produce no hydrocarbon liquids, and the only solid waste is an inert slag. The relatively high H2/CO ratio and CO2 content of GEE gasification fuel gas helps achieve low NOx and CO emissions in even the higher-temperature advanced CTs.

The key disadvantages of the GEE coal gasification technology are the limited refractory life, the relatively high oxygen requirements and high waste heat recovery duty (SGC design). As with the other entrained-flow slagging gasifiers, the GEE process has this disadvantage due to its high operating temperature. The disadvantage is magnified in the single-stage, slurry feed design.

The quench design significantly reduces the capital cost of syngas cooling, while innovative heat integration maintains good overall thermal efficiency although lower than the SGC design.

Another disadvantage of the GEE process is the limited ability to economically handle low-rank coals relative to moving-bed and fluidized-bed gasifiers or to entrained-flow gasifiers with dry feed. For slurry fed entrained gasifiers using low-rank coals, developers of two-stage slurry fed gasifiers claim advantages over single-stage slurry fed.

Important Coal Characteristics - The slurry feeding system and the recycle of process condensate water as the principal slurrying liquid make low levels of ash and soluble salts desirable coal characteristics for use in the GEE coal gasification process. High ash levels increase the ratio of water-to-carbon in the feed slurry, thereby increasing the oxygen requirements. The slurry feeding also favors the use of high-rank coals, such as bituminous coal, since their low inherent moisture content increases the moisture-free solids content of the slurry and thereby reduces oxygen requirements.

95

Cost and Performance Baseline for Fossil Energy Plants 3.2.2 Process Description In this section the overall GEE gasification process is described. The system description follows the block flow diagram (BFD) in Exhibit 3-13 and stream numbers reference the same exhibit.

The tables in Exhibit 3-14 provide stream compositions, temperature, pressure, enthalpy, and flow rates for the numbered streams in the BFD.

Coal Grinding and Slurry Preparation Coal receiving and handling is common to all cases and was covered in Section 3.1.1. The receiving and handling subsystem ends at the coal silo. Coal is then fed onto a conveyor by vibratory feeders located below each silo. The conveyor feeds the coal to an inclined conveyor that delivers the coal to the rod mill feed hopper. The feed hopper provides a surge capacity of about two hours and contains two hopper outlets. Each hopper outlet discharges onto a weigh feeder, which in turn feeds a rod mill. Each rod mill is sized to process 55 percent of the coal feed requirements of the gasifier. The rod mill grinds the coal and wets it with treated slurry water transferred from the slurry water tank by the slurry water pumps. The coal slurry is discharged through a trommel screen into the rod mill discharge tank, and then the slurry is pumped to the slurry storage tanks. The dry solids concentration of the final slurry is 63 percent.

The Polk Power Station operates at a slurry concentration of 62-68 percent using bituminous coal and CoP presented a paper showing the slurry concentration of Illinois No. 6 coal as 63 percent

[58].

The coal grinding system is equipped with a dust suppression system consisting of water sprays aided by a wetting agent. The degree of dust suppression required depends on local environmental regulations. All of the tanks are equipped with vertical agitators to keep the coal slurry solids suspended.

The equipment in the coal grinding and slurry preparation system is fabricated of materials appropriate for the abrasive environment present in the system. The tanks and agitators are rubber lined. The pumps are either rubber-lined or hardened metal to minimize erosion. Piping is fabricated of high-density polyethylene (HDPE).

Gasification This plant utilizes two gasification trains to process a total of 5,083 tonnes/day (5,603 TPD) of Illinois No. 6 coal. Each of the 2 x 50 percent gasifiers operates at maximum capacity. The largest operating GEE gasifier is the 2,268 tonne/day (2,500 TPD) unit at Polk Power Station.

However, that unit operates at about 2.8 MPa (400 psia). The gasifier in this study, which operates at 5.6 MPa (815 psia), will be able to process more coal and maintain the same gas residence time.

The slurry feed pump takes suction from the slurry run tank, and the discharge is sent to the feed injector of the GEE gasifier (stream 6). Oxygen from the ASU is vented during preparation for startup and is sent to the feed injector during normal operation. The air separation plant supplies 4,171 tonnes/day (4,597 TPD) of 95 mol% oxygen to the gasifiers (stream 5) and the Claus plant (stream 3). Carbon conversion in the gasifier is assumed to be 98 percent including a fines recycle stream.

96

Cost and Performance Baseline for Fossil Energy Plants The gasifier vessel is a refractory-lined, HP combustion chamber. The coal slurry feedstock and oxygen are fed through a fuel injector at the top of the gasifier vessel. The coal slurry and the oxygen react in the gasifier at 5.6 MPa (815 psia) and 1,316°C (2,400°F) to produce syngas.

The syngas consists primarily of hydrogen and carbon monoxide, with lesser amounts of water vapor and carbon dioxide, and small amounts of hydrogen sulfide, COS, methane, argon, and nitrogen. The heat in the gasifier liquefies coal ash. Hot syngas and molten solids from the reactor flow downward into a radiant heat exchanger where the syngas is cooled.

Raw Gas Cooling/Particulate Removal Syngas is cooled from 1,316°C (2,400°F) to 677°C (1,250°F) in the radiant SGC (stream 9) and the molten slag solidifies in the process. The solids collect in the water sump at the bottom of the gasifier and are removed periodically using a lock hopper system (stream 8). The waste heat from this cooling is used to generate HP steam. BFW in the tubes is saturated, and then steam and water are separated in a steam drum. Approximately 412,096 kg/hr (908,500 lb/hr) of saturated steam at 13.8 MPa (2,000 psia) is produced. This steam then forms part of the general heat recovery system that provides steam to the steam turbine.

The syngas exiting the radiant cooler is directed downwards by a dip tube into a water sump.

Most of the entrained solids are separated from the syngas at the bottom of the dip tube as the syngas goes upwards through the water. The syngas exits the quench chamber saturated at a temperature of 232°C (450°F).

The slag handling system removes solids from the gasification process equipment. These solids consist of a small amount of unconverted carbon and essentially all of the ash contained in the feed coal. These solids are in the form of glass, which fully encapsulates any metals. Solids collected in the water sump below the radiant SGC are removed by gravity and forced circulation of water from the lock hopper circulating pump. The fine solids not removed from the bottom of the quench water sump remain entrained in the water circulating through the quench chamber. In order to limit the amount of solids recycled to the quench chamber, a continuous blowdown stream is removed from the bottom of the syngas quench. The blowdown is sent to the vacuum flash drum in the black water flash section. The circulating quench water is pumped by circulating pumps to the quench gasifier.

Syngas Scrubber/Sour Water Stripper Syngas exiting the water quench passes to a syngas scrubber where a water wash is used to remove remaining chlorides, NH3, SO2, and PM. The syngas exits the scrubber still saturated at 206°C (403°F) before it is preheated to 223°C (433°F) (stream 10) prior to entering the COS hydrolysis reactor.

The sour water stripper removes NH3, SO2, and other impurities from the scrubber and other waste streams. The stripper consists of a sour drum that accumulates sour water from the gas scrubber and condensate from SGCs. Sour water from the drum flows to the sour stripper, which consists of a packed column with a steam-heated reboiler. Sour gas is stripped from the liquid and sent to the SRU. Remaining water is sent to wastewater treatment.

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Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-13 Case 1 Block Flow Diagram, GEE IGCC without CO2 Capture 98

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-14 Case 1 Stream Table, GEE IGCC without CO2 Capture 1 2 3 4 5 6 7 8 9 10 11 12 V-L Mole Fraction Ar 0.0092 0.0233 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0068 0.0099 CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0012 0.0009 0.0009 0.0013 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3579 0.2825 0.2825 0.4151 CO2 0.0003 0.0081 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1366 0.1078 0.1079 0.1586 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3416 0.2696 0.2696 0.3961 H2O 0.0099 0.2081 0.0000 0.0003 0.0000 0.0000 0.9994 0.0000 0.1358 0.3181 0.3180 0.0012 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0002 0.0000 H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0059 0.0085 N2 0.7732 0.5621 0.0178 0.9919 0.0178 0.0000 0.0000 0.0000 0.0080 0.0063 0.0063 0.0092 NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0021 0.0020 0.0020 0.0000 O2 0.2074 0.1985 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 V-L Flowrate (kgmol/hr) 21,872 1,067 102 19,380 5,298 0 4,829 0 22,212 28,142 28,142 19,153 V-L Flowrate (kg/hr) 631,164 28,941 3,290 543,810 170,485 0 87,000 0 446,032 552,597 552,597 390,595 Solids Flowrate (kg/hr) 0 0 0 0 0 211,783 0 23,236 0 0 0 0 Temperature (°C) 15 20 32 93 32 15 146 1,316 677 223 223 35 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.48 5.41 5.24 Enthalpy (kJ/kg)A 30.23 36.80 26.67 92.52 26.67 --- 558.58 --- 1,424.13 1,066.74 1,066.63 40.35 Density (kg/m3) 1.2 1.6 11.0 24.4 11.0 --- 866.9 --- 13.9 26.7 26.3 41.9 V-L Molecular Weight 28.857 27.132 32.181 28.060 32.181 --- 18.015 --- 20.081 19.636 19.636 20.393 V-L Flowrate (lbmol/hr) 48,220 2,352 225 42,726 11,680 0 10,647 0 48,969 62,043 62,043 42,226 V-L Flowrate (lb/hr) 1,391,479 63,803 7,253 1,198,895 375,855 0 191,803 0 983,333 1,218,267 1,218,267 861,115 Solids Flowrate (lb/hr) 0 0 0 0 0 466,901 0 51,227 0 0 0 0 Temperature (°F) 59 68 90 199 90 59 295 2,400 1,250 433 433 95 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 795.0 785.0 760.0 Enthalpy (Btu/lb)A 13.0 15.8 11.5 39.8 11.5 --- 240.1 --- 612.3 458.6 458.6 17.3 Density (lb/ft 3) 0.076 0.098 0.687 1.521 0.687 --- 54.120 --- 0.870 1.665 1.643 2.617 A - Reference conditions are 32.02 F & 0.089 PSIA 99

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-14 Case 1 Stream Table, GEE IGCC without CO2 Capture (Continued) 13 14 15 16 17 18 19 20 21 22 23 24 V-L Mole Fraction Ar 0.0097 0.0000 0.0000 0.0040 0.0100 0.0100 0.0100 0.0092 0.0092 0.0089 0.0089 0.0000 CH4 0.0013 0.0000 0.0000 0.0000 0.0013 0.0013 0.0013 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.3977 0.0002 0.0000 0.0021 0.4089 0.4089 0.4089 0.0000 0.0000 0.0000 0.0000 0.0000 CO2 0.1811 0.6124 0.0000 0.6947 0.1562 0.1562 0.1562 0.0003 0.0003 0.0807 0.0807 0.0000 COS 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2 0.3812 0.0000 0.0000 0.0415 0.3920 0.3920 0.3920 0.0000 0.0000 0.0000 0.0000 0.0000 H2O 0.0012 0.0128 0.0000 0.0018 0.0006 0.0006 0.0006 0.0099 0.0099 0.0638 0.0638 1.0000 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2S 0.0086 0.1817 0.0000 0.0111 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 N2 0.0191 0.1905 0.0000 0.2448 0.0309 0.0309 0.0309 0.7732 0.7732 0.7427 0.7427 0.0000 NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O2 0.0000 0.0023 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.2074 0.1039 0.1039 0.0000 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 V-L Flowrate (kgmol/hr) 19,992 951 0 839 19,445 19,445 19,445 110,253 4,410 136,882 136,882 35,596 V-L Flowrate (kg/hr) 422,592 36,883 0 31,997 397,047 397,047 397,047 3,181,557 127,262 3,995,152 3,995,152 641,276 Solids Flowrate (kg/hr) 0 0 5,307 0 0 0 0 0 0 0 0 0 Temperature (°C) 35 45 174 38 45 241 196 15 432 589 132 561 Pressure (MPa, abs) 5.21 5.2 0.409 5.512 5.171 5.136 3.172 0.101 1.619 0.105 0.105 12.512 Enthalpy (kJ/kg)A 36.92 -1.2 --- -5.039 54.553 365.190 296.114 30.227 463.785 741.466 235.132 3,502.816 Density (kg/m3) 43.4 95.0 5,288.2 97.7 40.0 24.1 16.4 1.2 7.9 0.4 0.9 35.1 V-L Molecular Weight 21.138 39 --- 38.145 20.419 20.419 20.419 28.857 28.857 29.187 29.187 18.015 V-L Flowrate (lbmol/hr) 44,075 2,096 0 1,849 42,870 42,870 42,870 243,066 9,723 301,773 301,773 78,476 V-L Flowrate (lb/hr) 931,655 81,313 0 70,540 875,339 875,339 875,339 7,014,133 280,565 8,807,803 8,807,803 1,413,772 Solids Flowrate (lb/hr) 0 0 11,699 0 0 0 0 0 0 0 0 0 Temperature (°F) 94 112 345 100 112 465 386 59 810 1,093 270 1,043 Pressure (psia) 755.0 750.0 59.3 799.5 750.0 745.0 460.0 14.7 234.9 15.2 15.2 1,814.7 Enthalpy (Btu/lb)A 15.9 -0.5 --- -2.2 23.5 157.0 127.3 13.0 199.4 318.8 101.1 1,505.9 Density (lb/ft 3) 2.712 6 330.129 6.098 2.499 1.508 1.026 0.076 0.495 0.027 0.057 2.191 100

Cost and Performance Baseline for Fossil Energy Plants COS Hydrolysis, Mercury Removal and Acid Gas Removal Syngas exiting the scrubber (stream 10) passes through a COS hydrolysis reactor where about 99.5 percent of the COS is converted to CO2 and H2S (Section 3.1.5). The gas exiting the COS reactor (stream 11) passes through a series of heat exchangers and knockout (KO) drums to lower the syngas temperature to 35°C (95°F) and to separate entrained water. The cooled syngas (stream 12) then passes through a carbon bed to remove 95 percent of the Hg (Section 3.1.4).

Cool, particulate-free syngas (stream 13) enters the Selexol absorber unit at approximately 5.2 MPa (755 psia) and 34°C (94°F). In this absorber, H2S is preferentially removed from the fuel gas stream along with smaller amounts of CO2, COS and other gases such as hydrogen. The rich solution leaving the bottom of the absorber is heated against the lean solvent returning from the regenerator before entering the H2S concentrator. A portion of the non-sulfur bearing absorbed gases is driven from the solvent in the H2S concentrator using N2 from the ASU as the stripping medium. The temperature of the H2S concentrator overhead stream is reduced prior to entering the reabsorber where a second stage of H2S absorption occurs. The rich solvent from the reabsorber is combined with the rich solvent from the absorber and sent to the stripper where it is regenerated through the indirect application of thermal energy via condensation of LP steam in a reboiler. The stripper acid gas stream (stream 14), consisting of 18 percent H2S and 61 percent CO2 (with the balance mostly N2), is then sent to the Claus unit.

Claus Unit Acid gas from the first-stage stripper of the Selexol unit is routed to the Claus plant. The Claus plant partially oxidizes the H2S in the acid gas to elemental sulfur. About 5,307 kg/hr (11,699 lb/hr) of elemental sulfur (stream 15) are recovered from the fuel gas stream. This value represents an overall sulfur recovery efficiency of 99.6 percent.

Acid gas from the Selexol unit is preheated to 232°C (450°F). A portion of the acid gas along with all of the sour gas from the stripper and oxygen from the ASU are fed to the Claus furnace.

In the furnace, H2S is catalytically oxidized to SO2 at a furnace temperature greater than 1,343°C (2,450°F), which must be maintained in order to thermally decompose all of the NH3 present in the sour gas stream.

Following the thermal stage and condensation of sulfur, two reheater and two sulfur converters are used to obtain a per-pass H2S conversion of approximately 99.9 percent. The Claus Plant tail gas is hydrogenated and recycled back to the Selexol process (stream 16). In the furnace waste heat boiler, 12,432 kg/hr (27,408 lb/hr) of 4.2 MPa (605 psia) steam are generated. This steam is used to satisfy all Claus process preheating and reheating requirements as well as to produce some steam for the medium-pressure steam header. The sulfur condensers produce 0.34 MPa (50 psig) and steam for the LP steam header and 2.9 MPa (415 psig) for IP steam.

Power Block Clean syngas exiting the Selexol absorber is re-heated (stream 18) using HP BFW and then expanded to 3.2 MPa (460 psia) using an expansion turbine (stream 19). The syngas stream is diluted with nitrogen from the ASU (stream 4) and enters the advanced F Class CT burner. The CT compressor provides combustion air to the burner and also 17 percent of the air requirements in the ASU (stream 21). The exhaust gas exits the CT at 589°C (1,093°F) (stream 22) and enters the HRSG where additional heat is recovered until the FG exits the HRSG at 132°C (270°F)

(stream 23) and is discharged through the plant stack. The steam raised in the HRSG is used to 101

Cost and Performance Baseline for Fossil Energy Plants power an advanced, commercially available steam turbine using a 12.4 MPa/562°C/562°C (1800 psig/1043°F/1043°F) steam cycle.

Air Separation Unit The elevated pressure ASU was described in Section 3.1.2. In Case 1 the ASU is designed to produce a nominal output of 4,171 tonnes/day (4,597 TPD) of 95 mol% O2 for use in the gasifier (stream 5) and Claus plant (stream 3). The plant is designed with two production trains. The air compressor is powered by an electric motor. Approximately 13,051 tonnes/day (14,387 TPD) of nitrogen are also recovered, compressed, and used for dilution in the GT combustor (stream 4).

About 4 percent of the GT air is used to supply approximately 17 percent of the ASU air requirements (stream 21).

Balance of Plant Balance of plant items were covered in Sections 3.1.9, 3.1.10, and 3.1.11.

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Cost and Performance Baseline for Fossil Energy Plants 3.2.3 Key System Assumptions System assumptions for Cases 1 and 2, GEE IGCC with and without CO2 capture, are presented in Exhibit 3-15.

Exhibit 3-15 GEE IGCC Plant Study Configuration Matrix Case 1 2 Gasifier Pressure, MPa (psia) 5.6 (815) 5.6 (815)

O2:Coal Ratio, kg O2/kg dry coal 0.91 0.91 Carbon Conversion, % 98 98 Syngas HHV at Gasifier Outlet, 8,663 (233) 8,644 (232) kJ/Nm3 (Btu/scf)

Steam Cycle, MPa/°C/°C 12.4/562/562 12.4/534/534 (psig/°F/°F) (1800/1043/1043) (1800/994/994)

Condenser Pressure, mm Hg 51 (2.0) 51 (2.0)

(in Hg) 2x Advanced F Class 2x Advanced F Class Combustion Turbine (232 MW output each) (232 MW output each)

Gasifier Technology GEE Radiant Only GEE Radiant Only Oxidant 95 vol% Oxygen 95 vol% Oxygen Coal Illinois No. 6 Illinois No. 6 Coal Slurry Solids Content, % 63 63 COS Hydrolysis Yes Occurs in SGS Sour Gas Shift No Yes H2S Separation Selexol Selexol 1st Stage Sulfur Removal, % 99.7 99.9 Claus Plant with Tail Gas Claus Plant with Tail Gas Sulfur Recovery Recycle to Selexol/ Recycle to Selexol/

Elemental Sulfur Elemental Sulfur Water Quench, Scrubber, Water Quench, Scrubber, Particulate Control and AGR Absorber and AGR Absorber Mercury Control Carbon Bed Carbon Bed Multi Nozzle Quiet MNQC (LNB) and N2 NOx Control Combustor (MNQC)

Dilution (LNB) and N2 Dilution CO2 Separation N/A Selexol 2nd Stage Overall CO2 Capture N/A 90.3%

CO2 Sequestration N/A Off-site Saline Formation 103

Cost and Performance Baseline for Fossil Energy Plants Balance of Plant - Cases 1 and 2 The balance of plant assumptions are common to all cases and are presented in Exhibit 3-16.

Exhibit 3-16 Balance of Plant Assumptions Cooling system Recirculating Wet Cooling Tower Fuel and Other storage Coal 30 days Slag 30 days Sulfur 30 days Sorbent 30 days Plant Distribution Voltage Motors below 1 hp 110/220 volt Motors between 1 hp and 480 volt 250 hp Motors between 250 hp and 4,160 volt 5,000 hp Motors above 5,000 hp 13,800 volt Steam and Gas Turbine 24,000 volt Generators Grid Interconnection Voltage 345 kV Water and Waste Water The water supply is 50 percent from a local POTW and 50 percent from groundwater, and is assumed to be in sufficient quantities to meet plant makeup Makeup Water requirements.

Makeup for potable, process, and de-ionized (DI) water is drawn from municipal sources Water associated with gasification activity and storm water that contacts equipment surfaces is collected Process Wastewater and treated for discharge through a permitted discharge.

Design includes a packaged domestic sewage treatment plant with effluent discharged to the Sanitary Waste Disposal industrial wastewater treatment system. Sludge is hauled off site. Packaged plant was sized for 5.68 cubic meters per day (1,500 gallons per day)

Most of the process wastewater is recycled to the Water Discharge cooling tower basin. Blowdown is treated for chloride and metals, and discharged.

104

Cost and Performance Baseline for Fossil Energy Plants 3.2.4 Sparing Philosophy The sparing philosophy for Cases 1 and 2 is provided below. Single trains are utilized throughout with exceptions where equipment capacity requires an additional train. There is no redundancy other than normal sparing of rotating equipment.

The plant design consists of the following major subsystems:

Two ASUs (2 x 50%)

Two trains of slurry preparation and slurry pumps (2 x 50%)

Two trains of gasification, including gasifier, SGC, quench and scrubber (2 x 50%).

Two trains of syngas clean-up process (2 x 50%).

Two trains of Selexol AGR, single-stage in Case 1 and two-stage in Case 2, (2 x 50%)

and one Claus-based SRU (1 x 100%).

Two CT/HRSG tandems (2 x 50%).

One steam turbine (1 x 100%).

3.2.5 Case 1 Performance Results The plant produces a net output of 622 MWe at a net plant efficiency of 39.0 percent (HHV basis). GEE has reported a net plant efficiency of 38.5 percent for their reference plant, and they also presented a range of efficiencies of 38.5-40 percent depending on fuel type [ 59,60].

Typically the higher efficiencies result from fuel blends that include petroleum coke.

Overall performance for the plant is summarized in Exhibit 3-17, which includes auxiliary power requirements. The ASU accounts for approximately 78 percent of the auxiliary load between the main air compressor, the nitrogen compressor, the oxygen compressor and ASU auxiliaries. The cooling water system, including the CWPs and the cooling tower fan, account for approximately 5 percent of the auxiliary load, and the BFW pumps account for an additional 3 percent. All other individual auxiliary loads are less than 3 percent of the total.

105

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-17 Case 1 Plant Performance Summary POWER

SUMMARY

(Gross Power at Generator Terminals, kWe)

Gas Turbine Power 464,000 Sweet Gas Expander Power 7,500 Steam Turbine Power 276,300 TOTAL POWER, kWe 747,800 AUXILIARY LOAD

SUMMARY

, kWe Coal Handling 460 Coal Milling 2,180 Sour Water Recycle Slurry Pump 180 Slag Handling 1,120 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 53,820 Oxygen Compressor 10,260 Nitrogen Compressors 33,340 Boiler Feedwater Pumps 3,980 Condensate Pump 230 Quench Water Pump 520 Circulating Water Pump 4,200 Ground Water Pumps 430 Cooling Tower Fans 2,170 Scrubber Pumps 220 Acid Gas Removal 2,590 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 250 Claus Plant TG Recycle Compressor 2,090 2

Miscellaneous Balance of Plant 3,000 Transformer Losses 2,610 TOTAL AUXILIARIES, kWe 125,750 NET POWER, kWe 622,050 Net Plant Efficiency, % (HHV) 39.0 Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,238 (8,756)

CONDENSER COOLING DUTY 106 kJ/hr (106 Btu/hr) 1,540 (1,460)

CONSUMABLES As-Received Coal Feed, kg/hr (lb/hr) 211,783 (466,901)

Thermal Input1, kWt 1,596,320 Raw Water Withdrawal, m3/min (gpm) 17.9 (4,735)

Raw Water Consumption, m3/min (gpm) 14.2 (3,755) 1 - HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 2 - Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads 106

Cost and Performance Baseline for Fossil Energy Plants Environmental Performance The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 2.4. A summary of the plant air emissions for Case 1 is presented in Exhibit 3-18.

Exhibit 3-18 Case 1 Emissions Tonne/year kg/GJ kg/MWh (ton/year) @

(lb/106 Btu) (lb/MWh) 80% capacity factor SO2 0.001 (0.001) 21 (24) 0.004 (.01)

NOx 0.025 (0.059) 1,023 (1,128) 0.195 (.430)

Particulates 0.003 (0.0071) 123 (136) 0.023 (.052) 2.46E-7 Hg 0.010 (0.011) 1.89E-6 (4.16E-6)

(5.71E-7) 3,407,901 CO2 84.6 (196.8) 650 (1,434)

(3,756,568)

CO21 782 (1,723) 1 CO2 emissions based on net power instead of gross power The low level of SO2 emissions is achieved by capture of the sulfur in the gas by the Selexol AGR process. The AGR process removes over 99 percent of the sulfur compounds in the fuel gas down to a level of less than 30 ppmv. This results in a concentration in the FG of less than 4 ppmv. The H2S-rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species to H2S and then recycled back to the Selexol process, thereby eliminating the need for a tail gas treatment unit.

NOx emissions are limited by nitrogen dilution of the syngas to 15 ppmvd (as NO2 @15 percent O2). Ammonia in the syngas is removed with process condensate prior to the low-temperature AGR process and ultimately destroyed in the Claus plant burner. This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of the syngas quench in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only.

Ninety five percent of the mercury is captured from the syngas by an activated carbon bed.

CO2 emissions represent the uncontrolled discharge from the process.

The carbon balance for the plant is shown in Exhibit 3-19. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected here since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag and as CO2 in the stack gas and ASU vent gas.

107

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-19 Case 1 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 135,000 (297,625) Slag 2,700 (5,952)

Air (CO2) 519 (1,143) Stack Gas 132,716 (292,588)

ASU Vent 103 (227)

CO2 Product 0 (0)

Total 135,519 (298,768) Total 135,519 (298,768)

Exhibit 3-20 shows the sulfur balances for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible.

Exhibit 3-20 Case 1 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 5,308 (11,702) Elemental Sulfur 5,307 (11,699)

Stack Gas 2 (3)

CO2 Product 0 (0)

Total 5,308 (11,702) Total 5,308 (11,702)

Exhibit 3-21 shows the overall water balance for the plant. Water demand represents the total amount of water required for a particular process. Some water is recovered within the process, primarily as syngas condensate, and is re-used as internal recycle. The difference between demand and recycle is raw water withdrawal. Raw water withdrawal is defined as the water removed from the ground or diverted from a surface-water source for use in the plant and was assumed to be provided 50 percent by a POTW and 50 percent from groundwater. Raw water withdrawal can be represented by the water metered from a raw water source and used in the plant processes for any and all purposes, such as cooling tower makeup, BFW makeup, quench system makeup, and slag handling makeup. The difference between water withdrawal and process water discharge is defined as water consumption and can be represented by the portion of the raw water withdrawn that is evaporated, transpired, incorporated into products or otherwise not returned to the water source from which it was withdrawn. Water consumption represents the net impact of the plant process on the water source balance.

108

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-21 Case 1 Water Balance Process Water Internal Raw Water Water Raw Water Demand, Recycle, Withdrawal, Water Use Discharge, Consumption, m3/min m3/min m3/min m3/min m3/min (gpm)

(gpm) (gpm) (gpm)

(gpm)

Slag Handling 0.50 (133) 0.50 (133) 0.0 (0) 0.0 (0) 0.0 (0)

Slurry Water 1.45 (384) 1.45 (384) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.7 (726) 0.90 (237) 1.9 (489) 0.0 (0) 1.9 (489)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (8) -0.03 (-8)

Condenser Makeup 0.2 (54) 0.0 (0) 0.2 (54) 0.0 (0) 0.2 (54)

Gasifier Steam Shift Steam GT Steam Dilution BFW Makeup 0.20 (54) 0.20 (54)

Cooling Tower 16.4 (4,321) 0.49 (129) 15.9 (4,192) 3.7 (972) 12.2 (3,220)

BFW Blowdown 0.20 (54) -0.20 (-54)

SWS Blowdown 0.29 (75) -0.29 (-75)

SWS Excess Water Humidifier Tower Blowdown Total 21.3 (5,618) 3.34 (883) 17.9 (4,735) 3.7 (979) 14.2 (3,755)

Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-22 through Exhibit 3-24:

Coal gasification and ASU

Syngas cleanup, sulfur recovery and tail gas recycle

Combined cycle power generation, steam, and FW An overall plant energy balance is provided in tabular form in Exhibit 3-25. The power out is the combined CT, steam turbine and expander power prior to generator losses. The power at the generator terminals (shown in Exhibit 3-17) is calculated by multiplying the power out by a combined generator efficiency of 98.2 percent.

109

Cost and Performance Baseline for Fossil Energy Plants This page intentionally left blank 110

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-22 Case 1 Coal Gasification and Air Separation Units Heat and Mass Balance Schematic ASU 63,803 W 280,565 W LEGEND Vent 68.2 T 220.0 T 16.4 P Ambient Air 224.9 P Air 15.8 H 1 50.9 H N2 to GT Combustor Coal/Char/

1,391,479 W 100.0 T 189.5 P 1,198,895 W Slurry/Slag 59.0 T 18.0 H 2 389.0 T 14.7 P Four Stage Air 384.0 P Nitrogen 13.0 H Compressor 88.2 H 4

1,198,895 W 280,565 W Oxygen 1,073,296 W 199.0 T Air From GT 809.8 T 90.0 T 384.0 P Compressor 234.9 P 56.4 P 39.8 H 199.4 H Steam 14.2 H 21 Elevated Synthesis Gas Four Stage N2 N2 Boost 5 Pressure Compressor Compressor ASU 24,996 W 375,855 W 24,996 W N2 to AGR 376.3 T Water 90.0 T 150,595 W 199.0 T 785.0 P 125.0 P 7,253 W 50.0 T 384.0 P 84.2 H 11.5 H 90.0 T 182.0 P 39.8 H Sour Water 2.9 H Raw Fuel Gas 125.0 P 11.5 H 3 To Claus Plant 1,218,267 W 402.9 T 800.0 P 445.7 H Four Stage O2 Compressor 983,333 W 1,346,417 W P ABSOLUTE PRESSURE, PSIA 375,855 W 1,250.0 T 450.0 T F TEMPERATURE, °F 241.2 T 466,901 W 805.0 P 805.0 P Process Water W FLOWRATE, LBM/HR 940.0 P 59.0 T 612.3 H 535.7 H From Sour Water Stripper H ENTHALPY, BTU/LBM 40.8 H Syngas Milled Coal 14.7 P MWE POWER, MEGAWATTS ELECTRICAL 658,704 W Scrubber 6

159.7 T NOTES:

840.0 P 2,933.2 H 7

Vent To Claus Unit

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA 191,803 W 295.0 T 840.0 P 240.1 H GE Energy Gasifier CWR 9

Slurry Mix Tank Syngas Quench HP BFW Knockout PLANT PERFORMANCE

SUMMARY

Drum Gross Plant Power: 748 MWe Radiant CWS Auxiliary Load: 126 MWe Syngas Black Net Plant Power: 622 MWe Cooler Water Net Plant Efficiency, HHV: 39.0%

Flash Net Plant Heat Rate: 8,756 BTU/KWe Saturated Steam Tank To HRSG HP Superheater DOE/NETL Slag Quench Section DUAL TRAIN IGCC PLANT CASE 1 HEAT AND MATERIAL FLOW DIAGRAM Drag BITUMINOUS BASELINE STUDY Conveyor Slag 51,227 W Fines CASE 1 8 2,400.0 T GEE GASIFIER 815.0 P ASU AND GASIFICATION DWG. NO. PAGES BB-HMB-CS-1-PG-1 1 OF 3 111

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-23 Case 1 Syngas Cleanup Heat and Mass Balance Schematic LEGEND Fuel Gas To GT Air 18 19 Coal/Char/

Syngas 875,339 W Fuel Gas 875,339 W Slurry/Slag Preheater 465.0 T Expander 385.6 T 745.0 P 460.0 P Nitrogen 875,339 W 157.0 H 127.3 H 17 112.2 T 750.0 P Oxygen Claus Plant 23.5 H Catalytic Sour Gas COS Hydrolysis Reactor 1,218,267 W 1,218,267 W Beds 432.9 T 432.7 T Sour Water 795.0 P 785.0 P 458.6 H 458.6 H Furnace 11 14 Tail Steam 10 Gas Clean Gas Acid Gas 81,313 W 112.2 T Synthesis Gas 750.0 P 931,655 W Water COS Hydrolysis 94.2 T N2 to AGR Preheater 755.0 P 15.9 H 7,253 W 15 CO2 450.0 T 13 124.5 P 91.9 H Tailgas Mercury P ABSOLUTE PRESSURE, PSIA Removal 24,996 W Claus Oxygen Sulfur F TEMPERATURE, °F 376.3 T Preheater 11,699 W W FLOWRATE, LBM/HR 785.0 P 861,115 W H ENTHALPY, BTU/LBM 84.2 H Syngas 95.3 T 12 AGR- Selexol 79,721 W MWE POWER, MEGAWATTS ELECTRICAL Coolers 760.0 P 450.0 T 17.3 H 3 From 58.9 P NOTES:

Raw Syngas ASU 249.7 H Knock Out 70,540 W 2,855 W 7,253 W 16 234.5 T 90.0 T 1,218,267 W Drum 100.0 T 1. ENTHALPY REFERENCE POINT IS NATURAL STATE 799.5 P 65.0 P 125.0 P AT 32 °F AND 0.08865 PSIA 402.9 T 405.2 H 11.5 H 800.0 P 457.9 H Hydrogenation and Tail Gas Cooling Sour PLANT PERFORMANCE

SUMMARY

Drum Gross Plant Power: 748 MWe Auxiliary Load: 126 MWe Sour Net Plant Power: 622 MWe Stripper Net Plant Efficiency, HHV: 39.0%

Net Plant Heat Rate: 8,756 BTU/KWe Tail Gas Recycle Compressor 71,392 W Makeup Water DOE/NETL 120.0 T 56.8 P 32.0 H DUAL TRAIN IGCC PLANT Knock Out CASE 1 Process Condensate to Syngas Scrubber 9,181 W HEAT AND MATERIAL FLOW DIAGRAM 118.2 T 56.8 P BITUMINOUS BASELINE STUDY 44.4 H CASE 1 GEE GASIFIER GAS CLEANUP SYSTEM DWG. NO. PAGES BB-HMB-CS-1-PG-2 2 OF 3 112

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-24 Case 1 Combined-Cycle Power Generation Heat and Mass Balance Schematic LEGEND LP Process Header Air HP BFW to Radiant Syngas Cooler Coal/Char/

HP Saturated Steam to HRSG Superheater Slurry/Slag Nitrogen 8,807,803 W 269.7 T Oxygen 15.2 P 101.1 H Sour Gas 22 HRSG 23 Stack 8,807,803 W LP Flash Tops Sour Water 1,092.7 T 15.2 P 9,644 W MP Flash Bottoms Steam Nitrogen Diluent 318.8 H 298.0 T From Gasifier 65.0 P Island Preheating 1,198,895 W 1,179.0 H Synthesis Gas 385.0 T 24 1,581,185 W 389.0 P 235.0 T Deaerator 87.2 H 1,413,772 W 105.0 P Water 1,042.7 T 203.7 H 1,814.7 P 1,440,764 W 1,505.9 H 278.8 T Flue Gas Fuel Gas 2,250.7 P LP BFW 19 252.3 H 875,339 W Blowdown 385.6 T 26,992 W Flash 460.0 P LP Pump P ABSOLUTE PRESSURE, PSIA 585.0 T To Claus 127.3 H 2,000.7 P F TEMPERATURE, °F To WWT 593.3 H HP Pump W FLOWRATE, LBM/HR Air Extraction IP BFW H ENTHALPY, BTU/LBM 21 MWE POWER, MEGAWATTS ELECTRICAL 280,565 W IP Pump 809.8 T NOTES:

234.9 P 1,542,260 W 199.4 H Compressor Expander 512.1 T 65.0 P 1. ENTHALPY REFERENCE POINT IS NATURAL STATE 1,288.0 H AT 32 °F AND 0.08865 PSIA Generator HP IP LP Turbine Turbine Steam Turbine Advanced F-Class Turbine Gas Turbine Generator Intake Ip Extraction Steam PLANT PERFORMANCE

SUMMARY

To 250 PSIA Header 35,544 W 9,515 W Gross Plant Power: 748 MWe 780 W 8,822 W 1,312 W 897.8 T 661.9 T Auxiliary Load: 126 MWe 1,042.7 T 701.7 T 540.7 T 280.0 P 65.0 P Net Plant Power: 622 MWe 1,814.7 P 501.4 P 65.0 P 1,472.7 H 1,361.9 H Ambient Air Net Plant Efficiency, HHV: 39.0%

20 1,505.9 H 1,358.0 H 1,302.1 H Net Plant Heat Rate: 8,756 BTU/KWe 7,014,133 W Steam Seal CONDENSER Make-up Regulator 27,011 W 59.0 T 1,400 W 14.7 P 59.0 T 212.0 T 1,400 W HOT WELL 14.7 P 13.0 H 14.7 P DOE/NETL 661.9 T 27.1 H 179.9 H 65.0 P 1,581,185 W 1,361.9 H 101.1 T DUAL TRAIN IGCC PLANT 1.0 P CASE 1 69.1 H Condensate HEAT AND MATERIAL FLOW DIAGRAM Pump BITUMINOUS BASELINE STUDY Gland CASE 1 1,581,185 W 103.2 T Steam GEE GASIFIER 120.0 P Condenser POWER BLOCK SYSTEM Condensate to Gasification Island 71.4 H DWG. NO. PAGES BB-HMB-CS-1-PG-3 3 OF 3 113

Cost and Performance Baseline for Fossil Energy Plants This page intentionally left blank 114

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-25 Case 1 Overall Energy Balance (0°C [32°F] Reference)

Sensible +

HHV Power Total Latent Heat In GJ/hr (MMBtu/hr)

Coal 5,747 (5,447) 4.8 (4.6) 5,752 (5,451)

ASU Air 19.1 (18.1) 19 (18)

CT Air 96.2 (91.2) 96 (91)

Water 67.4 (63.9) 67 (64)

Auxiliary Power 453 (429) 453 (429)

TOTAL 5,747 (5,447) 187.4 (177.7) 453 (429) 6,387 (6,054)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 1.1 (1.0) 1 (1)

Slag 89 (84) 36.3 (34.4) 125 (118)

Sulfur 49 (47) 0.6 (0.6) 50 (47)

CO2 Cooling Tower 27.3 (25.9) 27 (26)

Blowdown HRSG Flue Gas 939 (890) 939 (890)

Condenser 1,536 (1,456) 1,536 (1,456)

Non-Condenser Cooling Tower 422 (400) 422 (400)

Loads*

Process Losses** 594 (563) 594 (563)

Power 2,692 (2,552) 2,692 (2,552)

TOTAL 138 (131) 3,557 (3,372) 2,692 (2,552) 6,387 (6,054)

Includes ASU compressor intercoolers, CO2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection) and extraction air cooler.

- Calculated by difference to close the energy balance.

115

Cost and Performance Baseline for Fossil Energy Plants 3.2.6 Case 1 - Major Equipment List Major equipment items for the GEE gasifier with no CO2 capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section 3.2.7. In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 COAL HANDLING Equipment Operating Description Type Design Condition Spares No. Qty.

Bottom Trestle Dumper and 1 N/A 181 tonne (200 ton) 2 0 Receiving Hoppers 2 Feeder Belt 572 tonne/hr (630 tph) 2 0 3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0 4 Transfer Tower No. 1 Enclosed N/A 1 0 5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0 As-Received Coal Sampling 6 Two-stage N/A 1 0 System 7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0 8 Reclaim Hopper N/A 45 tonne (50 ton) 2 1 9 Feeder Vibratory 172 tonne/hr (190 tph) 2 1 10 Conveyor No. 3 Belt w/ tripper 354 tonne/hr (390 tph) 1 0 11 Crusher Tower N/A N/A 1 0 12 Coal Surge Bin w/ Vent Filter Dual outlet 172 tonne (190 ton) 2 0 Impactor 8 cm x 0 - 3 cm x 0 13 Crusher 2 0 reduction (3" x 0 1/4" x 0)

As-Fired Coal Sampling 14 Swing hammer N/A 1 1 System 15 Conveyor No. 4 Belt w/tripper 354 tonne/hr (390 tph) 1 0 16 Transfer Tower No. 2 Enclosed N/A 1 0 17 Conveyor No. 5 Belt w/ tripper 354 tonne/hr (390 tph) 1 0 Coal Silo w/ Vent Filter and 18 Field erected 816 tonne (900 ton) 3 0 Slide Gates 116

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 2 COAL PREPARATION AND FEED Equipment Operating Description Type Design Condition Spares No. Qty.

1 Feeder Vibratory 82 tonne/h (90 tph) 3 0 2 Conveyor No. 6 Belt w/tripper 236 tonne/h (260 tph) 1 0 3 Rod Mill Feed Hopper Dual Outlet 463 tonne (510 ton) 1 0 4 Weigh Feeder Belt 118 tonne/h (130 tph) 2 0 5 Rod Mill Rotary 118 tonne/h (130 tph) 2 0 Slurry Water Storage Tank 6 Field erected 287,504 liters (75,950 gal) 2 0 with Agitator 7 Slurry Water Pumps Centrifugal 795 lpm (210 gpm) 2 1 8 Trommel Screen Coarse 163 tonne/h (180 tph) 2 0 Rod Mill Discharge Tank with 9 Field erected 376,122 liters (99,360 gal) 2 0 Agitator 10 Rod Mill Product Pumps Centrifugal 3,028 lpm (800 gpm) 2 2 Slurry Storage Tank with 11 Field erected 1,128,440 liters (298,100 gal) 2 0 Agitator 12 Slurry Recycle Pumps Centrifugal 6,435 lpm (1,700 gpm) 2 2 Positive 13 Slurry Product Pumps 3,028 lpm (800 gpm) 2 2 displacement 117

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment Operating Description Type Design Condition Spares No. Qty.

Demineralized Water Vertical, cylindrical, 1 1,082,628 liters (286,000 gal) 2 0 Storage Tank outdoor 6,624 lpm @ 91 m H2O 2 Condensate Pumps Vertical canned 2 1 (1,750 gpm @ 300 ft H2O)

Deaerator (integral w/

3 Horizontal spray type 493,508 kg/hr (1,088,000 lb/hr) 2 0 HRSG)

Intermediate Pressure Horizontal centrifugal, 8,366 lpm @ 27 m H2O 4 2 1 Feedwater Pump single stage (2,210 gpm @ 90 ft H2O)

HP water: 6,246 lpm @ 1,859 m High Pressure Barrel type, multi-stage, 5 H2O (1,650 gpm @ 6,100 ft 2 1 Feedwater Pump No. 1 centrifugal H2O)

High Pressure Barrel type, multi-stage, IP water: 1,060 lpm @ 223 m 6 2 1 Feedwater Pump No. 2 centrifugal H2O (280 gpm @ 730 ft H2O)

Shop fabricated, water 18,144 kg/hr, 2.8 MPa, 343°C 7 Auxiliary Boiler 1 0 tube (40,000 lb/hr, 400 psig, 650°F)

Service Air 28 m3/min @ 0.7 MPa 8 Flooded Screw 2 1 Compressors (1,000 scfm @ 100 psig) 9 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1 Closed Cylce Cooling 10 Plate and frame 247 GJ/hr (234 MMBtu/hr) each 2 0 Heat Exchangers Closed Cycle Cooling 88,579 lpm @ 21 m H2O 11 Horizontal centrifugal 2 1 Water Pumps (23,400 gpm @ 70 ft H2O)

Engine-Driven Fire Vertical turbine, diesel 3,785 lpm @ 107 m H2O 12 1 1 Pump engine (1,000 gpm @ 350 ft H2O)

Fire Service Booster Two-stage horizontal 2,650 lpm @ 76 m H2O 13 1 1 Pump centrifugal (700 gpm @ 250 ft H2O)

Stainless steel, single 4,618 lpm @ 18 m H2O 14 Raw Water Pumps 2 1 suction (1,220 gpm @ 60 ft H2O)

Stainless steel, single 3,066 lpm @ 268 m H2O 15 Ground Water Pumps 3 1 suction (810 gpm @ 880 ft H2O)

Stainless steel, single 2,082 lpm @ 49 m H2O 16 Filtered Water Pumps 2 1 suction (550 gpm @ 160 ft H2O) 17 Filtered Water Tank Vertical, cylindrical 1,003,134 liter (265,000 gal) 2 0 Makeup Water Anion, cation, and 18 303 lpm (80 gpm) 2 0 Demineralizer mixed bed Liquid Waste Treatment 19 10 years, 24-hour storm 1 0 System 118

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY Equipment Operating Description Type Design Condition Spares No. Qty.

Pressurized slurry-feed, 2,812 tonne/day, 5.6 MPa 1 Gasifier 2 0 entrained bed (3,100 tpd, 815 psia)

Vertical downflow radiant heat exchanger 2 Synthesis Gas Cooler 245,393 kg/hr (541,000 lb/hr) 2 0 with outlet quench chamber Syngas Scrubber 3 Including Sour Water Vertical upflow 336,112 kg/hr (741,000 lb/hr) 2 0 Stripper Shell and tube with 4 Raw Gas Coolers 215,910 kg/hr (476,000 lb/hr) 8 0 condensate drain Raw Gas Knockout Vertical with mist 215,456 kg/hr, 35°C, 5.3 MPa 5 2 0 Drum eliminator (475,000 lb/hr, 95°F, 765 psia)

Self-supporting, carbon 336,112 kg/hr (741,000 lb/hr) 6 Flare Stack steel, stainless steel top, 2 0 syngas pilot ignition ASU Main Air 4,757 m3/min @ 1.3 MPa 7 Centrifugal, multi-stage 2 0 Compressor (168,000 scfm @ 190 psia) 2,268 tonne/day (2,500 tpd) of 8 Cold Box Vendor design 2 0 95% purity oxygen 1,161 m3/min (41,000 scfm) 9 Oxygen Compressor Centrifugal, multi-stage Suction - 0.9 MPa (130 psia) 2 0 Discharge - 6.5 MPa (940 psia) 3,766 m3/min (133,000 scfm)

Primary Nitrogen 10 Centrifugal, multi-stage Suction - 0.4 MPa (60 psia) 2 0 Compressor Discharge - 2.7 MPa (390 psia) 538 m3/min (19,000 scfm)

Secondary Nitrogen 11 Centrifugal, single-stage Suction - 1.2 MPa (180 psia) 2 0 Compressor Discharge - 2.7 MPa (390 psia) 0 m3/min (0 scfm)

Syngas Dilution Nitrogen 12 Centrifugal, single-stage Suction - 2.6 MPa (380 psia) 2 0 Boost Compressor Discharge - 3.2 MPa (470 psia) 85 m3/min (3,000 scfm)

AGR Nitrogen Boost 13 Centrifugal, single-stage Suction - 2.6 MPa (380 psia) 2 0 Compressor Discharge - 5.4 MPa (790 psia)

Extraction Air Heat Gas-to-gas, vendor 69,853 kg/hr, 432°C, 1.6 MPa 14 2 0 Exchanger design (154,000 lb/hr, 810°F, 235 psia) 119

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 5A SYNGAS CLEANUP Equipment Operating Description Type Design Condition Spares No. Qty.

215,003 kg/hr (474,000 lb/hr)

Sulfated carbon 1 Mercury Adsorber 35°C (95°F) 2 0 bed 5.2 MPa (760 psia) 2 Sulfur Plant Claus type 140 tonne/day (154 tpd) 1 0 303,907 kg/hr (670,000 lb/hr)

Fixed bed, 3 COS Hydrolysis Reactor 221°C (430°F) 2 0 catalytic 5.4 MPa (790 psia) 232,239 kg/hr (512,000 lb/hr) 4 Acid Gas Removal Plant Selexol 35°C (94°F) 2 0 5.2 MPa (755 psia) 36,161 kg/hr (79,721 lb/hr)

Fixed bed, 5 Hydrogenation Reactor 232°C (450°F) 1 0 catalytic 0.4 MPa (58.9 psia)

Tail Gas Recycle 6 Centrifugal 31,997 kg/hr (70,540 lb/hr) each 1 0 Compressor ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES Equipment Operating Description Type Design Condition Spares No. Qty.

1 Gas Turbine Advanced F class 230 MW 2 0 260 MVA @ 0.9 p.f., 24 kV, 2 Gas Turbine Generator TEWAC 2 0 60 Hz, 3-phase 218,359 kg/h (481,400 lb/h)

Syngas Expansion 3 Turbo Expander 5.1 MPa (745 psia) Inlet 2 0 Turbine/Generator 3.2 MPa (460 psia) Outlet ACCOUNT 7 HRSG, DUCTING, AND STACK Equipment Operating Description Type Design Condition Spares No. Qty.

CS plate, type 409SS 76 m (250 ft) high x 1 Stack 1 0 liner 8.4 m (27 ft) diameter Main steam - 352,702 kg/hr, 12.4 Drum, multi-pressure MPa/561°C (777,575 lb/hr, Heat Recovery with economizer 1,800 psig/1,043°F) 2 2 0 Steam Generator section and integral Reheat steam - 345,710 kg/hr, deaerator 3.1 MPa/561°C (762,160 lb/hr, 452 psig/1,043°F) 120

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES Equipment Operating Description Type Design Condition Spares No. Qty.

Commercially 291 MW 1 Steam Turbine available advanced 12.4 MPa/561°C/561°C 1 0 steam turbine (1,800 psig/ 1043°F/1043°F)

Hydrogen cooled, 320 MVA @ 0.9 p.f., 24 2 Steam Turbine Generator 1 0 static excitiation kV, 60 Hz, 3-phase 50% steam flow @ design 3 Steam Bypass One per HRSG 2 0 steam conditions 1,688 GJ/hr (1,600 Single pass, divided MMBtu/hr), Inlet water 4 Surface Condenser waterbox including temperature 16°C (60°F), 1 0 vacuum pumps Water temperature rise 11°C (20°F)

ACCOUNT 9 COOLING WATER SYSTEM Equipment Operating Description Type Design Condition Spares No. Qty.

Circulating Water 420,181 lpm @ 30 m 1 Vertical, wet pit 2 1 Pumps (111,000 gpm @ 100 ft) 11°C (51.5°F) wet bulb / 16°C Evaporative, (60°F) CWT / 27°C (80°F) HWT 2 Cooling Tower mechanical draft, multi- 1 0

/ 2,353 GJ/hr (2,230 MMBtu/hr) cell heat duty 121

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 10 SLAG RECOVERY AND HANDLING Equipment Operating Description Type Design Condition Spares No. Qty.

1 Slag Quench Tank Water bath 242,266 liters (64,000 gal) 2 0 2 Slag Crusher Roll 13 tonne/hr (14 tph) 2 0 3 Slag Depressurizer Lock Hopper 13 tonne/hr (14 tph) 2 0 4 Slag Receiving Tank Horizontal, weir 147,631 liters (39,000 gal) 2 0 5 Black Water Overflow Tank Shop fabricated 64,352 liters (17,000 gal) 2 6 Slag Conveyor Drag chain 13 tonne/hr (14 tph) 2 0 7 Slag Separation Screen Vibrating 13 tonne/hr (14 tph) 2 0 8 Coarse Slag Conveyor Belt/bucket 13 tonne/hr (14 tph) 2 0 9 Fine Ash Settling Tank Vertical, gravity 208,198 liters (55,000 gal) 2 0 Horizontal 38 lpm @ 14 m H2O 10 Fine Ash Recycle Pumps 2 2 centrifugal (10 gpm @ 46 ft H2O) 11 Grey Water Storage Tank Field erected 68,137 liters (18,000 gal) 2 0 227 lpm @ 564 m H2O 12 Grey Water Pumps Centrifugal 2 2 (60 gpm @ 1,850 ft H2O)

Vertical, field 13 Slag Storage Bin 907 tonne (1,000 tons) 2 0 erected 14 Unloading Equipment Telescoping chute 109 tonne/hr (120 tph) 1 0 122

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 11 ACCESSORY ELECTRIC PLANT Equipment Operating Description Type Design Condition Spares No. Qty.

CTG Step-up 24 kV/345 kV, 260 MVA, 1 Oil-filled 2 0 Transformer 3-ph, 60 Hz STG Step-up 24 kV/345 kV, 320 MVA, 2 Oil-filled 1 0 Transformer 3-ph, 60 Hz High Voltage 345 kV/13.8 kV, 54 MVA, 3 Auxiliary Oil-filled 2 0 3-ph, 60 Hz Transformer Medium Voltage 24 kV/4.16 kV, 29 MVA, 4 Auxiliary Oil-filled 1 1 3-ph, 60 Hz Transformer Low Voltage 4.16 kV/480 V, 4 MVA, 5 Dry ventilated 1 1 Transformer 3-ph, 60 Hz CTG Isolated 6 Phase Bus Duct Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 2 0 and Tap Bus STG Isolated 7 Phase Bus Duct Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0 and Tap Bus Medium Voltage 8 Metal clad 4.16 kV, 3-ph, 60 Hz 1 1 Switchgear Low Voltage 9 Metal enclosed 480 V, 3-ph, 60 Hz 1 1 Switchgear Emergency Diesel Sized for emergency 10 750 kW, 480 V, 3-ph, 60 Hz 1 0 Generator shutdown ACCOUNT 12 INSTRUMENTATION AND CONTROLS Equipment Operating Description Type Design Condition Spares No. Qty.

Monitor/keyboard; DCS - Main Operator printer (laser Operator stations/printers and 1 1 0 Control color); Engineering engineering stations/printers printer (laser B&W)

Microprocessor with 2 DCS - Processor N/A 1 0 redundant input/output DCS - Data 3 Fiber optic Fully redundant, 25% spare 1 0 Highway 123

Cost and Performance Baseline for Fossil Energy Plants 3.2.7 Case 1 - Cost Estimating The cost estimating methodology was described previously in Section 2.6. Exhibit 3-26 shows the total plant capital cost summary organized by cost account and Exhibit 3-27 shows a more detailed breakdown of the capital costs, along with owners costs, TOC, and TASC.

Exhibit 3-28 shows the initial and annual O&M costs.

The estimated TOC of the GEE gasifier with no CO2 capture is $2,447/kW. Process contingency represents 2.0 percent of the TOC and project contingency represents 10.8 percent. The COE is 76.3 mills/kWh.

124

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-26 Case 1 Total Plant Cost Summary Client: USDOE/NETL Report Date: 2009-Oct-08 Project: Bituminous Baseline Study TOTAL PLANT COST

SUMMARY

Case: Case 1 - GEE Radiant 640MW IGCC w/o CO2 Plant Size: 622.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING $13,912 $2,585 $10,788 $0 $0 $27,285 $2,477 $0 $5,952 $35,714 $57 2 COAL & SORBENT PREP & FEED $23,713 $4,326 $14,245 $0 $0 $42,284 $3,844 $1,535 $9,533 $57,195 $92 3 FEEDWATER & MISC. BOP SYSTEMS $9,622 $7,783 $9,458 $0 $0 $26,863 $2,531 $0 $6,737 $36,131 $58 4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $111,116 $0 $60,871 $0 $0 $171,987 $15,755 $23,878 $32,445 $244,065 $392 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $160,703 $0 w/equip. $0 $0 $160,703 $15,577 $0 $17,628 $193,908 $312 4.4-4.9 Other Gasification Equipment $7,664 $11,266 $12,070 $0 $0 $31,001 $3,020 $0 $7,624 $41,645 $67 SUBTOTAL 4 $279,483 $11,266 $72,942 $0 $0 $363,691 $34,352 $23,878 $57,697 $479,618 $771 5A GAS CLEANUP & PIPING $57,957 $3,800 $55,494 $0 $0 $117,251 $11,380 $93 $25,944 $154,668 $249 5B CO2 REMOVAL & COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $85,752 $0 $6,269 $0 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $186 6.2-6.9 Combustion Turbine Other $5,928 $887 $1,801 $0 $0 $8,615 $816 $0 $1,721 $11,152 $18 SUBTOTAL 6 $91,679 $887 $8,070 $0 $0 $100,636 $9,540 $4,601 $12,256 $127,033 $204 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $35,357 $0 $5,027 $0 $0 $40,384 $3,840 $0 $4,422 $48,646 $78 7.2-7.9 SCR System, Ductwork and Stack $3,329 $2,373 $3,108 $0 $0 $8,810 $817 $0 $1,566 $11,193 $18 SUBTOTAL 7 $38,685 $2,373 $8,136 $0 $0 $49,194 $4,657 $0 $5,989 $59,839 $96 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $29,111 $0 $4,994 $0 $0 $34,104 $3,272 $0 $3,738 $41,114 $66 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $10,373 $1,001 $7,239 $0 $0 $18,613 $1,694 $0 $4,041 $24,348 $39 SUBTOTAL 8 $39,483 $1,001 $12,233 $0 $0 $52,718 $4,967 $0 $7,778 $65,462 $105 9 COOLING WATER SYSTEM $9,649 $9,237 $7,877 $0 $0 $26,763 $2,486 $0 $5,971 $35,220 $57 10 ASH/SPENT SORBENT HANDLING SYS $14,359 $8,029 $14,555 $0 $0 $36,943 $3,559 $0 $4,363 $44,864 $72 11 ACCESSORY ELECTRIC PLANT $28,222 $10,643 $21,238 $0 $0 $60,103 $5,165 $0 $12,277 $77,546 $125 12 INSTRUMENTATION & CONTROL $10,249 $1,885 $6,603 $0 $0 $18,737 $1,698 $937 $3,561 $24,933 $40 13 IMPROVEMENTS TO SITE $3,349 $1,974 $8,263 $0 $0 $13,586 $1,341 $0 $4,478 $19,405 $31 14 BUILDINGS & STRUCTURES $0 $6,725 $7,701 $0 $0 $14,427 $1,314 $0 $2,573 $18,313 $29 TOTAL COST $620,363 $72,516 $257,603 $0 $0 $950,481 $89,310 $31,044 $165,109 $1,235,944 $1,987 125

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-27 Case 1 Total Plant Cost Details Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $3,653 $0 $1,785 $0 $0 $5,439 $487 $0 $1,185 $7,111 $11 1.2 Coal Stackout & Reclaim $4,721 $0 $1,144 $0 $0 $5,865 $514 $0 $1,276 $7,655 $12 1.3 Coal Conveyors & Yd Crush $4,389 $0 $1,132 $0 $0 $5,522 $485 $0 $1,201 $7,207 $12 1.4 Other Coal Handling $1,148 $0 $262 $0 $0 $1,410 $123 $0 $307 $1,840 $3 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,585 $6,464 $0 $0 $9,049 $867 $0 $1,983 $11,900 $19 SUBTOTAL 1. $13,912 $2,585 $10,788 $0 $0 $27,285 $2,477 $0 $5,952 $35,714 $57 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying w/ 2.3 $0 w/ 2.3 $0 $0 $0 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,558 $373 $244 $0 $0 $2,175 $186 $0 $472 $2,833 $5 2.3 Slurry Prep & Feed $21,299 $0 $9,398 $0 $0 $30,697 $2,789 $1,535 $7,004 $42,025 $68 2.4 Misc.Coal Prep & Feed $857 $623 $1,869 $0 $0 $3,349 $308 $0 $731 $4,388 $7 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,330 $2,734 $0 $0 $6,063 $562 $0 $1,325 $7,950 $13 SUBTOTAL 2. $23,713 $4,326 $14,245 $0 $0 $42,284 $3,844 $1,535 $9,533 $57,195 $92 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,896 $4,974 $2,626 $0 $0 $10,496 $972 $0 $2,294 $13,762 $22 3.2 Water Makeup & Pretreating $620 $65 $347 $0 $0 $1,031 $98 $0 $339 $1,469 $2 3.3 Other Feedwater Subsystems $1,585 $536 $482 $0 $0 $2,602 $234 $0 $567 $3,403 $5 3.4 Service Water Systems $355 $731 $2,536 $0 $0 $3,621 $353 $0 $1,192 $5,167 $8 3.5 Other Boiler Plant Systems $1,904 $738 $1,829 $0 $0 $4,471 $424 $0 $979 $5,874 $9 3.6 FO Supply Sys & Nat Gas $315 $596 $556 $0 $0 $1,467 $141 $0 $322 $1,930 $3 3.7 Waste Treatment Equipment $867 $0 $529 $0 $0 $1,395 $136 $0 $459 $1,991 $3 3.8 Misc. Power Plant Equipment $1,080 $145 $554 $0 $0 $1,779 $172 $0 $585 $2,536 $4 SUBTOTAL 3. $9,622 $7,783 $9,458 $0 $0 $26,863 $2,531 $0 $6,737 $36,131 $58 4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $111,116 $0 $60,871 $0 $0 $171,987 $15,755 $23,878 $32,445 $244,065 $392 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $160,703 $0 w/equip. $0 $0 $160,703 $15,577 $0 $17,628 $193,908 $312 4.4 Scrubber & Low Temperature Cooling $5,873 $4,781 $4,975 $0 $0 $15,629 $1,501 $0 $3,426 $20,556 $33 4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Other Gasification Equipment $1,791 $0 $1,681 $0 $0 $3,472 $417 $0 $948 $4,837 $8 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $6,486 $5,414 $0 $0 $11,900 $1,103 $0 $3,251 $16,253 $26 SUBTOTAL 4. $279,483 $11,266 $72,942 $0 $0 $363,691 $34,352 $23,878 $57,697 $479,618 $771 126

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-27 Case 1 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 5A GAS CLEANUP & PIPING 5A.1 Single Stage Selexol $41,961 $0 $35,605 $0 $0 $77,565 $7,501 $0 $17,013 $102,080 $164 5A.2 Elemental Sulfur Plant $10,055 $2,004 $12,972 $0 $0 $25,031 $2,431 $0 $5,493 $32,955 $53 5A.3 Mercury Removal $1,057 $0 $804 $0 $0 $1,862 $180 $93 $427 $2,561 $4 5A.4 COS Hydrolysis $3,575 $0 $4,668 $0 $0 $8,243 $801 $0 $1,809 $10,853 $17 5A.5 Particulate Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $1,310 $0 $248 $0 $0 $1,558 $190 $0 $350 $2,098 $3 5A.7 Fuel Gas Piping $0 $688 $482 $0 $0 $1,170 $108 $0 $256 $1,534 $2 5A.9 HGCU Foundations $0 $1,108 $714 $0 $0 $1,822 $167 $0 $597 $2,586 $4 SUBTOTAL 5A. $57,957 $3,800 $55,494 $0 $0 $117,251 $11,380 $93 $25,944 $154,668 $249 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5B. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $85,752 $0 $6,269 $0 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $186 6.2 Syngas Expander $5,928 $0 $819 $0 $0 $6,747 $641 $0 $1,108 $8,496 $14 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $887 $982 $0 $0 $1,868 $175 $0 $613 $2,656 $4 SUBTOTAL 6. $91,679 $887 $8,070 $0 $0 $100,636 $9,540 $4,601 $12,256 $127,033 $204 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $35,357 $0 $5,027 $0 $0 $40,384 $3,840 $0 $4,422 $48,646 $78 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,706 $1,217 $0 $0 $2,923 $256 $0 $636 $3,816 $6 7.4 Stack $3,329 $0 $1,250 $0 $0 $4,579 $439 $0 $502 $5,519 $9 7.9 HRSG,Duct & Stack Foundations $0 $667 $640 $0 $0 $1,307 $122 $0 $429 $1,858 $3 SUBTOTAL 7. $38,685 $2,373 $8,136 $0 $0 $49,194 $4,657 $0 $5,989 $59,839 $96 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $29,111 $0 $4,994 $0 $0 $34,104 $3,272 $0 $3,738 $41,114 $66 8.2 Turbine Plant Auxiliaries $202 $0 $463 $0 $0 $665 $65 $0 $73 $803 $1 8.3 Condenser & Auxiliaries $5,053 $0 $1,484 $0 $0 $6,537 $625 $0 $716 $7,878 $13 8.4 Steam Piping $5,117 $0 $3,600 $0 $0 $8,717 $749 $0 $2,367 $11,833 $19 8.9 TG Foundations $0 $1,001 $1,693 $0 $0 $2,694 $255 $0 $885 $3,835 $6 SUBTOTAL 8. $39,483 $1,001 $12,233 $0 $0 $52,718 $4,967 $0 $7,778 $65,462 $105 127

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-27 Case 1 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 9 COOLING WATER SYSTEM 9.1 Cooling Towers $6,699 $0 $1,219 $0 $0 $7,918 $754 $0 $1,301 $9,973 $16 9.2 Circulating Water Pumps $1,737 $0 $122 $0 $0 $1,859 $157 $0 $302 $2,318 $4 9.3 Circ.Water System Auxiliaries $147 $0 $21 $0 $0 $168 $16 $0 $28 $211 $0 9.4 Circ.Water Piping $0 $6,124 $1,588 $0 $0 $7,712 $697 $0 $1,682 $10,090 $16 9.5 Make-up Water System $343 $0 $490 $0 $0 $833 $80 $0 $183 $1,096 $2 9.6 Component Cooling Water Sys $723 $865 $615 $0 $0 $2,203 $206 $0 $482 $2,891 $5 9.9 Circ.Water System Foundations $0 $2,248 $3,822 $0 $0 $6,071 $576 $0 $1,994 $8,640 $14 SUBTOTAL 9. $9,649 $9,237 $7,877 $0 $0 $26,763 $2,486 $0 $5,971 $35,220 $57 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $11,822 $6,519 $13,243 $0 $0 $31,584 $3,048 $0 $3,463 $38,095 $61 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $575 $0 $626 $0 $0 $1,201 $116 $0 $198 $1,515 $2 10.7 Ash Transport & Feed Equipment $771 $0 $186 $0 $0 $957 $89 $0 $157 $1,204 $2 10.8 Misc. Ash Handling Equipment $1,191 $1,460 $436 $0 $0 $3,087 $294 $0 $507 $3,888 $6 10.9 Ash/Spent Sorbent Foundation $0 $51 $64 $0 $0 $115 $11 $0 $38 $163 $0 SUBTOTAL 10. $14,359 $8,029 $14,555 $0 $0 $36,943 $3,559 $0 $4,363 $44,864 $72 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $958 $0 $947 $0 $0 $1,905 $182 $0 $209 $2,296 $4 11.2 Station Service Equipment $3,920 $0 $353 $0 $0 $4,273 $394 $0 $467 $5,134 $8 11.3 Switchgear & Motor Control $7,247 $0 $1,318 $0 $0 $8,565 $794 $0 $1,404 $10,763 $17 11.4 Conduit & Cable Tray $0 $3,366 $11,106 $0 $0 $14,472 $1,400 $0 $3,968 $19,840 $32 11.5 Wire & Cable $0 $6,432 $4,226 $0 $0 $10,658 $774 $0 $2,858 $14,291 $23 11.6 Protective Equipment $0 $686 $2,496 $0 $0 $3,182 $311 $0 $524 $4,017 $6 11.7 Standby Equipment $236 $0 $230 $0 $0 $466 $44 $0 $77 $587 $1 11.8 Main Power Transformers $15,862 $0 $146 $0 $0 $16,008 $1,211 $0 $2,583 $19,801 $32 11.9 Electrical Foundations $0 $158 $416 $0 $0 $574 $55 $0 $189 $818 $1 SUBTOTAL 11. $28,222 $10,643 $21,238 $0 $0 $60,103 $5,165 $0 $12,277 $77,546 $125 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,012 $0 $676 $0 $0 $1,687 $160 $84 $290 $2,221 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $233 $0 $149 $0 $0 $382 $36 $19 $87 $524 $1 12.7 Computer & Accessories $5,397 $0 $173 $0 $0 $5,570 $511 $278 $636 $6,995 $11 12.8 Instrument Wiring & Tubing $0 $1,885 $3,854 $0 $0 $5,739 $487 $287 $1,628 $8,141 $13 12.9 Other I & C Equipment $3,608 $0 $1,752 $0 $0 $5,359 $504 $268 $920 $7,051 $11 SUBTOTAL 12. $10,249 $1,885 $6,603 $0 $0 $18,737 $1,698 $937 $3,561 $24,933 $40 128

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-27 Case 1 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $105 $2,246 $0 $0 $2,351 $233 $0 $775 $3,360 $5 13.2 Site Improvements $0 $1,869 $2,483 $0 $0 $4,352 $429 $0 $1,435 $6,216 $10 13.3 Site Facilities $3,349 $0 $3,534 $0 $0 $6,883 $679 $0 $2,268 $9,830 $16 SUBTOTAL 13. $3,349 $1,974 $8,263 $0 $0 $13,586 $1,341 $0 $4,478 $19,405 $31 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,446 $3,484 $0 $0 $5,930 $546 $0 $971 $7,447 $12 14.3 Administration Building $0 $845 $613 $0 $0 $1,459 $130 $0 $238 $1,827 $3 14.4 Circulation Water Pumphouse $0 $167 $88 $0 $0 $255 $22 $0 $42 $319 $1 14.5 Water Treatment Buildings $0 $518 $506 $0 $0 $1,024 $93 $0 $167 $1,284 $2 14.6 Machine Shop $0 $433 $296 $0 $0 $729 $65 $0 $119 $912 $1 14.7 Warehouse $0 $699 $451 $0 $0 $1,149 $102 $0 $188 $1,439 $2 14.8 Other Buildings & Structures $0 $418 $326 $0 $0 $744 $66 $0 $162 $973 $2 14.9 Waste Treating Building & Str. $0 $935 $1,787 $0 $0 $2,723 $254 $0 $595 $3,572 $6 SUBTOTAL 14. $0 $6,725 $7,701 $0 $0 $14,427 $1,314 $0 $2,573 $18,313 $29 TOTAL COST $620,363 $72,516 $257,603 $0 $0 $950,481 $89,310 $31,044 $165,109 $1,235,944 $1,987 Owner's Costs Preproduction Costs 6 Months All Labor $12,214 $20 1 Month Maintenance Materials $2,742 $4 1 Month Non-fuel Consumables $269 $0 1 Month Waste Disposal $304 $0 25% of 1 Months Fuel Cost at 100% CF $1,627 $3 2% of TPC $24,719 $40 Total $41,874 $67 Inventory Capital 60 day supply of fuel and consumables at 100% CF $13,328 $21 0.5% of TPC (spare parts) $6,180 $10 Total $19,507 $31 Initial Cost for Catalyst and Chemicals $4,892 $8 Land $900 $1 Other Owner's Costs $185,392 $298 Financing Costs $33,370 $54 Total Overnight Costs (TOC) $1,521,880 $2,447 TASC Multiplier (IOU, high-risk, 35 year) 1.140 Total As-Spent Cost (TASC) $1,734,944 $2,789 129

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-28 Case 1 Initial and Annual O&M Costs INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 1 - GEE Radiant 640MW IGCC w/o CO2 Heat Rate-net (Btu/kWh): 8,756 MWe-net: 622 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant Skilled Operator 2.0 2.0 Operator 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 3.0 3.0 TOTAL-O.J.'s 15.0 15.0 Annual Cost Annual Unit Cost

$ $/kW-net Annual Operating Labor Cost $5,918,913 $9.515 Maintenance Labor Cost $13,622,877 $21.900 Administrative & Support Labor $4,885,447 $7.854 Property Taxes and Insurance $24,718,883 $39.738 TOTAL FIXED OPERATING COSTS $49,146,120 $79.007 VARIABLE OPERATING COSTS

$/kWh-net Maintenance Material Cost $26,322,759 $0.00604 Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water (/1000 gallons) 0 3,409 1.08 $0 $1,076,793 $0.00025 Chemicals MU & WT Chem. (lbs) 0 20,311 0.17 $0 $1,026,436 $0.00024 Carbon (Mercury Removal) (lb) 54,833 75 1.05 $57,584 $23,034 $0.00001 COS Catalyst (m3) 422 0.29 2,397.36 $1,011,578 $202,316 $0.00005 Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 $0.00000 Selexol Solution (gal) 285,358 45 13.40 $3,823,295 $175,961 $0.00004 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 1.94 131.27 $0 $74,422 $0.00002 Subtotal Chemicals $4,892,457 $1,502,168 $0.00034 Other Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 $0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $0 $0.00000 Waste Disposal Spent Mercury Catalyst (lb.) 0 75 0.42 $0 $9,148 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 615 16.23 $0 $2,912,403 $0.00067 Subtotal-Waste Disposal $0 $2,921,551 $0.00067 By-products & Emissions Sulfur (tons) 0 140 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000 TOTAL VARIABLE OPERATING COSTS $4,892,457 $31,823,271 $0.00730 Fuel (ton) 0 5,603 38.18 $0 $62,470,676 $0.01433 130

Cost and Performance Baseline for Fossil Energy Plants 3.2.8 Case 2 - GEE IGCC with CO2 Capture Case 2 is configured to produce electric power with CO2 capture. The plant configuration is the same as Case 1, namely two gasifier trains, two advanced F Class turbines, two HRSGs, and one steam turbine. The gross power output from the plant is constrained by the capacity of the two CTs, and since the CO2 capture process increases the auxiliary load on the plant, the net output is significantly reduced relative to Case 1.

The process description for Case 2 is similar to Case 1 with several notable exceptions to accommodate CO2 capture. A BFD and stream tables for Case 2 are shown in Exhibit 3-29 and Exhibit 3-30, respectively. Instead of repeating the entire process description, only differences from Case 1 are reported here.

Gasification The gasification process is the same as Case 1 with the exception that total coal feed to the two gasifiers is 5,302 tonnes/day (5,844 TPD) (stream 6) and the ASU provides 4,342 tonnes/day (4,786 TPD) of 95 percent oxygen to the gasifier and Claus plant (streams 3 and 5).

Raw Gas Cooling/Particulate Removal Raw gas cooling and particulate removal are the same as Case 1 with the exception that approximately 443,118 kg/hr (976,891 lb/hr) of saturated steam at 13.8 MPa (2,000 psia) is generated in the radiant SGCs.

Syngas Scrubber/Sour Water Stripper No differences from Case 1.

SGS The SGS process was described in Section 3.1.3. In Case 2 steam (stream 11) is added to the syngas exiting the scrubber to adjust the H2O:CO molar ratio to 2:1 prior to the first SGS reactor.

The hot syngas exiting the first stage of SGS is used to generate the steam that is added in stream

11. A second stage of SGS results in 97 percent overall conversion of the CO to CO2. The warm syngas from the second stage of SGS (stream 12) is cooled to 236°C (456°F) by preheating the unshifted syngas prior to the SGS. The SGS catalyst also serves to hydrolyze COS thus eliminating the need for a separate COS hydrolysis reactor. Following the second SGS cooler the syngas is further cooled to 35°C (95°F) prior to the mercury removal beds.

Mercury Removal and AGR Mercury removal is the same as in Case 1.

The AGR process in Case 2 is a two stage Selexol process where H2S is removed in the first stage and CO2 in the second stage of absorption as previously described in Section 3.1.5. The process results in three product streams, the clean syngas, a CO2-rich stream and an acid gas feed to the Claus plant. The acid gas (stream 18) contains 35 percent H2S and 52 percent CO2 with the balance primarily N2. The CO2-rich stream is discussed further in the CO2 compression section.

131

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-29 Case 2 Block Flow Diagram, GEE IGCC with CO2 Capture 132

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-30 Case 2 Stream Table, GEE IGCC with CO2 Capture 1 2 3 4 5 6 7 8 9 10 11 12 V-L Mole Fraction Ar 0.0092 0.0166 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0054 CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0007 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2823 0.0000 0.0060 CO2 0.0003 0.0054 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1089 0.0000 0.3082 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2689 0.0000 0.4366 H2O 0.0099 0.1363 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3190 1.0000 0.2325 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0000 0.0001 H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0047 N2 0.7732 0.7061 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0044 NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0013 O2 0.2074 0.1356 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 V-L Flowrate (kgmol/hr) 27,361 1,650 96 20,051 5,526 0 5,037 0 23,122 29,284 7,193 36,478 V-L Flowrate (kg/hr) 789,560 45,332 3,080 562,615 177,828 0 90,748 0 465,243 575,983 129,587 705,570 Solids Flowrate (kg/hr) 0 0 0 0 0 220,904 0 24,237 0 0 0 0 Temperature (°C) 15 18 32 93 32 15 142 1,316 677 206 288 240 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.52 5.52 5.41 Enthalpy (kJ/kg)A 30.23 35.64 26.67 92.50 26.67 --- 537.77 --- 1,424.65 1,065.71 2,918.18 942.21 Density (kg/m3) 1.2 1.5 11.0 24.4 11.0 --- 872.0 --- 14.0 27.2 25.6 24.8 V-L Molecular Weight 28.857 27.476 32.181 28.060 32.181 --- 18.015 --- 20.121 19.669 18.015 19.343 V-L Flowrate (lbmol/hr) 60,321 3,637 211 44,204 12,183 0 11,106 0 50,976 64,561 15,858 80,419 V-L Flowrate (lb/hr) 1,740,683 99,940 6,791 1,240,354 392,044 0 200,064 0 1,025,685 1,269,825 285,691 1,555,516 Solids Flowrate (lb/hr) 0 0 0 0 0 487,011 0 53,433 0 0 0 0 Temperature (°F) 59 65 90 199 90 59 287 2,400 1,250 403 550 463 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 785.0 Enthalpy (Btu/lb)A 13.0 15.3 11.5 39.8 11.5 --- 231.2 --- 612.5 458.2 1,254.6 405.1 Density (lb/ft 3) 0.076 0.091 0.687 1.521 0.687 --- 54.440 --- 0.871 1.699 1.597 1.550 A - Reference conditions are 32.02 F & 0.089 PSIA 133

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-30 Case 2 Stream Table, GEE IGCC with CO2 Capture (Continued) 13 14 15 16 17 18 19 20 21 22 23 24 V-L Mole Fraction Ar 0.0071 0.0071 0.0115 0.0115 0.0002 0.0018 0.0000 0.0103 0.0092 0.0091 0.0091 0.0000 CH4 0.0009 0.0009 0.0015 0.0015 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.0078 0.0077 0.0124 0.0124 0.0002 0.0022 0.0000 0.0064 0.0000 0.0000 0.0000 0.0000 CO2 0.4019 0.4055 0.0502 0.0502 0.9948 0.5214 0.0000 0.6664 0.0003 0.0083 0.0083 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2 0.5692 0.5649 0.9139 0.9139 0.0048 0.1028 0.0000 0.2561 0.0000 0.0000 0.0000 0.0000 H2O 0.0012 0.0013 0.0001 0.0001 0.0000 0.0226 0.0000 0.0017 0.0099 0.1222 0.1222 1.0000 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2S 0.0061 0.0061 0.0000 0.0000 0.0000 0.3477 0.0000 0.0050 0.0000 0.0000 0.0000 0.0000 N2 0.0058 0.0064 0.0105 0.0105 0.0000 0.0008 0.0000 0.0542 0.7732 0.7541 0.7541 0.0000 NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1064 0.1064 0.0000 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 V-L Flowrate (kgmol/hr) 27,978 28,368 17,423 17,423 10,425 497 0 390 110,253 139,657 139,657 34,500 V-L Flowrate (kg/hr) 552,391 564,920 90,179 90,179 456,650 17,684 0 12,529 3,181,557 3,834,352 3,834,352 621,521 Solids Flowrate (kg/hr) 0 0 0 0 0 0 5,524 0 0 0 0 0 Temperature (°C) 35 35 35 196 51 48 178 38 15 562 132 534 Pressure (MPa, abs) 5.14 5.1 5.102 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512 Enthalpy (kJ/kg)A 37.11 36.4 195.532 1,124.237 -162.306 74.865 --- 5.295 30.227 834.762 343.819 3,432.885 Density (kg/m3) 40.7 40.9 10.1 4.2 641.8 2.2 5,280.5 77.9 1.2 0.4 0.9 36.7 V-L Molecular Weight 19.744 20 5.176 5.176 43.805 35.588 --- 32.153 28.857 27.455 27.455 18.015 V-L Flowrate (lbmol/hr) 61,681 62,540 38,412 38,412 22,983 1,095 0 859 243,066 307,891 307,891 76,059 V-L Flowrate (lb/hr) 1,217,813 1,245,436 198,810 198,810 1,006,740 38,986 0 27,622 7,014,133 8,453,299 8,453,299 1,370,220 Solids Flowrate (lb/hr) 0 0 0 0 0 0 12,178 0 0 0 0 0 Temperature (°F) 95 95 95 384 124 119 352 100 59 1,044 270 994 Pressure (psia) 745.0 740.0 740.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7 Enthalpy (Btu/lb)A 16.0 15.7 84.1 483.3 -69.8 32.2 --- 2.3 13.0 358.9 147.8 1,475.9 Density (lb/ft 3) 2.544 3 0.630 0.260 40.068 0.137 329.649 4.864 0.076 0.026 0.053 2.293 134

Cost and Performance Baseline for Fossil Energy Plants CO2 Compression and Dehydration CO2 from the AGR process is flashed at three pressure levels to separate CO2 and decrease H2 losses to the CO2 product pipeline. The HP CO2 stream is flashed at 2.0 MPa (289.7 psia),

compressed, and recycled back to the CO2 absorber. The MP CO2 stream is flashed at 1.0 MPa (149.7 psia). The LP CO2 stream is flashed at 0.1 MPa (16.7 psia), compressed to 1.0 MPa (149.5 psia), and combined with the MP CO2 stream. The combined stream is compressed from 2.1 MPa (149.5 psia) to a SC condition at 15.3 MPa (2,215 psia) using a multiple-stage, intercooled compressor. During compression, the CO2 stream is dehydrated to a dewpoint of

-40ºC (-40°F) with triethylene glycol. The raw CO2 stream from the Selexol process contains over 99 percent CO2. The CO2 (stream 17) is transported to the plant fence line and is sequestration ready. CO2 TS&M costs were estimated using the methodology described in Section 2.7.

Claus Unit The Claus plant is the same as Case 1 with the following exceptions:

5,528 kg/hr (12,178 lb/hr) of sulfur (stream 19) are produced

The waste heat boiler generates 13,555 kg/hr (29,884 lb/hr) of 4.0 MPa (575 psia) steam of which 12,679 kg/hr (27,953 lb/hr) is available to the medium pressure steam header.

Power Block Clean syngas from the AGR plant is heated to 241°C (465°F) using HP BFW before passing through an expansion turbine. The clean syngas (stream 16) is diluted with nitrogen (stream 4) and then enters the CT burner. There is no integration between the CT and the ASU in this case.

The exhaust gas (stream 22) exits the CT at 562°C (1044°F) and enters the HRSG where additional heat is recovered. The FG exits the HRSG at 132°C (270°F) (stream 23) and is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced commercially available steam turbine using a 12.4 MPa/534°C/534°C (1800 psig/994°F/994°F) steam cycle.

Air Separation Unit (ASU)

The same elevated pressure ASU is used in Case 2 and produces 4,342 tonnes/day (4,786 TPD) of 95 mole% oxygen and 14,591 tonnes/day (16,084 TPD) of nitrogen. There is no integration between the ASU and the CT.

3.2.9 Case 2 Performance Results The Case 2 modeling assumptions were presented previously in Section 3.2.3.

The plant produces a net output of 543 MW at a net plant efficiency of 32.6 percent (HHV basis). Overall performance for the entire plant is summarized in Exhibit 3-31, which includes auxiliary power requirements. The ASU accounts for nearly 60 percent of the auxiliary load between the main air compressor, the nitrogen compressor, the oxygen compressor, and ASU auxiliaries. The two-stage Selexol process and CO2 compression account for an additional 26 percent of the auxiliary power load. The BFW pumps and cooling water system (CWPs and cooling tower fan) comprise over 6 percent of the load, leaving 8 percent of the auxiliary load for all other systems.

135

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-31 Case 2 Plant Performance Summary POWER

SUMMARY

(Gross Power at Generator Terminals, kWe)

Gas Turbine Power 464,000 Sweet Gas Expander Power 6,500 Steam Turbine Power 263,500 TOTAL POWER, kWe 734,000 AUXILIARY LOAD

SUMMARY

, kWe Coal Handling 470 Coal Milling 2,270 Sour Water Recycle Slurry Pump 190 Slag Handling 1,160 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 67,330 Oxygen Compressor 10,640 Nitrogen Compressors 35,640 CO2 Compressor 31,160 Boiler Feedwater Pumps 4,180 Condensate Pump 280 Quench Water Pump 540 Circulating Water Pump 4,620 Ground Water Pumps 530 Cooling Tower Fans 2,390 Scrubber Pumps 230 Acid Gas Removal 19,230 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 250 Claus Plant TG Recycle Compressor 1,780 Miscellaneous Balance of Plant2 3,000 Transformer Losses 2,760 TOTAL AUXILIARIES, kWe 190,750 NET POWER, kWe 543,250 Net Plant Efficiency, % (HHV) 32.6 Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,034 (10,458)

CONDENSER COOLING DUTY 106 kJ/hr (106 Btu/hr) 1,509 (1,430)

CONSUMABLES As-Received Coal Feed, kg/hr (lb/hr) 220,904 (487,011)

Thermal Input1, kWt 1,665,074 Raw Water Withdrawal, m3/min (gpm) 22.0 (5,815)

Raw Water Consumption, m3/min (gpm) 17.9 (4,739) 1 - HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 2 - Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads 136

Cost and Performance Baseline for Fossil Energy Plants Environmental Performance The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 2.4. A summary of the plant air emissions for Case 2 is presented in Exhibit 3-32.

Exhibit 3-32 Case 2 Air Emissions Tonne/year kg/GJ kg/MWh (tons/year) @

(lb/106 Btu) (lb/MWh) 80% capacity factor SO2 0.001 (0.002) 39 (43) 0.008 (.02)

NOx 0.021 (0.049) 878 (967) 0.171 (.376)

Particulates 0.003 (0.0071) 128 (141) 0.025 (.055)

Hg 2.46E-7 (5.71E-7) 0.010 (0.011) 2.01E-6 (4.42E-6)

CO2 8.5 (19.7) 355,438 (391,804) 69 (152)

CO21 93 (206) 1 CO2 emissions based on net power instead of gross power The low level of SO2 emissions is achieved by capture of the sulfur in the gas by the two-stage Selexol AGR process. As a result of achieving the 90 percent CO2 removal target, the sulfur compounds are removed to an extent that exceeds the environmental target in Section 2.4. The clean syngas exiting the AGR process has a sulfur concentration of approximately 5 ppmv. This results in a concentration in the FG of less than 1 ppmv. The H2S-rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species to H2S and then recycled back to the Selexol process, thereby eliminating the need for a tail gas treatment unit.

NOx emissions are limited by nitrogen dilution to 15 ppmvd (as NO2 @15 percent O2).

Ammonia in the syngas is removed with process condensate prior to the low-temperature AGR process. This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of the syngas quench in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only.

Ninety-five percent of mercury is captured from the syngas by an activated carbon bed.

Ninety-two percent of the CO2 from the syngas is captured in the AGR system and compressed for sequestration.

The carbon balance for the plant is shown in Exhibit 3-33. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected here since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag, as CO2 in the stack gas, ASU vent gas, and the captured CO2 product. The carbon capture efficiency is defined as the amount of carbon in the CO2 product stream relative to the amount of carbon in the coal less carbon contained in the slag, represented by the following fraction:

137

Cost and Performance Baseline for Fossil Energy Plants (Carbon in CO2 Product)/[(Carbon in the Coal)-(Carbon in Slag)] or 274,672/(310,444-6,209) *100 or 90.3 percent Exhibit 3-33 Case 2 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 140,815 (310,444) Slag 2,816 (6,209)

Air (CO2) 540 (1,191) Stack Gas 13,842 (30,516)

ASU Vent 107 (237)

CO2 Product 124,589 (274,672)

Total 141,355 (311,634) Total 141,355 (311,634)

Exhibit 3-34 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible.

Exhibit 3-34 Case 2 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 5,537 (12,207) Elemental Sulfur 5,524 (12,178)

Stack Gas 3 (6)

CO2 Product 10 (23)

Total 5,537 (12,207) Total 5,537 (12,207)

Exhibit 3-35 shows the overall water balance for the plant. The exhibit is presented in an identical manner for Case 1.

138

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-35 Case 2 Water Balance Process Water Internal Raw Water Water Raw Water Demand, Recycle, Withdrawal, Water Use Discharge, Consumption, m3/min m3/min m3/min m3/min m3/min (gpm)

(gpm) (gpm) (gpm)

(gpm)

Slag Handling 0.53 (139) 0.53 (139) 0.0 (0) 0.0 (0) 0.0 (0)

Slurry Water 1.51 (400) 1.51 (400) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.9 (757) 0.72 (191) 2.1 (566) 0.0 (0) 2.1 (566)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7) -0.03 (-7)

Condenser Makeup 2.4 (627) 0.0 (0) 2.4 (627) 0.0 (0) 2.4 (627)

Gasifier Steam Shift Steam 2.2 (571) 2.2 (571)

GT Steam Dilution BFW Makeup 0.21 (56) 0.21 (56)

Cooling Tower 18.0 (4,750) 0.49 (129) 17.5 (4,622) 4.0 (1,068) 13.5 (3,553)

BFW Blowdown 0.21 (56) -0.21 (-56)

SWS Blowdown 0.28 (73) -0.28 (-73)

SWS Excess Water Humidifier Tower Blowdown Total 25.3 (6,673) 3.25 (858) 22.0 (5,815) 4.1 (1,076) 17.9 (4,739)

Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-36 through Exhibit 3-38:

Coal gasification and ASU

Syngas cleanup, sulfur recovery, and tail gas recycle

Combined cycle power generation, steam, and FW An overall plant energy balance is presented in tabular form in Exhibit 3-39. The power out is the combined CT, steam turbine and expander power prior to generator losses. The power at the generator terminals (shown in Exhibit 3-31) is calculated by multiplying the power out by a combined generator efficiency of 98.3 percent.

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Cost and Performance Baseline for Fossil Energy Plants This page intentionally left blank 140

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-36 Case 2 Coal Gasification and Air Separation Units Heat and Mass Balance Schematic ASU 99,940 W LEGEND Vent 64.8 T 16.4 P Ambient Air Air 15.3 H 1

N2 to GT Combustor Coal/Char/

1,740,683 W 100.0 T 189.5 P 676,491 W Slurry/Slag 59.0 T 18.0 H 2 385.0 T 14.7 P Four Stage Air 384.0 P Nitrogen 13.0 H Compressor 87.2 H 676,491 W Oxygen 1,083,577 W 199.0 T 90.0 T 384.0 P 56.4 P 39.8 H Steam 14.2 H Elevated Synthesis Gas Four Stage N2 N2 Boost 5 Pressure 4 Compressor Compressor ASU 563,864 W 563,864 W 392,044 W N2 to GT Combustor 199.0 T 385.0 T Water 90.0 T 156,777 W 384.0 P 469.0 P 125.0 P 6,791 W 50.0 T 39.8 H 87.0 H 11.5 H 90.0 T 182.0 P Sour Water 2.9 H Raw Fuel Gas 125.0 P 10 11.5 H 3 To Claus Plant 1,269,825 W 403.1 T 800.0 P 458.2 H Four Stage O2 Compressor 1,025,685 W 1,403,986 W P ABSOLUTE PRESSURE, PSIA 392,044 W 1,250.0 T 450.0 T F TEMPERATURE, °F 241.2 T 487,011 W 805.0 P 805.0 P Process Water W FLOWRATE, LBM/HR 940.0 P 59.0 T 612.5 H 536.1 H From Sour Water Stripper H ENTHALPY, BTU/LBM 40.8 H Syngas Milled Coal 14.7 P MWE POWER, MEGAWATTS ELECTRICAL 687,075 W Scrubber 6

156.4 T NOTES:

840.0 P 2,950.2 H 7

Vent To Claus Unit

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA 200,064 W 287.0 T 840.0 P 231.2 H GE Energy Gasifier CWR 9

Slurry Mix Tank Syngas Quench HP BFW Knockout PLANT PERFORMANCE

SUMMARY

Drum Gross Plant Power: 734 MWe Radiant CWS Auxiliary Load: 191 MWe Syngas Black Net Plant Power: 543 MWe Cooler Water Net Plant Efficiency, HHV: 32.6%

Flash Net Plant Heat Rate: 10,458 BTU/KWe Saturated Steam Tank To HRSG HP Superheater DOE/NETL Slag Quench Section DUAL TRAIN IGCC PLANT CASE 2 HEAT AND MATERIAL FLOW DIAGRAM Drag BITUMINOUS BASELINE STUDY Conveyor Slag 53,433 W Fines CASE 2 8 2,400.0 T GEE GASIFIER 815.0 P ASU AND GASIFICATION DWG. NO. PAGES BB-HMB-CS-2-PG-1 1 OF 3 141

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-37 Case 2 Syngas Cleanup Heat and Mass Balance Schematic LEGEND Fuel Gas To GT Air 16 198,810 W Coal/Char/

Syngas 465.0 T Fuel Gas 198,810 W Slurry/Slag Preheater 735.0 P Expander 384.3 T 597.2 H 460.0 P Nitrogen 198,810 W 483.3 H 15 94.6 T 740.0 P Oxygen Claus Plant 84.1 H Catalytic Sour Gas Clean Gas Reactor Beds High Low Sour Water Temperature Temperature 1,555,516 W Shift #1 Shift #2 Furnace 436.4 T 1,245,436 W Acid Gas 18 Tail Steam 795.0 P 94.6 T Gas 598.0 H 38,986 W 740.0 P Synthesis Gas 119.0 T Shift Steam 15.7 H 776.2 T 400.0 T 23.7 P 285,691 W 795.0 P 795.0 P 14 Water 550.0 T 582.1 H 408.0 H 800.0 P 1,555,516 W 1,254.1 H 463.4 T Two-Stage 19 CO2 11 6,791 W 785.0 P 405.1 H Selexol CO2 450.0 T 124.5 P 12 91.9 H Tailgas 36,094 W 1,269,825 W Mercury 450.0 T 413.1 T P ABSOLUTE PRESSURE, PSIA Removal Claus Oxygen Sulfur 12.3 P 795.0 P F TEMPERATURE, °F Preheater 12,178 W 457.8 H 450.3 H 27,622 W W FLOWRATE, LBM/HR 1,217,813 W 100.0 T H ENTHALPY, BTU/LBM 20 Syngas 94.9 T 799.5 P MWE POWER, MEGAWATTS ELECTRICAL 13 From Coolers 745.0 P Multistage ASU NOTES:

16.0 H 3 COS Hydrolysis Intercooled CO2 6,791 W CO2 Product Preheater Knock Compressor 90.0 T 1,006,740 W Out 1,555,516 W 125.0 P 123.8 T Drum 1. ENTHALPY REFERENCE POINT IS NATURAL STATE 455.6 T 11.5 H 2,214.7 P AT 32 °F AND 0.08865 PSIA 17 780.0 P 401.5 H 10 Interstage Knockout Hydrogenation Raw Syngas and Tail Gas Sour Cooling PLANT PERFORMANCE

SUMMARY

Drum 1,269,825 W 403.1 T 800.0 P 2,495 W Gross Plant Power: 734 MWe 458.2 H 239.1 T Auxiliary Load: 191 MWe 65.0 P Net Plant Power: 543 MWe Sour 441.9 H Stripper Net Plant Efficiency, HHV: 32.6%

Net Plant Heat Rate: 10,458 BTU/KWe Tail Gas Recycle Compressor 30,072 W DOE/NETL Makeup Water 120.0 T 10.6 P 112.1 H DUAL TRAIN IGCC PLANT Knock Out CASE 2 Process Condensate to Syngas Scrubber 8,472 W HEAT AND MATERIAL FLOW DIAGRAM 114.3 T 10.6 P BITUMINOUS BASELINE STUDY 40.0 H CASE 2 GEE GASIFIER GAS CLEANUP SYSTEM DWG. NO. PAGES BB-HMB-CS-2-PG-2 2 OF 3 142

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-38 Case 2 Combined-Cycle Power Generation Heat and Mass Balance Schematic LEGEND LP Process Header Air HP BFW to Radiant Syngas Cooler Coal/Char/

HP Saturated Steam to HRSG Superheater Slurry/Slag Nitrogen 8,453,299 W 269.9 T Oxygen 15.2 P 147.8 H Sour Gas 22 HRSG 23 Stack 8,453,299 W LP Flash Tops Sour Water 1,043.8 T 15.2 P 10,303 W MP Flash Bottoms Steam Nitrogen Diluent 358.9 H 298.0 T From Gasifier 65.0 P Island Preheating 1,179.0 H Synthesis Gas 24 1,875,803 W 235.0 T Deaerator 1,370,220 W 105.0 P Water 993.8 T 203.7 H 1,814.7 P 1,399,040 W 1,475.9 H 278.8 T Flue Gas Fuel Gas 2,250.7 P LP BFW 16 252.3 H 198,810 W Blowdown 384.3 T 28,836 W Flash 460.0 P LP Pump P ABSOLUTE PRESSURE, PSIA 585.0 T To Claus 483.3 H 2,000.7 P F TEMPERATURE, °F To WWT 593.3 H HP Pump W FLOWRATE, LBM/HR IP BFW H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL IP Pump NOTES:

1,550,132 W Compressor Expander 474.9 T 65.0 P 1. ENTHALPY REFERENCE POINT IS NATURAL STATE 1,269.6 H AT 32 °F AND 0.08865 PSIA Generator HP IP LP Turbine Turbine Steam Turbine Advanced F-Class Turbine Gas Turbine Generator Intake Ip Extraction Steam PLANT PERFORMANCE

SUMMARY

To 250 PSIA Header 34,034 W 9,761 W Gross Plant Power: 734 MWe 798 W 9,026 W 1,337 W 852.1 T 614.9 T Auxiliary Load: 191 MWe 993.8 T 660.5 T 505.0 T 280.0 P 65.0 P Net Plant Power: 543 MWe 1,814.7 P 501.4 P 65.0 P 1,448.8 H 1,338.7 H Ambient Air Net Plant Efficiency, HHV: 32.6%

21 1,475.9 H 1,334.5 H 1,284.5 H Net Plant Heat Rate: 10,458 BTU/KWe 7,014,133 W Steam Seal CONDENSER Make-up Regulator 313,510 W 59.0 T 1,400 W 14.7 P 59.0 T 212.0 T 1,400 W HOT WELL 14.7 P 13.0 H 14.7 P DOE/NETL 614.9 T 27.1 H 179.9 H 65.0 P 1,875,803 W 1,338.7 H 101.1 T DUAL TRAIN IGCC PLANT 1.0 P CASE 2 69.1 H Condensate HEAT AND MATERIAL FLOW DIAGRAM Pump BITUMINOUS BASELINE STUDY Gland CASE 2 1,875,803 W 102.9 T Steam GEE GASIFIER 120.0 P Condenser POWER BLOCK SYSTEM Condensate to Gasification Island 71.1 H DWG. NO. PAGES BB-HMB-CS-2-PG-3 3 OF 3 143

Cost and Performance Baseline for Fossil Energy Plants This page intentionally left blank 144

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-39 Case 2 Overall Energy Balance (0°C [32°F] Reference)

Sensible +

HHV Power Total Latent Heat In GJ/hr (MMBtu/hr)

Coal 5,994 (5,681) 5.0 (4.7) 5,999 (5,686)

ASU Air 24 (23) 24 (23)

GT Air 96 (91) 96 (91)

Water 83 (78) 83 (78)

Auxiliary Power 687 (651) 687 (651)

TOTAL 5,994 (5,681) 208 (197) 687 (651) 6,889 (6,529)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 2 (2) 2 (2)

Slag 92 (88) 38 (36) 130 (123)

Sulfur 51 (49) 1 (1) 52 (49)

CO2 -74 (-70) -74 (-70)

Cooling Tower 30 (28) 30 (28)

Blowdown HRSG Flue Gas 1,318 (1,250) 1,318 (1,250)

Condenser 1,513 (1,434) 1,513 (1,434)

Non-Condenser Cooling Tower 632 (599) 632 (599)

Loads*

Process Losses** 643 (610) 643 (610)

Power 2,642 (2,505) 2,642 (2,505)

TOTAL 144 (136) 4,103 (3,889) 2,642 (2,505) 6,889 (6,529)

Includes ASU compressor intercoolers, CO2 compressor intercoolers, sour water stripper condenser, and syngas cooler (low level heat rejection).

- Calculated by difference to close the energy balance.

145

Cost and Performance Baseline for Fossil Energy Plants 3.2.10 Case 2 - Major Equipment List Major equipment items for the GEE gasifier with CO2 capture are shown in the following tables.

The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section 3.2.11. In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 COAL HANDLING Equipment Operating Description Type Design Condition Spares No. Qty.

Bottom Trestle Dumper and 1 N/A 181 tonne (200 ton) 2 0 Receiving Hoppers 2 Feeder Belt 572 tonne/hr (630 tph) 2 0 3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0 4 Transfer Tower No. 1 Enclosed N/A 1 0 5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0 As-Received Coal Sampling 6 Two-stage N/A 1 0 System 7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0 8 Reclaim Hopper N/A 45 tonne (50 ton) 2 1 9 Feeder Vibratory 181 tonne/hr (200 tph) 2 1 10 Conveyor No. 3 Belt w/ tripper 363 tonne/hr (400 tph) 1 0 11 Crusher Tower N/A N/A 1 0 12 Coal Surge Bin w/ Vent Filter Dual outlet 181 tonne (200 ton) 2 0 Impactor 8 cm x 0 - 3 cm x 0 13 Crusher 2 0 reduction (3" x 0 1/4" x 0)

As-Fired Coal Sampling 14 Swing hammer N/A 1 1 System 15 Conveyor No. 4 Belt w/tripper 363 tonne/hr (400 tph) 1 0 16 Transfer Tower No. 2 Enclosed N/A 1 0 17 Conveyor No. 5 Belt w/ tripper 363 tonne/hr (400 tph) 1 0 Coal Silo w/ Vent Filter and 18 Field erected 816 tonne (900 ton) 3 0 Slide Gates 146

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 2 COAL PREPARATION AND FEED Equipment Operating Description Type Design Condition Spares No. Qty.

1 Feeder Vibratory 82 tonne/h (90 tph) 3 0 2 Conveyor No. 6 Belt w/tripper 245 tonne/h (270 tph) 1 0 3 Rod Mill Feed Hopper Dual Outlet 490 tonne (540 ton) 1 0 4 Weigh Feeder Belt 118 tonne/h (130 tph) 2 0 5 Rod Mill Rotary 118 tonne/h (130 tph) 2 0 Slurry Water Storage Tank 6 Field erected 299,921 liters (79,230 gal) 2 0 with Agitator 7 Slurry Water Pumps Centrifugal 833 lpm (220 gpm) 2 1 8 Trommel Screen Coarse 172 tonne/h (190 tph) 2 0 Rod Mill Discharge Tank with 9 Field erected 392,323 liters (103,640 gal) 2 0 Agitator 10 Rod Mill Product Pumps Centrifugal 3,407 lpm (900 gpm) 2 2 Slurry Storage Tank with 11 Field erected 1,176,894 liters (310,900 gal) 2 0 Agitator 12 Slurry Recycle Pumps Centrifugal 6,435 lpm (1,700 gpm) 2 2 Positive 13 Slurry Product Pumps 3,407 lpm (900 gpm) 2 2 displacement 147

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment Operating Description Type Design Condition Spares No. Qty.

Demineralized Water Vertical, cylindrical, 1 1,093,984 liters (289,000 gal) 2 0 Storage Tank outdoor 7,836 lpm @ 91 m H2O 2 Condensate Pumps Vertical canned 2 1 (2,070 gpm @ 300 ft H2O)

Deaerator (integral w/

3 Horizontal spray type 546,579 kg/hr (1,205,000 lb/hr) 2 0 HRSG)

Intermediate Pressure Horizontal centrifugal, 8,025 lpm @ 27 m H2O 4 2 1 Feedwater Pump single stage (2,120 gpm @ 90 ft H2O)

HP water: 6,057 lpm @ 1,859 m High Pressure Barrel type, multi-stage, 5 H2O (1,600 gpm @ 6,100 ft 2 1 Feedwater Pump No. 1 centrifugal H2O)

High Pressure Barrel type, multi-stage, IP water: 1,703 lpm @ 223 m 6 2 1 Feedwater Pump No. 2 centrifugal H2O (450 gpm @ 730 ft H2O)

Shop fabricated, water 18,144 kg/hr, 2.8 MPa, 343°C 7 Auxiliary Boiler 1 0 tube (40,000 lb/hr, 400 psig, 650°F)

Service Air 28 m3/min @ 0.7 MPa 8 Flooded Screw 2 1 Compressors (1,000 scfm @ 100 psig) 9 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1 Closed Cylce Cooling 10 Plate and frame 362 GJ/hr (343 MMBtu/hr) each 2 0 Heat Exchangers Closed Cycle Cooling 129,840 lpm @ 21 m H2O 11 Horizontal centrifugal 2 1 Water Pumps (34,300 gpm @ 70 ft H2O)

Engine-Driven Fire Vertical turbine, diesel 3,785 lpm @ 107 m H2O 12 1 1 Pump engine (1,000 gpm @ 350 ft H2O)

Fire Service Booster Two-stage horizontal 2,650 lpm @ 76 m H2O 13 1 1 Pump centrifugal (700 gpm @ 250 ft H2O)

Stainless steel, single 5,716 lpm @ 18 m H2O 14 Raw Water Pumps 2 1 suction (1,510 gpm @ 60 ft H2O)

Stainless steel, single 2,839 lpm @ 268 m H2O 15 Ground Water Pumps 4 1 suction (750 gpm @ 880 ft H2O)

Stainless steel, single 3,369 lpm @ 49 m H2O 16 Filtered Water Pumps 2 1 suction (890 gpm @ 160 ft H2O) 17 Filtered Water Tank Vertical, cylindrical 1,608,800 liter (425,000 gal) 2 0 Makeup Water Anion, cation, and 18 1,476 lpm (390 gpm) 2 0 Demineralizer mixed bed Liquid Waste Treatment 19 10 years, 24-hour storm 1 0 System 148

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY Equipment Operating Description Type Design Condition Spares No. Qty.

Pressurized slurry-feed, 2,903 tonne/day, 5.6 MPa 1 Gasifier 2 0 entrained bed (3,200 tpd, 814.96 psia)

Vertical downflow radiant heat exchanger 2 Synthesis Gas Cooler 255,826 kg/hr (564,000 lb/hr) 2 0 with outlet quench chamber Syngas Scrubber 3 Including Sour Water Vertical upflow 350,173 kg/hr (772,000 lb/hr) 2 0 Stripper Shell and tube with 4 Raw Gas Coolers 388,275 kg/hr (856,000 lb/hr) 8 0 condensate drain Raw Gas Knockout Vertical with mist 304,360 kg/hr, 35°C, 5.2 MPa 5 2 0 Drum eliminator (671,000 lb/hr, 95°F, 750 psia)

Self-supporting, carbon 350,173 kg/hr (772,000 lb/hr) 6 Flare Stack steel, stainless steel top, 2 0 syngas pilot ignition ASU Main Air 5,947 m3/min @ 1.3 MPa 7 Centrifugal, multi-stage 2 0 Compressor (210,000 scfm @ 190 psia) 2,359 tonne/day (2,600 tpd) of 8 Cold Box Vendor design 2 0 95% purity oxygen 1,189 m3/min (42,000 scfm) 9 Oxygen Compressor Centrifugal, multi-stage Suction - 0.9 MPa (130 psia) 2 0 Discharge - 6.5 MPa (940 psia) 3,794 m3/min (134,000 scfm)

Primary Nitrogen 10 Centrifugal, multi-stage Suction - 0.4 MPa (60 psia) 2 0 Compressor Discharge - 2.7 MPa (390 psia) 538 m3/min (19,000 scfm)

Secondary Nitrogen 11 Centrifugal, single-stage Suction - 1.2 MPa (180 psia) 2 0 Compressor Discharge - 2.7 MPa (390 psia) 1,982 m3/min (70,000 scfm)

Syngas Dilution Nitrogen 12 Centrifugal, single-stage Suction - 2.6 MPa (380 psia) 2 0 Boost Compressor Discharge - 3.2 MPa (470 psia) 149

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 5A SOUR GAS SHIFT AND SYNGAS CLEANUP Equipment Operating Description Type Design Condition Spares No. Qty.

303,907 kg/hr (670,000 lb/hr)

Sulfated carbon 1 Mercury Adsorber 35°C (95°F) 2 0 bed 5.1 MPa (745 psia) 2 Sulfur Plant Claus type 146 tonne/day (161 tpd) 1 0 388,275 kg/hr (856,000 lb/hr)

Fixed bed, 3 Water Gas Shift Reactors 227°C (440°F) 4 0 catalytic 5.4 MPa (790 psia)

Exchanger 1: 157 GJ/hr (149 Shift Reactor Heat Recovery MMBtu/hr) 4 Shell and Tube 4 0 Exchangers Exchanger 2: 3 GJ/hr (3 MMBtu/hr) 310,711 kg/hr (685,000 lb/hr)

Two-stage 5 Acid Gas Removal Plant 35°C (95°F) 2 0 Selexol 5.1 MPa (740 psia) 18,009 kg/hr (39,704 lb/hr)

Fixed bed, 6 Hydrogenation Reactor 232°C (450°F) 1 0 catalytic 0.1 MPa (12.3 psia)

Tail Gas Recycle 7 Centrifugal 13,782 kg/hr (30,385 lb/hr) 1 0 Compressor ACCOUNT 5B CO 2 COMPRESSION Equipment Operating Description Type Design Condition Spares No. Qty.

CO2 Integrally geared, 1,133 m3/min @ 15.3 MPa 1 4 0 Compressor multi-stage centrifugal (40,000 scfm @ 2,215 psia) 150

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES Equipment Operating Description Type Design Condition Spares No. Qty.

1 Gas Turbine Advanced F class 232 MW 2 0 260 MVA @ 0.9 p.f., 24 kV, 2 Gas Turbine Generator TEWAC 2 0 60 Hz, 3-phase 49,578 kg/h (109,300 lb/h)

Syngas Expansion 3 Turbo Expander 5.1 MPa (735 psia) Inlet 2 0 Turbine/Generator 3.2 MPa (460 psia) Outlet ACCOUNT 7 HRSG, DUCTING, AND STACK Equipment Operating Description Type Design Condition Spares No. Qty.

CS plate, type 409SS 76 m (250 ft) high x 1 Stack 1 0 liner 8.5 m (28 ft) diameter Main steam - 341,837 kg/hr, 12.4 Drum, multi-pressure MPa/534°C (753,621 lb/hr, Heat Recovery with economizer 1,800 psig/994°F) 2 2 0 Steam Generator section and integral Reheat steam - 336,628 kg/hr, deaerator 3.1 MPa/534°C (742,137 lb/hr, 452 psig/994°F) 151

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES Equipment Operating Description Type Design Condition Spares No. Qty.

Commercially 277 MW 1 Steam Turbine available advanced 12.4 MPa/534°C/534°C 1 0 steam turbine (1,800 psig/ 994°F/994°F)

Hydrogen cooled, 310 MVA @ 0.9 p.f., 24 2 Steam Turbine Generator 1 0 static excitiation kV, 60 Hz, 3-phase 50% steam flow @ design 3 Steam Bypass One per HRSG 2 0 steam conditions 1,667 GJ/hr (1,580 Single pass, divided MMBtu/hr), Inlet water 4 Surface Condenser waterbox including temperature 16°C (60°F), 1 0 vacuum pumps Water temperature rise 11°C (20°F)

ACCOUNT 9 COOLING WATER SYSTEM Equipment Operating Description Type Design Condition Spares No. Qty.

Circulating Water 461,820 lpm @ 30 m 1 Vertical, wet pit 2 1 Pumps (122,000 gpm @ 100 ft) 11°C (51.5°F) wet bulb / 16°C Evaporative, (60°F) CWT / 27°C (80°F) HWT 2 Cooling Tower mechanical draft, multi- 1 0

/ 2,585 GJ/hr (2,450 MMBtu/hr) cell heat duty 152

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 10 SLAG RECOVERY AND HANDLING Equipment Operating Description Type Design Condition Spares No. Qty.

1 Slag Quench Tank Water bath 253,623 liters (67,000 gal) 2 0 2 Slag Crusher Roll 14 tonne/hr (15 tph) 2 0 3 Slag Depressurizer Lock Hopper 14 tonne/hr (15 tph) 2 0 4 Slag Receiving Tank Horizontal, weir 151,416 liters (40,000 gal) 2 0 5 Black Water Overflow Tank Shop fabricated 68,137 liters (18,000 gal) 2 6 Slag Conveyor Drag chain 14 tonne/hr (15 tph) 2 0 7 Slag Separation Screen Vibrating 14 tonne/hr (15 tph) 2 0 8 Coarse Slag Conveyor Belt/bucket 14 tonne/hr (15 tph) 2 0 9 Fine Ash Settling Tank Vertical, gravity 215,768 liters (57,000 gal) 2 0 Horizontal 38 lpm @ 14 m H2O 10 Fine Ash Recycle Pumps 2 2 centrifugal (10 gpm @ 46 ft H2O) 11 Grey Water Storage Tank Field erected 68,137 liters (18,000 gal) 2 0 227 lpm @ 564 m H2O 12 Grey Water Pumps Centrifugal 2 2 (60 gpm @ 1,850 ft H2O)

Vertical, field 13 Slag Storage Bin 998 tonne (1,100 tons) 2 0 erected 14 Unloading Equipment Telescoping chute 109 tonne/hr (120 tph) 1 0 153

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 11 ACCESSORY ELECTRIC PLANT Equipment Operating Description Type Design Condition Spares No. Qty.

CTG Step-up 24 kV/345 kV, 260 MVA, 1 Oil-filled 2 0 Transformer 3-ph, 60 Hz STG Step-up 24 kV/345 kV, 310 MVA, 2 Oil-filled 1 0 Transformer 3-ph, 60 Hz High Voltage 345 kV/13.8 kV, 80 MVA, 3 Auxiliary Oil-filled 2 0 3-ph, 60 Hz Transformer Medium Voltage 24 kV/4.16 kV, 48 MVA, 4 Auxiliary Oil-filled 1 1 3-ph, 60 Hz Transformer Low Voltage 4.16 kV/480 V, 7 MVA, 5 Dry ventilated 1 1 Transformer 3-ph, 60 Hz CTG Isolated 6 Phase Bus Duct Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 2 0 and Tap Bus STG Isolated 7 Phase Bus Duct Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0 and Tap Bus Medium Voltage 8 Metal clad 4.16 kV, 3-ph, 60 Hz 1 1 Switchgear Low Voltage 9 Metal enclosed 480 V, 3-ph, 60 Hz 1 1 Switchgear Emergency Diesel Sized for emergency 10 750 kW, 480 V, 3-ph, 60 Hz 1 0 Generator shutdown ACCOUNT 12 INSTRUMENTATION AND CONTROL Equipment Operating Description Type Design Condition Spares No. Qty.

Monitor/keyboard; DCS - Main Operator printer (laser Operator stations/printers and 1 1 0 Control color); Engineering engineering stations/printers printer (laser B&W)

Microprocessor with 2 DCS - Processor N/A 1 0 redundant input/output DCS - Data 3 Fiber optic Fully redundant, 25% spare 1 0 Highway 154

Cost and Performance Baseline for Fossil Energy Plants 3.2.11 Case 2 - Cost Estimating The cost estimating methodology was described previously in Section 2.7. Exhibit 3-40 shows the TPC summary organized by cost account and Exhibit 3-41 shows a more detailed breakdown of the capital costs along with owners costs, TOC, and TASC. Exhibit 3-42 shows the initial and annual O&M costs.

The estimated TOC of the GEE gasifier with CO2 capture is $3,334/kW. Process contingency represents 3.6 percent of the TPC and project contingency represents 11.1 percent. The COE, including CO2 TS&M costs of 5.3 mills/kWh is 105.7 mills/kWh.

155

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-40 Case 2 Total Plant Cost Summary Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study TOTAL PLANT COST

SUMMARY

Case: Case 2 - GEE Radiant 550MW IGCC w/ CO2 Plant Size: 543.3 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING $14,280 $2,654 $11,074 $0 $0 $28,008 $2,542 $0 $6,110 $36,660 $67 2 COAL & SORBENT PREP & FEED $24,391 $4,448 $14,651 $0 $0 $43,489 $3,954 $1,579 $9,804 $58,826 $108 3 FEEDWATER & MISC. BOP SYSTEMS $10,158 $7,914 $10,237 $0 $0 $28,309 $2,671 $0 $7,166 $38,146 $70 4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $113,863 $0 $62,389 $0 $0 $176,251 $16,146 $24,460 $33,252 $250,109 $460 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $193,046 $0 w/equip. $0 $0 $193,046 $18,712 $0 $21,176 $232,934 $429 4.4-4.9 Other Gasification Equipment $7,894 $12,285 $12,270 $0 $0 $32,449 $3,078 $0 $7,755 $43,282 $80 SUBTOTAL 4 $314,803 $12,285 $74,659 $0 $0 $401,747 $37,935 $24,460 $62,183 $526,325 $969 5A GAS CLEANUP & PIPING $96,775 $3,334 $82,247 $0 $0 $182,357 $17,666 $27,526 $45,625 $273,174 $503 5B CO2 COMPRESSION $18,256 $0 $11,190 $0 $0 $29,446 $2,836 $0 $6,456 $38,739 $71 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,600 $239 6.2-6.9 Combustion Turbine Other $5,550 $887 $1,748 $0 $0 $8,185 $775 $0 $1,650 $10,610 $20 SUBTOTAL 6 $97,576 $887 $8,331 $0 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $258 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,620 $0 $4,780 $0 $0 $38,401 $3,651 $0 $4,205 $46,257 $85 7.2-7.9 SCR System, Ductwork and Stack $3,376 $2,407 $3,153 $0 $0 $8,936 $828 $0 $1,589 $11,353 $21 SUBTOTAL 7 $36,996 $2,407 $7,933 $0 $0 $47,336 $4,480 $0 $5,794 $57,610 $106 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $28,123 $0 $4,808 $0 $0 $32,931 $3,160 $0 $3,609 $39,699 $73 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $10,211 $967 $7,075 $0 $0 $18,253 $1,662 $0 $3,950 $23,865 $44 SUBTOTAL 8 $38,333 $967 $11,883 $0 $0 $51,183 $4,821 $0 $7,559 $63,564 $117 9 COOLING WATER SYSTEM $10,319 $9,775 $8,388 $0 $0 $28,483 $2,646 $0 $6,348 $37,477 $69 10 ASH/SPENT SORBENT HANDLING SYS $14,734 $8,239 $14,938 $0 $0 $37,910 $3,652 $0 $4,476 $46,038 $85 11 ACCESSORY ELECTRIC PLANT $32,062 $12,584 $24,591 $0 $0 $69,237 $5,953 $0 $14,261 $89,451 $165 12 INSTRUMENTATION & CONTROL $11,404 $2,098 $7,347 $0 $0 $20,849 $1,889 $1,042 $3,962 $27,743 $51 13 IMPROVEMENTS TO SITE $3,485 $2,054 $8,600 $0 $0 $14,140 $1,396 $0 $4,661 $20,196 $37 14 BUILDINGS & STRUCTURES $0 $6,882 $7,834 $0 $0 $14,716 $1,340 $0 $2,628 $18,684 $34 TOTAL COST $723,574 $76,529 $303,902 $0 $0 $1,104,005 $103,905 $64,468 $200,468 $1,472,845 $2,711 156

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-41 Case 2 Total Plant Cost Details Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $3,750 $0 $1,833 $0 $0 $5,583 $500 $0 $1,217 $7,299 $13 1.2 Coal Stackout & Reclaim $4,846 $0 $1,175 $0 $0 $6,021 $528 $0 $1,310 $7,858 $14 1.3 Coal Conveyors & Yd Crush $4,505 $0 $1,162 $0 $0 $5,668 $498 $0 $1,233 $7,398 $14 1.4 Other Coal Handling $1,179 $0 $269 $0 $0 $1,448 $127 $0 $315 $1,889 $3 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,654 $6,635 $0 $0 $9,289 $890 $0 $2,036 $12,215 $22 SUBTOTAL 1. $14,280 $2,654 $11,074 $0 $0 $28,008 $2,542 $0 $6,110 $36,660 $67 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying w/2.3 $0 w/2.3 $0 $0 $0 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,602 $383 $251 $0 $0 $2,236 $191 $0 $485 $2,913 $5 2.3 Slurry Prep & Feed $21,908 $0 $9,667 $0 $0 $31,575 $2,869 $1,579 $7,205 $43,227 $80 2.4 Misc.Coal Prep & Feed $881 $641 $1,922 $0 $0 $3,443 $316 $0 $752 $4,512 $8 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,424 $2,811 $0 $0 $6,234 $577 $0 $1,362 $8,174 $15 SUBTOTAL 2. $24,391 $4,448 $14,651 $0 $0 $43,489 $3,954 $1,579 $9,804 $58,826 $108 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,836 $4,870 $2,571 $0 $0 $10,276 $952 $0 $2,246 $13,474 $25 3.2 Water Makeup & Pretreating $717 $75 $401 $0 $0 $1,193 $114 $0 $392 $1,699 $3 3.3 Other Feedwater Subsystems $1,552 $524 $472 $0 $0 $2,548 $229 $0 $555 $3,332 $6 3.4 Service Water Systems $411 $845 $2,934 $0 $0 $4,190 $409 $0 $1,380 $5,979 $11 3.5 Other Boiler Plant Systems $2,203 $854 $2,116 $0 $0 $5,173 $491 $0 $1,133 $6,796 $13 3.6 FO Supply Sys & Nat Gas $315 $596 $556 $0 $0 $1,467 $141 $0 $322 $1,930 $4 3.7 Waste Treatment Equipment $1,003 $0 $612 $0 $0 $1,615 $157 $0 $532 $2,303 $4 3.8 Misc. Power Plant Equipment $1,121 $150 $576 $0 $0 $1,847 $178 $0 $608 $2,634 $5 SUBTOTAL 3. $10,158 $7,914 $10,237 $0 $0 $28,309 $2,671 $0 $7,166 $38,146 $70 4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $113,863 $0 $62,389 $0 $0 $176,251 $16,146 $24,460 $33,252 $250,109 $460 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $193,046 $0 w/equip. $0 $0 $193,046 $18,712 $0 $21,176 $232,934 $429 4.4 Scrubber & Low Temperature Cooling $6,049 $4,924 $5,125 $0 $0 $16,097 $1,546 $0 $3,529 $21,172 $39 4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Soot Recovery & SARU $1,845 $876 $1,731 $0 $0 $4,452 $429 $0 $976 $5,857 $11 4.8 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $6,486 $5,414 $0 $0 $11,900 $1,103 $0 $3,251 $16,253 $30 SUBTOTAL 4. $314,803 $12,285 $74,659 $0 $0 $401,747 $37,935 $24,460 $62,183 $526,325 $969 157

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-41 Case 2 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $74,127 $0 $62,899 $0 $0 $137,025 $13,252 $27,405 $35,536 $213,219 $392 5A.2 Elemental Sulfur Plant $10,329 $2,059 $13,326 $0 $0 $25,713 $2,498 $0 $5,642 $33,853 $62 5A.3 Mercury Removal $1,376 $0 $1,047 $0 $0 $2,423 $234 $121 $556 $3,334 $6 5A.4 Shift Reactors $9,594 $0 $3,862 $0 $0 $13,456 $1,290 $0 $2,949 $17,696 $33 5A.5 Particulate Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $1,349 $0 $256 $0 $0 $1,605 $196 $0 $360 $2,161 $4 5A.7 Fuel Gas Piping $0 $634 $444 $0 $0 $1,078 $100 $0 $236 $1,413 $3 5A.9 HGCU Foundations $0 $642 $414 $0 $0 $1,056 $97 $0 $346 $1,498 $3 SUBTOTAL 5A. $96,775 $3,334 $82,247 $0 $0 $182,357 $17,666 $27,526 $45,625 $273,174 $503 5B CO2 COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $18,256 $0 $11,190 $0 $0 $29,446 $2,836 $0 $6,456 $38,739 $71 SUBTOTAL 5B. $18,256 $0 $11,190 $0 $0 $29,446 $2,836 $0 $6,456 $38,739 $71 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,600 $239 6.2 Syngas Expander $5,550 $0 $767 $0 $0 $6,316 $600 $0 $1,038 $7,954 $15 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $887 $982 $0 $0 $1,868 $175 $0 $613 $2,656 $5 SUBTOTAL 6. $97,576 $887 $8,331 $0 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $258 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,620 $0 $4,780 $0 $0 $38,401 $3,651 $0 $4,205 $46,257 $85 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,731 $1,235 $0 $0 $2,965 $260 $0 $645 $3,870 $7 7.4 Stack $3,376 $0 $1,268 $0 $0 $4,644 $445 $0 $509 $5,598 $10 7.9 HRSG, Duct & Stack Foundations $0 $676 $650 $0 $0 $1,326 $123 $0 $435 $1,884 $3 SUBTOTAL 7. $36,996 $2,407 $7,933 $0 $0 $47,336 $4,480 $0 $5,794 $57,610 $106 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $28,123 $0 $4,808 $0 $0 $32,931 $3,160 $0 $3,609 $39,699 $73 8.2 Turbine Plant Auxiliaries $195 $0 $447 $0 $0 $642 $63 $0 $70 $775 $1 8.3 Condenser & Auxiliaries $5,009 $0 $1,471 $0 $0 $6,480 $619 $0 $710 $7,809 $14 8.4 Steam Piping $5,006 $0 $3,522 $0 $0 $8,528 $733 $0 $2,315 $11,576 $21 8.9 TG Foundations $0 $967 $1,635 $0 $0 $2,603 $247 $0 $855 $3,704 $7 SUBTOTAL 8. $38,333 $967 $11,883 $0 $0 $51,183 $4,821 $0 $7,559 $63,564 $117 158

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-41 Case 2 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 9 COOLING WATER SYSTEM 9.1 Cooling Towers $7,155 $0 $1,302 $0 $0 $8,457 $805 $0 $1,389 $10,652 $20 9.2 Circulating Water Pumps $1,856 $0 $134 $0 $0 $1,990 $168 $0 $324 $2,481 $5 9.3 Circ.Water System Auxiliaries $155 $0 $22 $0 $0 $177 $17 $0 $29 $224 $0 9.4 Circ.Water Piping $0 $6,481 $1,680 $0 $0 $8,161 $738 $0 $1,780 $10,679 $20 9.5 Make-up Water System $388 $0 $555 $0 $0 $943 $90 $0 $207 $1,240 $2 9.6 Component Cooling Water Sys $765 $915 $651 $0 $0 $2,331 $218 $0 $510 $3,060 $6 9.9 Circ.Water System Foundations $0 $2,379 $4,044 $0 $0 $6,423 $609 $0 $2,110 $9,142 $17 SUBTOTAL 9. $10,319 $9,775 $8,388 $0 $0 $28,483 $2,646 $0 $6,348 $37,477 $69 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $12,136 $6,692 $13,595 $0 $0 $32,424 $3,129 $0 $3,555 $39,109 $72 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $589 $0 $641 $0 $0 $1,229 $119 $0 $202 $1,551 $3 10.7 Ash Transport & Feed Equipment $790 $0 $190 $0 $0 $980 $91 $0 $161 $1,232 $2 10.8 Misc. Ash Handling Equipment $1,219 $1,494 $446 $0 $0 $3,160 $301 $0 $519 $3,980 $7 10.9 Ash/Spent Sorbent Foundation $0 $52 $65 $0 $0 $117 $11 $0 $39 $167 $0 SUBTOTAL 10. $14,734 $8,239 $14,938 $0 $0 $37,910 $3,652 $0 $4,476 $46,038 $85 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $947 $0 $937 $0 $0 $1,885 $180 $0 $206 $2,271 $4 11.2 Station Service Equipment $4,697 $0 $423 $0 $0 $5,121 $472 $0 $559 $6,152 $11 11.3 Switchgear & Motor Control $8,684 $0 $1,579 $0 $0 $10,264 $952 $0 $1,682 $12,898 $24 11.4 Conduit & Cable Tray $0 $4,034 $13,308 $0 $0 $17,342 $1,677 $0 $4,755 $23,775 $44 11.5 Wire & Cable $0 $7,708 $5,064 $0 $0 $12,772 $928 $0 $3,425 $17,125 $32 11.6 Protective Equipment $0 $686 $2,496 $0 $0 $3,182 $311 $0 $524 $4,016 $7 11.7 Standby Equipment $234 $0 $228 $0 $0 $462 $44 $0 $76 $581 $1 11.8 Main Power Transformers $17,500 $0 $144 $0 $0 $17,644 $1,334 $0 $2,847 $21,825 $40 11.9 Electrical Foundations $0 $156 $410 $0 $0 $567 $54 $0 $186 $807 $1 SUBTOTAL 11. $32,062 $12,584 $24,591 $0 $0 $69,237 $5,953 $0 $14,261 $89,451 $165 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,126 $0 $752 $0 $0 $1,877 $178 $94 $322 $2,471 $5 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $259 $0 $166 $0 $0 $425 $40 $21 $97 $583 $1 12.7 Computer & Accessories $6,005 $0 $192 $0 $0 $6,197 $569 $310 $708 $7,784 $14 12.8 Instrument Wiring & Tubing $0 $2,098 $4,288 $0 $0 $6,386 $542 $319 $1,812 $9,059 $17 12.9 Other I & C Equipment $4,014 $0 $1,949 $0 $0 $5,963 $561 $298 $1,023 $7,846 $14 SUBTOTAL 12. $11,404 $2,098 $7,347 $0 $0 $20,849 $1,889 $1,042 $3,962 $27,743 $51 159

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-41 Case 2 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $109 $2,337 $0 $0 $2,447 $243 $0 $807 $3,496 $6 13.2 Site Improvements $0 $1,945 $2,585 $0 $0 $4,530 $447 $0 $1,493 $6,470 $12 13.3 Site Facilities $3,485 $0 $3,678 $0 $0 $7,163 $706 $0 $2,361 $10,230 $19 SUBTOTAL 13. $3,485 $2,054 $8,600 $0 $0 $14,140 $1,396 $0 $4,661 $20,196 $37 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,377 $3,387 $0 $0 $5,764 $530 $0 $944 $7,238 $13 14.3 Administration Building $0 $882 $640 $0 $0 $1,522 $136 $0 $249 $1,906 $4 14.4 Circulation Water Pumphouse $0 $166 $88 $0 $0 $253 $22 $0 $41 $317 $1 14.5 Water Treatment Buildings $0 $600 $585 $0 $0 $1,185 $107 $0 $194 $1,486 $3 14.6 Machine Shop $0 $452 $309 $0 $0 $761 $68 $0 $124 $952 $2 14.7 Warehouse $0 $729 $471 $0 $0 $1,200 $106 $0 $196 $1,502 $3 14.8 Other Buildings & Structures $0 $437 $340 $0 $0 $777 $69 $0 $169 $1,015 $2 14.9 Waste Treating Building & Str. $0 $976 $1,865 $0 $0 $2,841 $265 $0 $621 $3,728 $7 SUBTOTAL 14. $0 $6,882 $7,834 $0 $0 $14,716 $1,340 $0 $2,628 $18,684 $34 TOTAL COST $723,574 $76,529 $303,902 $0 $0 $1,104,005 $103,905 $64,468 $200,468 $1,472,845 $2,711 Owner's Costs Preproduction Costs 6 Months All Labor $13,488 $25 1 Month Maintenance Materials $2,998 $6 1 Month Non-fuel Consumables $384 $1 1 Month Waste Disposal $318 $1 25% of 1 Months Fuel Cost at 100% CF $1,697 $3 2% of TPC $29,457 $54 Total $48,341 $89 Inventory Capital 60 day supply of fuel and consumables at 100% CF $14,068 $26 0.5% of TPC (spare parts) $7,364 $14 Total $21,432 $39 Initial Cost for Catalyst and Chemicals $7,199 $13 Land $900 $2 Other Owner's Costs $220,927 $407 Financing Costs $39,767 $73 Total Overnight Costs (TOC) $1,811,411 $3,334 TASC Multiplier (IOU, high-risk, 35 year) 1.140 Total As-Spent Cost (TASC) $2,065,009 $3,801 160

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-42 Case 2 Initial and Annual Operating and Maintenance Costs INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 2 - GEE Radiant 550MW IGCC w/ CO2 Heat Rate-net (Btu/kWh): 10,458 MWe-net: 543 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant Skilled Operator 2.0 2.0 Operator 10.0 10.0 Foreman 1.0 1.0 Lab Tech's, etc. 3.0 3.0 TOTAL-O.J.'s 16.0 16.0 Annual Cost Annual Unit Cost

$ $/kW-net Annual Operating Labor Cost $6,313,507 $11.622 Maintenance Labor Cost $15,266,708 $28.103 Administrative & Support Labor $5,395,054 $9.931 Property Taxes and Insurance $29,456,896 $54.223 TOTAL FIXED OPERATING COSTS $56,432,165 $103.879 VARIABLE OPERATING COSTS

$/kWh-net Maintenance Material Cost $28,779,845 $0.00756 Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water (/1000 gallons) 0 4,187 1.08 $0 $1,322,398 $0.00035 Chemicals MU & WT Chem. (lbs) 0 24,944 0.17 $0 $1,260,554 $0.00033 Carbon (Mercury Removal) (lb) 79,786 109 1.05 $83,789 $33,516 $0.00001 COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000 Water Gas Shift Catalyst (ft3) 6,246 4.28 498.83 $3,115,855 $623,171 $0.00016 Selexol Solution (gal) 298,502 95 13.40 $3,999,401 $371,618 $0.00010 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip 2.01 131.27 $0 $77,209 $0.00002 Subtotal-Chemicals $7,199,046 $2,366,068 $0.00062 Other Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 $0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 $0.00000 Subtotal-Other $0 $0 $0.00000 Waste Disposal Spent Mercury Catalyst (lb.) 0 109 0.42 $0 $13,311 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 641 16.23 $0 $3,037,841 $0.00080 Subtotal Waste Disposal $0 $3,051,152 $0.00080 By-products & Emissions 0 0 0.00 $0 $0.00000 Sulfur (ton) 0 146 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000 TOTAL VARIABLE OPERATING COSTS $7,199,046 $35,519,462 $0.00933 Fuel (ton) 0 5,844 38.18 $0 $65,161,317 $0.01712 161

Cost and Performance Baseline for Fossil Energy Plants 3.3 CONOCOPHILLIPS E-GASTM IGCC CASES This section contains an evaluation of plant designs for Cases 3 and 4, which are based on the CoP E-Gas' gasifier. Cases 3 and 4 are very similar in terms of process, equipment, scope and arrangement, except that Case 4 includes SGS reactors, CO2 absorption/regeneration and compression/transport systems. There are no provisions for CO2 removal in Case 3.

The balance of this section is organized in an analogous manner to Section 3.2:

Gasifier Background

Process System Description for Case 3

Key Assumptions for Cases 3 and 4

Sparing Philosophy for Cases 3 and 4

Performance Results for Case 3

Equipment List for Case 3

Cost Estimates for Case 3

Process and System Description, Performance Results, Equipment List, and Cost Estimate for Case 4 3.3.1 Gasifier Background Dow Chemical (the former principal stockholder of Destec Energy, which was bought by Global Energy, Inc., the gasifier business that was later purchased by CoP is a major producer of chemicals. They began coal gasification development work in 1976 with bench-scale (2 kg/hr

[4 lb/hr]) reactor testing. Important fundamental data were obtained for conversion and yields with various coals and operating conditions. This work led to the construction of a pilot plant at Dows large chemical complex in Plaquemine, Louisiana. The pilot plant was designed for a capacity of 11 tonnes/day (12 TPD) (dry lignite basis) and was principally operated with air as the oxidant. The plant also operated with oxygen at an increased capacity of 33 tonnes/day (36 TPD) (dry lignite basis). This pilot plant operated from 1978 through 1983.

Following successful operation of the pilot plant, Dow built a larger 499 tonnes/day (550 TPD)

(dry lignite basis) gasifier at Plaquemine. In 1984, Dow Chemical and the U.S. Synthetic Fuels Corporation (SFC) announced a price guarantee contract, which allowed the building of the first commercial-scale Dow coal gasification unit. The Louisiana Gasification Technology, Inc.

(LGTI) plant, sometimes called the Dow Syngas Project, was also located in the Dow Plaquemine chemical complex. The plant gasified about 1,451 tonnes/day (1,600 TPD) (dry basis) of subbituminous coal to generate 184 MW (gross) of combined-cycle electricity. To ensure continuous power output to the petrochemical complex, a minimum of 20 percent of natural gas was co-fired with the syngas. LGTI was operated from 1987 through 1995.

In September 1991, DOE selected the Wabash River coal gasification repowering project, which used the Destec Energy process, for funding under the Clean Coal Technology Demonstration Program. The project was a joint venture of Destec and Public Service of Indiana (PSI Energy, Inc.). Its purpose was to repower a unit at PSIs Wabash River station in West Terre Haute, Indiana to produce 265 MW of net power from local high-sulfur bituminous coal. The design of 162

Cost and Performance Baseline for Fossil Energy Plants the project gasifier was based on the Destec LGTI gasifier. Experience gained in that project provided significant input to the design of the Wabash River coal gasification facility and eliminated much of the risk associated with scale-up and process variables.

Gasifier Capacity - The gasifier originally developed by Dow is now known as the CoP E-Gas' gasifier. The daily coal-handling capacity of the E-Gas gasifier operating at Plaquemine was in the range of 1,270 tonnes (1,400 tons) (moisture/ash-free [MAF] basis) for bituminous coal to 1,497 tonnes (1,650 tons) for lignite. The dry gas production rate was 141,600 Nm3/hr (5 million scf/hr) with an energy content of about 1,370 MMkJ/hr (1,300 MMBtu/hr) (HHV).

The daily coal-handling capacity of the gasifier at Wabash River is about 1,678 tonnes (1,850 tons) (MAF basis) for high-sulfur bituminous coal. The dry gas production rate is about 189,724 Nm3/hr (6.7 million scf/hr) with an energy content of about 1,950 MMkJ/hr (1,850 MMBtu/hr) (HHV). This size matches the CT, which is a GE 7FA.

With increased power and fuel GT demand, the gasifier coal feed increases proportionately. CoP has indicated that the gasifier can readily handle the increased demand.

Distinguishing Characteristics - A key advantage of the CoP coal gasification technology is the current operating experience with subbituminous coal at full commercial scale at the Plaquemine plant and bituminous coal at the Wabash plant. The two-stage operation improves the efficiency, reduces oxygen requirements, and enables more effective operation on slurry feeds relative to a single stage gasifier. The fire-tube SGC used by E-Gas has a lower capital cost than a water-tube design, an added advantage for the CoP technology at this time. However, this experience may spur other developers to try fire-tube designs.

Entrained-flow gasifiers have fundamental environmental advantages over fluidized-bed and moving-bed gasifiers. They produce no hydrocarbon liquids, and the only solid waste is an inert slag.

The key disadvantages of the CoP coal gasification technology are the relatively short refractory life and the high waste heat recovery (SGC) duty. As with the other entrained-flow slagging gasifiers, these disadvantages result from high operating temperature. However, the two-stage operation results in a quenched syngas that is higher in CH4 content than other gasifiers. This becomes a disadvantage in CO2 capture cases since the CH4 passes through the SGS reactors without change, and is also not separated by the AGR thus limiting the amount of carbon that can be captured.

Important Coal Characteristics - The slurry feeding system and the recycle of process condensate water as the principal slurrying liquid make low levels of ash and soluble salts desirable coal characteristics for use in the E-Gas' coal gasification process. High ash levels increase the ratio of water to carbon in the coal in the feed slurry, thereby increasing the oxygen requirements. Soluble salts affect the processing cost and amount of water blowdown required to avoid problems associated with excessive buildup of salts in the slurry water recycle loop.

Bituminous coals with lower inherent moisture improve the slurry concentration and reduce oxygen requirements. The two-stage operation reduces the negative impact of low-rank coal use in slurry feed, entrained-flow gasification. Low to moderate ash fusion-temperature coals are preferred for slagging gasifiers. Coals with high ash fusion temperatures may require flux addition for optimal gasification operation.

163

Cost and Performance Baseline for Fossil Energy Plants 3.3.2 Process Description In this section the overall CoP gasification process is described. The system description follows the BFD in Exhibit 3-43 and stream numbers reference the same exhibit. The tables in Exhibit 3-44 provide process data for the numbered streams in the BFD.

Coal Grinding and Slurry Preparation Coal receiving and handling is common to all cases and was covered in Section 3.1.1. The receiving and handling subsystem ends at the coal silo. Coal grinding and slurry preparation is similar to the GEE cases but repeated here for completeness.

Coal from the coal silo is fed onto a conveyor by vibratory feeders located below each silo. The conveyor feeds the coal to an inclined conveyor that delivers the coal to the rod mill feed hopper.

The feed hopper provides a surge capacity of about two hours and contains two hopper outlets.

Each hopper outlet discharges onto a weigh feeder, which in turn feeds a rod mill. Each rod mill is sized to process 55 percent of the coal feed requirements of the gasifier. The rod mill grinds the coal and wets it with treated slurry water transferred from the slurry water tank by the slurry water pumps. The coal slurry is discharged through a trommel screen into the rod mill discharge tank, and then the slurry is pumped to the slurry storage tanks. The dry solids concentration of the final slurry is 63 percent. The Polk Power Station operates at a slurry concentration of 62-68 percent using bituminous coal and CoP presented a paper showing the slurry concentration of Illinois No. 6 coal as 63 percent [58].

The coal grinding system is equipped with a dust suppression system consisting of water sprays aided by a wetting agent. The degree of dust suppression required depends on local environmental regulations. All of the tanks are equipped with vertical agitators to keep the coal slurry solids suspended.

The equipment in the coal grinding and slurry preparation system is fabricated of materials appropriate for the abrasive environment present in the system. The tanks and agitators are rubber lined. The pumps are either rubber-lined or hardened metal to minimize erosion. Piping is fabricated of HDPE.

Gasification This plant utilizes two gasification trains to process a total of 5,007 tonnes/day (5,519 TPD) of Illinois No. 6 coal. Each of the 2 x 50 percent gasifiers operate at maximum capacity. The E-Gas' two-stage coal gasification technology features an oxygen-blown, entrained-flow, refractory-lined gasifier with continuous slag removal. About 78 percent of the total slurry feed is fed to the first (or bottom) stage of the gasifier. The air separation plant supplies 3,711 tonnes/day (4,090 TPD) of 95 percent oxygen to the gasifiers (stream 5) and the Claus plant (stream 3). All oxygen for gasification is fed to this stage of the gasifier at a pressure of 4.2 MPa (615 psia). This stage is best described as a horizontal cylinder with two horizontally opposed burners. The highly exothermic gasification/oxidation reactions take place rapidly at temperatures of 1,316 to 1,427°C (2,400 to 2,600°F). The hot raw gas from the first stage enters the second (top) stage, which is a vertical cylinder perpendicular to the first stage. The remaining 22 percent of coal slurry is injected into this hot raw gas. The endothermic gasification/devolatilization reaction in this stage reduces the final gas temperature to about 1,038°C (1,900°F). Total slurry to both stages is shown as stream 7 in Exhibit 3-43.

164

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-43 Case 3 Block Flow Diagram, E-Gas' IGCC without CO2 Capture 165

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-44 Case 3 Stream Table, E-Gas' IGCC without CO2 Capture 1 2 3 4 5 6 7 8 9 10 11 12 V-L Mole Fraction Ar 0.0092 0.0241 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0000 0.0078 0.0078 0.0096 CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0465 0.0465 0.0575 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3011 0.3011 0.3727 CO2 0.0003 0.0083 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1556 0.1559 0.1929 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0003 0.0000 0.0000 H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2724 0.2724 0.3372 H2O 0.0099 0.2163 0.0000 0.0003 0.0000 1.0000 0.0000 0.9968 0.0000 0.1889 0.1885 0.0015 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0002 0.0000 H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0072 0.0075 0.0092 N2 0.7732 0.5460 0.0178 0.9919 0.0178 0.0000 0.0000 0.0000 0.0000 0.0157 0.0157 0.0194 NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0032 0.0000 0.0045 0.0045 0.0000 O2 0.2074 0.2054 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 V-L Flowrate (kgmol/hr) 18,976 916 111 17,427 4,694 3,766 0 4,758 0 21,817 21,817 17,626 V-L Flowrate (kg/hr) 547,576 24,820 3,567 489,004 151,056 67,848 0 85,707 0 459,732 459,732 384,240 Solids Flowrate (kg/hr) 0 0 0 0 0 0 208,634 0 21,295 0 0 0 Temperature (°C) 15 20 32 93 32 343 15 149 1,038 186 186 35 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 5.10 0.10 5.79 4.24 4.07 4.00 3.83 Enthalpy (kJ/kg)A 30.23 36.92 26.67 92.52 26.67 0.00 --- 567.36 --- 673.10 672.88 39.55 Density (kg/m3) 1.2 1.6 11.0 24.4 11.0 20.1 --- 862.4 --- 22.7 22.3 33.0 V-L Molecular Weight 28.857 27.090 32.181 28.060 32.181 18.015 --- 18.012 --- 21.073 21.073 21.799 V-L Flowrate (lbmol/hr) 41,834 2,020 244 38,420 10,348 8,303 0 10,490 0 48,098 48,098 38,859 V-L Flowrate (lb/hr) 1,207,199 54,719 7,864 1,078,070 333,021 149,578 0 188,951 0 1,013,536 1,013,536 847,104 Solids Flowrate (lb/hr) 0 0 0 0 0 0 459,958 0 46,947 0 0 0 Temperature (°F) 59 69 90 199 90 650 59 300 1,900 367 367 95 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 740.0 14.7 840.0 615.0 590.0 580.0 555.0 Enthalpy (Btu/lb)A 13.0 15.9 11.5 39.8 11.5 --- 243.9 --- 289.4 289.3 17.0 Density (lb/ft 3) 0.076 0.098 0.687 1.521 0.687 1.257 --- 53.837 --- 1.416 1.391 2.061 A - Reference conditions are 32.02 F & 0.089 PSIA 166

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-44 Case 3 Stream Table (Continued) 13 14 15 16 17 18 19 20 21 22 23 24 25 V-L Mole Fraction Ar 0.0095 0.0098 0.0085 0.0085 0.0000 0.0000 0.0041 0.0055 0.0092 0.0092 0.0087 0.0087 0.0000 CH4 0.0555 0.0576 0.0500 0.0500 0.0002 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.3597 0.3734 0.3241 0.3241 0.0010 0.0000 0.0848 0.0061 0.0000 0.0000 0.0000 0.0000 0.0000 CO2 0.2137 0.1931 0.1676 0.1676 0.7537 0.0000 0.4983 0.7790 0.0003 0.0003 0.0803 0.0803 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0003 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2 0.3299 0.3425 0.2973 0.2973 0.0009 0.0000 0.0209 0.1311 0.0000 0.0000 0.0000 0.0000 0.0000 H2O 0.0015 0.0015 0.1333 0.1333 0.0000 0.0000 0.3350 0.0018 0.0099 0.0099 0.0860 0.0860 1.0000 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2S 0.0090 0.0000 0.0000 0.0000 0.2443 0.0000 0.0014 0.0043 0.0000 0.0000 0.0000 0.0000 0.0000 N2 0.0213 0.0221 0.0192 0.0192 0.0000 0.0000 0.0537 0.0723 0.7732 0.7732 0.7250 0.7250 0.0000 NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.2074 0.1000 0.1000 0.0000 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0013 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 V-L Flowrate (kgmol/hr) 18,275 17,601 20,276 20,276 674 0 873 649 110,253 4,410 137,246 137,246 40,181 V-L Flowrate (kg/hr) 408,330 380,350 428,548 428,548 27,980 0 28,108 24,090 3,181,557 127,262 3,971,848 3,971,848 723,874 Solids Flowrate (kg/hr) 0 0 0 0 0 5,215 0 0 0 0 0 0 0 Temperature (°C) 34 45 143 193 45 175 232 38 15 432 588 132 561 Pressure (MPa, abs) 3.79 3.76 3.21 3.2 3.757 0.409 0.406 5.512 0.101 1.619 0.105 0.105 12.512 Enthalpy (kJ/kg)A 36.82 55.08 489.40 569.9 -0.670 --- 731.470 -6.625 30.227 463.785 783.868 272.294 3,500.624 Density (kg/m3) 33.7 31.0 19.7 17.3 73.5 5,285.4 3.1 96.3 1.2 7.9 0.4 0.9 35.2 V-L Molecular Weight 22.344 21.610 21.135 21 41.529 --- 32.209 37.141 28.857 28.857 28.940 28.940 18.015 V-L Flowrate (lbmol/hr) 40,289 38,804 44,702 44,702 1,485 0 1,924 1,430 243,066 9,723 302,576 302,576 88,584 V-L Flowrate (lb/hr) 900,213 838,528 944,788 944,788 61,685 0 61,967 53,110 7,014,133 280,565 8,756,427 8,756,427 1,595,870 Solids Flowrate (lb/hr) 0 0 0 0 0 11,497 0 0 0 0 0 0 0 Temperature (°F) 94 112 290 380 112 347 450 100 59 810 1,091 270 1,041 Pressure (psia) 550.0 545.0 465.0 460.0 545.0 59.3 58.9 799.5 14.7 234.9 15.2 15.2 1,814.7 Enthalpy (Btu/lb)A 15.8 23.7 210.4 245.0 -0.3 --- 314.5 -2.8 13.0 199.4 337.0 117.1 1,505.0 Density (lb/ft 3) 2.105 1.938 1.230 1 4.586 329.954 0.195 6.012 0.076 0.495 0.026 0.056 2.194 167

Cost and Performance Baseline for Fossil Energy Plants The syngas produced by the CoP gasifier is higher in methane content than either the GEE or Shell gasifier. The two stage design allows for improved cold gas efficiency (CGE) and lower oxygen consumption, but the quenched second stage allows some CH4 to remain. The syngas CH4 concentration exiting the gasifier in Case 3 is 4.3 vol% (compared to 0.10 vol% in Case 1

[GEE] and 0.001 vol% in Case 5 [Shell]). The relatively high CH4 concentration impacts CO2 capture efficiency as discussed further in Section 3.3.8.

Raw Gas Cooling/Particulate Removal The raw syngas, less than 1,038°C (1,900°F), from the second stage of the gasifier is cooled to 316°C (600°F) in the waste heat recovery (SGC) unit, which consists of a fire-tube boiler and convective superheating and economizing sections. 554,830 kg/hr (1,223,171 lb/hr) of HP saturated steam is raised as a result of the raw gas cooling. Fire-tube boilers cost markedly less than comparable duty water-tube boilers. This is because of the large savings in high-grade steel associated with containing the hot HP syngas in relatively small tubes.

The coal ash is converted to molten slag, which flows down through a tap hole. The molten slag is quenched in water and removed through a proprietary continuous-pressure letdown/dewatering system (stream 9). Char is produced in the second gasifier stage and is captured and recycled to the hotter first stage to be gasified.

The cooled gas from the SGC is cleaned of remaining particulate via a cyclone collector followed by a ceramic candle filter. Recycled syngas is used as the pulse gas to clean the candle filters. The recovered fines are pneumatically returned to the first stage of the gasifier. The combination of recycled char and recycled particulate results in high overall carbon conversion (99.2 percent used in this study).

Following particulate removal, additional heat is removed from the syngas to raise saturated IP steam at 0.4 MPa (65 psia). In this manner the syngas is cooled to 232°C (450°F) prior to the syngas scrubber.

Syngas Scrubber/Sour Water Stripper Syngas exiting the second of the two low temperature heat exchangers passes to a syngas scrubber where a water wash is used to remove chlorides, SO2, NH3, and particulate. The syngas exits the scrubber saturated at 169°C (337°F).

The sour water stripper removes NH3, SO2, and other impurities from the scrubber and other waste streams. The stripper consists of a sour drum that accumulates sour water from the gas scrubber and condensate from SGCs. Sour water from the drum flows to the sour stripper, which consists of a packed column with a steam-heated reboiler. Sour gas is stripped from the liquid and sent to the SRU. Remaining water is sent to wastewater treatment.

COS Hydrolysis, Mercury Removal and Acid Gas Removal Syngas exiting the scrubber is reheated to 186°C (367°F) by using HP steam from the HRSG evaporator prior to entering a COS hydrolysis reactor (stream 10). About 99.5 percent of the COS is converted to CO2 and H2O (Section 3.1.5). The gas exiting the COS reactor (stream 11) passes through a series of heat exchangers and KO drums to lower the syngas temperature to 35°C (95°F) and to separate entrained water. The cooled syngas (stream 12) then passes through a carbon bed to remove 95 percent of the Hg (Section 3.1.4).

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Cost and Performance Baseline for Fossil Energy Plants Cool, particulate-free syngas (stream 13) enters the absorber unit at approximately 3.8 MPa (550 psia) and 34°C (94°F). In the absorber, H2S is preferentially removed from the fuel gas stream by contact with MDEA. The absorber column is operated at 44°C (112°F) by refrigerating the lean MDEA solvent. The lower temperature is required to achieve an outlet H2S concentration of less than 30 ppmv in the sweet syngas. The stripper acid gas stream (stream 17), consisting of 24 percent H2S and 75 percent CO2, is sent to the Claus unit. The acid gas is combined with the sour water stripper off gas and introduced into the Claus plant burner section.

Claus Unit Acid gas from the MDEA unit is preheated to 232°C (450°F). A portion of the acid gas along with all of the sour gas from the stripper and oxygen from the ASU are fed to the Claus furnace.

In the furnace, H2S is catalytically oxidized to SO2 at a furnace temperature of 1,316°C (2,400°F), which must be maintained in order to thermally decompose all of the NH3 present in the sour gas stream.

Following the thermal stage and condensation of sulfur, two reheaters and two sulfur converters are used to obtain a per-pass H2S conversion of approximately 99.5 percent. The Claus Plant tail gas is hydrogenated and recycled back to the gasifier (stream 20). In the furnace waste heat boiler, 13,866 kg/hr (30,568 lb/hr) of 3.0 MPa (430 psia) steam is generated. This steam is used to satisfy all Claus process preheating and reheating requirements as well as to provide some steam to the medium-pressure steam header. The sulfur condensers produce 0.34 MPa (50 psig) steam for the LP steam header and IP steam at 2.9 MPa (415 psig).

A flow rate of 5,215 kg/hr (11,497 lb/hr) of elemental sulfur (stream 18) is recovered from the fuel gas stream. This value represents an overall sulfur recovery efficiency of 99.7 percent.

Power Block Clean syngas exiting the MDEA absorber (stream 14) is partially humidified (stream 15) because there is not sufficient nitrogen from the ASU to provide the level of dilution required to reach the target syngas heating value. The moisturized syngas stream is reheated (stream 16), further diluted with nitrogen from the ASU (stream 4) and enters the advanced F Class CT burner. The CT compressor provides combustion air to the burner and also 19 percent of the total ASU air requirement (stream 22). The exhaust gas exits the CT at 588°C (1,091°F) (stream 23) and enters the HRSG where additional heat is recovered until the FG exits the HRSG at 132°C (270°F) (stream 24) and is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced, commercially available steam turbine using a 12.4 MPa/561°C/561°C (1800 psig/1041°F/1041°F) steam cycle.

Air Separation Unit The elevated pressure ASU was described in Section 3.1.2. In Case 3, the ASU is designed to produce a nominal output of 3,711 tonnes/day (4,091 TPD) of 95 mol% O2 for use in the gasifier (stream 5) and Claus plant (stream 3). The plant is designed with two production trains. The air compressor is powered by an electric motor. Approximately 11,736 tonnes/day (12,937 TPD) of nitrogen are also recovered, compressed, and used as dilution in the GT combustor (stream 4).

About 4 percent of the GT air is used to supply approximately 19 percent of the ASU air requirements (stream 22).

169

Cost and Performance Baseline for Fossil Energy Plants Balance of Plant Balance of plant items were covered in Sections 3.1.9, 3.1.10, and 3.1.11.

3.3.3 Key System Assumptions System assumptions for Cases 3 and 4, CoP IGCC with and without CO2 capture, are compiled in Exhibit 3-45.

Balance of Plant - Cases 3 and 4 The balance of plant assumptions are common to all cases and were presented previously in Exhibit 3-16.

3.3.4 Sparing Philosophy The sparing philosophy for Cases 3 and 4 is provided below. Single trains are utilized throughout with exceptions where equipment capacity requires an additional train. There is no redundancy other than normal sparing of rotating equipment.

The plant design consists of the following major subsystems:

Two ASUs (2 x 50%)

Two trains of slurry preparation and slurry pumps (2 x 50%)

Two trains of gasification, including gasifier, SGC, cyclone, and candle filter (2 x 50%).

Two trains of syngas clean-up process (2 x 50%).

Two trains of refrigerated MDEA AGR in Case 3 and two-stage Selexol in Case 4 (2 x 50%),

One train of Claus-based sulfur recovery (1 x 100%).

Two CT/HRSG tandems (2 x 50%).

One steam turbine (1 x 100%).

170

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-45 CoP IGCC Plant Study Configuration Matrix Case 3 4 Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)

O2:Coal Ratio, kg O2/kg dry coal 0.81 0.88 Carbon Conversion, % 99.2 99.2 Syngas HHV at Gasifier Outlet, 8,319 (223) 7,021 (189) kJ/Nm3 (Btu/scf)

Steam Cycle, MPa/°C/°C 12.4/561/561 12.4/534/534 (psig/°F/°F) (1800/1041/1041) (1800/994/994)

Condenser Pressure, mm Hg 51 (2.0) 51 (2.0)

(in Hg) 2x Advanced F Class 2x Advanced F Class CT (232 MW output each) (232 MW output each)

Gasifier Technology CoP E-Gas' CoP E-Gas' Oxidant 95 vol% Oxygen 95 vol% Oxygen Coal Illinois No. 6 Illinois No. 6 Coal Slurry Solids Content, % 63 63 COS Hydrolysis Yes Occurs in SGS SGS No Yes H2S Separation Refrigerated MDEA Selexol 1st Stage Sulfur Removal, % 99.7 99.9 Claus Plant with Tail Gas Claus Plant with Tail Gas Sulfur Recovery Recycle to Gasifier/ Recycle to Gasifier/

Elemental Sulfur Elemental Sulfur Cyclone, Candle Filter, Cyclone, Candle Filter, Particulate Control Scrubber, and AGR Scrubber, and AGR Absorber Absorber Mercury Control Carbon Bed Carbon Bed MNQC (LNB), N2 MNQC (LNB), N2 Dilution NOx Control Dilution and and Humidification Humidification CO2 Separation N/A Selexol 2nd Stage Overall CO2 Capture N/A 90.4%

CO2 Sequestration N/A Off-site Saline Formation 171

Cost and Performance Baseline for Fossil Energy Plants 3.3.5 Case 3 Performance Results The plant produces a net output of 625 MWe at a net plant efficiency of 39.7 percent (HHV basis).

Overall performance for the entire plant is summarized in Exhibit 3-46, which includes auxiliary power requirements. The ASU accounts for approximately 76 percent of the total auxiliary load distributed between the main air compressor, the oxygen compressor, the nitrogen compressor, and ASU auxiliaries. The cooling water system, including the CWPs and cooling tower fan, accounts for approximately 5 percent of the auxiliary load, and the BFW pumps account for an additional 3.9 percent. All other individual auxiliary loads are less than 3.5 percent of the total.

172

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-46 Case 3 Plant Performance Summary POWER

SUMMARY

(Gross Power at Generator Terminals, kWe)

Gas Turbine Power 464,000 Sweet Gas Expander Power 0 Steam Turbine Power 274,200 TOTAL POWER, kWe 738,200 AUXILIARY LOAD

SUMMARY

, kWe Coal Handling 460 Coal Milling 2,150 Sour Water Recycle Slurry Pump 180 Slag Handling 1,100 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 46,700 Oxygen Compressor 7,920 Nitrogen Compressors 29,910 Boiler Feedwater Pumps 4,410 Condensate Pump 240 Syngas Recycle Compressor 810 Circulating Water Pump 3,880 Ground Water Pumps 400 Cooling Tower Fans 2,010 Scrubber Pumps 320 Acid Gas Removal 3,150 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 250 Claus Plant TG Recycle Compressor 1,610 Miscellaneous Balance of Plant2 3,000 Transformer Losses 2,540 TOTAL AUXILIARIES, kWe 113,140 NET POWER, kWe 625,060 Net Plant Efficiency, % (HHV) 39.7 Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,057 (8,585)

CONDENSER COOLING DUTY 106 kJ/hr (106 Btu/hr) 1,414 (1,340)

CONSUMABLES As-Received Coal Feed, kg/hr (lb/hr) 208,634 (459,958)

Thermal Input1, kWt 1,572,582 Raw Water Withdrawal, m3/min (gpm) 16.5 (4,367)

Raw Water Consumption, m3/min (gpm) 13.1 (3,465) 1 - HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 2 - Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads 173

Cost and Performance Baseline for Fossil Energy Plants Environmental Performance The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 2.4. A summary of the plant air emissions for Case 3 is presented in Exhibit 3-47.

Exhibit 3-47 Case 3 Air Emissions Tonne/year kg/GJ kg/MWh (ton/year)

(lb/106 Btu) (lb/MWh) 80% capacity factor SO2 0.005 (0.012) 200 (220) 0.039 (.09)

NOx 0.026 (0.060) 1,017 (1,122) 0.197 (.434)

Particulates 0.003 (0.0071) 121 (133) 0.023 (.052)

Hg 2.46E-7 (5.71E-7) 0.010 (0.011) 1.88E-6 (4.15E-6)

CO2 85.7 (199.2) 3,398,362 (3,746,053) 657 (1,448)

CO21 776 (1,710) 1 CO2 emissions based on net power instead of gross power The low level of SO2 in the plant emissions is achieved by capture of the sulfur in the gas by the refrigerated Coastal SS Specialty Amine (SS Amine) AGR process. The AGR process removes 99.7 percent of the sulfur compounds in the fuel gas down to a level of less than 30 ppmv. This results in a concentration in the FG of less than 4 ppmv. The H2S-rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species to H2S and then recycled back to the gasifier, thereby eliminating the need for a tail gas treatment unit.

NOx emissions are limited by the use of nitrogen dilution (primarily) and humidification (to a lesser extent) to 15 ppmvd (as NO2 @ 15 percent O2). Ammonia in the syngas is removed with process condensate prior to the low-temperature AGR process and destroyed in the Claus plant burner. This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only.

Ninety five percent of the mercury is captured from the syngas by an activated carbon bed.

CO2 emissions represent the uncontrolled discharge from the process.

The carbon balance for the plant is shown in Exhibit 3-48. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected here since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag and CO2 in the stack gas and ASU vent gas.

174

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-48 Case 3 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 132,993 (293,199) Slag 1,064 (2,346)

Air (CO2) 507 (1,118) Stack Gas 132,344 (291,769)

ASU Vent 92 (202)

CO2 Product 0 (0)

Total 133,500 (294,317) Total 133,500 (294,317)

Exhibit 3-49 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible.

Exhibit 3-49 Case 3 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 5,229 (11,528) Elemental Sulfur 5,215 (11,497)

Stack Gas 14 (31)

CO2 Product 0 (0)

Total 5,229 (11,528) Total 5,229 (11,528)

Exhibit 3-50 shows the overall water balance for the plant. The water balance was explained in Case 1 [GEE], but is also presented here for completeness.

Water demand represents the total amount of water required for a particular process. Some water is recovered within the process, primarily as syngas condensate, and is re-used as internal recycle. The difference between demand and recycle is raw water withdrawal. Raw water withdrawal is defined as the water removed from the ground or diverted from a surface-water source for use in the plant and was assumed to be provided 50 percent by a POTW and 50 percent from groundwater. Raw water withdrawal can be represented by the water metered from a raw water source and used in the plant processes for any and all purposes, such as cooling tower makeup, BFW makeup, quench system makeup, and slag handling makeup. The difference between water withdrawal and process water discharge is defined as water consumption and can be represented by the portion of the raw water withdrawn that is evaporated, transpired, incorporated into products or otherwise not returned to the water source from which it was withdrawn. Water consumption represents the net impact of the plant process on the water source balance.

175

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-50 Case 3 Water Balance Process Water Internal Raw Water Water Raw Water Demand, Recycle, Withdrawal, Water Use Discharge, Consumption, m3/min m3/min m3/min m3/min m3/min (gpm)

(gpm) (gpm) (gpm)

(gpm)

Slag Handling 0.46 (122) 0.46 (122) 0.0 (0) 0.0 (0) 0.0 (0)

Slurry Water 1.43 (378) 0.99 (263) 0.4 (115) 0.0 (0) 0.4 (115)

Quench/Wash 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

Humidifier 0.8 (222) 0.8 (222) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.01 (4) -0.01 (-4)

Condenser Makeup 1.3 (354) 0.0 (0) 1.3 (354) 0.0 (0) 1.3 (354)

Gasifier Steam 1.1 (299) 1.1 (299)

Shift Steam GT Steam Dilution BFW Makeup 0.21 (55) 0.21 (55)

Cooling Tower 15.1 (3,991) 0.35 (93) 14.8 (3,898) 3.4 (897) 11.4 (3,000)

BFW Blowdown 0.21 (55) -0.21 (-55)

SWS Blowdown 0.15 (38) -0.15 (-38)

SWS Excess Water Humidifier Tower Blowdown Total 19.2 (5,067) 2.65 (700) 16.5 (4,367) 3.4 (901) 13.1 (3,465)

Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-51 through Exhibit 3-53:

Coal gasification and ASU

Syngas cleanup, sulfur recovery, and tail gas recycle

Combined cycle power generation, steam, and FW An overall plant energy balance is provided in tabular form in Exhibit 3-54. The power out is the combined CT and steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 3-46) is calculated by multiplying the power out by a combined generator efficiency of 98.3 percent.

176

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-51 Case 3 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic LEGEND Ambient Air 280,565 W Air 1 220.0 T N2 to GT Combustor 1,207,199 W 100.0 T 224.9 P 4 Coal/Char/

59.0 T 50.9 H 189.5 P 1,078,070 W Slurry/Slag 14.7 P 18.0 H Four Stage Air 1,078,070 W 389.0 T 13.0 H ASU Compressor Vent 199.0 T 384.0 P Nitrogen 384.0 P Air From GT 88.2 H 54,719 W 39.8 H Compressor 2 68.5 T 22 Oxygen 16.4 P 15.9 H Four Stage N2 280,565 W Compressor 809.8 T Steam 234.9 P Elevated 199.4 H 957,085 W Synthesis Gas 5 Pressure 90.0 T 133,998 W ASU 333,021 W 56.4 P 50.0 T 14.2 H Water 90.0 T 182.0 P 144,019 W 144,019 W 125.0 P 2.9 H 158.8 T 105.0 T 11.5 H Fuel Gas 800.0 P 600.0 P 36.9 H Syngas Recycle 18.8 H Compressor 3 To Claus Plant 1,241,593 W Four Stage O2 1,833.8 T P ABSOLUTE PRESSURE, PSIA Compressor 7,864 W 615.0 P Saturated Steam to HRSG F TEMPERATURE, °F 90.0 T 968.9 H W FLOWRATE, LBM/HR 125.0 P Steam H ENTHALPY, BTU/LBM 11.5 H Drum BFW from HRSG MWE POWER, MEGAWATTS ELECTRICAL Blowdown to Flash Tank Raw Syngas NOTES:

to Scrubber Steam

1. ENTHALPY REFERENCE POINT IS NATURAL STATE Milled Coal Fire AT 32 °F AND 0.08865 PSIA 149,578 W 1,241,593 W 1,061,562 W Tube 333,021 W 650.0 T 450.0 T 450.0 T 459,958 W 6 Boiler 223.0 T 740.0 P 600.0 P 600.0 P 59.0 T 361.4 H 361.4 H 740.0 P 1,316.8 H 14.7 P 7 37.5 H IP BFW 8

188,951 W N2 Diluent 300.0 T Preheater PLANT PERFORMANCE

SUMMARY

840.0 P 1,241,593 W 1,241,593 W 243.9 H Slurry Mix 600.0 T 600.0 T Tank 605.0 P 605.0 P Water Gross Plant Power: 738 MWe 422.3 H 422.3 H Auxiliary Load: 113 MWe Net Plant Power: 625 MWe 648,909 W Net Plant Efficiency, HHV: 39.7%

161.6 T Net Plant Heat Rate: 8,585 BTU/KWe 840.0 P E-Gas TM 3,007.7 H Gasifier Cyclones Candle Filter DOE/NETL DUAL TRAIN IGCC PLANT CASE 3 9

HEAT AND MATERIAL FLOW DIAGRAM 46,947 W Slag 1,900.0 T BITUMINOUS BASELINE STUDY 615.0 P CASE 3 COP GASIFIER ASU AND GASIFICATION DWG. NO. PAGES BB-HMB-CS-3-PG-1 1 OF 3 177

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-52 Case 3 Syngas Cleanup Heat and Mass Balance Schematic LEGEND Air Fuel Gas to GT Humidification 15 16 Coal/Char/

944,788 W Syngas 944,788 W Slurry/Slag 290.3 T Preheater 380.0 T 465.0 P 460.0 P Nitrogen 838,528 W 210.4 H 245.0 H 112.2 T 14 545.0 P Oxygen Claus Plant 23.7 H Catalytic Sour Gas COS Hydrolysis Reactor 1,013,536 W 1,013,536 W Beds 366.7 T 367.0 T Sour Water 590.0 P 580.0 P 289.4 H 289.3 H Furnace 11 17 Tail Steam 10 Gas Clean Gas Acid Gas 61,685 W Synthesis Gas 112.2 T 545.0 P 900,213 W Water COS Hydrolysis 93.7 T Preheater 550.0 P 15.8 H 7,864 W 18 CO2 450.0 T 13 124.5 P 91.9 H Tailgas Mercury P ABSOLUTE PRESSURE, PSIA Removal Claus Oxygen Sulfur F TEMPERATURE, °F Preheater 11,497 W 61,967 W 1,013,536 W W FLOWRATE, LBM/HR 450.0 T 336.7 T 847,104 W 19 H ENTHALPY, BTU/LBM 58.9 P 595.0 P Syngas 95.2 T 12 AGR- MDEA 314.5 H MWE POWER, MEGAWATTS ELECTRICAL 284.4 H Coolers 555.0 P 17.0 H 3 From NOTES:

ASU Knock Out 53,110 W 3,916 W 7,864 W 20 191.1 T 90.0 T Drum 100.0 T 1. ENTHALPY REFERENCE POINT IS NATURAL STATE 799.5 P 65.0 P 125.0 P AT 32 °F AND 0.08865 PSIA Syngas 190.1 H 11.5 H Scrubber Condensate Hydrogenation Raw Syngas to Deaerator And Tail Gas Cooling Sour PLANT PERFORMANCE

SUMMARY

Drum Condensate Gross Plant Power: 738 MWe 1,061,562 W Auxiliary Load: 113 MWe 450.0 T Net Plant Power: 625 MWe 600.0 P Net Plant Efficiency, HHV: 39.7%

361.4 H Net Plant Heat Rate: 8,585 BTU/KWe Sour Stripper Tail Gas Makeup Water Compressor DOE/NETL 53,768 W 120.0 T 56.8 P DUAL TRAIN IGCC PLANT 33.1 H CASE 3 Knock Out HEAT AND MATERIAL FLOW DIAGRAM 8,858 W 118.5 T BITUMINOUS BASELINE STUDY 56.8 P CASE 3 44.8 H COP GASIFIER GAS CLEANUP SYSTEM To Water Treatment DWG. NO. PAGES BB-HMB-CS-3-PG-2 2 OF 3 178

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-53 Case 3 Combined Cycle Power Generation Heat and Mass Balance Schematic LEGEND Air HP BFW to Syngas Cooler Coal/Char/

HP Saturated Steam to HRSG Superheater Slurry/Slag Nitrogen 8,756,427 W 269.9 T Oxygen 15.2 P 117.1 H Sour Gas 23 HRSG 24 Stack 8,756,427 W LP Flash Tops Sour Water 1,091.1 T 15.2 P 9,989 W MP Flash Bottoms Steam Nitrogen Diluent 337.0 H 298.0 T From Gasifier 65.0 P Island Preheating 1,078,070 W 1,179.0 H Synthesis Gas 199.0 T 25 1,603,037 W 384.0 P 235.0 T Deaerator 39.8 H 1,595,870 W 105.0 P Water 1,041.1 T 203.7 H 1,814.7 P 1,623,826 W 1,505.0 H 278.8 T Flue Gas Fuel Gas 2,250.7 P LP BFW 16 252.3 H 944,788 W Blowdown 380.0 T 27,956 W Flash 460.0 P LP Pump P ABSOLUTE PRESSURE, PSIA 585.0 T To Claus 245.0 H Gasifier Steam 2,000.7 P F TEMPERATURE, °F To WWT 593.3 H HP Pump W FLOWRATE, LBM/HR Air Extraction IP BFW H ENTHALPY, BTU/LBM 22 MWE POWER, MEGAWATTS ELECTRICAL 280,565 W IP Pump 809.8 T NOTES:

234.9 P 1,414,204 W 199.4 H Compressor Expander 539.6 T 65.0 P 1. ENTHALPY REFERENCE POINT IS NATURAL STATE 1,301.6 H AT 32 °F AND 0.08865 PSIA Generator HP IP LP Turbine Turbine Steam Turbine Advanced F-Class Turbine Gas Turbine LP Generator Process Header Intake Ip Extraction Steam PLANT PERFORMANCE

SUMMARY

To 250 PSIA Header 25,722 W 9,522 W Gross Plant Power: 738 MWe 781 W 8,828 W 1,313 W 896.4 T 660.4 T Auxiliary Load: 113 MWe 1,041.1 T 700.3 T 539.6 T 280.0 P 65.0 P Net Plant Power: 625 MWe 1,814.7 P 501.4 P 65.0 P 1,472.0 H 1,361.1 H Ambient Air Net Plant Efficiency, HHV: 39.7%

21 1,505.0 H 1,357.3 H 1,301.6 H Net Plant Heat Rate: 8,585 BTU/KWe 7,014,133 W Steam Seal CONDENSER Make-up Regulator 176,912 W 59.0 T 1,400 W 14.7 P 59.0 T 212.0 T 1,400 W HOT WELL 14.7 P 13.0 H 14.7 P DOE/NETL 660.4 T 27.1 H 179.9 H 65.0 P 1,603,037 W 1,361.1 H 101.1 T DUAL TRAIN IGCC PLANT 1.0 P CASE 3 69.1 H Condensate HEAT AND MATERIAL FLOW DIAGRAM Pump BITUMINOUS BASELINE STUDY Gland CASE 3 1,603,037 W 103.2 T Steam COP GASIFIER 120.0 P Condenser POWER BLOCK SYSTEM Condensate to Gasification Island 71.4 H DWG. NO. PAGES BB-HMB-CS-3-PG-3 3 OF 3 179

Cost and Performance Baseline for Fossil Energy Plants This page intentionally left blank 180

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-54 Case 3 Overall Energy Balance (0°C [32°F] Reference)

Sensible +

HHV Power Total Latent Heat In GJ/hr (MMBtu/hr)

Coal 5,661 (5,366) 4.7 (4.5) 5,666 (5,370)

ASU Air 16.6 (15.7) 17 (16)

GT Air 96.2 (91.2) 96 (91)

Water 62.2 (58.9) 62 (59)

Auxiliary Power 407 (386) 407 (386)

TOTAL 5,661 (5,366) 179.6 (170.2) 407 (386) 6,248 (5,922)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0.9 (0.9) 1 (1)

Slag 35 (33) 23.9 (22.7) 59 (56)

Sulfur 48 (46) 0.6 (0.6) 49 (46)

CO2 Cooling Tower 25.2 (23.9) 25 (24)

Blowdown HRSG Flue Gas 1,082 (1,025) 1,082 (1,025)

Condenser 1,415 (1,342) 1,415 (1,342)

Non-Condenser 411 (389) 411 (389)

Cooling Tower Loads*

Process Losses** 549 (521) 549 (521)

Power 2,658 (2,519) 2,658 (2,519)

TOTAL 83 (79) 3,507 (3,324) 2,658 (2,519) 6,248 (5,922)

Includes ASU compressor intercoolers, CO2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection) and extraction air cooler.

- Calculated by difference to close the energy balance.

181

Cost and Performance Baseline for Fossil Energy Plants 3.3.6 Case 3 - Major Equipment List Major equipment items for the CoP gasifier with no CO2 capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section 3.3.7. In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 COAL HANDLING Equipment Operating Description Type Design Condition Spares No. Qty.

Bottom Trestle Dumper and 1 N/A 181 tonne (200 ton) 2 0 Receiving Hoppers 2 Feeder Belt 572 tonne/hr (630 tph) 2 0 3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0 4 Transfer Tower No. 1 Enclosed N/A 1 0 5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0 As-Received Coal Sampling 6 Two-stage N/A 1 0 System 7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0 8 Reclaim Hopper N/A 45 tonne (50 ton) 2 1 9 Feeder Vibratory 172 tonne/hr (190 tph) 2 1 10 Conveyor No. 3 Belt w/ tripper 345 tonne/hr (380 tph) 1 0 11 Crusher Tower N/A N/A 1 0 12 Coal Surge Bin w/ Vent Filter Dual outlet 172 tonne (190 ton) 2 0 Impactor 8 cm x 0 - 3 cm x 0 13 Crusher 2 0 reduction (3" x 0 1/4" x 0)

As-Fired Coal Sampling 14 Swing hammer N/A 1 1 System 15 Conveyor No. 4 Belt w/tripper 345 tonne/hr (380 tph) 1 0 16 Transfer Tower No. 2 Enclosed N/A 1 0 17 Conveyor No. 5 Belt w/ tripper 345 tonne/hr (380 tph) 1 0 Coal Silo w/ Vent Filter and 18 Field erected 726 tonne (800 ton) 3 0 Slide Gates 182

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 2 COAL PREPARATION AND FEED Equipment Operating Description Type Design Condition Spares No. Qty.

1 Feeder Vibratory 73 tonne/h (80 tph) 3 0 2 Conveyor No. 6 Belt w/tripper 227 tonne/h (250 tph) 1 0 3 Rod Mill Feed Hopper Dual Outlet 463 tonne (510 ton) 1 0 4 Weigh Feeder Belt 118 tonne/h (130 tph) 2 0 5 Rod Mill Rotary 118 tonne/h (130 tph) 2 0 Slurry Water Storage Tank 6 Field erected 283,227 liters (74,820 gal) 2 0 with Agitator 7 Slurry Water Pumps Centrifugal 795 lpm (210 gpm) 2 1 8 Trommel Screen Coarse 163 tonne/h (180 tph) 2 0 Rod Mill Discharge Tank with 9 Field erected 370,519 liters (97,880 gal) 2 0 Agitator 10 Rod Mill Product Pumps Centrifugal 3,028 lpm (800 gpm) 2 2 Slurry Storage Tank with 11 Field erected 1,111,406 liters (293,600 gal) 2 0 Agitator 12 Slurry Recycle Pumps Centrifugal 6,057 lpm (1,600 gpm) 2 2 Positive 13 Slurry Product Pumps 3,028 lpm (800 gpm) 2 2 displacement 183

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment Operating Description Type Design Condition Spares No. Qty.

Demineralized Water Vertical, cylindrical, 1 1,082,628 liters (286,000 gal) 2 0 Storage Tank outdoor 6,700 lpm @ 91 m H2O 2 Condensate Pumps Vertical canned 2 1 (1,770 gpm @ 300 ft H2O)

Deaerator (integral w/

3 Horizontal spray type 478,994 kg/hr (1,056,000 lb/hr) 2 0 HRSG)

Intermediate Pressure Horizontal centrifugal, 8,101 lpm @ 27 m H2O 4 2 1 Feedwater Pump single stage (2,140 gpm @ 90 ft H2O)

HP water: 7,041 lpm @ 1,859 m High Pressure Barrel type, multi-stage, 5 H2O (1,860 gpm @ 6,100 ft 2 1 Feedwater Pump No. 1 centrifugal H2O)

High Pressure Barrel type, multi-stage, IP water: 492 lpm @ 223 m H2O 6 2 1 Feedwater Pump No. 2 centrifugal (130 gpm @ 730 ft H2O)

Shop fabricated, water 18,144 kg/hr, 2.8 MPa, 343°C 7 Auxiliary Boiler 1 0 tube (40,000 lb/hr, 400 psig, 650°F)

Service Air 28 m3/min @ 0.7 MPa 8 Flooded Screw 2 1 Compressors (1,000 scfm @ 100 psig) 9 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1 Closed Cylce Cooling 10 Plate and frame 240 GJ/hr (228 MMBtu/hr) each 2 0 Heat Exchangers Closed Cycle Cooling 86,307 lpm @ 21 m H2O 11 Horizontal centrifugal 2 1 Water Pumps (22,800 gpm @ 70 ft H2O)

Engine-Driven Fire Vertical turbine, diesel 3,785 lpm @ 107 m H2O 12 1 1 Pump engine (1,000 gpm @ 350 ft H2O)

Fire Service Booster Two-stage horizontal 2,650 lpm @ 76 m H2O 13 1 1 Pump centrifugal (700 gpm @ 250 ft H2O)

Stainless steel, single 4,240 lpm @ 18 m H2O 14 Raw Water Pumps 2 1 suction (1,120 gpm @ 60 ft H2O)

Stainless steel, single 2,801 lpm @ 268 m H2O 15 Ground Water Pumps 3 1 suction (740 gpm @ 880 ft H2O)

Stainless steel, single 1,628 lpm @ 49 m H2O 16 Filtered Water Pumps 2 1 suction (430 gpm @ 160 ft H2O) 17 Filtered Water Tank Vertical, cylindrical 787,366 liter (208,000 gal) 2 0 Makeup Water Anion, cation, and 18 303 lpm (80 gpm) 2 0 Demineralizer mixed bed Liquid Waste Treatment 19 10 years, 24-hour storm 1 0 System 184

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY AND FUEL GAS SATURATION Equipment Operating Description Type Design Condition Spares No. Qty.

Pressurized two-stage, 2,722 tonne/day, 4.2 MPa 1 Gasifier slurry-feed entrained 2 0 (3,000 tpd, 615 psia) bed 2 Synthesis Gas Cooler Fire-tube boiler 309,804 kg/hr (683,000 lb/hr) 2 0 309,804 kg/hr (683,000 lb/hr) 3 Synthesis Gas Cyclone High efficiency 2 0 Design efficiency 90%

Pressurized filter with 4 Candle Filter metallic filters 2 0 pulse-jet cleaning Syngas Scrubber 5 Including Sour Water Vertical upflow 264,898 kg/hr (584,000 lb/hr) 2 0 Stripper Shell and tube with 6 Raw Gas Coolers 212,735 kg/hr (469,000 lb/hr) 8 0 condensate drain Raw Gas Knockout Vertical with mist 212,281 kg/hr, 35°C, 3.9 MPa 7 2 0 Drum eliminator (468,000 lb/hr, 95°F, 560 psia)

Saturation Water 8 Shell and tube 91 GJ/hr (86 MMBtu/hr) 2 0 Economizers 235,868 kg/hr, 143°C, 3.3 MPa 9 Fuel Gas Saturator Vertical tray tower 2 0 (520,000 lb/hr, 290°F, 480 psia) 2,271 lpm @ 12 m H2O 10 Saturator Water Pump Centrifugal 2 2 (600 gpm @ 40 ft H2O) 11 Synthesis Gas Reheater Shell and tube 209,106 kg/hr (461,000 lb/hr) 2 0 Self-supporting, carbon 264,898 kg/hr (584,000 lb/hr) 12 Flare Stack steel, stainless steel top, 2 0 syngas pilot ignition ASU Main Air 4,134 m3/min @ 1.3 MPa 13 Centrifugal, multi-stage 2 0 Compressor (146,000 scfm @ 190 psia) 1,996 tonne/day (2,200 tpd) of 14 Cold Box Vendor design 2 0 95% purity oxygen 1,019 m3/min (36,000 scfm) 15 Oxygen Compressor Centrifugal, multi-stage Suction - 0.9 MPa (130 psia) 2 0 Discharge - 5.1 MPa (740 psia) 3,370 m3/min (119,000 scfm)

Primary Nitrogen 16 Centrifugal, multi-stage Suction - 0.4 MPa (60 psia) 2 0 Compressor Discharge - 2.7 MPa (390 psia) 481 m3/min (17,000 scfm)

Secondary Nitrogen 17 Centrifugal, single-stage Suction - 1.2 MPa (180 psia) 2 0 Compressor Discharge - 2.7 MPa (390 psia) 57 m3/min (2,000 scfm)

Transport Nitrogen 18 Centrifugal, single-stage Suction - 2.6 MPa (380 psia) 2 0 Boost Compressor Discharge - 5.4 MPa (790 psia)

Extraction Air Heat Gas-to-gas, vendor 69,853 kg/hr, 432°C, 1.6 MPa 19 2 0 Exchanger design (154,000 lb/hr, 810°F, 235 psia) 185

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 5 SYNGAS CLEANUP Equipment Operating Description Type Design Condition Spares No. Qty.

211,374 kg/hr (466,000 lb/hr)

Sulfated carbon 1 Mercury Adsorber 35°C (95°F) 2 0 bed 3.8 MPa (555 psia) 2 Sulfur Plant Claus type 138 tonne/day (152 tpd) 1 0 252,651 kg/hr (557,000 lb/hr)

Fixed bed, 3 COS Hydrolysis Reactor 188°C (370°F) 2 0 catalytic 4.1 MPa (590 psia) 224,528 kg/hr (495,000 lb/hr) 4 Acid Gas Removal Plant MDEA 34°C (94°F) 2 0 3.8 MPa (550 psia) 28,108 kg/hr (61,967 lb/hr)

Fixed bed, 5 Hydrogenation Reactor 232°C (450°F) 1 0 catalytic 0.4 MPa (58.9 psia)

Tail Gas Recycle 6 Centrifugal 24,090 kg/hr (53,110 lb/hr) each 1 0 Compressor ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES Equipment Operating Description Type Design Condition Spares No. Qty.

1 Gas Turbine Advanced F class 232 MW 2 0 260 MVA @ 0.9 p.f., 24 kV, 2 Gas Turbine Generator TEWAC 2 0 60 Hz, 3-phase ACCOUNT 7 HRSG, STACK, AND DUCTING Equipment Operating Description Type Design Condition Spares No. Qty.

CS plate, type 409SS 76 m (250 ft) high x 1 Stack 1 0 liner 8.4 m (28 ft) diameter Main steam - 398,131 kg/hr, 12.4 Drum, multi-pressure MPa/561°C (877,728 lb/hr, Heat Recovery with economizer 1,800 psig/1,041°F) 2 2 0 Steam Generator section and integral Reheat steam - 358,685 kg/hr, deaerator 3.1 MPa/561°C (790,766 lb/hr, 452 psig/1,041°F) 186

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES Equipment Operating Description Type Design Condition Spares No. Qty.

Commercially 289 MW 1 Steam Turbine available advanced 12.4 MPa/561°C/561°C 1 0 steam turbine (1,800 psig/ 1041°F/1041°F)

Hydrogen cooled, 320 MVA @ 0.9 p.f., 24 2 Steam Turbine Generator 1 0 static excitiation kV, 60 Hz, 3-phase 50% steam flow @ design 3 Steam Bypass One per HRSG 2 0 steam conditions 1,561 GJ/hr (1,480 Single pass, divided MMBtu/hr), Inlet water 4 Surface Condenser waterbox including temperature 16°C (60°F), 1 0 vacuum pumps Water temperature rise 11°C (20°F)

ACCOUNT 9 COOLING WATER SYSTEM Equipment Operating Description Type Design Condition Spares No. Qty.

Circulating Water 389,897 lpm @ 30 m 1 Vertical, wet pit 2 1 Pumps (103,000 gpm @ 100 ft) 11°C (51.5°F) wet bulb / 16°C Evaporative, (60°F) CWT / 27°C (80°F) HWT 2 Cooling Tower mechanical draft, multi- 1 0

/ 2,173 GJ/hr (2,060 MMBtu/hr) cell heat duty 187

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 10 SLAG RECOVERY AND HANDLING Equipment Operating Description Type Design Condition Spares No. Qty.

1 Slag Quench Tank Water bath 223,339 liters (59,000 gal) 2 0 2 Slag Crusher Roll 12 tonne/hr (13 tph) 2 0 3 Slag Depressurizer Proprietary 12 tonne/hr (13 tph) 2 0 4 Slag Receiving Tank Horizontal, weir 136,275 liters (36,000 gal) 2 0 5 Black Water Overflow Tank Shop fabricated 60,567 liters (16,000 gal) 2 6 Slag Conveyor Drag chain 12 tonne/hr (13 tph) 2 0 7 Slag Separation Screen Vibrating 12 tonne/hr (13 tph) 2 0 8 Coarse Slag Conveyor Belt/bucket 12 tonne/hr (13 tph) 2 0 9 Fine Ash Settling Tank Vertical, gravity 189,271 liters (50,000 gal) 2 0 Horizontal 38 lpm @ 14 m H2O 10 Fine Ash Recycle Pumps 2 2 centrifugal (10 gpm @ 46 ft H2O) 11 Grey Water Storage Tank Field erected 60,567 liters (16,000 gal) 2 0 227 lpm @ 433 m H2O 12 Grey Water Pumps Centrifugal 2 2 (60 gpm @ 1,420 ft H2O)

Vertical, field 13 Slag Storage Bin 816 tonne (900 tons) 2 0 erected 14 Unloading Equipment Telescoping chute 100 tonne/hr (110 tph) 1 0 188

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 11 ACCESSORY ELECTRIC PLANT Equipment Operating Description Type Design Condition Spares No. Qty.

CTG Step-up 24 kV/345 kV, 260 MVA, 1 Oil-filled 2 0 Transformer 3-ph, 60 Hz STG Step-up 24 kV/345 kV, 320 MVA, 2 Oil-filled 1 0 Transformer 3-ph, 60 Hz High Voltage 345 kV/13.8 kV, 47 MVA, 3 Auxiliary Oil-filled 2 0 3-ph, 60 Hz Transformer Medium Voltage 24 kV/4.16 kV, 29 MVA, 4 Auxiliary Oil-filled 1 1 3-ph, 60 Hz Transformer Low Voltage 4.16 kV/480 V, 4 MVA, 5 Dry ventilated 1 1 Transformer 3-ph, 60 Hz CTG Isolated 6 Phase Bus Duct Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 2 0 and Tap Bus STG Isolated 7 Phase Bus Duct Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0 and Tap Bus Medium Voltage 8 Metal clad 4.16 kV, 3-ph, 60 Hz 1 1 Switchgear Low Voltage 9 Metal enclosed 480 V, 3-ph, 60 Hz 1 1 Switchgear Emergency Diesel Sized for emergency 10 750 kW, 480 V, 3-ph, 60 Hz 1 0 Generator shutdown 189

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 12 INSTRUMENTATION AND CONTROLS Equipment Operating Description Type Design Condition Spares No. Qty.

Monitor/keyboard; DCS - Main Operator printer (laser Operator stations/printers and 1 1 0 Control color); Engineering engineering stations/printers printer (laser B&W)

Microprocessor with 2 DCS - Processor N/A 1 0 redundant input/output DCS - Data 3 Fiber optic Fully redundant, 25% spare 1 0 Highway 190

Cost and Performance Baseline for Fossil Energy Plants 3.3.7 Case 3 - Costs Estimating Results The cost estimating methodology was described previously in Section 2.6. Exhibit 3-55 shows the total plant capital cost summary organized by cost account and Exhibit 3-56 shows a more detailed breakdown of the capital costs along with owners costs, TOC and TASC. Exhibit 3-57 shows the initial and annual O&M costs.

The estimated TOC of the CoP gasifier with no CO2 capture is $2,351/kW. Process contingency represents 2.1 percent of the TOC and project contingency is 10.9 percent. The COE is 74.0 mills/kWh.

191

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-55 Case 3 Total Plant Cost Summary Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study TOTAL PLANT COST

SUMMARY

Case: Case 3 - ConocoPhillips 625MW IGCC w/o CO2 Plant Size: 625.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING $13,783 $2,561 $10,689 $0 $0 $27,033 $2,454 $0 $5,897 $35,384 $57 2 COAL & SORBENT PREP & FEED $23,433 $4,283 $14,157 $0 $0 $41,873 $3,759 $0 $9,126 $54,759 $88 3 FEEDWATER & MISC. BOP SYSTEMS $9,806 $8,188 $9,436 $0 $0 $27,429 $2,581 $0 $6,822 $36,832 $59 4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $117,991 $0 $65,449 $0 $0 $183,440 $16,853 $25,442 $34,617 $260,352 $417 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $145,765 $0 w/equip. $0 $0 $145,765 $14,129 $0 $15,989 $175,883 $281 4.4-4.9 Other Gasification Equipment $17,104 $9,335 $11,583 $0 $0 $38,023 $3,633 $0 $9,003 $50,658 $81 SUBTOTAL 4 $280,861 $9,335 $77,032 $0 $0 $367,228 $34,614 $25,442 $59,609 $486,893 $779 5A GAS CLEANUP & PIPING $47,943 $3,806 $47,221 $0 $0 $98,970 $9,573 $85 $21,865 $130,493 $209 5B CO2 COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $85,751 $0 $6,269 $0 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $185 6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4 SUBTOTAL 6 $85,751 $806 $7,162 $0 $0 $93,719 $8,883 $4,601 $11,092 $118,295 $189 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $35,467 $0 $5,043 $0 $0 $40,510 $3,852 $0 $4,436 $48,798 $78 7.2-7.9 SCR System, Ductwork and Stack $3,335 $2,378 $3,114 $0 $0 $8,827 $818 $0 $1,570 $11,215 $18 SUBTOTAL 7 $38,802 $2,378 $8,157 $0 $0 $49,337 $4,670 $0 $6,006 $60,013 $96 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $28,970 $0 $4,963 $0 $0 $33,934 $3,256 $0 $3,719 $40,909 $65 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $10,556 $996 $7,591 $0 $0 $19,143 $1,738 $0 $4,220 $25,101 $40 SUBTOTAL 8 $39,526 $996 $12,554 $0 $0 $53,076 $4,994 $0 $7,939 $66,009 $106 9 COOLING WATER SYSTEM $9,144 $8,826 $7,504 $0 $0 $25,474 $2,366 $0 $5,687 $33,527 $54 10 ASH/SPENT SORBENT HANDLING SYS $19,026 $1,439 $9,440 $0 $0 $29,905 $2,869 $0 $3,575 $36,349 $58 11 ACCESSORY ELECTRIC PLANT $27,425 $10,189 $20,427 $0 $0 $58,041 $4,986 $0 $11,827 $74,854 $120 12 INSTRUMENTATION & CONTROL $10,234 $1,883 $6,594 $0 $0 $18,710 $1,696 $936 $3,556 $24,897 $40 13 IMPROVEMENTS TO SITE $3,328 $1,962 $8,212 $0 $0 $13,503 $1,333 $0 $4,451 $19,287 $31 14 BUILDINGS & STRUCTURES $0 $6,670 $7,642 $0 $0 $14,313 $1,303 $0 $2,553 $18,169 $29 TOTAL COST $609,063 $63,322 $246,227 $0 $0 $918,612 $86,080 $31,064 $160,007 $1,195,762 $1,913 192

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-56 Case 3 Total Plant Cost Details Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $3,619 $0 $1,769 $0 $0 $5,388 $483 $0 $1,174 $7,045 $11 1.2 Coal Stackout & Reclaim $4,677 $0 $1,134 $0 $0 $5,811 $509 $0 $1,264 $7,584 $12 1.3 Coal Conveyors & Yd Crush $4,349 $0 $1,122 $0 $0 $5,470 $480 $0 $1,190 $7,141 $11 1.4 Other Coal Handling $1,138 $0 $260 $0 $0 $1,397 $122 $0 $304 $1,823 $3 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,561 $6,404 $0 $0 $8,966 $859 $0 $1,965 $11,790 $19 SUBTOTAL 1. $13,783 $2,561 $10,689 $0 $0 $27,033 $2,454 $0 $5,897 $35,384 $57 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying (incl. w/2.3) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,542 $369 $242 $0 $0 $2,153 $184 $0 $467 $2,805 $4 2.3 Slurry Prep & Feed $21,042 $0 $9,358 $0 $0 $30,400 $2,714 $0 $6,623 $39,737 $64 2.4 Misc.Coal Prep & Feed $848 $617 $1,851 $0 $0 $3,316 $305 $0 $724 $4,345 $7 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,297 $2,707 $0 $0 $6,004 $556 $0 $1,312 $7,871 $13 SUBTOTAL 2. $23,433 $4,283 $14,157 $0 $0 $41,873 $3,759 $0 $9,126 $54,759 $88 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $3,157 $5,422 $2,862 $0 $0 $11,440 $1,060 $0 $2,500 $15,000 $24 3.2 Water Makeup & Pretreating $585 $61 $327 $0 $0 $974 $93 $0 $320 $1,387 $2 3.3 Other Feedwater Subsystems $1,727 $584 $525 $0 $0 $2,836 $255 $0 $618 $3,709 $6 3.4 Service Water Systems $335 $690 $2,394 $0 $0 $3,419 $334 $0 $1,126 $4,879 $8 3.5 Other Boiler Plant Systems $1,798 $697 $1,727 $0 $0 $4,221 $400 $0 $924 $5,546 $9 3.6 FO Supply Sys & Nat Gas $313 $591 $551 $0 $0 $1,456 $140 $0 $319 $1,915 $3 3.7 Waste Treatment Equipment $818 $0 $499 $0 $0 $1,318 $128 $0 $434 $1,880 $3 3.8 Misc. Power Plant Equipment $1,072 $143 $550 $0 $0 $1,765 $170 $0 $581 $2,517 $4 SUBTOTAL 3. $9,806 $8,188 $9,436 $0 $0 $27,429 $2,581 $0 $6,822 $36,832 $59 4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $117,991 $0 $65,449 $0 $0 $183,440 $16,853 $25,442 $34,617 $260,352 $417 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $145,765 $0 w/equip. $0 $0 $145,765 $14,129 $0 $15,989 $175,883 $281 4.4 LT Heat Recovery & FG Saturation $17,104 $0 $6,502 $0 $0 $23,606 $2,304 $0 $5,182 $31,092 $50 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Flare Stack System $0 $1,503 $612 $0 $0 $2,114 $203 $0 $463 $2,780 $4 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $7,833 $4,469 $0 $0 $12,302 $1,126 $0 $3,357 $16,785 $27 SUBTOTAL 4. $280,861 $9,335 $77,032 $0 $0 $367,228 $34,614 $25,442 $59,609 $486,893 $779 193

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-56 Case 3 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 5A GAS CLEANUP & PIPING 5A.1 MDEA-LT AGR $33,341 $0 $28,290 $0 $0 $61,631 $5,960 $0 $13,518 $81,110 $130 5A.2 Elemental Sulfur Plant $9,938 $1,981 $12,822 $0 $0 $24,741 $2,403 $0 $5,429 $32,573 $52 5A.3 Mercury Removal $970 $0 $738 $0 $0 $1,708 $165 $85 $392 $2,350 $4 5A.4 COS Hydrolysis $3,196 $0 $4,173 $0 $0 $7,369 $717 $0 $1,617 $9,703 $16 5A.5 Particulate Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $499 $280 $157 $0 $0 $936 $89 $0 $205 $1,230 $2 5A.7 Fuel Gas Piping $0 $768 $538 $0 $0 $1,306 $121 $0 $285 $1,712 $3 5A.9 HGCU Foundations $0 $778 $501 $0 $0 $1,279 $118 $0 $419 $1,816 $3 SUBTOTAL 5A. $47,943 $3,806 $47,221 $0 $0 $98,970 $9,573 $85 $21,865 $130,493 $209 5B CO2 COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5B. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $85,751 $0 $6,269 $0 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $185 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4 SUBTOTAL 6. $85,751 $806 $7,162 $0 $0 $93,719 $8,883 $4,601 $11,092 $118,295 $189 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $35,467 $0 $5,043 $0 $0 $40,510 $3,852 $0 $4,436 $48,798 $78 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,710 $1,220 $0 $0 $2,929 $257 $0 $637 $3,823 $6 7.4 Stack $3,335 $0 $1,253 $0 $0 $4,588 $440 $0 $503 $5,530 $9 7.9 HRSG, Duct & Stack Foundations $0 $668 $642 $0 $0 $1,310 $122 $0 $430 $1,861 $3 SUBTOTAL 7. $38,802 $2,378 $8,157 $0 $0 $49,337 $4,670 $0 $6,006 $60,013 $96 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $28,970 $0 $4,963 $0 $0 $33,934 $3,256 $0 $3,719 $40,909 $65 8.2 Turbine Plant Auxiliaries $201 $0 $460 $0 $0 $661 $65 $0 $73 $798 $1 8.3 Condenser & Auxiliaries $4,785 $0 $1,529 $0 $0 $6,314 $604 $0 $692 $7,609 $12 8.4 Steam Piping $5,570 $0 $3,918 $0 $0 $9,489 $815 $0 $2,576 $12,880 $21 8.9 TG Foundations $0 $996 $1,683 $0 $0 $2,679 $254 $0 $880 $3,813 $6 SUBTOTAL 8. $39,526 $996 $12,554 $0 $0 $53,076 $4,994 $0 $7,939 $66,009 $106 194

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-56 Case 3 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 9 COOLING WATER SYSTEM 9.1 Cooling Towers $6,338 $0 $1,153 $0 $0 $7,491 $713 $0 $1,231 $9,434 $15 9.2 Circulating Water Pumps $1,648 $0 $113 $0 $0 $1,761 $149 $0 $287 $2,197 $4 9.3 Circ.Water System Auxiliaries $140 $0 $20 $0 $0 $160 $15 $0 $26 $202 $0 9.4 Circ.Water Piping $0 $5,855 $1,518 $0 $0 $7,373 $666 $0 $1,608 $9,647 $15 9.5 Make-up Water System $327 $0 $467 $0 $0 $794 $76 $0 $174 $1,044 $2 9.6 Component Cooling Water Sys $691 $827 $588 $0 $0 $2,106 $197 $0 $461 $2,764 $4 9.9 Circ.Water System Foundations $0 $2,144 $3,645 $0 $0 $5,789 $549 $0 $1,901 $8,239 $13 SUBTOTAL 9. $9,144 $8,826 $7,504 $0 $0 $25,474 $2,366 $0 $5,687 $33,527 $54 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $16,609 $0 $8,191 $0 $0 $24,799 $2,383 $0 $2,718 $29,900 $48 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $548 $0 $596 $0 $0 $1,144 $111 $0 $188 $1,443 $2 10.7 Ash Transport & Feed Equipment $735 $0 $177 $0 $0 $912 $85 $0 $150 $1,147 $2 10.8 Misc. Ash Handling Equipment $1,135 $1,391 $415 $0 $0 $2,941 $280 $0 $483 $3,704 $6 10.9 Ash/Spent Sorbent Foundation $0 $48 $61 $0 $0 $109 $10 $0 $36 $155 $0 SUBTOTAL 10. $19,026 $1,439 $9,440 $0 $0 $29,905 $2,869 $0 $3,575 $36,349 $58 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $951 $0 $940 $0 $0 $1,891 $181 $0 $207 $2,279 $4 11.2 Station Service Equipment $3,741 $0 $337 $0 $0 $4,078 $376 $0 $445 $4,900 $8 11.3 Switchgear & Motor Control $6,917 $0 $1,258 $0 $0 $8,174 $758 $0 $1,340 $10,272 $16 11.4 Conduit & Cable Tray $0 $3,213 $10,599 $0 $0 $13,812 $1,336 $0 $3,787 $18,935 $30 11.5 Wire & Cable $0 $6,139 $4,034 $0 $0 $10,172 $739 $0 $2,728 $13,639 $22 11.6 Protective Equipment $0 $680 $2,474 $0 $0 $3,153 $308 $0 $519 $3,980 $6 11.7 Standby Equipment $234 $0 $229 $0 $0 $463 $44 $0 $76 $583 $1 11.8 Main Power Transformers $15,583 $0 $145 $0 $0 $15,727 $1,190 $0 $2,538 $19,454 $31 11.9 Electrical Foundations $0 $157 $412 $0 $0 $569 $54 $0 $187 $810 $1 SUBTOTAL 11. $27,425 $10,189 $20,427 $0 $0 $58,041 $4,986 $0 $11,827 $74,854 $120 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,010 $0 $675 $0 $0 $1,685 $159 $84 $289 $2,218 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $232 $0 $149 $0 $0 $381 $36 $19 $87 $523 $1 12.7 Computer & Accessories $5,389 $0 $173 $0 $0 $5,562 $510 $278 $635 $6,985 $11 12.8 Instrument Wiring & Tubing $0 $1,883 $3,849 $0 $0 $5,731 $486 $287 $1,626 $8,130 $13 12.9 Other I & C Equipment $3,602 $0 $1,749 $0 $0 $5,352 $504 $268 $918 $7,041 $11 SUBTOTAL 12. $10,234 $1,883 $6,594 $0 $0 $18,710 $1,696 $936 $3,556 $24,897 $40 195

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-56 Case 3 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $104 $2,232 $0 $0 $2,336 $232 $0 $771 $3,339 $5 13.2 Site Improvements $0 $1,857 $2,468 $0 $0 $4,326 $427 $0 $1,426 $6,178 $10 13.3 Site Facilities $3,328 $0 $3,512 $0 $0 $6,841 $674 $0 $2,255 $9,770 $16 SUBTOTAL 13. $3,328 $1,962 $8,212 $0 $0 $13,503 $1,333 $0 $4,451 $19,287 $31 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,435 $3,468 $0 $0 $5,903 $543 $0 $967 $7,413 $12 14.3 Administration Building $0 $842 $611 $0 $0 $1,452 $129 $0 $237 $1,819 $3 14.4 Circulation Water Pumphouse $0 $166 $88 $0 $0 $254 $22 $0 $41 $317 $1 14.5 Water Treatment Buildings $0 $489 $477 $0 $0 $967 $87 $0 $158 $1,212 $2 14.6 Machine Shop $0 $431 $295 $0 $0 $726 $64 $0 $119 $909 $1 14.7 Warehouse $0 $696 $449 $0 $0 $1,145 $101 $0 $187 $1,433 $2 14.8 Other Buildings & Structures $0 $417 $324 $0 $0 $741 $66 $0 $161 $969 $2 14.9 Waste Treating Building & Str. $0 $931 $1,780 $0 $0 $2,711 $253 $0 $593 $3,557 $6 SUBTOTAL 14. $0 $6,670 $7,642 $0 $0 $14,313 $1,303 $0 $2,553 $18,169 $29 TOTAL COST $609,063 $63,322 $246,227 $0 $0 $918,612 $86,080 $31,064 $160,007 $1,195,762 $1,913 Owner's Costs Preproduction Costs 6 Months All Labor $12,309 $20 1 Month Maintenance Materials $2,766 $4 1 Month Non-fuel Consumables $239 $0 1 Month Waste Disposal $279 $0 25% of 1 Months Fuel Cost at 100% CF $1,603 $3 2% of TPC $23,915 $38 Total $41,111 $66 Inventory Capital 60 day supply of fuel and consumables at 100% CF $13,092 $21 0.5% of TPC (spare parts) $5,979 $10 Total $19,071 $31 Initial Cost for Catalyst and Chemicals $1,084 $2 Land $900 $1 Other Owner's Costs $179,364 $287 Financing Costs $32,286 $52 Total Overnight Costs (TOC) $1,469,577 $2,351 TASC Multiplier (IOU, high-risk, 35 year) 1.140 Total As-Spent Cost (TASC) $1,675,318 $2,680 196

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-57 Case 3 Initial and Annual Operating and Maintenance Costs INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 3 - ConocoPhillips 625MW IGCC w/o CO2 Heat Rate-net(Btu/kWh): 8,585 MWe-net: 625 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant Skilled Operator 2.0 2.0 Operator 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 3.0 3.0 TOTAL-O.J.'s 15.0 15.0 Annual Cost Annual Unit Cost

$ $/kW-net Annual Operating Labor Cost $5,918,913 $9.469 Maintenance Labor Cost $13,775,415 $22.039 Administrative & Support Labor $4,923,582 $7.877 Property Taxes and Insurance $23,935,631 $38.293 TOTAL FIXED OPERATING COSTS $48,553,541 $77.678 VARIABLE OPERATING COSTS

$/kWh-net Maintenance Material Cost $26,551,568 $0.00606 Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water (/1000 gallons) 0 3,144.24 1.08 $0 $993,106 $0.00023 Chemicals MU & WT Chem. (lbs) 0 18,732 0.17 $0 $946,662 $0.00022 Carbon (Mercury Removal) (lb) 68,511 94 1.05 $71,948 $28,779 $0.00001 COS Catalyst (m3) 327 0.22 2,397.36 $784,204 $156,841 $0.00004 Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 $0.00000 MDEA Solution (gal) 26,146 37 8.70 $227,412 $93,463 $0.00002 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 1.91 131.27 $0 $73,243 $0.00002 Subtotal Chemicals $1,083,564 $1,298,988 $0.00030 Other Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 $0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $0 $0.00000 Waste Disposal Spent Mercury Catalyst (lb.) 0 94 0.42 $0 $11,430 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 563 16.23 $0 $2,669,064 $0.00061 Subtotal-Waste Disposal $0 $2,680,493 $0.00061 By-products & Emissions Sulfur (ton) 0 138 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000 TOTAL VARIABLE OPERATING COSTS $1,083,564 $31,524,155 $0.00720 Fuel (ton) 0 5,519 38.18 $0 $61,541,712 $0.01405 197

Cost and Performance Baseline for Fossil Energy Plants 3.3.8 Case 4 - E-Gas' IGCC Power Plant with CO2 Capture This case is configured to produce electric power with CO2 capture. The plant configuration is the same as Case 3, namely two gasifier trains, two advanced F class turbines, two HRSGs, and one steam turbine. The gross power output from the plant is constrained by the capacity of the two CTs, and since the CO2 capture and compression process increases the auxiliary load on the plant, the net output is significantly reduced relative to Case 3.

The process description for Case 4 is similar to Case 3 with several notable exceptions to accommodate CO2 capture. A BFD and stream tables for Case 4 are shown in Exhibit 3-58 and Exhibit 3-59, respectively. Instead of repeating the entire process description, only differences from Case 3 are reported here.

Coal Preparation and Feed Systems No differences from Case 3.

Gasification The gasification process is the same as Case 3 with the exception that total coal feed to the two gasifiers is 5,271 tonnes/day (5,811 TPD) (stream 8) and the ASU provides 4,234 tonnes/day (4,668 TPD) of 95 mol% oxygen to the gasifier and Claus plant (streams 5 and 3).

Raw Gas Cooling/Particulate Removal Raw gas cooling and particulate removal are the same as Case 3 with the exception that approximately 418,710 kg/hr (923,082 lb/hr) of saturated steam at 13.8 MPa (2,000 psia) is generated in the SGC.

Syngas Scrubber/Sour Water Stripper No differences from Case 3.

Sour Gas Shift (SGS)

The SGS process was described in Section 3.1.3. In Case 4 steam (stream 11) is added to the syngas exiting the scrubber to adjust the H2O:CO molar ratio to approximately 2.25:1 prior to the first WGS reactor. The hot syngas exiting the first stage of SGS is used to preheat a portion of the water used to humidify the clean syngas leaving the AGR. The final stage of SGS brings the overall conversion of the CO to CO2 to 98.5 percent. The syngas exiting the final stage of SGS still contains 1.2 vol% CH4, which is subsequently oxidized to CO2 in the CT and results in a carbon capture of 90.4 percent. The warm syngas exiting the second stage of the SGS at 204°C (400°F) (stream 12) is cooled to 201°C (393°F) by preheating the syngas entering the first SGS reactor. The SGS catalyst also serves to hydrolyze COS thus eliminating the need for a separate COS hydrolysis reactor. The syngas is further dehydrated and cooled to 35°C (95°F) in syngas coolers prior to the mercury removal beds.

Mercury Removal and Acid Gas Removal Mercury removal is the same as in Case 3.

198

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-58 Case 4 Block Flow Diagram, E-Gas' IGCC with CO2 Capture 199

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-59 Case 4 Stream Table, E-Gas' IGCC with CO2 Capture 1 2 3 4 5 6 7 8 9 10 11 12 13 V-L Mole Fraction Ar 0.0092 0.0209 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0054 0.0071 CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0125 0.0164 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0028 0.0037 CO2 0.0003 0.0071 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3103 0.4090 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.4128 0.5441 H2O 0.0099 0.1780 0.0000 0.0003 0.0000 1.0000 1.0000 0.0000 0.9963 0.0000 1.0000 0.2376 0.0015 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0048 0.0063 N2 0.7732 0.6187 0.0178 0.9919 0.0178 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0090 0.0119 NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0037 0.0000 0.0000 0.0046 0.0000 O2 0.2074 0.1754 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 V-L Flowrate (kgmol/hr) 26,685 1,231 145 19,704 5,338 1,287 4,969 0 5,009 0 9,357 37,866 26,948 V-L Flowrate (kg/hr) 770,042 33,603 4,654 552,893 171,782 23,193 89,523 0 90,226 0 168,566 748,369 547,649 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 219,635 0 22,418 0 0 0 Temperature (°C) 15 19 32 93 32 154 343 15 171 1,038 288 204 35 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 5.79 5.10 0.10 5.79 4.24 5.52 4.07 3.79 Enthalpy (kJ/kg)A 30.23 36.49 26.67 92.50 26.67 599.34 3,063.97 --- 673.50 --- 2,918.18 873.73 40.91 Density (kg/m3) 1.2 1.5 11.0 24.4 11.0 857.7 20.1 --- 836.0 --- 25.6 20.6 30.9 V-L Molecular Weight 28.857 27.295 32.181 28.060 32.181 18.015 18.015 --- 18.012 --- 18.015 19.764 20.322 V-L Flowrate (lbmol/hr) 58,830 2,714 319 43,440 11,768 2,838 10,955 0 11,044 0 20,628 83,479 59,411 V-L Flowrate (lb/hr) 1,697,652 74,082 10,260 1,218,920 378,715 51,133 197,365 0 198,914 0 371,625 1,649,872 1,207,359 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 484,212 0 49,422 0 0 0 Temperature (°F) 59 67 90 199 90 310 650 59 340 1,900 550 400 95 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 840.0 740.0 14.7 840.0 615.0 800.0 590.0 550.0 Enthalpy (Btu/lb)A 13.0 15.7 11.5 39.8 11.5 257.7 1,317.3 --- 289.6 --- 1,254.6 375.6 17.6 Density (lb/ft 3) 0.076 0.095 0.687 1.521 0.687 53.543 1.257 --- 52.192 --- 1.597 1.285 1.928 A - Reference conditions are 32.02 F & 0.089 PSIA 200

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-59 Case 4 Stream Table, E-Gas' IGCC with CO2 Capture (Continued) 14 15 16 17 18 19 20 21 22 23 24 25 V-L Mole Fraction Ar 0.0071 0.0119 0.0114 0.0114 0.0002 0.0011 0.0000 0.0068 0.0092 0.0090 0.0090 0.0000 CH4 0.0159 0.0262 0.0251 0.0251 0.0008 0.0045 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.0038 0.0063 0.0060 0.0060 0.0001 0.0007 0.0000 0.0076 0.0000 0.0000 0.0000 0.0000 CO2 0.4172 0.0352 0.0338 0.0338 0.9945 0.7021 0.0000 0.6907 0.0003 0.0082 0.0082 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2 0.5341 0.8964 0.8588 0.8588 0.0044 0.0591 0.0000 0.2007 0.0000 0.0000 0.0000 0.0000 H2O 0.0015 0.0001 0.0421 0.0421 0.0000 0.0162 0.0000 0.0017 0.0099 0.1246 0.1246 1.0000 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2S 0.0062 0.0000 0.0000 0.0000 0.0000 0.2153 0.0000 0.0026 0.0000 0.0000 0.0000 0.0000 N2 0.0142 0.0239 0.0229 0.0229 0.0001 0.0010 0.0000 0.0901 0.7732 0.7529 0.7529 0.0000 NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1052 0.1052 0.0000 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 V-L Flowrate (kgmol/hr) 27,761 16,435 17,155 17,155 10,499 800 0 812 110,253 139,694 139,694 34,515 V-L Flowrate (kg/hr) 575,208 83,813 96,780 96,780 459,855 31,069 0 27,560 3,181,557 3,831,230 3,831,230 621,792 Solids Flowrate (kg/hr) 0 0 0 0 0 0 5,494 0 0 0 0 0 Temperature (°C) 34 34 108 193 51 48 176 38 15 562 132 534 Pressure (MPa, abs) 3.8 3.757 3.206 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512 Enthalpy (kJ/kg)A 39.0 196.106 903.063 1,360.503 -162.349 62.132 --- 1.774 30.227 839.766 348.188 3,432.696 Density (kg/m3) 31.3 7.4 5.6 4.6 641.8 2.4 5,283.7 83.6 1.2 0.4 0.9 36.7 V-L Molecular Weight 21 5.100 5.642 5.642 43.800 38.814 --- 33.925 28.857 27.426 27.426 18.015 V-L Flowrate (lbmol/hr) 61,202 36,233 37,820 37,820 23,146 1,765 0 1,791 243,066 307,972 307,972 76,092 V-L Flowrate (lb/hr) 1,268,117 184,776 213,363 213,363 1,013,807 68,496 0 60,759 7,014,133 8,446,417 8,446,417 1,370,817 Solids Flowrate (lb/hr) 0 0 0 0 0 0 12,112 0 0 0 0 0 Temperature (°F) 94 94 227 380 124 119 349 100 59 1,044 270 994 Pressure (psia) 545.0 545.0 465.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7 Enthalpy (Btu/lb)A 16.8 84.3 388.2 584.9 -69.8 26.7 --- 0.8 13.0 361.0 149.7 1,475.8 Density (lb/ft 3) 2 0.461 0.352 0.285 40.067 0.149 329.851 5.220 0.076 0.026 0.053 2.293 201

Cost and Performance Baseline for Fossil Energy Plants The AGR process in Case 4 is a two stage Selexol process where H2S is removed in the first stage and CO2 in the second stage of absorption as previously described in Section 3.1.5. The process results in three product streams, the clean syngas, a CO2-rich stream, and an acid gas feed to the Claus plant. The acid gas (stream 19) contains 21.5 percent H2S and 70 percent CO2 with the balance primarily H2. The CO2-rich stream is discussed further in the CO2 compression section.

CO2 Compression and Dehydration CO2 from the AGR process is flashed at three pressure levels to separate CO2 and decrease H2 losses to the CO2 product pipeline. The HP CO2 stream is flashed at 2.0 MPa (289.7 psia),

compressed, and recycled back to the CO2 absorber. The MP CO2 stream is flashed at 1.0 MPa (149.7 psia). The LP CO2 stream is flashed at 0.1 MPa (16.7 psia), compressed to 1.0 MPa (149.5 psia), and combined with the MP CO2 stream. The combined stream is compressed from 1.0 MPa (149.5 psia) to a SC condition at 15.3 MPa (2215 psia) using a multiple-stage, intercooled compressor. During compression, the CO2 stream is dehydrated to a dewpoint of

-40ºC (-40°F) with triethylene glycol. The raw CO2 stream from the Selexol process contains over 99 percent CO2. The CO2 (stream 18) is transported to the plant fence line and is sequestration ready. CO2 TS&M costs were estimated using the methodology described in Section 2.7.

Claus Unit The Claus plant is the same as Case 3 with the following exceptions:

5,494 kg/hr (12,112 lb/hr) of sulfur (stream 20) are produced

The waste heat boiler generates 12,679 kg/hr (27,953 lb/hr) of 3.0 MPa (430 psia) steam, which provides all of the Claus plant process needs and provides some additional steam to the medium pressure steam header.

Power Block Clean syngas from the AGR plant is partially humidified to 4 percent because the nitrogen available from the ASU is insufficient to provide adequate dilution. The moisturized syngas is reheated (stream 17) to 193°C (380°F) using HP BFW, diluted with nitrogen (stream 4), and then enters the CT burner. There is no integration between the CT and the ASU in this case. The exhaust gas (stream 23) exits the CT at 562°C (1044°F) and enters the HRSG where additional heat is recovered. The FG exits the HRSG at 132°C (270°F) (stream 24) and is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced commercially available steam turbine using a 12.4 MPa/534°C/534°C (1800 psig/994°F/994°F) steam cycle.

Air Separation Unit (ASU)

The elevated pressure ASU is the same as in other cases and produces 4,234 tonnes/day (4,668 TPD) of 95 mol% oxygen and 14,230 tonnes/day (15,686 TPD) of nitrogen. There is no integration between the ASU and the CT.

3.3.9 Case 4 Performance Results The Case 4 modeling assumptions were presented previously in Section 3.3.3.

202

Cost and Performance Baseline for Fossil Energy Plants The plant produces a net output of 514 MWe at a net plant efficiency of 31.0 percent (HHV basis). Overall performance for the entire plant is summarized in Exhibit 3-60, which includes auxiliary power requirements. The ASU accounts for nearly 58 percent of the auxiliary load between the main air compressor, the nitrogen compressor, the oxygen compressor, and ASU auxiliaries. The two-stage Selexol process and CO2 compression account for an additional 27 percent of the auxiliary power load. The BFW pumps and cooling water system (CWPs and cooling tower fan) comprise nearly 6 percent of the load, leaving 9 percent of the auxiliary load for all other systems.

203

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-60 Case 4 Plant Performance Summary POWER

SUMMARY

(Gross Power at Generator Terminals, kWe)

Gas Turbine Power 464,000 Sweet Gas Expander Power 0 Steam Turbine Power 239,700 TOTAL POWER, kWe 703,700 AUXILIARY LOAD

SUMMARY

, kWe Coal Handling 470 Coal Milling 2,260 Sour Water Recycle Slurry Pump 200 Slag Handling 1,160 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 65,670 Oxygen Compressor 9,010 Nitrogen Compressors 35,340 CO2 Compressor 31,380 Boiler Feedwater Pumps 4,160 Condensate Pump 310 Syngas Recycle Compressor 520 Circulating Water Pump 4,670 Ground Water Pumps 520 Cooling Tower Fans 2,410 Scrubber Pumps 400 Acid Gas Removal 19,900 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 250 Claus Plant TG Recycle Compressor 3,700 Miscellaneous Balance of Plant2 3,000 Transformer Losses 2,660 TOTAL AUXILIARIES, kWe 190,090 NET POWER, kWe 513,610 Net Plant Efficiency, % (HHV) 31.0 Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,604 (10,998)

CONDENSER COOLING DUTY 106 kJ/hr (106 Btu/hr) 1,403 (1,330)

CONSUMABLES As-Received Coal Feed, kg/hr (lb/hr) 219,635 (484,212)

Thermal Input1, kWt 1,655,503 Raw Water Withdrawal, m3/min (gpm) 21.6 (5,717)

Raw Water Consumption, m3/min (gpm) 17.5 (4,631) 1 - HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 2 - Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads 204

Cost and Performance Baseline for Fossil Energy Plants Environmental Performance The environmental targets for emissions of Hg, NOx, SO2, CO2, and PM were presented in Section 2.4. A summary of the plant air emissions for Case 4 is presented in Exhibit 3-61.

Exhibit 3-61 Case 4 Air Emissions Tonne/year kg/GJ kg/MWh (tons/year)

(lb/106 Btu) (lb/MWh) 80% CF SO2 0.001 (0.002) 39 (43) 0.008 (.02)

NOx 0.021 (0.049) 885 (976) 0.180 (.396)

Particulates 0.003 (0.0071) 127 (141) 0.026 (.057) 2.46E-7 Hg 0.010 (0.011) 2.08E-6 (4.59E-6)

(5.71E-7)

CO2 8.5 (19.7) 354,267 (390,512) 72 (158)

CO21 98 (217) 1 CO2 emissions based on net power instead of gross power The low level of SO2 emissions is achieved by capture of the sulfur in the gas by the two-stage Selexol AGR process. The CO2 capture target results in the sulfur compounds being removed to a greater extent than required in the environmental targets of Section 2.4. The clean syngas exiting the AGR process has a sulfur concentration of approximately 5 ppmv. This results in a concentration in the FG of less than 1 ppmv. The H2S-rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species to H2S, and then recycled back to the Selexol, thereby eliminating the need for a tail gas treatment unit.

NOx emissions are limited by the use of humidification and nitrogen dilution to 15 ppmvd (NO2

@ 15 percent O2). Ammonia in the syngas is removed with process condensate prior to the low-temperature AGR process and ultimately destroyed in the Claus plant burner. This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only.

Ninety five percent of mercury is captured from the syngas by an activated carbon bed.

Ninety five percent of the CO2 from the syngas is captured in the AGR system and compressed for sequestration. The overall carbon removal is 90.4 percent.

The carbon balance for the plant is shown in Exhibit 3-62. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected in the carbon balance below since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag, CO2 in the stack gas, ASU vent gas and the captured CO2 product. The carbon capture efficiency is defined as the amount of carbon in the 205

Cost and Performance Baseline for Fossil Energy Plants CO2 product stream relative to the amount of carbon in the coal less carbon contained in the slag, represented by the following fraction:

(Carbon in Product for Sequestration)/[(Carbon in the Coal)-(Carbon in Slag)] or 276,728/(308,659-2,469) *100 or 90.4 percent In revision 1 of this report, the reported CO2 capture efficiency was 88.4 percent. The high methane content of the syngas, relative to the GEE and Shell cases, prevented reaching the nominal 90 percent CO2 capture. In order to achieve 90 percent capture, the two-stage Selexol CO2 removal efficiency was increased from 92 to 95 percent.

Exhibit 3-62 Case 4 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 140,006 (308,659) Slag 1,120 (2,469)

Air (CO2) 537 (1,185) Stack Gas 13,796 (30,416)

ASU Vent 105 (231)

CO2 Product 125,522 (276,728)

Total 140,543 (309,844) Total 140,543 (309,844)

Exhibit 3-63 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur emitted in the stack gas, and sulfur in the CO2 product. Sulfur in the slag is considered to be negligible.

Exhibit 3-63 Case 4 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 5,505 (12,136) Elemental Sulfur 5,494 (12,112)

Stack Gas 3 (6)

CO2 Product 8 (18)

Total 5,505 (12,136) Total 5,505 (12,136)

Exhibit 3-64 shows the overall water balance for the plant. The exhibit is presented in an identical manner for Cases 1 through 3.

206

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-64 Case 4 Water Balance Process Water Internal Raw Water Water Raw Water Demand, Recycle, Water Use Withdrawal, Discharge, Consumption, m3/min m3/min m3/min (gpm) m3/min m3/min (gpm)

(gpm) (gpm)

(gpm)

Slag Handling 0.49 (128) 0.49 (128) 0.0 (0) 0.0 (0) 0.0 (0)

Slurry Water 1.51 (398) 1.51 (398) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

Humidifier 0.2 (61) 0.2 (61) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7) -0.03 (-7)

Condenser Makeup 4.5 (1,193) 0.0 (0) 4.5 (1,193) 0.0 (0) 4.5 (1,193)

Gasifier Steam 1.5 (395) 1.5 (395)

Shift Steam 2.8 (743) 2.8 (743)

GT Steam Dilution 0.21 (55) 0.21 (55)

BFW Makeup Cooling Tower 18.2 (4,798) 1.0 (274) 17.1 (4,524) 4.1 (1,079) 13.0 (3,445)

BFW Blowdown 0.21 (55) -0.21 (-55)

SWS Blowdown 0.26 (68) -0.26 (-68)

SWS Excess 0.6 (152) -0.6 (-152)

Water Humidifier Tower Blowdown Total 24.9 (6,578) 3.3 (861) 21.6 (5,717) 4.1 (1,086) 17.5 (4,631)

Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-65 through Exhibit 3-67:

Coal gasification and ASU

Syngas cleanup including sulfur recovery and tail gas recycle

Combined cycle power generation, steam, and FW An overall plant energy balance is provided in tabular form in Exhibit 3-68. The power out is the combined CT and steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 3-60) is calculated by multiplying the power out by a combined generator efficiency of 98.4 percent.

207

Cost and Performance Baseline for Fossil Energy Plants This page intentionally left blank 208

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-65 Case 4 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic LEGEND N2 to GT Combustor 4

Ambient Air Air 1 761,167 W 1,697,652 W 385.0 T 100.0 T Coal/Char/

59.0 T 384.0 P 189.5 P 87.2 H Slurry/Slag 14.7 P 18.0 H 13.0 H Four Stage Air ASU Compressor Vent Nitrogen 74,082 W N2 to GT Combustor 2 66.9 T Oxygen 16.4 P 15.7 H Four Stage N2 457,753 W Compressor 385.0 T Steam Boost Compressor 469.0 P Elevated 87.0 H Synthesis Gas 1,080,178 W 5 Pressure 90.0 T 152,901 W ASU 378,715 W 56.4 P 50.0 T 14.2 H Water 90.0 T 182.0 P 79,928 W 79,928 W 125.0 P 2.9 H 160.9 T 105.0 T 11.5 H Fuel Gas 800.0 P 585.0 P 42.6 H Syngas Recycle 21.6 H Compressor 3 To Claus Plant Four Stage O2 P ABSOLUTE PRESSURE, PSIA Compressor 10,260 W Saturated Steam to HRSG F TEMPERATURE, °F 90.0 T W FLOWRATE, LBM/HR 125.0 P Steam 1,355,003 W H ENTHALPY, BTU/LBM 11.5 H Drum BFW from HRSG 1,801.8 T MWE POWER, MEGAWATTS ELECTRICAL 615.0 P Sour Water 1,029.4 H Blowdown to Flash Tank 51,133 W NOTES:

Raw Syngas 310.0 T to Scrubber Steam 840.0 P 257.7 H

1. ENTHALPY REFERENCE POINT IS NATURAL STATE Milled Coal 6 Fire AT 32 °F AND 0.08865 PSIA 197,365 W Syngas Recycle Tube 1,355,003 W 484,212 W 378,715 W 650.0 T Boiler 223.0 T 7 450.0 T 59.0 T 740.0 P 600.0 P 14.7 P 740.0 P 1,316.8 H 8 37.5 H 422.6 H N2 Diluent Preheater 9

198,914 W 340.0 T 1,355,003 W PLANT PERFORMANCE

SUMMARY

840.0 P 600.0 T 289.6 H Slurry Mix 605.0 P Tank 485.6 H Gross Plant Power: 704 MWe Water Auxiliary Load: 190 MWe Net Plant Power: 514 MWe 683,126 W Net Plant Efficiency, HHV: 31.0%

178.6 T 1,355,003 W Net Plant Heat Rate: 10,998 BTU/KWe 840.0 P 600.0 T E-Gas TM 3,040.6 H 605.0 P Gasifier 485.6 H Cyclones Candle Filter DOE/NETL DUAL TRAIN IGCC PLANT CASE 4 10 HEAT AND MATERIAL FLOW DIAGRAM Slag 49,422 W BITUMINOUS BASELINE STUDY CASE 4 COP GASIFIER ASU AND GASIFICATION DWG. NO. PAGES BB-HMB-CS-4-PG-1 1 OF 3 209

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-66 Case 4 Syngas Cleanup Heat and Mass Balance Schematic LEGEND Air Fuel Gas Fuel Gas to GT Humidification Humidification 16 17 Coal/Char/

213,363 W Syngas 213,363 W Slurry/Slag 227.0 T Preheater 380.0 T High Low 465.0 P 460.0 P Temperature Temperature Nitrogen 184,776 W 388.2 H 584.9 H Shift #1 Shift #2 93.8 T 15 545.0 P Oxygen 84.3 H Claus Plant 1,649,872 W Sour Gas 698.4 T 400.0 T Catalytic 398.4 T 590.0 P 590.0 P Reactor 590.0 P Beds 532.7 H 397.7 H 546.0 H Sour Water Shift Steam 11 Furnace 1,649,872 W Tail Steam 371,625 W 400.0 T Clean Gas Gas 550.0 T 12 590.0 P 800.0 P 375.6 H 19 Synthesis Gas 1,254.1 H Acid Gas 1,268,117 W Water 362.9 T 68,496 W 93.8 T 590.0 P 119.0 T 545.0 P 72,809 W 340.0 H 102,292 W 16.8 H 23.7 P 10,260 W 20 CO2 392.6 T 26.7 H 280.0 T 450.0 T 585.0 P 14 17.3 P 124.5 P 372.4 H 312.6 H Tailgas 91.9 H Mercury Two-Stage P ABSOLUTE PRESSURE, PSIA Syngas Recycle Claus Oxygen Sulfur Removal F TEMPERATURE, °F Selexol Preheater 12,112 W CO2 W FLOWRATE, LBM/HR 1,547,580 W Hydrogenation 1,207,359 W H ENTHALPY, BTU/LBM 392.6 T And Tail Gas Syngas 94.6 T MWE POWER, MEGAWATTS ELECTRICAL 585.0 P 13 1,014,845 W Cooling 1,278,247 W Coolers 550.0 P 372.4 H 60.0 T 352.9 T 17.6 H 3 From NOTES:

595.0 P 135.0 P ASU Knock 60,759 W 343.8 H 10,260 W Out 100.0 T 21 90.0 T Drum CO2 Product 1. ENTHALPY REFERENCE POINT IS NATURAL STATE 799.5 P Multistage 125.0 P Syngas AT 32 °F AND 0.08865 PSIA 0.8 H Intercooled CO2 11.5 H 1,013,807 W Scrubber 123.7 T Compressor 2,214.7 P 18 Condensate Raw Syngas to Deaerator Interstage Knockout Sour PLANT PERFORMANCE

SUMMARY

Drum Condensate Gross Plant Power: 704 MWe 6,165 W Auxiliary Load: 190 MWe 1,355,003 W 195.4 T Net Plant Power: 514 MWe 450.0 T 65.0 P Net Plant Efficiency, HHV: 31.0%

600.0 P 206.5 H Net Plant Heat Rate: 10,998 BTU/KWe 422.6 H Sour Stripper Tail Gas Compressor DOE/NETL Makeup Water 65,864 W 120.0 T 10.6 P DUAL TRAIN IGCC PLANT 106.8 H CASE 4 Knock Out HEAT AND MATERIAL FLOW DIAGRAM 12,050 W 111.6 T BITUMINOUS BASELINE STUDY 10.6 P 37.1 H CASE 4 COP GASIFIER GAS CLEANUP SYSTEM To Water Treatment DWG. NO. PAGES BB-HMB-CS-4-PG-2 2 OF 3 210

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-67 Case 4 Combined Cycle Power Generation Heat and Mass Balance Schematic LEGEND Air HP BFW to Syngas Cooler Coal/Char/

HP Saturated Steam to HRSG Superheater Slurry/Slag Nitrogen 8,446,417 W 270.0 T Oxygen 15.2 P 149.7 H Sour Gas 23 HRSG 24 Stack 8,446,417 W LP Flash Tops Sour Water 1,043.7 T 15.2 P 9,744 W MP Flash Bottoms Steam Nitrogen Diluent 361.0 H 298.0 T From Gasifier 65.0 P Island Preheating 1,218,920 W 1,179.0 H Synthesis Gas 25 2,068,816 W 235.0 T Deaerator 1,370,817 W 105.0 P Water 993.7 T 203.7 H 1,814.7 P 1,398,140 W 1,475.8 H 278.8 T Flue Gas Fuel Gas 2,250.7 P LP BFW 17 252.3 H 213,363 W Blowdown 380.0 T 27,273 W Flash 460.0 P LP Pump P ABSOLUTE PRESSURE, PSIA Gasifier and WGS 585.0 T To Claus 584.9 H Steam 2,000.7 P F TEMPERATURE, °F To WWT 593.3 H HP Pump W FLOWRATE, LBM/HR IP BFW H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL IP Pump NOTES:

1,460,271 W Compressor Expander 464.8 T 65.0 P 1. ENTHALPY REFERENCE POINT IS NATURAL STATE 1,264.6 H AT 32 °F AND 0.08865 PSIA Generator HP IP LP Turbine Turbine Steam Turbine Advanced F-Class Turbine Gas Turbine LP Generator Process Header Intake Ip Extraction Steam PLANT PERFORMANCE

SUMMARY

To 250 PSIA Header 25,041 W 9,762 W Gross Plant Power: 704 MWe 798 W 9,026 W 1,337 W 851.8 T 614.7 T Auxiliary Load: 190 MWe 993.7 T 660.4 T 504.8 T 280.0 P 65.0 P Net Plant Power: 514 MWe 1,814.7 P 501.4 P 65.0 P 1,448.7 H 1,338.6 H Ambient Air Net Plant Efficiency, HHV: 31.0%

22 1,475.8 H 1,334.5 H 1,284.4 H Net Plant Heat Rate: 10,998 BTU/KWe 7,014,133 W Steam Seal CONDENSER Make-up Regulator 596,383 W 59.0 T 1,400 W 14.7 P 59.0 T 212.0 T 1,400 W HOT WELL 14.7 P 13.0 H 14.7 P DOE/NETL 614.7 T 27.1 H 179.9 H 65.0 P 2,068,816 W 1,338.6 H 101.1 T DUAL TRAIN IGCC PLANT 1.0 P CASE 4 69.1 H Condensate HEAT AND MATERIAL FLOW DIAGRAM Pump BITUMINOUS BASELINE STUDY Gland CASE 4 2,068,816 W 102.7 T Steam COP GASIFIER 120.0 P Condenser POWER BLOCK SYSTEM Condensate to Gasification Island 70.9 H DWG. NO. PAGES BB-HMB-CS-4-PG-3 3 OF 3 211

Cost and Performance Baseline for Fossil Energy Plants This page intentionally left blank 212

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-68 Case 4 Overall Energy Balance (0°C [32°F] Reference)

Sensible +

HHV Power Total Latent Heat In GJ/hr (MMBtu/hr)

Coal 5,960 (5,649) 5.0 (4.7) 5,965 (5,654)

ASU Air 23.3 (22.1) 23 (22)

GT Air 96.2 (91.2) 96 (91)

Water 81.4 (77.1) 81 (77)

Auxiliary Power 684 (649) 684 (649)

TOTAL 5,960 (5,649) 205.8 (195.1) 684 (649) 6,850 (6,492)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 1.2 (1.2) 1 (1)

Slag 37 (35) 25.2 (23.9) 62 (59)

Sulfur 51 (48) 0.6 (0.6) 52 (49)

CO2 -74.7 (-70.8) -75 (-71)

Cooling Tower Blowdown 30.3 (28.8) 30 (29)

HRSG Flue Gas 1,334 (1,264) 1,334 (1,264)

Condenser 1,408 (1,334) 1,408 (1,334)

Non-Condenser Cooling 755 (716) 755 (716)

Tower Loads*

Process Losses** 749 (710) 749 (710)

Power 2,533 (2,401) 2,533 (2,401)

TOTAL 88 (83) 4,229 (4,008) 2,533 (2,401) 6,850 (6,492)

Includes ASU compressor intercoolers, CO2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection) and extraction air cooler.

- Calculated by difference to close the energy balance 213

Cost and Performance Baseline for Fossil Energy Plants 3.3.10 Case 4 - Major Equipment List Major equipment items for the CoP gasifier with CO2 capture are shown in the following tables.

The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section 3.3.11. In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 COAL HANDLING Equipment Operating Description Type Design Condition Spares No. Qty.

Bottom Trestle Dumper and 1 N/A 181 tonne (200 ton) 2 0 Receiving Hoppers 2 Feeder Belt 572 tonne/hr (630 tph) 2 0 3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0 4 Transfer Tower No. 1 Enclosed N/A 1 0 5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0 As-Received Coal Sampling 6 Two-stage N/A 1 0 System 7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0 8 Reclaim Hopper N/A 45 tonne (50 ton) 2 1 9 Feeder Vibratory 181 tonne/hr (200 tph) 2 1 10 Conveyor No. 3 Belt w/ tripper 363 tonne/hr (400 tph) 1 0 11 Crusher Tower N/A N/A 1 0 12 Coal Surge Bin w/ Vent Filter Dual outlet 181 tonne (200 ton) 2 0 Impactor 8 cm x 0 - 3 cm x 0 13 Crusher 2 0 reduction (3" x 0 1/4" x 0)

As-Fired Coal Sampling 14 Swing hammer N/A 1 1 System 15 Conveyor No. 4 Belt w/tripper 363 tonne/hr (400 tph) 1 0 16 Transfer Tower No. 2 Enclosed N/A 1 0 17 Conveyor No. 5 Belt w/ tripper 363 tonne/hr (400 tph) 1 0 Coal Silo w/ Vent Filter and 18 Field erected 363 tonne (400 ton) 6 0 Slide Gates 214

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 2 COAL PREPARATION AND FEED Equipment Operating Description Type Design Condition Spares No. Qty.

1 Feeder Vibratory 82 tonne/h (90 tph) 3 0 2 Conveyor No. 6 Belt w/tripper 245 tonne/h (270 tph) 1 0 3 Rod Mill Feed Hopper Dual Outlet 481 tonne (530 ton) 1 0 4 Weigh Feeder Belt 118 tonne/h (130 tph) 2 0 5 Rod Mill Rotary 118 tonne/h (130 tph) 2 0 Slurry Water Storage Tank 6 Field erected 298,179 liters (78,770 gal) 2 0 with Agitator 7 Slurry Water Pumps Centrifugal 833 lpm (220 gpm) 2 1 8 Trommel Screen Coarse 172 tonne/h (190 tph) 2 0 Rod Mill Discharge Tank with 9 Field erected 390,052 liters (103,040 gal) 2 0 Agitator 10 Rod Mill Product Pumps Centrifugal 3,407 lpm (900 gpm) 2 2 Slurry Storage Tank with 11 Field erected 1,170,080 liters (309,100 gal) 2 0 Agitator 12 Slurry Recycle Pumps Centrifugal 6,435 lpm (1,700 gpm) 2 2 Positive 13 Slurry Product Pumps 3,407 lpm (900 gpm) 2 2 displacement 215

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment Operating Description Type Design Condition Spares No. Qty.

Demineralized Water Vertical, cylindrical, 1 1,101,555 liters (291,000 gal) 2 0 Storage Tank outdoor 8,669 lpm @ 91 m H2O 2 Condensate Pumps Vertical canned 2 1 (2,290 gpm @ 300 ft H2O)

Deaerator (integral w/

3 Horizontal spray type 606,907 kg/hr (1,338,000 lb/hr) 2 0 HRSG)

Intermediate Pressure Horizontal centrifugal, 8,555 lpm @ 27 m H2O 4 2 1 Feedwater Pump single stage (2,260 gpm @ 90 ft H2O)

HP water: 6,057 lpm @ 1,859 m High Pressure Barrel type, multi-stage, 5 H2O (1,600 gpm @ 6,100 ft 2 1 Feedwater Pump No. 1 centrifugal H2O)

High Pressure Barrel type, multi-stage, IP water: 1,287 lpm @ 223 m 6 2 1 Feedwater Pump No. 2 centrifugal H2O (340 gpm @ 730 ft H2O)

Shop fabricated, water 18,144 kg/hr, 2.8 MPa, 343°C 7 Auxiliary Boiler 1 0 tube (40,000 lb/hr, 400 psig, 650°F)

Service Air 28 m3/min @ 0.7 MPa 8 Flooded Screw 2 1 Compressors (1,000 scfm @ 100 psig) 9 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1 Closed Cylce Cooling 10 Plate and frame 430 GJ/hr (407 MMBtu/hr) each 2 0 Heat Exchangers Closed Cycle Cooling 154,066 lpm @ 21 m H2O 11 Horizontal centrifugal 2 1 Water Pumps (40,700 gpm @ 70 ft H2O)

Engine-Driven Fire Vertical turbine, diesel 3,785 lpm @ 107 m H2O 12 1 1 Pump engine (1,000 gpm @ 350 ft H2O)

Fire Service Booster Two-stage horizontal 2,650 lpm @ 76 m H2O 13 1 1 Pump centrifugal (700 gpm @ 250 ft H2O)

Stainless steel, single 5,602 lpm @ 18 m H2O 14 Raw Water Pumps 2 1 suction (1,480 gpm @ 60 ft H2O)

Stainless steel, single 2,801 lpm @ 268 m H2O 15 Ground Water Pumps 4 1 suction (740 gpm @ 880 ft H2O)

Stainless steel, single 3,066 lpm @ 49 m H2O 16 Filtered Water Pumps 2 1 suction (810 gpm @ 160 ft H2O) 17 Filtered Water Tank Vertical, cylindrical 1,472,525 liter (389,000 gal) 2 0 Makeup Water Anion, cation, and 18 1,855 lpm (490 gpm) 2 0 Demineralizer mixed bed Liquid Waste Treatment 19 10 years, 24-hour storm 1 0 System 216

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY AND FUEL GAS SATURATION Equipment Operating Description Type Design Condition Spares No. Qty.

Pressurized two-stage, 2,903 tonne/day, 4.2 MPa 1 Gasifier slurry-feed entrained 2 0 (3,200 tpd, 614.96 psia) bed 2 Synthesis Gas Cooler Fire-tube boiler 337,926 kg/hr (745,000 lb/hr) 2 0 337,926 kg/hr (745,000 lb/hr) 3 Synthesis Gas Cyclone High efficiency 2 0 Design efficiency 90%

Pressurized filter with 4 Candle Filter metallic filters 2 0 pulse-jet cleaning Syngas Scrubber 5 Including Sour Water Vertical upflow 337,926 kg/hr (745,000 lb/hr) 2 0 Stripper Shell and tube with 6 Raw Gas Coolers 386,007 kg/hr (851,000 lb/hr) 8 0 condensate drain Raw Gas Knockout Vertical with mist 303,000 kg/hr, 35°C, 3.8 MPa 7 2 0 Drum eliminator (668,000 lb/hr, 95°F, 555 psia)

Saturation Water 8 Shell and tube 36 GJ/hr (34 MMBtu/hr) 2 0 Economizers 53,070 kg/hr, 108°C, 3.8 MPa 9 Fuel Gas Saturator Vertical tray tower 2 0 (117,000 lb/hr, 227°F, 545 psia) 757 lpm @ 12 m H2O 10 Saturator Water Pump Centrifugal 2 2 (200 gpm @ 40 ft H2O) 11 Synthesis Gas Reheater Shell and tube 53,070 kg/hr (117,000 lb/hr) 2 0 Self-supporting, carbon 337,926 kg/hr (745,000 lb/hr) 12 Flare Stack steel, stainless steel top, 2 0 syngas pilot ignition ASU Main Air 5,805 m3/min @ 1.3 MPa 13 Centrifugal, multi-stage 2 0 Compressor (205,000 scfm @ 190 psia) 2,359 tonne/day (2,600 tpd) of 14 Cold Box Vendor design 2 0 95% purity oxygen 1,161 m3/min (41,000 scfm) 15 Oxygen Compressor Centrifugal, multi-stage Suction - 0.9 MPa (130 psia) 2 0 Discharge - 5.1 MPa (740 psia) 3,794 m3/min (134,000 scfm)

Primary Nitrogen 16 Centrifugal, multi-stage Suction - 0.4 MPa (60 psia) 2 0 Compressor Discharge - 2.7 MPa (390 psia) 538 m3/min (19,000 scfm)

Secondary Nitrogen 17 Centrifugal, single-stage Suction - 1.2 MPa (180 psia) 2 0 Compressor Discharge - 2.7 MPa (390 psia) 1,614 m3/min (57,000 scfm)

Gasifier Purge Nitrogen 18 Centrifugal, single-stage Suction - 2.6 MPa (380 psia) 2 0 Boost Compressor Discharge - 3.2 MPa (470 psia) 217

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 5A SOUR GAS SHIFT AND SYNGAS CLEANUP Equipment Operating Description Type Design Condition Spares No. Qty.

301,185 kg/hr (664,000 lb/hr)

Sulfated carbon 1 Mercury Adsorber 35°C (95°F) 2 0 bed 3.8 MPa (550 psia) 2 Sulfur Plant Claus type 145 tonne/day (160 tpd) 1 0 411,408 kg/hr (907,000 lb/hr)

Fixed bed, 3 Water Gas Shift Reactors 204°C (400°F) 4 0 catalytic 4.1 MPa (590 psia)

Exchanger 1: 94 GJ/hr (89 Shift Reactor Heat Recovery MMBtu/hr) 4 Shell and Tube 4 0 Exchangers Exchanger 2: 3 GJ/hr (3 MMBtu/hr) 316,154 kg/hr (697,000 lb/hr)

Two-stage 5 Acid Gas Removal Plant 34°C (94°F) 2 0 Selexol 3.8 MPa (545 psia) 36,328 kg/hr (80,090 lb/hr)

Fixed bed, 6 Hydrogenation Reactor 232°C (450°F) 1 0 catalytic 0.1 MPa (12.3 psia)

Tail Gas Recycle 7 Centrifugal 30,316 kg/hr (66,835 lb/hr) 1 0 Compressor ACCOUNT 5B CO 2 COMPRESSION Equipment Operating Description Type Design Condition Spares No. Qty.

CO2 Integrally geared, 1,141 m3/min @ 15.3 MPa 1 4 0 Compressor multi-stage centrifugal (40,300 scfm @ 2,215 psia)

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES Equipment Operating Description Type Design Condition Spares No. Qty.

1 Gas Turbine Advanced F class 232 MW 2 0 260 MVA @ 0.9 p.f., 24 kV, 2 Gas Turbine Generator TEWAC 2 0 60 Hz, 3-phase 218

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 7 HRSG, DUCTING, AND STACK Equipment Operating Description Type Design Condition Spares No. Qty.

CS plate, type 409SS 76 m (250 ft) high x 1 Stack 1 0 liner 8.5 m (28 ft) diameter Main steam - 341,986 kg/hr, 12.4 Drum, multi-pressure MPa/534°C (753,949 lb/hr, Heat Recovery with economizer 1,800 psig/994°F) 2 2 0 Steam Generator section and integral Reheat steam - 298,222 kg/hr, deaerator 3.1 MPa/534°C (657,466 lb/hr, 452 psig/994°F)

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES Equipment Operating Description Type Design Condition Spares No. Qty.

Commercially 252 MW 1 Steam Turbine available advanced 12.4 MPa/534°C/534°C 1 0 steam turbine (1800 psig/ 994°F/994°F)

Hydrogen cooled, 280 MVA @ 0.9 p.f., 24 2 Steam Turbine Generator 1 0 static excitiation kV, 60 Hz, 3-phase 50% steam flow @ design 3 Steam Bypass One per HRSG 2 0 steam conditions 1,551 GJ/hr (1,470 Single pass, divided MMBtu/hr), Inlet water 4 Surface Condenser waterbox including temperature 16°C (60°F), 1 0 vacuum pumps Water temperature rise 11°C (20°F) 219

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 9 COOLING WATER SYSTEM Equipment Operating Description Type Design Condition Spares No. Qty.

Circulating Water 469,391 lpm @ 30 m 1 Vertical, wet pit 2 1 Pumps (124,000 gpm @ 100 ft) 11°C (51.5°F) wet bulb / 16°C Evaporative, (60°F) CWT / 27°C (80°F) HWT 2 Cooling Tower mechanical draft, multi- 1 0

/ 2606 GJ/hr (2470 MMBtu/hr) cell heat duty ACCOUNT 10 SLAG RECOVERY AND HANDLING Equipment Operating Description Type Design Condition Spares No. Qty.

1 Slag Quench Tank Water bath 234,696 liters (62,000 gal) 2 0 2 Slag Crusher Roll 13 tonne/hr (14 tph) 2 0 3 Slag Depressurizer Proprietary 13 tonne/hr (14 tph) 2 0 4 Slag Receiving Tank Horizontal, weir 140,060 liters (37,000 gal) 2 0 5 Black Water Overflow Tank Shop fabricated 64,352 liters (17,000 gal) 2 6 Slag Conveyor Drag chain 13 tonne/hr (14 tph) 2 0 7 Slag Separation Screen Vibrating 13 tonne/hr (14 tph) 2 0 8 Coarse Slag Conveyor Belt/bucket 13 tonne/hr (14 tph) 2 0 9 Fine Ash Settling Tank Vertical, gravity 200,627 liters (53,000 gal) 2 0 Horizontal 38 lpm @ 14 m H2O 10 Fine Ash Recycle Pumps 2 2 centrifugal (10 gpm @ 46 ft H2O) 11 Grey Water Storage Tank Field erected 64,352 liters (17,000 gal) 2 0 227 lpm @ 433 m H2O 12 Grey Water Pumps Centrifugal 2 2 (60 gpm @ 1,420 ft H2O)

Vertical, field 13 Slag Storage Bin 907 tonne (1,000 tons) 2 0 erected 14 Unloading Equipment Telescoping chute 100 tonne/hr (110 tph) 1 0 220

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 11 ACCESSORY ELECTRIC PLANT Equipment Operating Description Type Design Condition Spares No. Qty.

CTG Step-up 24 kV/345 kV, 260 MVA, 1 Oil-filled 2 0 Transformer 3-ph, 60 Hz STG Step-up 24 kV/345 kV, 280 MVA, 2 Oil-filled 1 0 Transformer 3-ph, 60 Hz High Voltage 345 kV/13.8 kV, 79 MVA, 3 Auxiliary Oil-filled 2 0 3-ph, 60 Hz Transformer Medium Voltage 24 kV/4.16 kV, 51 MVA, 4 Auxiliary Oil-filled 1 1 3-ph, 60 Hz Transformer Low Voltage 4.16 kV/480 V, 8 MVA, 5 Dry ventilated 1 1 Transformer 3-ph, 60 Hz CTG Isolated 6 Phase Bus Duct Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 2 0 and Tap Bus STG Isolated 7 Phase Bus Duct Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0 and Tap Bus Medium Voltage 8 Metal clad 4.16 kV, 3-ph, 60 Hz 1 1 Switchgear Low Voltage 9 Metal enclosed 480 V, 3-ph, 60 Hz 1 1 Switchgear Emergency Diesel Sized for emergency 10 750 kW, 480 V, 3-ph, 60 Hz 1 0 Generator shutdown ACCOUNT 12 INSTRUMENTATION AND CONTROLS Equipment Operating Description Type Design Condition Spares No. Qty.

Monitor/keyboard; DCS - Main Operator printer (laser Operator stations/printers and 1 1 0 Control color); Engineering engineering stations/printers printer (laser B&W)

Microprocessor with 2 DCS - Processor N/A 1 0 redundant input/output DCS - Data 3 Fiber optic Fully redundant, 25% spare 1 0 Highway 221

Cost and Performance Baseline for Fossil Energy Plants 3.3.11 Case 4 - Cost Estimating Results The cost estimating methodology was described previously in Section 2.6. Exhibit 3-69 shows the total plant capital cost summary organized by cost account and Exhibit 3-70 shows a more detailed breakdown of the capital costs as well as TOC, TASC, and breakdown of owners costs.

Exhibit 3-71 shows the initial and annual O&M costs.

The estimated TOC of the CoP gasifier with CO2 capture is $3,466/kW. Process contingency represents 3.5 percent of the TOC and project contingency represents 11.1 percent. The COE, including CO2 TS&M costs of 5.6 mills/kWh, is 110.4 mills/kWh.

222

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-69 Case 4 Total Plant Cost Summary Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study TOTAL PLANT COST

SUMMARY

Case: Case 4 - ConocoPhillips 500MW IGCC w/ CO2 Plant Size: 513.6 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING $14,229 $2,644 $11,035 $0 $0 $27,908 $2,533 $0 $6,088 $36,529 $71 2 COAL & SORBENT PREP & FEED $24,241 $4,431 $14,646 $0 $0 $43,318 $3,889 $0 $9,441 $56,648 $110 3 FEEDWATER & MISC. BOP SYSTEMS $10,074 $7,882 $10,144 $0 $0 $28,101 $2,651 $0 $7,106 $37,858 $74 4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $114,050 $0 $63,266 $0 $0 $177,316 $16,295 $24,521 $33,478 $251,609 $490 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $186,025 $0 w/equip. $0 $0 $186,025 $18,031 $0 $20,406 $224,461 $437 4.4-4.9 Other Gasification Equipment $24,056 $10,168 $14,678 $0 $0 $48,902 $4,688 $0 $11,449 $65,038 $127 SUBTOTAL 4 $324,131 $10,168 $77,944 $0 $0 $412,242 $39,014 $24,521 $65,332 $541,109 $1,054 5A GAS CLEANUP & PIPING $89,500 $3,812 $77,878 $0 $0 $171,190 $16,546 $26,077 $42,894 $256,707 $500 5B CO2 COMPRESSION $18,339 $0 $11,242 $0 $0 $29,581 $2,849 $0 $6,486 $38,916 $76 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,600 $252 6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6 $92,027 $806 $7,475 $0 $0 $100,308 $9,507 $9,861 $12,339 $132,015 $257 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,631 $0 $4,782 $0 $0 $38,414 $3,652 $0 $4,207 $46,272 $90 7.2-7.9 SCR System, Ductwork and Stack $3,377 $2,407 $3,153 $0 $0 $8,938 $829 $0 $1,589 $11,355 $22 SUBTOTAL 7 $37,008 $2,407 $7,935 $0 $0 $47,351 $4,481 $0 $5,796 $57,628 $112 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $26,321 $0 $4,278 $0 $0 $30,600 $2,935 $0 $3,353 $36,888 $72 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $9,952 $903 $6,987 $0 $0 $17,843 $1,623 $0 $3,868 $23,333 $45 SUBTOTAL 8 $36,274 $903 $11,266 $0 $0 $48,442 $4,558 $0 $7,221 $60,222 $117 9 COOLING WATER SYSTEM $10,387 $9,859 $8,527 $0 $0 $28,773 $2,673 $0 $6,406 $37,852 $74 10 ASH/SPENT SORBENT HANDLING SYS $19,651 $1,481 $9,750 $0 $0 $30,882 $2,963 $0 $3,691 $37,536 $73 11 ACCESSORY ELECTRIC PLANT $31,778 $12,519 $24,431 $0 $0 $68,728 $5,909 $0 $14,164 $88,801 $173 12 INSTRUMENTATION & CONTROL $11,157 $2,052 $7,188 $0 $0 $20,397 $1,849 $1,020 $3,877 $27,142 $53 13 IMPROVEMENTS TO SITE $3,416 $2,014 $8,429 $0 $0 $13,859 $1,368 $0 $4,568 $19,796 $39 14 BUILDINGS & STRUCTURES $0 $6,693 $7,589 $0 $0 $14,282 $1,300 $0 $2,555 $18,136 $35 TOTAL COST $722,212 $67,672 $295,478 $0 $0 $1,085,363 $102,090 $61,479 $197,964 $1,446,895 $2,817 223

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-70 Case 4 Total Plant Cost Details Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $3,737 $0 $1,826 $0 $0 $5,563 $498 $0 $1,212 $7,273 $14 1.2 Coal Stackout & Reclaim $4,829 $0 $1,171 $0 $0 $5,999 $526 $0 $1,305 $7,830 $15 1.3 Coal Conveyors & Yd Crush $4,489 $0 $1,158 $0 $0 $5,648 $496 $0 $1,229 $7,372 $14 1.4 Other Coal Handling $1,175 $0 $268 $0 $0 $1,443 $126 $0 $314 $1,883 $4 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,644 $6,612 $0 $0 $9,256 $887 $0 $2,029 $12,172 $24 SUBTOTAL 1. $14,229 $2,644 $11,035 $0 $0 $27,908 $2,533 $0 $6,088 $36,529 $71 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying (incl. w/2.3) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,596 $382 $250 $0 $0 $2,228 $190 $0 $484 $2,902 $6 2.3 Slurry Prep & Feed $21,768 $0 $9,681 $0 $0 $31,449 $2,808 $0 $6,851 $41,108 $80 2.4 Misc.Coal Prep & Feed $877 $639 $1,914 $0 $0 $3,430 $315 $0 $749 $4,495 $9 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,411 $2,800 $0 $0 $6,211 $575 $0 $1,357 $8,143 $16 SUBTOTAL 2. $24,241 $4,431 $14,646 $0 $0 $43,318 $3,889 $0 $9,441 $56,648 $110 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,834 $4,868 $2,570 $0 $0 $10,272 $952 $0 $2,245 $13,468 $26 3.2 Water Makeup & Pretreating $709 $74 $396 $0 $0 $1,179 $112 $0 $387 $1,679 $3 3.3 Other Feedwater Subsystems $1,551 $524 $472 $0 $0 $2,546 $229 $0 $555 $3,330 $6 3.4 Service Water Systems $406 $835 $2,899 $0 $0 $4,140 $404 $0 $1,363 $5,907 $12 3.5 Other Boiler Plant Systems $2,177 $843 $2,090 $0 $0 $5,111 $485 $0 $1,119 $6,714 $13 3.6 FO Supply Sys & Nat Gas $313 $591 $551 $0 $0 $1,456 $140 $0 $319 $1,915 $4 3.7 Waste Treatment Equipment $991 $0 $604 $0 $0 $1,595 $155 $0 $525 $2,276 $4 3.8 Misc. Power Plant Equipment $1,094 $146 $562 $0 $0 $1,802 $174 $0 $593 $2,569 $5 SUBTOTAL 3. $10,074 $7,882 $10,144 $0 $0 $28,101 $2,651 $0 $7,106 $37,858 $74 4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $114,050 $0 $63,266 $0 $0 $177,316 $16,295 $24,521 $33,478 $251,609 $490 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $186,025 $0 w/equip. $0 $0 $186,025 $18,031 $0 $20,406 $224,461 $437 4.4 LT Heat Recovery & FG Saturation $24,056 $0 $9,145 $0 $0 $33,201 $3,240 $0 $7,288 $43,730 $85 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Flare Stack System $0 $1,643 $669 $0 $0 $2,312 $222 $0 $507 $3,041 $6 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $8,525 $4,864 $0 $0 $13,389 $1,226 $0 $3,654 $18,268 $36 SUBTOTAL 4. $324,131 $10,168 $77,944 $0 $0 $412,242 $39,014 $24,521 $65,332 $541,109 $1,054 224

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-70 Case 4 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $70,224 $0 $59,586 $0 $0 $129,810 $12,554 $25,962 $33,665 $201,991 $393 5A.2 Elemental Sulfur Plant $10,291 $2,051 $13,278 $0 $0 $25,620 $2,489 $0 $5,622 $33,730 $66 5A.3 Mercury Removal $1,302 $0 $991 $0 $0 $2,294 $222 $115 $526 $3,156 $6 5A.4 Shift Reactors $7,138 $0 $2,873 $0 $0 $10,011 $960 $0 $2,194 $13,164 $26 5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $545 $306 $172 $0 $0 $1,023 $98 $0 $224 $1,345 $3 5A.7 Fuel Gas Piping $0 $723 $506 $0 $0 $1,229 $114 $0 $269 $1,612 $3 5A.9 HGCU Foundations $0 $732 $472 $0 $0 $1,204 $111 $0 $394 $1,709 $3 SUBTOTAL 5A. $89,500 $3,812 $77,878 $0 $0 $171,190 $16,546 $26,077 $42,894 $256,707 $500 5B CO2 COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $18,339 $0 $11,242 $0 $0 $29,581 $2,849 $0 $6,486 $38,916 $76 SUBTOTAL 5B. $18,339 $0 $11,242 $0 $0 $29,581 $2,849 $0 $6,486 $38,916 $76 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,600 $252 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6. $92,027 $806 $7,475 $0 $0 $100,308 $9,507 $9,861 $12,339 $132,015 $257 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,631 $0 $4,782 $0 $0 $38,414 $3,652 $0 $4,207 $46,272 $90 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,731 $1,235 $0 $0 $2,966 $260 $0 $645 $3,871 $8 7.4 Stack $3,377 $0 $1,269 $0 $0 $4,645 $445 $0 $509 $5,599 $11 7.9 HRSG,Duct & Stack Foundations $0 $677 $650 $0 $0 $1,326 $123 $0 $435 $1,885 $4 SUBTOTAL 7. $37,008 $2,407 $7,935 $0 $0 $47,351 $4,481 $0 $5,796 $57,628 $112 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $26,321 $0 $4,278 $0 $0 $30,600 $2,935 $0 $3,353 $36,888 $72 8.2 Turbine Plant Auxiliaries $182 $0 $417 $0 $0 $599 $59 $0 $66 $724 $1 8.3 Condenser & Auxiliaries $4,762 $0 $1,521 $0 $0 $6,284 $601 $0 $688 $7,573 $15 8.4 Steam Piping $5,008 $0 $3,523 $0 $0 $8,531 $733 $0 $2,316 $11,580 $23 8.9 TG Foundations $0 $903 $1,526 $0 $0 $2,429 $230 $0 $798 $3,457 $7 SUBTOTAL 8. $36,274 $903 $11,266 $0 $0 $48,442 $4,558 $0 $7,221 $60,222 $117 225

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-70 Case 4 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 9 COOLING WATER SYSTEM 9.1 Cooling Towers $7,196 $0 $1,401 $0 $0 $8,597 $819 $0 $1,412 $10,828 $21 9.2 Circulating Water Pumps $1,877 $0 $136 $0 $0 $2,013 $170 $0 $327 $2,510 $5 9.3 Circ.Water System Auxiliaries $157 $0 $22 $0 $0 $179 $17 $0 $29 $226 $0 9.4 Circ.Water Piping $0 $6,545 $1,697 $0 $0 $8,241 $745 $0 $1,797 $10,783 $21 9.5 Make-up Water System $384 $0 $549 $0 $0 $933 $90 $0 $205 $1,227 $2 9.6 Component Cooling Water Sys $773 $924 $657 $0 $0 $2,354 $221 $0 $515 $3,090 $6 9.9 Circ.Water System Foundations $0 $2,391 $4,064 $0 $0 $6,455 $612 $0 $2,120 $9,187 $18 SUBTOTAL 9. $10,387 $9,859 $8,527 $0 $0 $28,773 $2,673 $0 $6,406 $37,852 $74 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $17,164 $0 $8,464 $0 $0 $25,628 $2,462 $0 $2,809 $30,900 $60 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $564 $0 $613 $0 $0 $1,177 $114 $0 $194 $1,485 $3 10.7 Ash Transport & Feed Equipment $756 $0 $182 $0 $0 $938 $88 $0 $154 $1,180 $2 10.8 Misc. Ash Handling Equipment $1,168 $1,431 $427 $0 $0 $3,026 $288 $0 $497 $3,811 $7 10.9 Ash/Spent Sorbent Foundation $0 $50 $63 $0 $0 $112 $11 $0 $37 $160 $0 SUBTOTAL 10. $19,651 $1,481 $9,750 $0 $0 $30,882 $2,963 $0 $3,691 $37,536 $73 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $924 $0 $914 $0 $0 $1,839 $176 $0 $201 $2,216 $4 11.2 Station Service Equipment $4,676 $0 $421 $0 $0 $5,097 $470 $0 $557 $6,124 $12 11.3 Switchgear & Motor Control $8,644 $0 $1,572 $0 $0 $10,216 $948 $0 $1,675 $12,838 $25 11.4 Conduit & Cable Tray $0 $4,015 $13,247 $0 $0 $17,262 $1,670 $0 $4,733 $23,665 $46 11.5 Wire & Cable $0 $7,672 $5,041 $0 $0 $12,713 $924 $0 $3,409 $17,046 $33 11.6 Protective Equipment $0 $680 $2,474 $0 $0 $3,153 $308 $0 $519 $3,980 $8 11.7 Standby Equipment $229 $0 $223 $0 $0 $452 $43 $0 $74 $570 $1 11.8 Main Power Transformers $17,305 $0 $140 $0 $0 $17,445 $1,319 $0 $2,815 $21,579 $42 11.9 Electrical Foundations $0 $152 $398 $0 $0 $550 $53 $0 $181 $784 $2 SUBTOTAL 11. $31,778 $12,519 $24,431 $0 $0 $68,728 $5,909 $0 $14,164 $88,801 $173 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,101 $0 $735 $0 $0 $1,837 $174 $92 $315 $2,418 $5 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $253 $0 $162 $0 $0 $415 $39 $21 $95 $571 $1 12.7 Computer & Accessories $5,875 $0 $188 $0 $0 $6,063 $557 $303 $692 $7,615 $15 12.8 Instrument Wiring & Tubing $0 $2,052 $4,196 $0 $0 $6,248 $530 $312 $1,773 $8,863 $17 12.9 Other I & C Equipment $3,927 $0 $1,907 $0 $0 $5,834 $549 $292 $1,001 $7,676 $15 SUBTOTAL 12. $11,157 $2,052 $7,188 $0 $0 $20,397 $1,849 $1,020 $3,877 $27,142 $53 226

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-70 Case 4 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $107 $2,291 $0 $0 $2,398 $238 $0 $791 $3,427 $7 13.2 Site Improvements $0 $1,906 $2,533 $0 $0 $4,440 $438 $0 $1,463 $6,341 $12 13.3 Site Facilities $3,416 $0 $3,605 $0 $0 $7,021 $692 $0 $2,314 $10,027 $20 SUBTOTAL 13. $3,416 $2,014 $8,429 $0 $0 $13,859 $1,368 $0 $4,568 $19,796 $39 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,246 $3,200 $0 $0 $5,445 $501 $0 $892 $6,838 $13 14.3 Administration Building $0 $870 $631 $0 $0 $1,501 $134 $0 $245 $1,880 $4 14.4 Circulation Water Pumphouse $0 $163 $86 $0 $0 $250 $22 $0 $41 $312 $1 14.5 Water Treatment Buildings $0 $592 $578 $0 $0 $1,171 $106 $0 $191 $1,468 $3 14.6 Machine Shop $0 $445 $305 $0 $0 $750 $67 $0 $122 $939 $2 14.7 Warehouse $0 $719 $464 $0 $0 $1,183 $105 $0 $193 $1,481 $3 14.8 Other Buildings & Structures $0 $431 $335 $0 $0 $766 $68 $0 $167 $1,001 $2 14.9 Waste Treating Building & Str. $0 $963 $1,840 $0 $0 $2,802 $261 $0 $613 $3,676 $7 SUBTOTAL 14. $0 $6,693 $7,589 $0 $0 $14,282 $1,300 $0 $2,555 $18,136 $35 TOTAL COST $722,212 $67,672 $295,478 $0 $0 $1,085,363 $102,090 $61,479 $197,964 $1,446,895 $2,817 Owner's Costs Preproduction Costs 6 Months All Labor $13,491 $26 1 Month Maintenance Materials $2,999 $6 1 Month Non-fuel Consumables $385 $1 1 Month Waste Disposal $295 $1 25% of 1 Months Fuel Cost at 100% CF $1,687 $3 2% of TPC $28,938 $56 Total $47,793 $93 Inventory Capital 60 day supply of fuel and consumables at 100% CF $13,995 $27 0.5% of TPC (spare parts) $7,234 $14 Total $21,230 $41 Initial Cost for Catalyst and Chemicals $7,371 $14 Land $900 $2 Other Owner's Costs $217,034 $423 Financing Costs $39,066 $76 Total Overnight Costs (TOC) $1,780,290 $3,466 TASC Multiplier (IOU, high-risk, 35 year) 1.140 Total As-Spent Cost (TASC) $2,029,531 $3,952 227

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-71 Case 4 Initial and Annual Operating and Maintenance Costs INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 4 - ConocoPhillips 500MW IGCC w/ CO2 Heat Rate-net (Btu/kWh): 10,998 MWe-net: 514 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant Skilled Operator 2.0 2.0 Operator 10.0 10.0 Foreman 1.0 1.0 Lab Tech's, etc. 3.0 3.0 TOTAL-O.J.'s 16.0 16.0 Annual Cost Annual Unit Cost

$ $/kW-net Annual Operating Labor Cost $6,313,507 $12.292 Maintenance Labor Cost $15,271,560 $29.734 Administrative & Support Labor $5,396,267 $10.507 Property Taxes and Insurance $28,937,909 $56.342 TOTAL FIXED OPERATING COSTS $55,919,243 $108.875 VARIABLE OPERATING COSTS

$/kWh-net Maintenance Material Cost $28,787,121 $0.00800 Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water(/1000 gallons) 0 4,116 1.08 $0 $1,300,111 $0.00036 Chemicals MU & WT Chem. (lbs) 0 24,523 0.17 $0 $1,239,310 $0.00034 Carbon (Mercury Removal) (lb) 104,394 143 1.05 $109,631 $43,852 $0.00001 COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000 Water Gas Shift Catalyst (ft3) 6,484 4.44 498.83 $3,234,413 $646,883 $0.00018 Selexol Solution (gal) 300,533 98 13.40 $4,026,613 $384,543 $0.00011 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 2.00 131.27 $0 $76,827 $0.00002 Subtotal Chemicals $7,370,657 $2,391,415 $0.00066 Other Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 $0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $0 $0.00000 Waste Disposal Spent Mercury Catalyst (lb.) 0 143 0.42 $0 $17,416 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 593 16.23 $0 $2,809,802 $0.00078 Subtotal Waste Disposal $0 $2,827,218 $0.00079 By-products & Emissions Sulfur (ton) 0 145 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000 TOTAL VARIABLE OPERATING COSTS $7,370,657 $35,305,866 $0.00981 Fuel (ton) 0 5,811 38.18 $0 $64,786,772 $0.01800 228

Cost and Performance Baseline for Fossil Energy Plants 3.4 SHELL GLOBAL SOLUTIONS IGCC CASES This section contains an evaluation of plant designs for Cases 5 and 6, which are based on the Shell gasifier. Cases 5 and 6 are very similar in terms of process, equipment, scope and arrangement, except that Case 6 employs a syngas quench and includes SGS reactors, CO2 absorption/regeneration, and compression/transport systems. There are no provisions for CO2 removal in Case 5.

The balance of this section is organized in an analogous manner to Sections 3.2 and 3.3:

Gasifier Background

Process System Description for Case 5

Key Assumptions for Cases 5 and 6

Sparing Philosophy for Cases 5 and 6

Performance Results for Case 5

Equipment List for Case 5

Cost Estimates For Case 5

Process and System Description, Performance Results, Equipment List, and Cost Estimate for Case 6 3.4.1 Gasifier Background Development and Current Status - Development of the Shell gasification process for partial oxidation of oil and gas began in the early 1950s. More than 75 commercial Shell partial-oxidation plants have been built worldwide to convert a variety of hydrocarbon liquids and gases to carbon monoxide and hydrogen.

Shell Internationale Petroleum Maatschappij B.V. began work on coal gasification in 1972. The coal gasifier is significantly different than the oil and gas gasifiers developed earlier. A pressurized, entrained-flow, slagging coal gasifier was built at Shells Amsterdam laboratories.

This 5 tonnes/day (6 TPD) process development unit has operated for approximately 12,000 hours0 days 0 hours 0 weeks 0 months since 1976. A larger 150 tonnes/day (165 TPD) pilot plant was built at Shells Hamburg refinery in Hamburg, Germany. This larger unit operated for approximately 6,000 hours0 days 0 hours 0 weeks 0 months from 1978 to 1983, and successfully gasified over 27,216 tonnes (30,000 tons) of coal.

From 1974 until mid-1981, Heinrich Koppers GmbH (now Krupp Koppers) cooperated with Shell in the development work for the coal gasification technology at the 150 tonnes/day (165 TPD) pilot plant in Hamburg. Krupp Koppers is the licensor of the commercially proven Koppers-Totzek coal gasification technology, an entrained-flow slagging gasification system operated at atmospheric pressure.

In June 1981, the partnership between Shell and Krupp Koppers was terminated. Since that time, this gasification technology has been developed solely by Shell as the Shell Coal Gasification Process. Krupp Koppers continued its own development of a similar pressurized, dry feed, entrained-flow gasification technology called PRENFLO. Krupp Koppers has built and successfully operated a small 45 tonnes/day (50 TPD) PRENFLO pilot plant at Fuerstenhausen, 229

Cost and Performance Baseline for Fossil Energy Plants Germany. In 2000 Shell and Krupp Uhde agreed to join forces again in gasification and jointly offer the Shell coal gasification process.

Based on the experience it gained with the Hamburg unit, Shell built a demonstration unit at its oil refinery and chemical complex in Deer Park, Texas, near Houston. This new unit, commonly called SCGP-1 (for Shell Coal Gasification Plant-1), was designed to gasify bituminous coal at the rate of 227 tonnes/day (250 TPD) and to gasify high-moisture, high-ash lignite at the rate of 363 tonnes/day (400 TPD). The relatively small difference in size between the Hamburg and Deer Park units reflects design changes and improvements.

The Deer Park demonstration plant operated successfully after startup in July 1987. Before the end of the program in 1991, after 15,000 hours0 days 0 hours 0 weeks 0 months of operation, 18 different feedstocks were gasified at the plant, including domestic coals ranging from lignite to high-sulfur bituminous, three widely traded foreign coals, and petroleum coke. The Deer Park unit produced superheated HP steam in the waste heat recovery boiler. The plant also had facilities for extensive environmental monitoring and for sidestream testing of several AGR processes, including Sulfinol-D, Sulfinol-M, highly loaded MDEA, and various wastewater treatment schemes.

In spring 1989, Shell announced that its technology had been selected for the large commercial-scale Demkolec B.V. IGCC plant at Buggenum, near Roermond, in The Netherlands. This plant generates 250 MW of IGCC electricity with a single Shell gasifier consuming 1,814 tonnes/day (2,000 TPD) (dry basis) of coal. The plant was originally owned and operated by Samenwerkende Electriciteits-Productiebedrijven NV (SEP), a consortium of Dutch utilities, and began operation in 1994. In 2000 the plant was purchased by Nuon. Shell was extensively involved in the design, startup, and initial operation of this plant. A key feature of this design is the use of extraction air from the CT air compressor to feed the oxygen plant.

Gasifier Capacity - As of 2009, Shell reported ten gasifiers in operation producing 100,000-150,000 Nm3/hr and three of the same size in construction. Another three ranging from 150,000-250,000 Nm3/hr are also in construction [61]. The large gasifier operating in The Netherlands has a bituminous coal-handling capacity of 1,633 tonnes/day (1,800 TPD) and produces dry gas at a rate of 158,575 Nm3/hr (5.6 million scf/hr) with an energy content of about 1,792 MMkJ/hr (1,700 MMBtu/hr) (HHV). This gasifier was sized to match the fuel gas requirements for the Siemens/Kraftwerk Union V-94.2 CT and could easily be scaled up to match advanced F Class turbine requirements.

Distinguishing Characteristics - The key advantage of the Shell coal gasification technology is its lack of feed coal limitations. One of the major achievements of the Shell development program has been the successful gasification of a wide variety of coals ranging from anthracite to brown coal. The dry pulverized feed system developed by Shell uses all coal types with essentially no operating and design modifications (provided the drying pulverizers are appropriately sized). The dry fed Shell gasifier also has the advantage of lower oxygen requirement than comparable slurry fed entrained flow gasifiers.

Entrained-flow slagging gasifiers have fundamental environmental advantages over fluidized-bed and moving-bed gasifiers. They produce no hydrocarbon liquids, and the only solid waste is an inert slag. The dry feed entrained-flow gasifiers also have minor environmental advantages over the slurry feed entrained-flow gasifiers. They produce a higher H2S/CO2 ratio acid gas, which improves sulfur recovery and lessens some of the gray water processing and the fixed-salts blowdown problems associated with slurry feeding.

230

Cost and Performance Baseline for Fossil Energy Plants A disadvantage of the Shell coal gasification technology is the high waste heat recovery (SGC) duty. As with the other slagging gasifiers, the Shell process has this disadvantage due to its high operating temperature. The ability to feed dry solids minimizes the oxygen requirement and makes the Shell gasifier somewhat more efficient than entrained flow gasifiers employing slurry feed systems. The penalty paid for this increase in efficiency is a coal feed system that is more costly and operationally more complex. Demonstration of the reliability and safety of the dry coal feeding system was essential for the successful development of the Shell technology. The high operating temperature required by all entrained-flow slagging processes can result in relatively high capital and maintenance costs. However, the Shell gasifier employs a cooled refractory, which requires fewer change outs than an uncooled refractory. Life of a water wall is determined by metallurgy and temperature and can provide a significant O&M cost benefit over refractory lined gasifiers.

Important Coal Characteristics - Characteristics desirable for coal considered for use in the Shell gasifier include moderate ash fusion temperature and relatively low ash content. The Shell gasifier is extremely flexible; it can handle a wide variety of different coals, including lignite.

High-ash fusion-temperature coals may require flux addition for optimal gasifier operation. The ash content, fusion temperature, and composition affect the required gasifier operating temperature level, oxygen requirements, heat removal, slag management, and maintenance.

However, dry feeding reduces the negative effects of high ash content relative to slurry feed gasifiers.

3.4.2 Process Description In this section the overall Shell gasification process for Case 5 is described. The system description follows the BFD in Exhibit 3-72 and stream numbers reference the same Exhibit.

The tables in Exhibit 3-73 provide process data for the numbered streams in the BFD.

Coal Preparation and Feed Systems Coal receiving and handling is common to all cases and was covered in Section 3.1.1. The receiving and handling subsystem ends at the coal silo. The Shell process uses a dry feed system, which is sensitive to the coal moisture content. Coal moisture consists of two parts, surface moisture and inherent moisture. For coal to flow smoothly through the lock hoppers, the surface moisture must be removed. The Illinois No. 6 coal used in this study contains 11.12 percent total moisture on an as-received basis (stream 9). It was assumed that the coal must be dried to 5 percent moisture to allow for smooth flow through the dry feed system (stream 10).

The coal is simultaneously crushed and dried in the coal mill then delivered to a surge hopper with an approximate 2-hour capacity. The drying medium is provided by combining the off-gas from the Claus plant TGTU and a slipstream of clean syngas (stream 8) and passing them through an incinerator. The incinerator FG, with an oxygen content of 6 vol%, is then used to dry the coal in the mill.

The coal is drawn from the surge hoppers and fed through a pressurization lock hopper system to a dense phase pneumatic conveyor, which uses nitrogen from the ASU to convey the coal to the gasifiers.

231

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-72 Case 5 Block Flow Diagram, Shell IGCC without CO2 Capture 232

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-73 Case 5 Stream Table, Shell IGCC without CO2 Capture 1 2 3 4 5 6 7 8 9 10 11 12 13 14 V-L Mole Fraction Ar 0.0092 0.0262 0.0318 0.0023 0.0318 0.0000 0.0023 0.0100 0.0000 0.0000 0.0000 0.0095 0.0095 0.0096 CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0000 0.0000 0.0006 0.0006 0.0006 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.5980 0.0000 0.0000 0.0000 0.5797 0.5797 0.5833 CO2 0.0003 0.0092 0.0000 0.0000 0.0000 0.0000 0.0000 0.0158 0.0000 0.0000 0.0000 0.0143 0.0143 0.0151 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0007 0.0007 0.0000 H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3142 0.0000 0.8090 0.0000 0.3006 0.3006 0.3024 H2O 0.0099 0.2378 0.0000 0.0003 0.0000 1.0000 0.0004 0.0013 0.0000 0.0935 0.0000 0.0252 0.0252 0.0194 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0030 0.0000 0.0009 0.0009 0.0001 H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0081 0.0081 0.0089 N2 0.7732 0.5018 0.0178 0.9919 0.0178 0.0000 0.9919 0.0601 0.0000 0.0163 0.0000 0.0567 0.0567 0.0570 NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0036 0.0036 0.0036 O2 0.2074 0.2251 0.9504 0.0054 0.9504 0.0000 0.0054 0.0000 0.0000 0.0782 0.0000 0.0000 0.0000 0.0000 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 V-L Flowrate (kgmol/hr) 18,364 812 88 16,375 4,591 1,061 882 252 0 0 0 25,096 17,567 17,460 V-L Flowrate (kg/hr) 529,935 21,917 2,828 459,480 147,752 19,111 24,747 5,088 0 0 0 509,993 356,995 354,790 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 198,059 185,222 19,837 0 0 0 Temperature (°C) 15 21 32 93 32 343 32 45 15 16 1,427 1,079 191 177 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 5.10 5.41 3.65 0.10 5.79 4.24 4.24 4.03 3.90 Enthalpy (kJ/kg)A 30.23 37.32 26.67 92.52 26.67 3,063.97 21.22 60.75 --- 0.00 0.00 0.00 325.96 297.28 Density (kg/m3) 1.2 1.6 11.0 24.4 11.0 20.1 60.5 27.8 --- 16.5 --- 7.6 21.0 20.9 V-L Molecular Weight 28.857 26.992 32.181 28.060 32.181 18.015 28.060 20.195 --- --- --- 20.322 20.322 20.320 V-L Flowrate (lbmol/hr) 40,486 1,790 194 36,101 10,122 2,339 1,944 555 0 0 0 55,328 38,729 38,493 V-L Flowrate (lb/hr) 1,168,307 48,319 6,236 1,012,980 325,738 42,132 54,557 11,218 0 0 0 1,124,342 787,039 782,178 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 436,646 408,345 43,732 0 0 0 Temperature (°F) 59 70 90 199 90 650 90 112 59 60 2,600 1,974 375 351 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 740.0 785.0 530.0 14.7 840.0 615.0 615.0 585.0 565.0 Enthalpy (Btu/lb)A 13.0 16.0 11.5 39.8 11.5 1,317.3 9.1 26.1 --- 140.1 127.8 Density (lb/ft 3) 0.076 0.101 0.687 1.521 0.687 1.257 3.774 1.734 --- 1.029 --- 0.475 1.310 1.303 A - Reference conditions are 32.02 F & 0.089 PSIA 233

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-73 Case 5 Stream Table, Shell IGCC without CO2 Capture (Continued) 15 16 17 18 19 20 21 22 23 24 25 26 27 V-L Mole Fraction Ar 0.0098 0.0098 0.0100 0.0079 0.0079 0.0004 0.0000 0.0058 0.0092 0.0092 0.0086 0.0086 0.0000 CH4 0.0006 0.0006 0.0006 0.0005 0.0005 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.5962 0.5845 0.5980 0.4741 0.4741 0.0167 0.0000 0.1034 0.0000 0.0000 0.0000 0.0000 0.0000 CO2 0.0155 0.0257 0.0158 0.0125 0.0125 0.4460 0.0000 0.2613 0.0003 0.0003 0.0752 0.0752 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0000 0.0000 0.0000 0.0000 H2 0.3091 0.3072 0.3142 0.2491 0.2491 0.0096 0.0000 0.0429 0.0000 0.0000 0.0000 0.0000 0.0000 H2O 0.0014 0.0015 0.0013 0.2083 0.2083 0.0063 0.0000 0.4259 0.0099 0.0099 0.0906 0.0906 1.0000 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2S 0.0091 0.0089 0.0000 0.0000 0.0000 0.3872 0.0000 0.0016 0.0000 0.0000 0.0000 0.0000 0.0000 N2 0.0583 0.0618 0.0601 0.0476 0.0476 0.1338 0.0000 0.1585 0.7732 0.7732 0.7210 0.7210 0.0000 NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.2074 0.1046 0.1046 0.0000 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 V-L Flowrate (kgmol/hr) 17,081 17,426 16,771 21,155 21,155 402 0 510 110,253 4,410 137,428 137,428 39,521 V-L Flowrate (kg/hr) 347,994 358,740 338,688 417,666 417,666 14,964 0 13,723 3,181,557 127,262 3,962,154 3,962,154 711,987 Solids Flowrate (kg/hr) 0 0 0 0 0 0 4,959 0 0 0 0 0 0 Temperature (°C) 35 34 45 161 193 45 178 232 15 432 587 132 559 Pressure (MPa, abs) 3.72 3.69 3.65 3.21 3.2 3.654 0.409 0.406 0.101 1.619 0.105 0.105 12.512 Enthalpy (kJ/kg)A 0.00 44.26 60.75 0.00 762.9 13.883 --- 1,007.135 30.227 463.785 791.043 280.131 3,496.259 Density (kg/m3) 29.5 29.6 27.8 17.7 16.2 60.9 5,278.6 2.6 1.2 7.9 0.4 0.9 35.2 V-L Molecular Weight 20.373 20.587 20.195 19.743 20 37.190 --- 26.923 28.857 28.857 28.831 28.831 18.015 V-L Flowrate (lbmol/hr) 37,657 38,417 36,974 46,639 46,639 887 0 1,124 243,066 9,723 302,978 302,978 87,130 V-L Flowrate (lb/hr) 767,195 790,887 746,680 920,797 920,797 32,989 0 30,253 7,014,133 280,565 8,735,053 8,735,053 1,569,662 Solids Flowrate (lb/hr) 0 0 0 0 0 0 10,933 0 0 0 0 0 0 Temperature (°F) 94 94 112 321 380 112 353 450 59 810 1,088 270 1,038 Pressure (psia) 540.0 535.0 530.0 465.0 460.0 530.0 59.3 58.9 14.7 234.9 15.2 15.2 1,814.7 Enthalpy (Btu/lb)A 19.0 26.1 328.0 6.0 --- 433.0 13.0 199.4 340.1 120.4 1,503.1 Density (lb/ft 3) 1.844 1.850 1.734 1.103 1 3.805 329.535 0.163 0.076 0.495 0.026 0.056 2.200 234

Cost and Performance Baseline for Fossil Energy Plants Gasifier There are two Shell dry feed, pressurized, upflow, entrained, slagging gasifiers, operating at 4.2 MPa (615 psia) and processing a total of 4,753 tonnes/day (5,240 TPD) of as-received coal. The air separation plant supplies 3,614 tonnes/day (3,984 TPD) of 95 percent oxygen to the gasifiers (stream 5) and the Claus plant (stream 3). Coal reacts with oxygen and steam at a temperature of 1427°C (2600°F) in the gasifier to produce principally hydrogen and carbon monoxide with little carbon dioxide formed.

The gasifier includes a refractory-lined water wall that is also protected by molten slag that solidifies on the cooled walls.

Raw Gas Cooling/Particulate Removal High-temperature heat recovery in each gasifier train is accomplished in three steps, including the gasifier jacket, which cools and solidifies slag touching the gasifier walls and maintains the syngas temperature at 1,427°C (2,600°F). The product gas from the gasifier is cooled to approximately 1,093°C (2,000°F) by adding cooled recycled fuel gas to lower the temperature below the ash melting point. Gas (stream 12) then goes through a duct cooler and syngas cooler, which lower the gas temperature from approximately 1,093°C (2,000°F) to 316°C (600°F), and produce HP steam for use in the steam cycle.

After passing through the duct cooler and syngas cooler, the syngas passes through a cyclone and a raw gas candle filter where a majority of the fine particles are removed and returned to the gasifier with the coal fuel. The filter consists of an array of ceramic candle elements in a pressure vessel. Fines produced by the gasification system are recirculated to extinction. The ash that is not carried out with the gas forms slag and runs down the interior walls, exiting the gasifier in liquid form. The slag is solidified in a quench tank for disposal (stream 11).

Lockhoppers are used to reduce the pressure of the solids from 4.2 to 0.1 MPa (615 to 15 psia).

The syngas scrubber removes additional PM further downstream.

After passing through the cyclone and ceramic candle filter array, the syngas is further cooled to 191°C (375°F) (stream 13) by raising IP steam.

Quench Gas Compressor About 30 percent of the cooled syngas is recycled back to the gasifier exit as quench gas. A single-stage compressor is utilized to boost the pressure of the cooled fuel gas stream from 4.0 MPa (575 psia) to 4.0 MPa (585 psia) to provide quench gas to cool the gas stream from the gasifier.

Syngas Scrubber/Sour Water Stripper The raw syngas exiting the final raw gas cooler at 191°C (375°F) (stream 13) then enters the scrubber for removal of chlorides, SO2, NH3 and remaining particulate. The quench scrubber washes the syngas in a counter-current flow in two packed beds. The syngas leaves the scrubber saturated at a temperature of 94°C (201ºF). The quench scrubber removes essentially all traces of entrained particles, principally unconverted carbon, slag, and metals. The bottoms from the scrubber are sent to the slag removal and handling system for processing.

The sour water stripper removes NH3, SO2, and other impurities from the waste stream of the scrubber. The sour gas stripper consists of a sour drum that accumulates sour water from the gas 235

Cost and Performance Baseline for Fossil Energy Plants scrubber and condensate from SGCs. Sour water from the drum flows to the sour stripper, which consists of a packed column with a steam-heated reboiler. Sour gas is stripped from the liquid and sent to the SRU. Remaining water is sent to wastewater treatment.

COS Hydrolysis, Mercury Removal and AGR H2S and COS are at significant concentrations, requiring removal for the power plant to achieve the low design level of SO2 emissions. H2S is removed in an AGR process; however, because COS is not readily removable, it is first catalytically converted to H2S in a COS hydrolysis unit.

Following the water scrubber, the gas is reheated to 177°C (350°F) and fed to the COS hydrolysis reactor. The COS in the sour gas is hydrolyzed with steam over a catalyst bed to H2S, which is more easily removed by the AGR solvent. Before the raw fuel gas can be treated in the AGR process (stream 14), it must be cooled to about 35°C (95°F). During this cooling through a series of heat exchangers, part of the water vapor condenses. This water, which contains some NH3, is sent to the sour water stripper. The cooled syngas (stream 15) then passes through a carbon bed to remove 95 percent of the Hg (Section 3.1.4).

The Sulfinol process, developed by Shell in the early 1960s, is a combination process that uses a mixture of amines and a physical solvent. The solvent consists of an aqueous amine and sulfolane. Sulfinol-D uses diisopropanolamine (DIPA), while Sulfinol-M uses MDEA. The mixed solvents allow for better solvent loadings at high acid gas partial pressures and higher solubility of COS and organic sulfur compounds than straight aqueous amines. Sulfinol-M was selected for this application.

The sour syngas is fed directly into an HP contactor. The HP contactor is an absorption column in which the H2S, COS, CO2, and small amounts of H2 and CO are removed from the gas by the Sulfinol solvent. The overhead gas stream from the HP contactor is then washed with water in the sweet gas scrubber before leaving the unit as the feed gas to the sulfur polishing unit.

The rich solvent from the bottom of the HP contactor flows through a hydraulic turbine and is flashed in the rich solvent flash vessel. The flashed gas is then scrubbed in the LP contactor with lean solvent to remove H2S and COS. The overhead from the LP contactor is flashed in the LP KO drum. This gas can be used as a utility fuel gas, consisting primarily of H2 and CO, at 0.8 MPa (118 psia) and 38°C (101°F). The solvent from the bottom of the LP contactor is returned to the rich solvent flash vessel.

Hot, lean solvent in the lean/rich solvent exchanger then heats the flashed rich solvent before entering the stripper. The stripper strips the H2S, COS, and CO2 from the solvent at LP with heat supplied through the stripper reboiler. The acid gas stream to sulfur recovery/tail gas cleanup is recovered as the flash gas from the stripper accumulator. The lean solvent from the bottom of the stripper is cooled in the lean/rich solvent exchanger and the lean solvent cooler. Most of the lean solvent is pumped to the HP contactor. A small amount goes to the LP contactor.

The Sulfinol process removes essentially all of the CO2 along with the H2S and COS. The acid gas fed to the SRU contains 39 vol% H2S and 45 vol% CO2. The CO2 passes through the SRU, the TGTU and ultimately is vented through the coal dryer. Since the amount of CO2 in the syngas is small initially, this does not have a significant effect on the mass flow reaching the GT.

However, the costs of the sulfur recovery/tail gas cleanup are higher than for a sulfur removal process producing an acid gas stream with a higher sulfur concentration.

236

Cost and Performance Baseline for Fossil Energy Plants Claus Unit The SRU is a Claus bypass type SRU utilizing oxygen (stream 3) instead of air. The Claus plant produces molten sulfur (stream 21) by reacting approximately one third of the H2S in the feed to SO2, then reacting the H2S and SO2 to sulfur and water. The use of Claus technology results in an overall sulfur recovery exceeding 99 percent.

Utilizing oxygen instead of air in the Claus plant reduces the overall cost of the sulfur recovery plant. The sulfur plant produces approximately 119 tonnes/day (131 TPD) of elemental sulfur.

Feed for this case consists of acid gas from both the acid gas cleanup unit (stream 20) and a vent stream from the sour water stripper in the gasifier section. A slipstream of clean syngas (stream

8) is passed through an incinerator and combusted with air. The hot, nearly inert incinerator off gas is used to dry coal before being vented to the atmosphere.

In the furnace waste heat boiler, 11,991 kg/hr (26,435 lb/hr) of 3.0 MPa (430 psia) steam are generated. This steam is used to satisfy all Claus process preheating and reheating requirements as well as to provide some steam to the medium-pressure steam header. The sulfur condensers produce 0.34 MPa (50 psig) steam for the LP steam header.

Power Block Clean syngas exiting the Sulfinol absorber (stream 17) is humidified because there is not sufficient nitrogen from the ASU to provide the level of dilution required. The moisturized syngas (stream 18) is reheated (stream 19), further diluted with nitrogen from the ASU (stream

4) and steam, and enters the advanced F Class CT burner. The CT compressor provides combustion air to the burner and also 19 percent of the air requirements in the ASU (stream 24).

The exhaust gas exits the CT at 587°C (1,088°F) (stream 25) and enters the HRSG where additional heat is recovered until the FG exits the HRSG at 132°C (270°F) (stream 26) and is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced, commercially available steam turbine using a 12.4 MPa/559°C/559°C (1800 psig/1038°F/1038°F) steam cycle.

Air Separation Unit (ASU)

The ASU is designed to produce a nominal output of 3,614 tonnes/day (3,984 TPD) of 95 mol%

O2 for use in the gasifier (stream 5) and SRU (stream 3). The plant is designed with two production trains. The air compressor is powered by an electric motor. Approximately 11,028 tonnes/day (12,156 TPD) of nitrogen are also recovered, compressed, and used as dilution in the GT combustor. About 4 percent of the GT air is used to supply approximately 19 percent of the ASU air requirements.

Balance of Plant Balance of plant items were covered in Sections 3.1.9, 3.1.10 and 3.1.11.

3.4.3 Key System Assumptions System assumptions for Cases 5 and 6, Shell IGCC with and without CO2 capture, are compiled in Exhibit 3-74.

237

Cost and Performance Baseline for Fossil Energy Plants Balance of Plant - Cases 5 and 6 The balance of plant assumptions are common to all cases and were presented previously in Exhibit 3-16.

Exhibit 3-74 Shell IGCC Plant Study Configuration Matrix Case 5 6 Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)

O2:Coal Ratio, kg O2/kg dry coal 0.84 0.84 Carbon Conversion, % 99.5 99.5 Syngas HHV at Gasifier Outlet, 10,841 (291) 10,849 (291) kJ/Nm3 (Btu/scf)

Steam Cycle, MPa/°C/°C 12.4/559/559 12.4/534/534 (psig/°F/°F) (1800/1038/1038) (1800/993/993)

Condenser Pressure, mm Hg 51 (2.0) 51 (2.0)

(in Hg) 2x Advanced F Class 2x Advanced F Class CT (232 MW output each) (232 MW output each)

Gasifier Technology Shell Shell Oxidant 95 vol% Oxygen 95 vol% Oxygen Coal Illinois No. 6 Illinois No. 6 Coal Feed Moisture Content, % 5 5 COS Hydrolysis Yes Occurs in SGS SGS No Yes H2S Separation Sulfinol-M Selexol 1st Stage Sulfur Removal, % 99.7 99.9 Claus Plant with Tail Gas Claus Plant with Tail Gas Sulfur Recovery Treatment / Elemental Treatment / Elemental Sulfur Sulfur Cyclone, Candle Filter, Cyclone, Candle Filter, Particulate Control Scrubber, and AGR Scrubber, and AGR Absorber Absorber Mercury Control Carbon Bed Carbon Bed MNQC (LNB), N2 MNQC (LNB), N2 Dilution NOx Control Dilution, Humidification and Humidification and steam dilution CO2 Separation N/A Selexol 2nd Stage Overall CO2 Capture N/A 90.1%

CO2 Sequestration N/A Off-site Saline Formation 238

Cost and Performance Baseline for Fossil Energy Plants 3.4.4 Sparing Philosophy The sparing philosophy for Cases 5 and 6 is provided below. Single trains are utilized throughout with exceptions where equipment capacity requires an additional train. There is no redundancy other than normal sparing of rotating equipment.

The plant design consists of the following major subsystems:

Two ASUs (2 x 50%)

Two trains of coal drying and dry feed systems (2 x 50%)

Two trains of gasification, including gasifier, SGC, cyclone, and barrier filter (2 x 50%).

Two trains of syngas clean-up process (2 x 50%).

Two trains of Sulfinol-M acid gas removal in Case 5 and two-stage Selexol in Case 6 (2 x 50%),

One train of Claus-based sulfur recovery (1 x 100%).

Two CT/HRSG tandems (2 x 50%).

One steam turbine (1 x 100%).

3.4.5 Case 5 Performance Results The plant produces a net output of 629 MWe at a net plant efficiency of 42.1 percent (HHV basis). Shell has reported expected efficiencies using bituminous coal of around 44-45 percent (HHV basis), although this value excluded the net power impact of coal drying [ 62]. Accounting for coal drying would reduce the efficiency by only about 0.5-1 percentage points so the efficiency results for the Shell case are still lower in this study than reported by the vendor.

Overall performance for the entire plant is summarized in Exhibit 3-75, which includes auxiliary power requirements. The ASU accounts for approximately 79 percent of the total auxiliary load distributed between the main air compressor, the oxygen compressor, the nitrogen compressor, and ASU auxiliaries. The cooling water system, including the CWPs and cooling tower fan, accounts for approximately 5 percent of the auxiliary load, and the BFW pumps account for an additional 4 percent. All other individual auxiliary loads are 3 percent or less of the total.

239

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-75 Case 5 Plant Performance Summary POWER

SUMMARY

(Gross Power at Generator Terminals, kWe)

Gas Turbine Power 464,000 Sweet Gas Expander Power 0 Steam Turbine Power 273,000 TOTAL POWER, kWe 737,000 AUXILIARY LOAD

SUMMARY

, kWe Coal Handling 440 Coal Milling 2,040 Slag Handling 520 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 45,190 Oxygen Compressor 8,890 Nitrogen Compressors 29,850 Boiler Feedwater Pumps 4,500 Condensate Pump 230 Syngas Recycle Compressor 680 Circulating Water Pump 3,400 Ground Water Pumps 370 Cooling Tower Fans 1,760 Scrubber Pumps 770 Acid Gas Removal 620 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 250 Claus Plant TG Recycle Compressor 890 Miscellaneous Balance of Plant2 3,000 Transformer Losses 2,520 TOTAL AUXILIARIES, kWe 108,020 NET POWER, kWe 628,980 Net Plant Efficiency, % (HHV) 42.1 Net Plant Heat Rate, kJ/kWh (Btu/kWh) 8,545 (8,099)

CONDENSER COOLING DUTY 106 kJ/hr (106 Btu/hr) 1,393 (1,320)

CONSUMABLES As-Received Coal Feed, kg/hr (lb/hr) 198,059 (436,646)

Thermal Input1, kWt 1,492,878 Raw Water Withdrawal, m3/min (gpm) 15.7 (4,142)

Raw Water Consumption, m3/min (gpm) 12.7 (3,356) 1 - HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 2 - Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads 240

Cost and Performance Baseline for Fossil Energy Plants Environmental Performance The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 2.4. A summary of the plant air emissions for Case 5 is presented in Exhibit 3-76.

Exhibit 3-76 Case 5 Air Emissions Tonne/year kg/GJ kg/MWh (ton/year)

(lb/106 Btu) (lb/MWh) 80% capacity factor SO2 0.002 (0.004) 68 (75) 0.013 (.03)

NOx 0.025 (0.059) 957 (1,055) 0.185 (.409)

Particulates 0.003 (0.0071) 115 (127) 0.022 (.049)

Hg 2.46E-7 (5.71E-7) 0.009 (0.010) 1.79E-6 (3.95E-6)

CO2 84.7 (196.9) 3,188,643 (3,514,877) 617 (1,361)

CO21 723 (1,595) 1 CO2 emissions based on net power instead of gross power The low level of SO2 emissions is achieved by capture of the sulfur in the gas by the Sulfinol-M AGR process. The AGR process removes over 99 percent of the sulfur compounds in the fuel gas down to a level of less than 6 ppmv. This results in a concentration in the HRSG FG of less than 2 ppmv. The H2S-rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is compressed and recycled back to the AGR to capture most of the remaining sulfur. The SO2 emissions in Exhibit 3-76 include both the stack emissions and the coal dryer emissions.

NOx emissions are limited by the use of nitrogen dilution, humidification and steam dilution to 15 ppmvd (as NO2 @ 15 percent O2). Ammonia in the syngas is removed with process condensate prior to the low-temperature AGR process and destroyed in the Claus plant burner.

This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only.

Ninety five percent of the mercury is captured from the syngas by an activated carbon bed.

CO2 emissions represent the uncontrolled discharge from the process.

The carbon balance for the plant is shown in Exhibit 3-77. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected here since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag, as dissolved CO2 in the wastewater blowdown stream, and as CO2 in the stack gas, ASU vent gas and coal dryer vent gas. Carbon in the wastewater blowdown stream is calculated by difference to close the material balance.

241

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-77 Case 5 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 126,252 (278,339) Slag 631 (1,392)

Air (CO2) 508 (1,120) Stack Gas 124,177 (273,764)

ASU Vent 89 (197)

CO2 Product 0 (0)

Dryer Stack 1,863 (4,106)

Gas Total 126,760 (279,459) Total 126,760 (279,459)

Exhibit 3-78 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur in the coal drying gas, and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible.

Exhibit 3-78 Case 5 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 4,964 (10,944) Elemental Sulfur 4,959 (10,933)

Stack Gas 5 (11)

CO2 Product 0 (0)

Total 4,964 (10,944) Total 4,964 (10,944)

Exhibit 3-79 shows the overall water balance for the plant. Explanation on the water balance has been given for Case 1 [GEE] and Case 3 [CoP] but is also presented here for completeness.

Water demand represents the total amount of water required for a particular process. Some water is recovered within the process, primarily as syngas condensate, and is re-used as internal recycle. The difference between demand and recycle is raw water withdrawal. Raw water withdrawal is defined as the water removed from the ground or diverted from a surface-water source for use in the plant and was assumed to be provided 50 percent by a POTW and 50 percent from groundwater. Raw water withdrawal can be represented by the water metered from a raw water source and used in the plant processes for any and all purposes, such as cooling tower makeup, BFW makeup, quench system makeup, and slag handling makeup. The difference between water withdrawal and process water discharge is defined as water consumption and can be represented by the portion of the raw water withdrawn that is evaporated, transpired, incorporated into products or otherwise not returned to the water source from which it was withdrawn. Water consumption represents the net impact of the plant process on the water source balance.

242

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-79 Case 5 Water Balance Process Water Internal Raw Water Water Raw Water Demand, Recycle, Withdrawal, Water Use Discharge, Consumption, m3/min m3/min m3/min m3/min m3/min (gpm)

(gpm) (gpm) (gpm)

(gpm)

Slag Handling 0.43 (114) 0.2 (45) 0.3 (69) 0.0 (0) 0.3 (69)

Quench/Wash 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

Humidifier 1.4 (365) 0.0 (0) 1.4 (365) 0.0 (0) 1.4 (365)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

Condenser Makeup 1.1 (282) 0.0 (0) 1.1 (282) 0.0 (0) 1.1 (282)

Gasifier Steam 0.3 (84) 0.3 (84)

Shift Steam GT Steam Dilution 0.5 (135) 0.5 (135)

BFW Makeup 0.2 (62) 0.2 (62)

Cooling Tower 13.2 (3,494) 0.25 (67) 13.0 (3,427) 3.0 (786) 10.0 (2,641)

BFW Blowdown 0.23 (62) -0.23 (-62)

SWS Blowdown 0.02 (4) -0.02 (-4)

SWS Excess Water 0.0 (0)

Humidifier Tower Blowdown Total 16.1 (4,254) 0.4 (112) 15.7 (4,142) 3.0 (786) 12.7 (3,356)

Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-80 through Exhibit 3-82:

Coal gasification and ASU

Syngas cleanup, sulfur recovery, and tail gas recycle

Combined cycle power generation, steam, and FW An overall plant energy balance is provided in tabular form in Exhibit 3-54. The power out is the combined CT and steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 3-75) is calculated by multiplying the power out by a combined generator efficiency of 98.3 percent.

243

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Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-80 Case 5 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic LEGEND Ambient Air Air 1 48,319 W 1,168,307 W 69.5 T Coal/Char/

59.0 T 16.4 P 14.7 P 220.0 T Slurry/Slag Intercooled 224.9 P ASU 50.9 H Nitrogen Air Compressor N2 to GT Combustor VENT 4

2 1,012,980 W Oxygen 199.0 T 389.0 T Intercooled 384.0 P 384.0 P Nitrogen Compressor 39.8 H 88.2 H Sour Gas Boost Compressor Air from GT Compressor Elevated 937,042 W Sour Water 5 Pressure 90.0 T 130,495 W 280,565 W ASU 56.4 P 50.0 T 809.8 T 325,738 W 14.2 H 182.0 P 234.9 P Steam 90.0 T 2.9 H 199.4 H 125.0 P 11.5 H Synthesis Gas Water 3 To Claus Plant Intercooled 6,236 W Flue Gas/

Recycle Oxygen Compressor 90.0 T 125.0 P 393.5 T Compressor 337,303 W Combustion 11.5 H 625.0 P 375.0 T Products 54,557 W 146.7 H 585.0 P Saturated Steam 376.3 T 140.1 H to HRSG P ABSOLUTE PRESSURE, PSIA 785.0 P Steam F TEMPERATURE, °F 325,738 W 42,132 W 12 W FLOWRATE, LB/HR Steam BFW 7 Syngas H ENTHALPY, BTU/LB 241.2 T 650.0 T 1,124,342 W Duct Cooler Drum from HRSG MWE POWER, MEGAWATTS ELECTRICAL 940.0 P 740.0 P Cooler Incinerator Exhaust 1,974.4 T 40.8 H 1,317.3 H 615.0 P 750.2 H NOTES:

Blowdown to Flash Tank 92,698 W 290.0 T 1. ENTHALPY REFERENCE POINT IS NATURAL STATE 14.4 P AT 32 °F AND 0.08865 PSIA 6

Steam Generation Shell Milled Coal Dry Coal Gasifier Coal 9 Drying 10 Coal PLANT PERFORMANCE

SUMMARY

Feeding Incinerator 436,646 W 408,345 W 59.0 T 60.0 T GROSS PLANT POWER: 737 MWE 14.7 P 840.0 P Raw Syngas AUXILIARY LOAD: 108 MWE 1,526.1 H to Scrubber NET PLANT POWER: 629 MWE NET PLANT EFFICIENCY, HHV: 42.1%

8 13 NET PLANT HEAT RATE: 8,099 BTU/KWE 53,179 W 11,218 W 59.0 T 112.2 T 787,039 W Raw Gas 14.7 P 530.0 P 375.0 T Cooler 26.1 H 1,124,342 W 585.0 P DOE/NETL 600.0 T 140.1 H Incinerator Air Syngas Slip Stream 595.0 P Cyclone Candle 221.1 H Filter DUAL TRAIN IGCC PLANT CASE 5 HEAT AND MATERIAL FLOW DIAGRAM Slag BITUMINOUS BASELINE STUDY 43,732 W CASE 5 11 2,600.0 T SHELL GASIFIER Slag 615.0 P ASU, GASIFICATION, AND GAS COOLING Removal DWG. NO. PAGES BB-HMB-CS-5-PG-1 1 OF 3 245

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-81 Case 5 Syngas Cleanup Heat and Mass Balance Schematic LEGEND Treated Syngas Humidification 18 19 Humidified Fuel Gas 746,680 W Acid Gas 112.2 T 530.0 P Air 26.1 H Claus Plant 17 Carbon Dioxide Catalytic Coal/Char/

Reactor Beds Slurry/Slag COS Slip Stream 8 32,989 W Hydrolysis to Coal Dryer 112.2 T 530.0 P Hydrogen Furnace 350.0 T 351.2 T Nitrogen 20 Tail 575.0 P 565.0 P Gas 128.0 H 127.8 H Oxygen Clean Gas Acid Gas Sour Gas Sour Water 790,887 W 93.9 T 10,933 W Sulfur 535.0 P 21 HP BFW HP BFW 353.2 T Synthesis Gas 19.0 H 59.3 P 16 Tailgas 30,253 W 14 450.0 T 22 Water 782,178 W Mercury Sulfur 58.9 P 200.9 T Removal 580.0 P 74.7 H AGR- Sulfinol 767,195 W P ABSOLUTE PRESSURE, PSIA Tailgas to AGR F TEMPERATURE, °F 94.4 T 15 From W FLOWRATE, LB/HR 540.0 P 23,692 W ASU H ENTHALPY, BTU/LB Syngas 19.5 H 11,669 W 100.0 T 90.0 T Hydrogenation MWE POWER, MEGAWATTS ELECTRICAL Syngas Coolers 799.5 P 125.0 P And Tail Gas Scrubber Knock 4.8 H 11.5 H Cooling Out NOTES:

Drum Raw Syngas 13 1,962 W 141.5 T 787,039 W 65.0 P 375.0 T Sour Drum 75.9 H 585.0 P 140.1 H PLANT PERFORMANCE

SUMMARY

Sour Stripper Makeup Water GROSS PLANT POWER: 737 MWE Tailgas Recycle AUXILIARY LOAD: 108 MWE Compressor 24,042 W NET PLANT POWER: 629 MWE 120.0 T NET PLANT EFFICIENCY, HHV: 42.1%

56.8 P NET PLANT HEAT RATE: 8,099 BTU/KWE Reboiler Knock Out DOE/NETL 6,561 W 118.9 T 56.8 P DUAL TRAIN IGCC PLANT 45.2 H CASE 5 To Water Treatment HEAT AND MATERIAL FLOW DIAGRAM BITUMINOUS BASELINE STUDY CASE 5 SHELL GASIFIER GAS CLEANUP SYSTEM DWG. NO. PAGES BB-HMB-CS-5-PG-2 2 OF 3 246

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-82 Case 5 Combined Cycle Power Generation Heat and Mass Balance Schematic LEGEND Air HP BFW to Raw Gas Coolers 80,190 W Flue Gas/

298.0 T Combustion HP Saturated Steam to HRSG Superheater 65.0 P Products 1,178.6 H Nitrogen 8,735,053 W 8,735,053 W Oxygen 1,088.0 T 269.6 T 15.2 P 15.2 P 340.1 H 120.4 H Steam 25 HRSG 26 LP Flash Tops Stack Synthesis Gas 67,709 W Steam Dilution 475.0 T 12,478 W MP Flash Bottoms Water 460.0 P 298.0 T From Gasifier 65.0 P Island Preheating 1,012,980 W 1,178.6 H Nitrogen Dilution 1,548,142 W 385.0 T 235.0 T 389.0 P Deaerator 4 1,569,662 W 105.0 P 920,797 W 1,038.0 T 203.3 H 1,814.7 P 27 1,604,593 W 380.0 T 278.8 T Humidified Fuel Gas 460.0 P 1,503.1 H 2,250.7 P LP BFW P ABSOLUTE PRESSURE, PSIA 328.0 H 251.9 H 19 F TEMPERATURE, °F W FLOWRATE, LB/HR Blowdown Air to ASU H ENTHALPY, BTU/LB 34,923 W Flash LP Pump MWE POWER, MEGAWATTS ELECTRICAL 24 585.0 T To Claus 280,565 W 2,000.7 P To WWT 809.8 T 592.9 H HP Pump NOTES:

234.9 P IP BFW IP Pump 1,395,354 W 537.3 T 40,813 W Compressor Expander 65.0 P 537.3 T 1,300.5 H 65.0 P Generator HP IP LP 1,300.5 H Turbine Turbine Steam Turbine Advanced F-Class Turbine Gas Turbine LP Generator Process Header Intake IP Extraction Steam PLANT PERFORMANCE

SUMMARY

to 250 PSIA Header 26,045 W GROSS PLANT POWER: 737 MWE 23 893.6 T AUXILIARY LOAD: 108 MWE 280.0 P NET PLANT POWER: 629 MWE 1,470.5 H NET PLANT EFFICIENCY, HHV: 42.1%

Ambient Air Make-up NET PLANT HEAT RATE: 8,099 BTU/KWE CONDENSER 140,851 W 7,014,133 W Steam Seal Regulator 59.0 T 59.0 T 14.7 P 14.7 P HOT WELL 27.1 H DOE/NETL 1,548,142 W 101.1 T DUAL TRAIN IGCC PLANT To Gasifier 1.0 P CASE 5 69.1 H 1,400 W 1,400 W HEAT AND MATERIAL FLOW DIAGRAM 657.5 T Condensate 212.0 T 65.0 P Pump 14.7 P 1,359.7 H 179.9 H BITUMINOUS BASELINE STUDY Gland CASE 5 103.2 T Steam SHELL GASIFIER 120.0 P Condenser POWER BLOCK SYSTEM Condensate to Gasification Island 71.5 H DWG. NO. PAGES BB-HMB-CS-5-PG-3 3 OF 3 247

Cost and Performance Baseline for Fossil Energy Plants This page intentionally left blank 248

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-83 Case 5 Overall Energy Balance (0°C [32°F] Reference)

Sensible +

HHV Power Total Latent Heat In GJ/hr (MMBtu/hr)

Coal 5,374 (5,094) 4.5 (4.3) 5,379 (5,098)

ASU Air 16.0 (15.2) 16 (15)

GT Air 96.2 (91.2) 96 (91)

Water 59.0 (55.9) 59 (56)

Auxiliary Power 389 (369) 389 (369)

TOTAL 5,374 (5,094) 175.6 (166.5) 389 (369) 5,939 (5,629)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0.8 (0.8) 1 (1)

Slag 21 (20) 33.5 (31.7) 54 (51)

Sulfur 46 (44) 0.6 (0.5) 47 (44)

CO2 Cooling Tower 22.1 (20.9) 22 (21)

Blowdown HRSG Flue Gas 1,110 (1,052) 1,110 (1,052)

Condenser 1,397 (1,324) 1,397 (1,324)

Non-Condenser 215 (204) 215 (204)

Cooling Tower Loads*

Process Losses** 439 (417) 439 (417)

Power 2,653 (2,515) 2,653 (2,515)

TOTAL 67 (63) 3,219 (3,051) 2,653 (2,515) 5,939 (5,629)

Includes ASU compressor intercoolers, CO2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection) and extraction air cooler.

- Calculated by difference to close the energy balance.

249

Cost and Performance Baseline for Fossil Energy Plants 3.4.6 Case 5 - Major Equipment List Major equipment items for the Shell gasifier with no CO2 capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section 3.4.7. In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 COAL HANDLING Equipment Operating Description Type Design Condition Spares No. Qty.

Bottom Trestle Dumper and 1 N/A 181 tonne (200 ton) 2 0 Receiving Hoppers 2 Feeder Belt 572 tonne/hr (630 tph) 2 0 3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0 4 Transfer Tower No. 1 Enclosed N/A 1 0 5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0 As-Received Coal Sampling 6 Two-stage N/A 1 0 System 7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0 8 Reclaim Hopper N/A 45 tonne (50 ton) 2 1 9 Feeder Vibratory 163 tonne/hr (180 tph) 2 1 10 Conveyor No. 3 Belt w/ tripper 327 tonne/hr (360 tph) 1 0 11 Crusher Tower N/A N/A 1 0 12 Coal Surge Bin w/ Vent Filter Dual outlet 163 tonne (180 ton) 2 0 Impactor 8 cm x 0 - 3 cm x 0 13 Crusher 2 0 reduction (3" x 0 1/4" x 0)

As-Fired Coal Sampling 14 Swing hammer N/A 1 1 System 15 Conveyor No. 4 Belt w/tripper 327 tonne/hr (360 tph) 1 0 16 Transfer Tower No. 2 Enclosed N/A 1 0 17 Conveyor No. 5 Belt w/ tripper 327 tonne/hr (360 tph) 1 0 Coal Silo w/ Vent Filter and 18 Field erected 726 tonne (800 ton) 3 0 Slide Gates 250

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 2 COAL PREPARATION AND FEED Equipment Operating Description Type Design Condition Spares No. Qty.

1 Feeder Vibratory 73 tonne/hr (80 tph) 3 0 2 Conveyor No. 6 Belt w/tripper 218 tonne/hr (240 tph) 1 0 3 Roller Mill Feed Hopper Dual Outlet 435 tonne (480 ton) 1 0 4 Weigh Feeder Belt 109 tonne/hr (120 tph) 2 0 5 Coal Dryer and Pulverizer Rotary 109 tonne/hr (120 tph) 2 0 6 Coal Dryer Feed Hopper Vertical Hopper 218 tonne (240 ton) 2 0 251

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment Operating Description Type Design Condition Spares No. Qty.

Demineralized Water Vertical, cylindrical, 1 1,165,907 liters (308,000 gal) 2 0 Storage Tank outdoor 6,473 lpm @ 91 m H2O 2 Condensate Pumps Vertical canned 2 1 (1,710 gpm @ 300 ft H2O)

Deaerator (integral w/

3 Horizontal spray type 436,356 kg/hr (962,000 lb/hr) 2 0 HRSG)

Intermediate Pressure Horizontal centrifugal, 7,419 lpm @ 27 m H2O 4 2 1 Feedwater Pump single stage (1,960 gpm @ 90 ft H2O)

HP water: 6,927 lpm @ 1,859 m High Pressure Barrel type, multi-stage, 5 H2O (1,830 gpm @ 6,100 ft 2 1 Feedwater Pump No. 1 centrifugal H2O)

High Pressure Barrel type, multi-stage, IP water: 2,461 lpm @ 223 m 6 2 1 Feedwater Pump No. 2 centrifugal H2O (650 gpm @ 730 ft H2O)

Shop fabricated, water 18,144 kg/hr, 2.8 MPa, 343°C 7 Auxiliary Boiler 1 0 tube (40,000 lb/hr, 400 psig, 650°F)

Service Air 28 m3/min @ 0.7 MPa 8 Flooded Screw 2 1 Compressors (1,000 scfm @ 100 psig) 9 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1 Closed Cylce Cooling 10 Plate and frame 133 GJ/hr (126 MMBtu/hr) each 2 0 Heat Exchangers Closed Cycle Cooling 47,696 lpm @ 21 m H2O 11 Horizontal centrifugal 2 1 Water Pumps (12,600 gpm @ 70 ft H2O)

Engine-Driven Fire Vertical turbine, diesel 3,785 lpm @ 107 m H2O 12 1 1 Pump engine (1,000 gpm @ 350 ft H2O)

Fire Service Booster Two-stage horizontal 2,650 lpm @ 76 m H2O 13 1 1 Pump centrifugal (700 gpm @ 250 ft H2O)

Stainless steel, single 4,391 lpm @ 18 m H2O 14 Raw Water Pumps 2 1 suction (1,160 gpm @ 60 ft H2O)

Stainless steel, single 2,915 lpm @ 268 m H2O 15 Ground Water Pumps 3 1 suction (770 gpm @ 880 ft H2O)

Stainless steel, single 1,779 lpm @ 49 m H2O 16 Filtered Water Pumps 2 1 suction (470 gpm @ 160 ft H2O) 17 Filtered Water Tank Vertical, cylindrical 851,718 liter (225,000 gal) 2 0 Makeup Water Anion, cation, and 18 341 lpm (90 gpm) 2 0 Demineralizer mixed bed Liquid Waste Treatment 19 10 years, 24-hour storm 1 0 System 252

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY AND FUEL GAS SATURATION Equipment Operating Description Type Design Condition Spares No. Qty.

Pressurized dry-feed, 2,631 tonne/day, 4.2 MPa 1 Gasifier 2 0 entrained bed (2,900 tpd, 615 psia)

Convective spiral-2 Synthesis Gas Cooler 280,320 kg/hr (618,000 lb/hr) 2 0 wound tube boiler 280,320 kg/hr (618,000 lb/hr) 3 Synthesis Gas Cyclone High efficiency 2 0 Design efficiency 90%

Pressurized filter with 4 Candle Filter metallic filters 2 0 pulse-jet cleaning Syngas Scrubber 5 Including Sour Water Vertical upflow 196,405 kg/hr (433,000 lb/hr) 2 0 Stripper Shell and tube with 6 Raw Gas Coolers 192,777 kg/hr (425,000 lb/hr) 8 0 condensate drain Raw Gas Knockout Vertical with mist 191,870 kg/hr, 35°C, 3.8 MPa 7 2 0 Drum eliminator (423,000 lb/hr, 94°F, 545 psia)

Saturation Water 8 Shell and tube 131 GJ/hr (124 MMBtu/hr) 2 0 Economizers 229,518 kg/hr, 161°C, 3.3 MPa 9 Fuel Gas Saturator Vertical tray tower 2 0 (506,000 lb/hr, 321°F, 480 psia) 3,407 lpm @ 12 m H2O 10 Saturator Water Pump Centrifugal 2 2 (900 gpm @ 40 ft H2O) 11 Synthesis Gas Reheater Shell and tube 186,426 kg/hr (411,000 lb/hr) 2 0 Self-supporting, carbon 196,405 kg/hr (433,000 lb/hr) 12 Flare Stack steel, stainless steel top, 2 0 syngas pilot ignition ASU Main Air 3,993 m3/min @ 1.3 MPa 13 Centrifugal, multi-stage 2 0 Compressor (141,000 scfm @ 190 psia) 1,996 tonne/day (2,200 tpd) of 14 Cold Box Vendor design 2 0 95% purity oxygen 991 m3/min (35,000 scfm) 15 Oxygen Compressor Centrifugal, multi-stage Suction - 0.9 MPa (130 psia) 2 0 Discharge - 6.5 MPa (940 psia) 3,285 m3/min (116,000 scfm)

Primary Nitrogen 16 Centrifugal, multi-stage Suction - 0.4 MPa (60 psia) 2 0 Compressor Discharge - 2.7 MPa (390 psia) 453 m3/min (16,000 scfm)

Secondary Nitrogen 17 Centrifugal, single-stage Suction - 1.2 MPa (180 psia) 2 0 Compressor Discharge - 2.7 MPa (390 psia) 198 m3/min (7,000 scfm)

Transport Nitrogen 18 Centrifugal, single-stage Suction - 2.6 MPa (380 psia) 2 0 Boost Compressor Discharge - 5.4 MPa (790 psia)

Extraction Air Heat Gas-to-gas, vendor 69,853 kg/hr, 432°C, 1.6 MPa 19 2 0 Exchanger design (154,000 lb/hr, 810°F, 235 psia) 253

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 5 SYNGAS CLEANUP Equipment Operating Description Type Design Condition Spares No. Qty.

191,416 kg/hr (422,000 lb/hr)

Sulfated carbon 1 Mercury Adsorber 35°C (94°F) 2 0 bed 3.7 MPa (540 psia) 2 Sulfur Plant Claus type 131 tonne/day (144 tpd) 1 0 195,045 kg/hr (430,000 lb/hr)

Fixed bed, 3 COS Hydrolysis Reactor 177°C (350°F) 2 0 catalytic 4.0 MPa (580 psia) 197,313 kg/hr (435,000 lb/hr) 4 Acid Gas Removal Plant Sulfinol 34°C (94°F) 2 0 3.7 MPa (535 psia) 13,723 kg/hr (30,253 lb/hr)

Fixed bed, 5 Hydrogenation Reactor 232°C (450°F) 1 0 catalytic 0.4 MPa (58.9 psia)

Tail Gas Recycle 6 Centrifugal 10,747 kg/hr (23,692 lb/hr) each 1 0 Compressor ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES Equipment Operating Description Type Design Condition Spares No. Qty.

1 Gas Turbine Advanced F class 232 MW 2 0 260 MVA @ 0.9 p.f., 24 kV, 2 Gas Turbine Generator TEWAC 2 0 60 Hz, 3-phase ACCOUNT 7 HRSG, DUCTING AND STACK Equipment Operating Description Type Design Condition Spares No. Qty.

CS plate, type 409SS 76 m (250 ft) high x 1 Stack 1 0 liner 8.4 m (28 ft) diameter Main steam - 393,555 kg/hr, 12.4 Drum, multi-pressure MPa/559°C (867,640 lb/hr, Heat Recovery with economizer 1,800 psig/1,038°F) 2 2 0 Steam Generator section and integral Reheat steam - 362,720 kg/hr, deaerator 3.1 MPa/559°C (799,662 lb/hr, 452 psig/1,038°F) 254

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES Equipment Operating Description Type Design Condition Spares No. Qty.

Commercially 289 MW 1 Steam Turbine available advanced 12.4 MPa/559°C/559°C 1 0 steam turbine (1,800 psig/ 1038°F/1038°F)

Hydrogen cooled, 320 MVA @ 0.9 p.f., 24 2 Steam Turbine Generator 1 0 static excitiation kV, 60 Hz, 3-phase 50% steam flow @ design 3 Steam Bypass One per HRSG 2 0 steam conditions 1,540 GJ/hr (1,460 Single pass, divided MMBtu/hr), Inlet water 4 Surface Condenser waterbox including temperature 16°C (60°F), 1 0 vacuum pumps Water temperature rise 11°C (20°F)

ACCOUNT 9 COOLING WATER SYSTEM Equipment Operating Description Type Design Condition Spares No. Qty.

Circulating Water 340,687 lpm @ 30 m 1 Vertical, wet pit 2 1 Pumps (90,000 gpm @ 100 ft) 11°C (51.5°F) wet bulb / 16°C Evaporative, (60°F) CWT / 27°C (80°F) HWT 2 Cooling Tower mechanical draft, multi- 1 0

/ 1,899 GJ/hr (1,800 MMBtu/hr) cell heat duty 255

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 10 SLAG RECOVERY AND HANDLING Equipment Operating Description Type Design Condition Spares No. Qty.

1 Slag Quench Tank Water bath 208,198 liters (55,000 gal) 2 0 2 Slag Crusher Roll 11 tonne/hr (12 tph) 2 0 3 Slag Depressurizer Lock Hopper 11 tonne/hr (12 tph) 2 0 4 Slag Receiving Tank Horizontal, weir 124,919 liters (33,000 gal) 2 0 5 Black Water Overflow Tank Shop fabricated 56,781 liters (15,000 gal) 2 6 Slag Conveyor Drag chain 11 tonne/hr (12 tph) 2 0 7 Slag Separation Screen Vibrating 11 tonne/hr (12 tph) 2 0 8 Coarse Slag Conveyor Belt/bucket 11 tonne/hr (12 tph) 2 0 9 Fine Ash Settling Tank Vertical, gravity 177,914 liters (47,000 gal) 2 0 Horizontal 38 lpm @ 14 m H2O 10 Fine Ash Recycle Pumps 2 2 centrifugal (10 gpm @ 46 ft H2O) 11 Grey Water Storage Tank Field erected 56,781 liters (15,000 gal) 2 0 189 lpm @ 433 m H2O 12 Grey Water Pumps Centrifugal 2 2 (50 gpm @ 1,420 ft H2O)

Vertical, field 13 Slag Storage Bin 816 tonne (900 tons) 2 0 erected 14 Unloading Equipment Telescoping chute 91 tonne/hr (100 tph) 1 0 256

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 11 ACCESSORY ELECTRIC PLANT Equipment Operating Description Type Design Condition Spares No. Qty.

CTG Step-up 24 kV/345 kV, 260 MVA, 1 Oil-filled 2 0 Transformer 3-ph, 60 Hz STG Step-up 24 kV/345 kV, 320 MVA, 2 Oil-filled 1 0 Transformer 3-ph, 60 Hz High Voltage 345 kV/13.8 kV, 47 MVA, 3 Auxiliary Oil-filled 2 0 3-ph, 60 Hz Transformer Medium Voltage 24 kV/4.16 kV, 27 MVA, 4 Auxiliary Oil-filled 1 1 3-ph, 60 Hz Transformer Low Voltage 4.16 kV/480 V, 4 MVA, 5 Dry ventilated 1 1 Transformer 3-ph, 60 Hz CTG Isolated 6 Phase Bus Duct Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 2 0 and Tap Bus STG Isolated 7 Phase Bus Duct Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0 and Tap Bus Medium Voltage 8 Metal clad 4.16 kV, 3-ph, 60 Hz 1 1 Switchgear Low Voltage 9 Metal enclosed 480 V, 3-ph, 60 Hz 1 1 Switchgear Emergency Diesel Sized for emergency 10 750 kW, 480 V, 3-ph, 60 Hz 1 0 Generator shutdown ACCOUNT 12 INSTRUMENTATION AND CONTROLS Equipment Operating Description Type Design Condition Spares No. Qty.

Monitor/keyboard; DCS - Main Operator printer (laser Operator stations/printers and 1 1 0 Control color); Engineering engineering stations/printers printer (laser B&W)

Microprocessor with 2 DCS - Processor N/A 1 0 redundant input/output DCS - Data 3 Fiber optic Fully redundant, 25% spare 1 0 Highway 257

Cost and Performance Baseline for Fossil Energy Plants 3.4.7 Case 5 - Cost Estimating Costs Results The cost estimating methodology was described previously in Section 2.6. Exhibit 3-84 shows the total plant capital cost summary organized by cost account and Exhibit 3-85 shows a more detailed breakdown of the capital costs along with owners costs, TOC and TASC. Exhibit 3-86 shows the initial and annual O&M costs.

The estimated TOC of the Shell gasifier with no CO2 capture is $2,716/kW. Process contingency represents 2.3 percent of the TOC and project contingency represents 11.1 percent.

The COE is 81.3 mills/kWh.

258

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-84 Case 5 Total Plant Cost Summary Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study TOTAL PLANT COST

SUMMARY

Case: Case 5 - Shell 600MW IGCC w/o CO2 Plant Size: 629.0 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING $13,346 $2,480 $10,349 $0 $0 $26,175 $2,376 $0 $5,710 $34,261 $54 2 COAL & SORBENT PREP & FEED $105,424 $8,399 $17,537 $0 $0 $131,359 $11,391 $0 $28,550 $171,300 $272 3 FEEDWATER & MISC. BOP SYSTEMS $9,632 $8,082 $9,224 $0 $0 $26,938 $2,534 $0 $6,691 $36,163 $57 4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (Shell) $171,446 $0 $73,699 $0 $0 $245,145 $21,883 $34,079 $46,149 $347,255 $552 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $148,365 $0 w/equip. $0 $0 $148,365 $14,381 $0 $16,275 $179,021 $285 4.4-4.9 Other Gasification Equipment $15,541 $9,100 $10,950 $0 $0 $35,592 $3,394 $0 $8,498 $47,483 $75 SUBTOTAL 4 $335,353 $9,100 $84,649 $0 $0 $429,102 $39,657 $34,079 $70,922 $573,760 $912 5A GAS CLEANUP & PIPING $50,101 $3,724 $47,806 $0 $0 $101,630 $9,827 $86 $22,447 $133,990 $213 5B CO2 REMOVAL & COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $85,752 $0 $6,269 $0 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $184 6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4 SUBTOTAL 6 $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $188 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $35,374 $0 $5,030 $0 $0 $40,404 $3,842 $0 $4,425 $48,670 $77 7.2-7.9 Ductwork and Stack $3,337 $2,379 $3,116 $0 $0 $8,833 $819 $0 $1,571 $11,222 $18 SUBTOTAL 7 $38,712 $2,379 $8,146 $0 $0 $49,237 $4,661 $0 $5,995 $59,893 $95 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $28,830 $0 $4,946 $0 $0 $33,776 $3,241 $0 $3,702 $40,718 $65 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $10,446 $993 $7,524 $0 $0 $18,963 $1,722 $0 $4,181 $24,865 $40 SUBTOTAL 8 $39,276 $993 $12,470 $0 $0 $52,739 $4,963 $0 $7,883 $65,584 $104 9 COOLING WATER SYSTEM $8,350 $8,140 $6,922 $0 $0 $23,411 $2,174 $0 $5,234 $30,819 $49 10 ASH/SPENT SORBENT HANDLING SYS $17,858 $1,384 $8,862 $0 $0 $28,104 $2,696 $0 $3,366 $34,166 $54 11 ACCESSORY ELECTRIC PLANT $26,986 $10,003 $20,101 $0 $0 $57,090 $4,905 $0 $11,625 $73,620 $117 12 INSTRUMENTATION & CONTROL $10,318 $1,898 $6,648 $0 $0 $18,864 $1,710 $943 $3,585 $25,102 $40 13 IMPROVEMENTS TO SITE $3,326 $1,960 $8,206 $0 $0 $13,492 $1,332 $0 $4,447 $19,272 $31 14 BUILDINGS & STRUCTURES $0 $6,644 $7,614 $0 $0 $14,258 $1,298 $0 $2,544 $18,100 $29 TOTAL COST $744,432 $65,991 $255,695 $0 $0 $1,066,118 $98,407 $39,709 $190,092 $1,394,325 $2,217 259

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-85 Case 5 Total Plant Cost Details Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study TOTAL PLANT COST

SUMMARY

Case: Case 5 - Shell 600MW IGCC w/o CO2 Plant Size: 629.0 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $3,505 $0 $1,713 $0 $0 $5,217 $467 $0 $1,137 $6,822 $11 1.2 Coal Stackout & Reclaim $4,529 $0 $1,098 $0 $0 $5,627 $493 $0 $1,224 $7,344 $12 1.3 Coal Conveyors & Yd Crush $4,211 $0 $1,086 $0 $0 $5,297 $465 $0 $1,152 $6,914 $11 1.4 Other Coal Handling $1,102 $0 $251 $0 $0 $1,353 $118 $0 $294 $1,766 $3 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,480 $6,201 $0 $0 $8,681 $832 $0 $1,903 $11,416 $18 SUBTOTAL 1. $13,346 $2,480 $10,349 $0 $0 $26,175 $2,376 $0 $5,710 $34,261 $54 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $40,051 $2,406 $5,836 $0 $0 $48,294 $4,167 $0 $10,492 $62,953 $100 2.2 Prepared Coal Storage & Feed $1,897 $454 $297 $0 $0 $2,648 $226 $0 $575 $3,450 $5 2.3 Dry Coal Injection System $62,432 $725 $5,798 $0 $0 $68,955 $5,939 $0 $14,979 $89,872 $143 2.4 Misc.Coal Prep & Feed $1,043 $759 $2,276 $0 $0 $4,078 $375 $0 $891 $5,344 $8 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $4,055 $3,329 $0 $0 $7,384 $684 $0 $1,614 $9,681 $15 SUBTOTAL 2. $105,424 $8,399 $17,537 $0 $0 $131,359 $11,391 $0 $28,550 $171,300 $272 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $3,130 $5,375 $2,837 $0 $0 $11,343 $1,051 $0 $2,479 $14,872 $24 3.2 Water Makeup & Pretreating $564 $59 $315 $0 $0 $938 $89 $0 $308 $1,335 $2 3.3 Other Feedwater Subsystems $1,713 $579 $521 $0 $0 $2,812 $253 $0 $613 $3,678 $6 3.4 Service Water Systems $323 $664 $2,306 $0 $0 $3,293 $321 $0 $1,084 $4,699 $7 3.5 Other Boiler Plant Systems $1,732 $671 $1,663 $0 $0 $4,065 $386 $0 $890 $5,341 $8 3.6 FO Supply Sys & Nat Gas $313 $591 $551 $0 $0 $1,454 $140 $0 $319 $1,913 $3 3.7 Waste Treatment Equipment $788 $0 $481 $0 $0 $1,269 $124 $0 $418 $1,810 $3 3.8 Misc. Power Plant Equipment $1,071 $143 $550 $0 $0 $1,764 $170 $0 $580 $2,514 $4 SUBTOTAL 3. $9,632 $8,082 $9,224 $0 $0 $26,938 $2,534 $0 $6,691 $36,163 $57 4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (Shell) $171,446 $0 $73,699 $0 $0 $245,145 $21,883 $34,079 $46,149 $347,255 $552 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $148,365 $0 w/equip. $0 $0 $148,365 $14,381 $0 $16,275 $179,021 $285 4.4 LT Heat Recovery & FG Saturation $15,541 $0 $5,908 $0 $0 $21,449 $2,093 $0 $4,709 $28,251 $45 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Flare Stack System $0 $921 $375 $0 $0 $1,296 $124 $0 $284 $1,704 $3 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $8,179 $4,667 $0 $0 $12,847 $1,176 $0 $3,506 $17,528 $28 SUBTOTAL 4. $335,353 $9,100 $84,649 $0 $0 $429,102 $39,657 $34,079 $70,922 $573,760 $912 260

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-85 Case 5 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 5A GAS CLEANUP & PIPING 5A.1 Sulfinol System $35,020 $0 $29,715 $0 $0 $64,735 $6,261 $0 $14,199 $85,194 $135 5A.2 Elemental Sulfur Plant $9,609 $1,915 $12,397 $0 $0 $23,921 $2,324 $0 $5,249 $31,494 $50 5A.3 Mercury Removal $976 $0 $743 $0 $0 $1,720 $166 $86 $394 $2,366 $4 5A.4 COS Hydrolysis $2,882 $0 $3,764 $0 $0 $6,646 $646 $0 $1,459 $8,751 $14 5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $1,613 $271 $153 $0 $0 $2,037 $193 $0 $446 $2,677 $4 5A.7 Fuel Gas Piping $0 $764 $535 $0 $0 $1,298 $120 $0 $284 $1,703 $3 5A.9 HGCU Foundations $0 $773 $499 $0 $0 $1,272 $117 $0 $417 $1,805 $3 SUBTOTAL 5A. $50,101 $3,724 $47,806 $0 $0 $101,630 $9,827 $86 $22,447 $133,990 $213 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5B. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $85,752 $0 $6,269 $0 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $184 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4 SUBTOTAL 6. $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $188 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $35,374 $0 $5,030 $0 $0 $40,404 $3,842 $0 $4,425 $48,670 $77 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,711 $1,220 $0 $0 $2,931 $257 $0 $638 $3,826 $6 7.4 Stack $3,337 $0 $1,254 $0 $0 $4,591 $440 $0 $503 $5,534 $9 7.9 HRSG,Duct & Stack Foundations $0 $669 $642 $0 $0 $1,311 $122 $0 $430 $1,863 $3 SUBTOTAL 7. $38,712 $2,379 $8,146 $0 $0 $49,237 $4,661 $0 $5,995 $59,893 $95 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $28,830 $0 $4,946 $0 $0 $33,776 $3,241 $0 $3,702 $40,718 $65 8.2 Turbine Plant Auxiliaries $200 $0 $459 $0 $0 $659 $64 $0 $72 $796 $1 8.3 Condenser & Auxiliaries $4,740 $0 $1,514 $0 $0 $6,254 $598 $0 $685 $7,537 $12 8.4 Steam Piping $5,506 $0 $3,873 $0 $0 $9,379 $806 $0 $2,546 $12,731 $20 8.9 TG Foundations $0 $993 $1,678 $0 $0 $2,671 $253 $0 $877 $3,801 $6 SUBTOTAL 8. $39,276 $993 $12,470 $0 $0 $52,739 $4,963 $0 $7,883 $65,584 $104 9 COOLING WATER SYSTEM 9.1 Cooling Towers $5,766 $0 $1,049 $0 $0 $6,815 $649 $0 $1,120 $8,584 $14 9.2 Circulating Water Pumps $1,500 $0 $99 $0 $0 $1,599 $135 $0 $260 $1,993 $3 9.3 Circ.Water System Auxiliaries $129 $0 $18 $0 $0 $148 $14 $0 $24 $186 $0 9.4 Circ.Water Piping $0 $5,400 $1,400 $0 $0 $6,800 $615 $0 $1,483 $8,897 $14 9.5 Make-up Water System $317 $0 $453 $0 $0 $769 $74 $0 $169 $1,012 $2 9.6 Component Cooling Water Sys $637 $762 $542 $0 $0 $1,942 $182 $0 $425 $2,549 $4 9.9 Circ.Water System Foundations $0 $1,977 $3,361 $0 $0 $5,339 $506 $0 $1,753 $7,598 $12 SUBTOTAL 9. $8,350 $8,140 $6,922 $0 $0 $23,411 $2,174 $0 $5,234 $30,819 $49 261

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-85 Case 5 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $15,534 $0 $7,661 $0 $0 $23,194 $2,229 $0 $2,542 $27,965 $44 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $527 $0 $573 $0 $0 $1,100 $107 $0 $181 $1,387 $2 10.7 Ash Transport & Feed Equipment $706 $0 $170 $0 $0 $877 $82 $0 $144 $1,102 $2 10.8 Misc. Ash Handling Equipment $1,091 $1,337 $399 $0 $0 $2,827 $269 $0 $464 $3,561 $6 10.9 Ash/Spent Sorbent Foundation $0 $47 $59 $0 $0 $105 $10 $0 $34 $149 $0 SUBTOTAL 10. $17,858 $1,384 $8,862 $0 $0 $28,104 $2,696 $0 $3,366 $34,166 $54 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $950 $0 $939 $0 $0 $1,889 $180 $0 $207 $2,276 $4 11.2 Station Service Equipment $3,667 $0 $330 $0 $0 $3,998 $369 $0 $437 $4,803 $8 11.3 Switchgear & Motor Control $6,780 $0 $1,233 $0 $0 $8,013 $743 $0 $1,313 $10,069 $16 11.4 Conduit & Cable Tray $0 $3,149 $10,390 $0 $0 $13,539 $1,309 $0 $3,712 $18,561 $30 11.5 Wire & Cable $0 $6,017 $3,954 $0 $0 $9,971 $724 $0 $2,674 $13,369 $21 11.6 Protective Equipment $0 $679 $2,471 $0 $0 $3,150 $308 $0 $519 $3,976 $6 11.7 Standby Equipment $234 $0 $228 $0 $0 $462 $44 $0 $76 $583 $1 11.8 Main Power Transformers $15,356 $0 $144 $0 $0 $15,500 $1,173 $0 $2,501 $19,174 $30 11.9 Electrical Foundations $0 $157 $411 $0 $0 $568 $54 $0 $187 $810 $1 SUBTOTAL 11. $26,986 $10,003 $20,101 $0 $0 $57,090 $4,905 $0 $11,625 $73,620 $117 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,019 $0 $680 $0 $0 $1,699 $161 $85 $292 $2,236 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $234 $0 $150 $0 $0 $384 $36 $19 $88 $528 $1 12.7 Computer & Accessories $5,433 $0 $174 $0 $0 $5,607 $515 $280 $640 $7,043 $11 12.8 Instrument Wiring & Tubing $0 $1,898 $3,880 $0 $0 $5,778 $490 $289 $1,639 $8,197 $13 12.9 Other I & C Equipment $3,632 $0 $1,764 $0 $0 $5,396 $508 $270 $926 $7,099 $11 SUBTOTAL 12. $10,318 $1,898 $6,648 $0 $0 $18,864 $1,710 $943 $3,585 $25,102 $40 262

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-85 Case 5 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $104 $2,230 $0 $0 $2,335 $232 $0 $770 $3,336 $5 13.2 Site Improvements $0 $1,856 $2,466 $0 $0 $4,322 $426 $0 $1,425 $6,173 $10 13.3 Site Facilities $3,326 $0 $3,509 $0 $0 $6,835 $674 $0 $2,253 $9,762 $16 SUBTOTAL 13. $3,326 $1,960 $8,206 $0 $0 $13,492 $1,332 $0 $4,447 $19,272 $31 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,428 $3,459 $0 $0 $5,887 $542 $0 $964 $7,394 $12 14.3 Administration Building $0 $841 $610 $0 $0 $1,452 $129 $0 $237 $1,818 $3 14.4 Circulation Water Pumphouse $0 $166 $88 $0 $0 $254 $22 $0 $41 $317 $1 14.5 Water Treatment Buildings $0 $471 $460 $0 $0 $931 $84 $0 $152 $1,168 $2 14.6 Machine Shop $0 $431 $295 $0 $0 $725 $64 $0 $118 $908 $1 14.7 Warehouse $0 $695 $449 $0 $0 $1,144 $101 $0 $187 $1,432 $2 14.8 Other Buildings & Structures $0 $416 $324 $0 $0 $741 $66 $0 $161 $968 $2 14.9 Waste Treating Building & Str. $0 $931 $1,779 $0 $0 $2,710 $253 $0 $592 $3,555 $6 SUBTOTAL 14. $0 $6,644 $7,614 $0 $0 $14,258 $1,298 $0 $2,544 $18,100 $29 TOTAL COST $744,432 $65,991 $255,695 $0 $0 $1,066,118 $98,407 $39,709 $190,092 $1,394,325 $2,217 Owner's Costs Preproduction Costs 6 Months All Labor $12,811 $20 1 Month Maintenance Materials $2,891 $5 1 Month Non-fuel Consumables $407 $1 1 Month Waste Disposal $260 $0 25% of 1 Months Fuel Cost at 100% CF $1,521 $2 2% of TPC $27,887 $44 Total $45,778 $73 Inventory Capital 60 day supply of fuel and consumables at 100% CF $12,790 $20 0.5% of TPC (spare parts) $6,972 $11 Total $19,762 $31 Initial Cost for Catalyst and Chemicals $963 $2 Land $900 $1 Other Owner's Costs $209,149 $333 Financing Costs $37,647 $60 Total Overnight Costs (TOC) $1,708,524 $2,716 TASC Multiplier (IOU, high-risk, 35 year) 1.140 Total As-Spent Cost (TASC) $1,947,717 $3,097 263

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-86 Case 5 Initial and Annual Operating and Maintenance Costs INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 5 - Shell 600MW IGCC w/o CO2 Heat Rate-net (Btu/kWh): 8,099 MWe-net: 629 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant Skilled Operator 2.0 2.0 Operator 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 3.0 3.0 TOTAL-O.J.'s 15.0 15.0 Annual Cost Annual Unit Cost

$ $/kW-net Annual Operating Labor Cost $5,918,913 $9.410 Maintenance Labor Cost $14,578,930 $23.179 Administrative & Support Labor $5,124,461 $8.147 Property Taxes and Insurance $27,886,508 $44.336 TOTAL FIXED OPERATING COSTS $53,508,812 $85.072 VARIABLE OPERATING COSTS

$/kWh-net Maintenance Material Cost $27,756,840 $0.00630 Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water (/1000 gallons) 0 2,982 1.08 $0 $941,938 $0.00021 Chemicals MU & WT Chem. (lbs) 0 17,767 0.17 $0 $897,887 $0.00020 Carbon (Mercury Removal) (lb) 69,345 95 1.05 $72,824 $29,130 $0.00001 COS Catalyst (m3) 262 0.18 2,397.36 $627,613 $125,523 $0.00003 Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 $0.00000 Sulfinol Solution (gal) 26,146 629 10.05 $262,733 $1,846,503 $0.00042 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 1.82 131.27 $0 $69,945 $0.00002 Subtotal Chemicals $963,170 $2,968,988 $0.00067 Other Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 $0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $0 $0.00000 Waste Disposal Spent Mercury Catalyst (lb.) 0 95 0.42 $0 $11,569 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 525 16.23 $0 $2,486,313 $0.00056 Subtotal-Waste Disposal $0 $2,497,882 $0.00057 By-products & Emissions Sulfur (ton) 0 131 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000 TOTAL VARIABLE OPERATING COSTS $963,170 $34,165,649 $0.00775 Fuel (ton) 0 5,240 38.18 $0 $58,422,569 $0.01325 264

Cost and Performance Baseline for Fossil Energy Plants 3.4.8 Case 6 - Shell IGCC Power Plant with CO2 Capture This case is configured to produce electric power with CO2 capture. The plant configuration is the same as Case 5, namely two Shell gasifier trains, two advanced F class turbines, two HRSGs and one steam turbine. The gross power output is constrained by the capacity of the two CTs, and since the CO2 capture and compression process increases the auxiliary load on the plant, the net output is significantly reduced relative to Case 5 (497 MW versus 629 MW).

The process description for Case 6 is similar to Case 5 with several notable exceptions to accommodate CO2 capture. A BFD and stream tables for Case 6 are shown in Exhibit 3-87 and Exhibit 3-88, respectively. Instead of repeating the entire process description, only differences from Case 5 are reported here.

Coal Preparation and Feed Systems No differences from Case 5.

Gasification The gasification process is the same as Case 5 with the following exceptions:

Total coal feed (as-received) to the two gasifiers is 5,065 tonnes/day (5,583 TPD)

(stream 9)

The ASU provides 3,852 tonnes/day (4,246 TPD) of 95 mol% oxygen to the gasifier and Claus plant (streams 5 and 3)

Raw Gas Cooling/Particulate Removal After the raw syngas is cooled to approximately 1,093°C (2,000°F) by the syngas quench recycle, syngas is further cooled to 899°C (1,650°F) by raising HP steam at 13.8 MPa (2,000 psia). A water quench follows to cool the raw syngas from 899°C (1,650°F) to 399°C (750°F) while providing a portion of the water required for WGS. The syngas is then cooled to 316°C (600°F) by raising steam, which is used in the SGS unit. After particulate filtration, the syngas is cooled to 232°C (450°F) by raising IP steam at 0.4 MPa (65 psia) before proceeding to the scrubber.

Syngas Scrubber/Sour Water Stripper Syngas exits the scrubber at 191°C (376°F).

Sour Gas Shift (SGS)

The SGS process was described in Section 3.1.3. In Case 6 the syngas after the scrubber is reheated to 197°C (386°F) and then steam (stream 14) is added to adjust the H2O:CO molar ratio to approximately 1.8:1 prior to the first SGS reactor. The hot syngas exiting the first stage of SGS is used to preheat water used to humidify clean syngas prior to entering the CT. One more stage of SGS (for a total of two) results in 97.8 percent overall conversion of the CO to CO2.

The warm syngas from the second stage of SGS is cooled to 248°C (478°F) by preheating the syngas prior to the first stage of SGS. The SGS catalyst also serves to hydrolyze COS thus eliminating the need for a separate COS hydrolysis reactor. Following the second stage of SGS, the syngas is further cooled to 35°C (95°F) prior to the mercury removal beds.

265

Cost and Performance Baseline for Fossil Energy Plants Mercury Removal and AGR Mercury removal is the same as in Case 5.

The AGR process in Case 6 is a two stage Selexol process where H2S is removed in the first stage and CO2 in the second stage of absorption. The process results in three product streams, the clean syngas (stream 18), a CO2-rich stream and an acid gas feed to the Claus plant (stream 22). The acid gas contains 34 percent H2S and 51 percent CO2 with the balance primarily H2.

The CO2-rich stream is discussed further in the CO2 compression section.

CO2 Compression and Dehydration CO2 from the AGR process is flashed at three pressure levels to separate CO2 and decrease H2 losses to the CO2 product pipeline. The HP CO2 stream is flashed at 2.0 MPa (289.7 psia),

compressed, and recycled back to the CO2 absorber. The MP CO2 stream is flashed at 1.0 MPa (149.7 psia). The LP CO2 stream is flashed at 0.1 MPa (16.7 psia), compressed to 1.0 MPa (149.5 psia), and combined with the MP CO2 stream. The combined stream is compressed from 1.0 MPa (149.5 psia) to a SC condition at 15.3 MPa (2215 psia) using a multiple-stage, intercooled compressor. During compression, the CO2 stream is dehydrated to a dewpoint of

-40ºC (-40°F) with triethylene glycol. The raw CO2 stream from the Selexol process contains over 99 percent CO2. The CO2 (stream 21) is transported to the plant fence line and is sequestration ready. CO2 TS&M costs were estimated using the methodology described in Section 2.7.

Claus Unit The Claus plant is the same as Case 5 with the following exceptions:

5,277 kg/hr (11,634 lb/hr) of sulfur (stream 23) are produced

The waste heat boiler generates 13,697 kg/hr (30,197 lb/hr) of 3.0 MPa (430 psia) steam, which provides all of the Claus plant process needs and provides some additional steam to the medium pressure steam header.

Power Block Clean syngas from the AGR plant is combined with a small amount of clean gas from the CO2 compression process (stream 18) and partially humidified because the nitrogen available from the ASU is insufficient to provide adequate dilution. The moisturized syngas is reheated to 193°C (380°F) using HP BFW, diluted with nitrogen (stream 4), and then enters the CT burner.

The exhaust gas (stream 27) exits the CT at 562°C (1,043°F) and enters the HRSG where additional heat is recovered. The FG exits the HRSG at 132°C (270°F) (stream 28) and is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced commercially available steam turbine using a 12.4 MPa/534°C/534°C (1800 psig/993°F/993°F) steam cycle. There is no integration between the CT and the ASU in this case.

Air Separation Unit (ASU)

The same elevated pressure ASU is used as in Case 5 and produces 3,852 tonnes/day (4,246 TPD) of 95 mol% oxygen and 12,290 tonnes/day (13,547 TPD) of nitrogen. There is no integration between the ASU and the CT.

266

Cost and Performance Baseline for Fossil Energy Plants Balance of Plant Balance of plant items were covered in Sections 3.1.9, 3.1.10 and 3.1.11.

267

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-87 Case 6 Block Flow Diagram, Shell IGCC with CO2 Capture 268

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-88 Case 6 Stream Table, Shell IGCC with CO2 Capture 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 V-L Mole Fraction Ar 0.0092 0.0230 0.0318 0.0023 0.0318 0.0000 0.0023 0.0096 0.0000 0.0000 0.0000 0.0085 0.0061 0.0000 0.0047 CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0000 0.0000 0.0005 0.0004 0.0000 0.0003 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0130 0.0000 0.0000 0.0000 0.5187 0.3712 0.0000 0.2873 CO2 0.0003 0.0079 0.0000 0.0000 0.0000 0.0000 0.0000 0.0455 0.0000 0.0000 0.0000 0.0126 0.0090 0.0000 0.0070 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0004 0.0000 0.0003 H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.8727 0.0000 0.8090 0.0000 0.2691 0.1926 0.0000 0.1491 H2O 0.0099 0.1984 0.0000 0.0003 0.0000 1.0000 0.0004 0.0001 0.0000 0.0935 0.0000 0.1278 0.3758 1.0000 0.5172 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0030 0.0000 0.0008 0.0006 0.0000 0.0001 H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0052 0.0000 0.0040 N2 0.7732 0.5759 0.0178 0.9919 0.0178 0.0000 0.9919 0.0585 0.0000 0.0163 0.0000 0.0507 0.0363 0.0000 0.0281 NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0033 0.0024 0.0000 0.0019 O2 0.2074 0.1948 0.9504 0.0054 0.9504 0.0000 0.0054 0.0000 0.0000 0.0782 0.0000 0.0000 0.0000 0.0000 0.0000 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 V-L Flowrate (kgmol/hr) 24,277 1,004 102 17,310 4,886 1,130 940 308 0 5,809 0 26,493 29,249 11,003 37,783 V-L Flowrate (kg/hr) 700,548 27,328 3,289 485,713 157,225 20,363 26,368 1,900 0 37,081 0 531,672 569,894 198,213 723,426 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 211,040 160,281 21,137 0 0 0 0 Temperature (°C) 15 20 32 93 32 343 32 35 15 16 1,427 1,082 232 288 217 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 5.10 5.62 3.59 0.10 5.79 4.24 4.24 4.03 5.52 3.96 Enthalpy (kJ/kg)A 30.23 36.90 26.67 92.51 26.67 3,063.97 20.78 163.14 --- 3,549.69 --- 2,043.24 1,217.35 2,918.18 1,541.02 Density (kg/m3) 1.2 1.5 11.0 24.4 11.0 20.1 62.8 8.5 --- 16.5 --- 7.5 19.1 25.6 19.5 V-L Molecular Weight 28.857 27.206 32.181 28.060 32.181 18.015 28.060 6.159 --- 6.383 --- 20.069 19.484 18.015 19.147 V-L Flowrate (lbmol/hr) 53,521 2,215 225 38,162 10,771 2,492 2,072 680 0 12,807 0 58,407 64,482 24,256 83,298 V-L Flowrate (lb/hr) 1,544,445 60,249 7,250 1,070,813 346,622 44,894 58,132 4,188 0 81,749 0 1,172,137 1,256,401 436,986 1,594,881 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 465,264 353,359 46,599 0 0 0 0 Temperature (°F) 59 68 90 199 90 650 90 94 59 60 2,600 1,980 450 550 422 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 740.0 815.0 520.0 14.7 840.0 615.0 615.0 585.0 800.0 575.0 Enthalpy (Btu/lb)A 13.0 15.9 11.5 39.8 11.5 1,317.3 8.9 70.1 --- 1,526.1 --- 878.4 523.4 1,254.6 662.5 Density (lb/ft 3) 0.076 0.097 0.687 1.521 0.687 1.257 3.918 0.531 --- 1.029 --- 0.468 1.190 1.597 1.218 A - Reference conditions are 32.02 F & 0.089 PSIA 269

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-88 Case 6 Stream Table (Continued) 16 17 18 19 20 21 22 23 24 25 26 27 28 29 V-L Mole Fraction Ar 0.0062 0.0062 0.0096 0.0086 0.0086 0.0002 0.0017 0.0000 0.0065 0.0102 0.0092 0.0088 0.0088 0.0000 CH4 0.0004 0.0004 0.0006 0.0005 0.0005 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.0084 0.0084 0.0130 0.0116 0.0116 0.0002 0.0025 0.0000 0.1143 0.0060 0.0000 0.0000 0.0000 0.0000 CO2 0.3776 0.3810 0.0455 0.0407 0.0407 0.9944 0.5141 0.0000 0.2866 0.6257 0.0003 0.0080 0.0080 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 H2 0.5633 0.5593 0.8727 0.7819 0.7819 0.0050 0.1068 0.0000 0.0659 0.2694 0.0000 0.0000 0.0000 0.0000 H2O 0.0016 0.0016 0.0001 0.1041 0.1041 0.0000 0.0300 0.0000 0.4715 0.0017 0.0099 0.1374 0.1374 1.0000 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2S 0.0057 0.0057 0.0000 0.0000 0.0000 0.0000 0.3398 0.0000 0.0014 0.0057 0.0000 0.0000 0.0000 0.0000 N2 0.0368 0.0374 0.0585 0.0524 0.0524 0.0002 0.0047 0.0000 0.0516 0.0813 0.7732 0.7397 0.7397 0.0000 NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1060 0.1060 0.0000 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0018 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 V-L Flowrate (kgmol/hr) 28,837 29,237 18,312 20,438 20,438 10,099 488 0 630 400 110,253 139,892 139,892 28,855 V-L Flowrate (kg/hr) 562,223 574,690 112,786 151,092 151,092 442,270 17,202 0 16,585 12,466 3,181,557 3,818,362 3,818,362 519,836 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 5,277 0 0 0 0 0 0 Temperature (°C) 35 35 35 137 193 51 48 178 232 38 15 562 132 534 Pressure (MPa, abs) 3.62 3.6 3.585 3.206 3.172 15.270 0.163 0.119 0.085 5.51 0.101 0.105 0.105 12.512 Enthalpy (kJ/kg)A 45.33 44.5 163.144 1,181.236 1,416.715 -161.704 85.006 --- 1,114.498 8.30 30.227 866.140 371.288 3,431.999 Density (kg/m3) 28.1 28.1 8.5 6.9 6.0 639.8 2.2 5,279.4 0.5 74.4 1.2 0.4 0.8 36.8 V-L Molecular Weight 19.496 20 6.159 7.393 7.393 43.792 35.245 --- 26.336 31.160 28.857 27.295 27.295 18.015 V-L Flowrate (lbmol/hr) 63,576 64,458 40,371 45,059 45,059 22,265 1,076 0 1,388 882 243,066 308,408 308,408 63,615 V-L Flowrate (lb/hr) 1,239,491 1,266,974 248,650 333,100 333,100 975,038 37,925 0 36,563 27,484 7,014,133 8,418,047 8,418,047 1,146,042 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 11,634 0 0 0 0 0 0 Temperature (°F) 95 94 94 278 380 124 119 352 450 100 59 1,043 270 993 Pressure (psia) 525.0 520.0 520.0 465.0 460.0 2,214.7 23.7 17.3 12.3 799.5 14.7 15.2 15.2 1,814.7 Enthalpy (Btu/lb)A 19.5 19.1 70.1 507.8 609.1 -69.5 36.5 --- 479.1 3.6 13.0 372.4 159.6 1,475.5 Density (lb/ft 3) 1.753 2 0.531 0.431 0.374 39.942 0.135 329.584 0.033 4.646 0.076 0.026 0.053 2.295 270

Cost and Performance Baseline for Fossil Energy Plants 3.4.9 Case 6 Performance Results The Case 6 modeling assumptions were presented previously in Section 3.4.3.

The plant produces a net output of 497 MWe at a net plant efficiency of 31.2 percent (HHV basis). Overall performance for the plant is summarized in Exhibit 3-89, which includes auxiliary power requirements. The ASU accounts for approximately 58 percent of the auxiliary load between the main air compressor, the nitrogen compressor, the oxygen compressor and ASU auxiliaries. The two-stage Selexol process and CO2 compression account for an additional 28 percent of the auxiliary power load. The BFW and CWS (CWPs and cooling tower fan) comprise approximately 4 percent of the load, leaving 10 percent of the auxiliary load for all other systems.

271

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-89 Case 6 Plant Performance Summary POWER

SUMMARY

(Gross Power at Generator Terminals, kWe)

Gas Turbine Power 464,000 Sweet Gas Expander Power 0 Steam Turbine Power 209,400 TOTAL POWER, kWe 673,400 AUXILIARY LOAD

SUMMARY

, kWe Coal Handling 460 Coal Milling 2,170 Slag Handling 550 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 59,740 Oxygen Compressor 9,460 Nitrogen Compressors 32,910 CO2 Compressor 30,210 Boiler Feedwater Pumps 3,500 Condensate Pump 280 Quench Water Pump 610 Syngas Recycle Compressor 790 Circulating Water Pump 4,370 Ground Water Pumps 510 Cooling Tower Fans 2,260 Scrubber Pumps 360 Acid Gas Removal 18,650 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 250 Claus Plant TG Recycle Compressor 1,830 Miscellaneous Balance of Plant2 3,000 Transformer Losses 2,530 TOTAL AUXILIARIES, kWe 176,540 NET POWER, kWe 496,860 Net Plant Efficiency, % (HHV) 31.2 Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,526 (10,924)

CONDENSER COOLING DUTY 106 kJ/hr (106 Btu/hr) 1,340 (1,270)

CONSUMABLES As-Received Coal Feed, kg/hr (lb/hr) 211,040 (465,264)

Thermal Input1, kWt 1,590,722 Raw Water Withdrawal, m3/min (gpm) 21.3 (5,633)

Raw Water Consumption, m3/min (gpm) 17.5 (4,616) 1 - HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 2 - Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads 272

Cost and Performance Baseline for Fossil Energy Plants Environmental Performance The environmental targets for emissions of Hg, NOx, SO2, CO2, and PM were presented in Section 2.4. A summary of the plant air emissions for Case 6 is presented in Exhibit 3-90.

Exhibit 3-90 Case 6 Air Emissions Tonne/year kg/GJ kg/MWh (ton/year)

(lb/106 Btu) (lb/MWh) 80% CF SO2 0.001 (0.002) 37 (40) 0.008 (.02)

NOx 0.021 (0.049) 847 (934) 0.180 (.396)

Particulates 0.003 (0.0071) 123 (135) 0.026 (.057)

Hg 2.46E-7 (5.71E-7) 0.010 (0.011) 2.09E-6 (4.61E-6)

CO2 8.6 (20.0) 344,507 (379,754) 73 (161)

CO21 99 (218) 1 CO2 emissions based on net power instead of gross power The low level of SO2 emissions is achieved by capture of the sulfur in the gas by the two-stage Selexol AGR process. The CO2 capture target results in the sulfur compounds being removed to a greater extent than required in the environmental targets of Section 2.4. The clean syngas exiting the AGR process has a sulfur concentration of approximately 4 ppmv. This results in a concentration in the HRSG FG of less than 1 ppmv. The H2S-rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is compressed and recycled back to the AGR where most of the remaining sulfur is removed.

NOx emissions are limited by the use of nitrogen dilution and humidification to 15 ppmvd (as NO2 @ 15 percent O2). Ammonia in the syngas is removed with process condensate prior to the low-temperature AGR process and subsequently destroyed in the Claus plant burner. This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only.

Ninety five percent of mercury is captured from the syngas by an activated carbon bed.

Ninety five percent of the CO2 from the syngas is captured in the AGR system and compressed for sequestration. Because not all CO is converted to CO2 in the shift reactors, the overall CO2 removal is 90.1 percent.

The carbon balance for the plant is shown in Exhibit 3-91. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not used in the carbon capture equation below, but it is not neglected in the balance since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag, CO2 in the stack gas, coal dryer vent gas, ASU vent gas and the captured CO2 product. The carbon capture efficiency is defined as the amount of carbon in the CO2 product stream relative to the amount of carbon in the coal less carbon contained in the slag, represented by the following fraction:

273

Cost and Performance Baseline for Fossil Energy Plants (Carbon in Product for Sequestration)/[(Carbon in the Coal)-(Carbon in Slag)] or 265,992/(296,581-1,483)

100 or 90.1 percent Exhibit 3-91 Case 6 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 134,527 (296,581) Slag 673 (1,483)

Air (CO2) 532 (1,173) Stack Gas 13,416 (29,578)

ASU Vent 95 (210)

CO2 Product 120,652 (265,992)

Coal Dryer 223 (491)

Stack Gas Total 135,059 (297,754) Total 135,059 (297,754)

Exhibit 3-92 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur emitted in the stack gas and sulfur from the tail gas unit that is vented through the coal dryer. Sulfur in the slag is considered negligible.

Exhibit 3-92 Case 6 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal Elemental 5,290 (11,661) 5,277 (11,634)

Sulfur Stack Gas 3 (6)

CO2 Product 10 (22)

Total 5,290 (11,661) Total 5,290 (11,661)

Exhibit 3-93 shows the overall water balance for the plant. The exhibit is presented in an identical manner as for previous cases.

274

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-93 Case 6 Water Balance Process Water Internal Raw Water Water Raw Water Demand, Recycle, Withdrawal, Water Use Discharge, Consumption, m3/min m3/min m3/min m3/min m3/min (gpm)

(gpm) (gpm) (gpm)

(gpm)

Slag Handling 0.46 (121) 0.46 (121) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 3.2 (836) 2.2 (587) 0.9 (250) 0.0 (0) 0.9 (250)

Humidifier 0.7 (177) 0.7 (177) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7) -0.03 (-7)

Condenser Makeup 3.8 (1,012) 0.0 (0) 3.8 (1,012) 0.0 (0) 3.8 (1,012)

Gasifier Steam 0.3 (90) 0.3 (90)

Shift Steam 3.3 (874) 3.3 (874)

GT Steam Dilution 0.18 (48) 0.18 (48)

BFW Makeup Cooling Tower 17.0 (4,490) 0.45 (119) 16.5 (4,371) 3.8 (1,010) 12.7 (3,361)

BFW Blowdown 0.18 (48) -0.18 (-48)

SWS Blowdown 0.27 (71) -0.27 (-71)

SWS Excess Water Humidifier Tower Blowdown Total 25.1 (6,637) 3.8 (1,004) 21.3 (5,633) 3.8 (1,017) 17.5 (4,616)

Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-94 through Exhibit 3-96:

Coal gasification and ASU

Syngas cleanup including sulfur recovery and tail gas recycle

Combined cycle power generation, steam, and FW An overall plant energy balance is provided in tabular form in Exhibit 3-97. The power out is the combined CT and steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 3-89) is calculated by multiplying the power out by a combined generator efficiency of 98.4 percent.

275

Cost and Performance Baseline for Fossil Energy Plants This page intentionally left blank 276

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-94 Case 6 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic LEGEND Ambient Air 60,249 W Air 1

67.9 T 1,544,445 W Coal/Char/

16.4 P 59.0 T 14.7 P 15.9 H Slurry/Slag 13.0 H Intercooled ASU N2 to GT Combustor Nitrogen Air Compressor VENT 4

2 Oxygen 199.0 T 687,451 W 100.0 T Intercooled 384.0 P 385.0 T 189.5 P Nitrogen Compressor 39.8 H 384.0 P Sour Gas Boost Compressor 18.0 H 87.2 H Elevated 989,843 W Sour Water 5 Pressure 90.0 T N2 to GT Combustor ASU 56.4 P 346,622 W 14.2 H 139,103 W Steam 90.0 T 50.0 T 125.0 P 182.0 P 383,362 W 11.5 H 2.9 H N2 Compressor 385.0 T Synthesis Gas 469.0 P 87.0 H Water 3 To Claus Plant Intercooled 7,250 W 333,980 W Flue Gas/

Oxygen Compressor 90.0 T 519.9 T 450.0 T 625.0 P 585.0 P Combustion 125.0 P 11.5 H 551.7 H 523.4 H Products 346,622 W Recycle 241.2 T Compressor P ABSOLUTE PRESSURE, PSIA 940.0 P F TEMPERATURE, °F 58,132 W 40.8 H 12 W FLOWRATE, LB/HR 7 386.6 T Duct Cooler Syngas H ENTHALPY, BTU/LB 1,172,137 W 815.0 P Steam Cooler MWE POWER, MEGAWATTS ELECTRICAL Incinerator Exhaust 1,979.6 T 86.8 H Saturated Steam 44,894 W 615.0 P 650.0 T 878.4 H To HRSG NOTES:

740.0 P 97,783 W 1,317.3 H 290.0 T 1. ENTHALPY REFERENCE POINT IS NATURAL STATE 14.4 P AT 32 °F AND 0.08865 PSIA 6 Steam Quench Water Generation 418,244 W 420.0 T Shell Dry Coal 1,200.0 P Milled Coal Coal Gasifier 9 Drying 10 Coal 387.9 H PLANT PERFORMANCE

SUMMARY

Feeding HP Incinerator 465,264 W 435,108 W BFW 60.0 T Shift Steam Saturated Steam 59.0 T 14.7 P 840.0 P For WGF Reactors To HRSG GROSS PLANT POWER: 673 MWE AUXILIARY LOAD: 177 MWE 1,526.1 H NET PLANT POWER: 497 MWE NET PLANT EFFICIENCY, HHV: 31.2%

8 Candle NET PLANT HEAT RATE: 10,924 BTU/KWE 63,439 W Filter 4,188 W Cyclone 59.0 T Raw Syngas 94.4 T 14.7 P to Scrubber 520.0 P Syngas 13.4 H 70.1 H Quench 13 DOE/NETL Cooler 1,590,381 W 600.0 T Incinerator Air Syngas Slip Stream 1,650.0 T 605.0 P 750.0 T 595.0 P 1,256,401 W DUAL TRAIN IGCC PLANT 739.8 H 605.0 P 585.2 H 450.0 T CASE 6 647.4 H 585.0 P 523.4 H IP HEAT AND MATERIAL FLOW DIAGRAM HP BFW BFW BITUMINOUS BASELINE STUDY CASE 6 Slag SHELL GASIFIER 11 46,599 W ASU, GASIFICATION, AND GAS COOLING 2,600.0 T Slag 615.0 P DWG. NO. PAGES Removal BB-HMB-CS-6-PG-1 1 OF 3 277

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-95 Case 6 Syngas Cleanup Heat and Mass Balance Schematic Treated Syngas LEGEND Humidification 19 20 Humidified Fuel Gas 248,650 W Acid Gas 94.4 T 520.0 P Air 70.1 H Claus Plant Carbon Dioxide 18 Catalytic Coal/Char/

37,925 W Reactor Slurry/Slag High Low Slip Stream Beds 8 119.0 T Temperature Temperature to Coal Dryer 23.7 P Shift #1 Shift #2 36.5 H Hydrogen 1,594,881 W Furnace 422.2 T 22 Tail Nitrogen 575.0 P Gas 662.5 H 15 Clean Gas Oxygen Sour Gas 436,986 W Shift Steam 1,594,881 W Sour Water 550.0 T Acid Gas 14 484.5 T 1,266,974 W 800.0 P 565.0 P 94.4 T Sulfur 1,254.1 H 11,634 W 36,563 W 385.6 T Fuel Gas 423.7 H 520.0 P 23 352.5 T 450.0 T 24 Synthesis Gas 575.0 P Humidification 19.1 H 17.3 P 12.3 P 439.1 H 17 479.1 H Tailgas Water Mercury Two-Stage Sulfur WGS and Steam Removal Selexol CO2 Hydrogenation 477.9 T Cycle Steam From And Tail Gas 1,157,895 W 560.0 P ASU 7,250 W Cooling 375.6 T 420.7 H 580.0 P 1,239,491 W 450.0 T P ABSOLUTE PRESSURE, PSIA Tailgas to AGR 124.5 P F TEMPERATURE, °F 435.0 H 94.8 T 16 525.0 P 25 91.9 H W FLOWRATE, LB/HR 19.5 H 27,484 W H ENTHALPY, BTU/LB Syngas 100.0 T MWE POWER, MEGAWATTS ELECTRICAL Syngas Coolers Scrubber 799.5 P Knock 3.6 H Multistage Out 975,038 W Intercooled CO2 NOTES:

Drum CO2 Product 124.0 T Compressor 2,214.7 P Raw Syngas 21 13 3,022 W 1,256,401 W 227.6 T Interstage Knockout 450.0 T Sour 65.0 P 585.0 P Drum 370.2 H 523.4 H PLANT PERFORMANCE

SUMMARY

Sour Stripper GROSS PLANT POWER: 673 MWE Tailgas Recycle AUXILIARY LOAD: 177 MWE Compressor NET PLANT POWER: 497 MWE Makeup Water NET PLANT EFFICIENCY, HHV: 31.2%

NET PLANT HEAT RATE: 10,924 BTU/KWE Reboiler Knock Out DOE/NETL 9,080 W 114.5 T 10.6 P DUAL TRAIN IGCC PLANT 40.3 H CASE 6 To Water Treatment HEAT AND MATERIAL FLOW DIAGRAM BITUMINOUS BASELINE STUDY CASE 6 SHELL GASIFIER GAS CLEANUP SYSTEM DWG. NO. PAGES BB-HMB-CS-6-PG-2 2 OF 3 278

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-96 Case 6 Combined Cycle Power Generation Heat and Mass Balance Schematic LEGEND Air HP& IP BFW to Raw Gas Coolers LP 217,834 W Process Header Flue Gas/

298.0 T Combustion HP & IP Saturated Steam to HRSG Superheater 65.0 P Products 1,178.6 H Nitrogen 8,418,047 W 8,418,047 W Oxygen 1,043.2 T 270.0 T 15.2 P 15.2 P 372.4 H 159.6 H Steam 27 HRSG 28 LP Flash Tops Stack Synthesis Gas 8,328 W MP Flash Bottoms Water 298.0 T From Gasifier 1,070,813 W 65.0 P Island Preheating 199.0 T 1,178.6 H Nitrogen Dilution 1,911,334 W 384.0 P 235.0 T 39.8 H Deaerator 4 1,146,042 W 105.0 P 333,100 W 993.2 T 203.3 H 1,814.7 P 29 1,169,363 W 380.0 T 278.8 T Humidified Fuel Gas 460.0 P 1,475.5 H 2,250.7 P LP BFW P ABSOLUTE PRESSURE, PSIA 609.1 H 251.9 H 20 F TEMPERATURE, °F W FLOWRATE, LB/HR Blowdown H ENTHALPY, BTU/LB 23,308 W Flash LP Pump MWE POWER, MEGAWATTS ELECTRICAL 585.0 T To Claus 2,000.7 P To WWT 592.9 H HP Pump NOTES:

IP BFW IP Pump 1,393,094 W 439.8 T Compressor Expander 65.0 P 1,252.2 H Generator HP IP LP Turbine Turbine Steam Turbine Advanced F-Class Turbine Gas Turbine Generator Intake IP Extraction Steam PLANT PERFORMANCE

SUMMARY

to 250 PSIA Header 26,345 W GROSS PLANT POWER: 673 MWE 26 851.0 T AUXILIARY LOAD: 177 MWE 280.0 P NET PLANT POWER: 497 MWE 1,448.2 H NET PLANT EFFICIENCY, HHV: 31.2%

Ambient Air Make-up NET PLANT HEAT RATE: 10,924 BTU/KWE CONDENSER 506,076 W 7,014,133 W Steam Seal Regulator 59.0 T 59.0 T 14.7 P 14.7 P HOT WELL 27.1 H 13.0 H DOE/NETL 1,911,334 W 101.1 T DUAL TRAIN IGCC PLANT To Gasifier 1.0 P CASE 6 69.1 H 1,400 W 1,400 W HEAT AND MATERIAL FLOW DIAGRAM 614.2 T Condensate 212.0 T 65.0 P Pump 14.7 P 1,338.3 H 179.9 H BITUMINOUS BASELINE STUDY Gland CASE 6 1,911,334 W Steam SHELL GASIFIER 102.8 T 120.0 P Condenser POWER BLOCK SYSTEM Condensate to Gasification Island 71.1 H DWG. NO. PAGES BB-HMB-CS-6-PG-3 3 OF 3 279

Cost and Performance Baseline for Fossil Energy Plants This page intentionally left blank 280

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-97 Case 6 Overall Energy Balance (0°C [32°F] Reference)

Sensible +

HHV Power Total Latent Heat In GJ/hr (MMBtu/hr)

Coal 5,727 (5,428) 4.8 (4.5) 5,731 (5,432)

ASU Air 21.2 (20.1) 21 (20)

GT Air 96.2 (91.2) 96 (91)

Water 80.2 (76.0) 80 (76)

Auxiliary Power 636 (602) 636 (602)

TOTAL 5,727 (5,428) 202.3 (191.7) 636 (602) 6,564 (6,222)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 1.0 (1.0) 1 (1)

Slag 22 (21) 35.7 (33.8) 58 (55)

Sulfur 49 (46) 0.6 (0.6) 50 (47)

CO2 -71.5 (-67.8) -72 (-68)

Cooling Tower 28.4 (26.9) 28 (27)

Blowdown HRSG Flue Gas 1,418 (1,344) 1,418 (1,344)

Condenser 1,335 (1,265) 1,335 (1,265)

Non-Condenser Cooling Tower 687 (651) 687 (651)

Loads*

Process Losses** 635 (602) 635 (602)

Power 2,424 (2,298) 2,424 (2,298)

TOTAL 71 (67) 4,069 (3,857) 2,424 (2,298) 6,564 (6,222)

Includes ASU compressor intercoolers, CO2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection) and extraction air cooler.

- Calculated by difference to close the energy balance.

281

Cost and Performance Baseline for Fossil Energy Plants 3.4.10 Case 6 - Major Equipment List Major equipment items for the Shell gasifier with CO2 capture are shown in the following tables.

The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section 3.4.11. In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 COAL HANDLING Equipment Operating Description Type Design Condition Spares No. Qty.

Bottom Trestle Dumper and 1 N/A 181 tonne (200 ton) 2 0 Receiving Hoppers 2 Feeder Belt 572 tonne/hr (630 tph) 2 0 3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0 4 Transfer Tower No. 1 Enclosed N/A 1 0 5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0 As-Received Coal Sampling 6 Two-stage N/A 1 0 System 7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0 8 Reclaim Hopper N/A 45 tonne (50 ton) 2 1 9 Feeder Vibratory 172 tonne/hr (190 tph) 2 1 10 Conveyor No. 3 Belt w/ tripper 345 tonne/hr (380 tph) 1 0 11 Crusher Tower N/A N/A 1 0 12 Coal Surge Bin w/ Vent Filter Dual outlet 172 tonne (190 ton) 2 0 Impactor 8 cm x 0 - 3 cm x 0 13 Crusher 2 0 reduction (3" x 0 1/4" x 0)

As-Fired Coal Sampling 14 Swing hammer N/A 1 1 System 15 Conveyor No. 4 Belt w/tripper 345 tonne/hr (380 tph) 1 0 16 Transfer Tower No. 2 Enclosed N/A 1 0 17 Conveyor No. 5 Belt w/ tripper 345 tonne/hr (380 tph) 1 0 Coal Silo w/ Vent Filter and 18 Field erected 816 tonne (900 ton) 3 0 Slide Gates 282

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 2 COAL PREPARATION AND FEED Equipment Operating Description Type Design Condition Spares No. Qty.

1 Feeder Vibratory 82 tonne/hr (90 tph) 3 0 2 Conveyor No. 6 Belt w/tripper 236 tonne/hr (260 tph) 1 0 3 Roller Mill Feed Hopper Dual Outlet 463 tonne (510 ton) 1 0 4 Weigh Feeder Belt 118 tonne/hr (130 tph) 2 0 5 Coal Dryer and Pulverizer Rotary 118 tonne/hr (130 tph) 2 0 6 Coal Dryer Feed Hopper Vertical Hopper 236 tonne (260 ton) 2 0 283

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment Operating Description Type Design Condition Spares No. Qty.

Demineralized Water Vertical, cylindrical, 1 987,992 liters (261,000 gal) 2 0 Storage Tank outdoor 7,987 lpm @ 91 m H2O 2 Condensate Pumps Vertical canned 2 1 (2,110 gpm @ 300 ft H2O)

Deaerator (integral w/

3 Horizontal spray type 551,115 kg/hr (1,215,000 lb/hr) 2 0 HRSG)

Intermediate Pressure Horizontal centrifugal, 7,987 lpm @ 27 m H2O 4 2 1 Feedwater Pump single stage (2,110 gpm @ 90 ft H2O)

HP water: 5,072 lpm @ 1,859 m High Pressure Barrel type, multi-stage, 5 H2O (1,340 gpm @ 6,100 ft 2 1 Feedwater Pump No. 1 centrifugal H2O)

High Pressure Barrel type, multi-stage, IP water: 1,211 lpm @ 223 m 6 2 1 Feedwater Pump No. 2 centrifugal H2O (320 gpm @ 730 ft H2O)

Shop fabricated, water 18,144 kg/hr, 2.8 MPa, 343°C 7 Auxiliary Boiler 1 0 tube (40,000 lb/hr, 400 psig, 650°F)

Service Air 28 m3/min @ 0.7 MPa 8 Flooded Screw 2 1 Compressors (1,000 scfm @ 100 psig) 9 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1 Closed Cylce Cooling 10 Plate and frame 393 GJ/hr (372 MMBtu/hr) each 2 0 Heat Exchangers Closed Cycle Cooling 140,817 lpm @ 21 m H2O 11 Horizontal centrifugal 2 1 Water Pumps (37,200 gpm @ 70 ft H2O)

Engine-Driven Fire Vertical turbine, diesel 3,785 lpm @ 107 m H2O 12 1 1 Pump engine (1,000 gpm @ 350 ft H2O)

Fire Service Booster Two-stage horizontal 2,650 lpm @ 76 m H2O 13 1 1 Pump centrifugal (700 gpm @ 250 ft H2O)

Stainless steel, single 5,943 lpm @ 18 m H2O 14 Raw Water Pumps 2 1 suction (1,570 gpm @ 60 ft H2O)

Stainless steel, single 2,953 lpm @ 268 m H2O 15 Ground Water Pumps 4 1 suction (780 gpm @ 880 ft H2O)

Stainless steel, single 4,656 lpm @ 49 m H2O 16 Filtered Water Pumps 2 1 suction (1,230 gpm @ 160 ft H2O) 17 Filtered Water Tank Vertical, cylindrical 2,225,822 liter (588,000 gal) 2 0 Makeup Water Anion, cation, and 18 2,082 lpm (550 gpm) 2 0 Demineralizer mixed bed Liquid Waste Treatment 19 10 years, 24-hour storm 1 0 System 284

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY AND FUEL GAS SATURATION Equipment Operating Description Type Design Condition Spares No. Qty.

Pressurized dry-feed, 2,812 tonne/day, 4.2 MPa 1 Gasifier 2 0 entrained bed (3,100 tpd, 615 psia)

Convective spiral-2 Synthesis Gas Cooler 396,893 kg/hr (875,000 lb/hr) 2 0 wound tube boiler 313,432 kg/hr (691,000 lb/hr) 3 Synthesis Gas Cyclone High efficiency 2 0 Design efficiency 90%

Pressurized filter with 4 Candle Filter metallic filters 2 0 pulse-jet cleaning Syngas Scrubber 5 Including Sour Water Vertical upflow 313,432 kg/hr (691,000 lb/hr) 2 0 Stripper Shell and tube with 6 Raw Gas Coolers 397,801 kg/hr (877,000 lb/hr) 8 0 condensate drain Raw Gas Knockout Vertical with mist 309,804 kg/hr, 35°C, 3.7 MPa 7 2 0 Drum eliminator (683,000 lb/hr, 95°F, 530 psia)

Saturation Water 8 Shell and tube 78 GJ/hr (74 MMBtu/hr) 2 0 Economizers 83,007 kg/hr, 137°C, 3.6 MPa 9 Fuel Gas Saturator Vertical tray tower 2 0 (183,000 lb/hr, 278°F, 520 psia) 1,893 lpm @ 12 m H2O 10 Saturator Water Pump Centrifugal 2 2 (500 gpm @ 40 ft H2O) 11 Synthesis Gas Reheater Shell and tube 83,007 kg/hr (183,000 lb/hr) 2 0 Self-supporting, carbon 313,432 kg/hr (691,000 lb/hr) 12 Flare Stack steel, stainless steel top, 2 0 syngas pilot ignition ASU Main Air 5,267 m3/min @ 1.3 MPa 13 Centrifugal, multi-stage 2 0 Compressor (186,000 scfm @ 190 psia) 2,087 tonne/day (2,300 tpd) of 14 Cold Box Vendor design 2 0 95% purity oxygen 1,048 m3/min (37,000 scfm) 15 Oxygen Compressor Centrifugal, multi-stage Suction - 0.9 MPa (130 psia) 2 0 Discharge - 6.5 MPa (940 psia) 3,483 m3/min (123,000 scfm)

Primary Nitrogen 16 Centrifugal, multi-stage Suction - 0.4 MPa (60 psia) 2 0 Compressor Discharge - 2.7 MPa (390 psia) 481 m3/min (17,000 scfm)

Secondary Nitrogen 17 Centrifugal, single-stage Suction - 1.2 MPa (180 psia) 2 0 Compressor Discharge - 2.7 MPa (390 psia) 1,359 m3/min (48,000 scfm)

Gasifier Purge Nitrogen 18 Centrifugal, single-stage Suction - 2.6 MPa (380 psia) 2 0 Boost Compressor Discharge - 3.2 MPa (470 psia) 285

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 5 SYNGAS CLEANUP Equipment Operating Description Type Design Condition Spares No. Qty.

309,350 kg/hr (682,000 lb/hr)

Sulfated carbon 1 Mercury Adsorber 35°C (95°F) 2 0 bed 3.6 MPa (525 psia) 2 Sulfur Plant Claus type 139 tonne/day (154 tpd) 1 0 397,801 kg/hr (877,000 lb/hr)

Fixed bed, 3 Water Gas Shift Reactors 216°C (420°F) 4 0 catalytic 4.0 MPa (580 psia)

Exchanger 1: 121 GJ/hr (114 Shift Reactor Heat Recovery MMBtu/hr) 4 Shell and Tube 4 0 Exchangers Exchanger 2: 3 GJ/hr (3 MMBtu/hr) 316,154 kg/hr (697,000 lb/hr)

Two-stage 5 Acid Gas Removal Plant 35°C (94°F) 2 0 Selexol 3.6 MPa (520 psia) 18,243 kg/hr (40,220 lb/hr)

Fixed bed, 6 Hydrogenation Reactor 232°C (450°F) 1 0 catalytic 0.1 MPa (12.3 psia)

Tail Gas Recycle 7 Centrifugal 13,713 kg/hr (30,232 lb/hr) 1 0 Compressor ACCOUNT 5B CO 2 COMPRESSION Equipment Operating Description Type Design Condition Spares No. Qty.

CO2 Integrally geared, 1,096 m3/min @ 15.3 MPa 1 4 0 Compressor multi-stage centrifugal (38,700 scfm @ 2,215 psia)

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES Equipment Operating Description Type Design Condition Spares No. Qty.

1 Gas Turbine Advanced F class 232 MW 2 0 260 MVA @ 0.9 p.f., 24 kV, 2 Gas Turbine Generator TEWAC 2 0 60 Hz, 3-phase 286

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 7 HRSG, DUCTING, AND STACK Equipment Operating Description Type Design Condition Spares No. Qty.

CS plate, type 409SS 76 m (250 ft) high x 1 Stack 1 0 liner 8.5 m (28 ft) diameter Main steam - 285,910 kg/hr, 12.4 Drum, multi-pressure MPa/534°C (630,323 lb/hr, Heat Recovery with economizer 1,800 psig/993°F) 2 2 0 Steam Generator section and integral Reheat steam - 244,783 kg/hr, deaerator 3.1 MPa/534°C (539,654 lb/hr, 452 psig/993°F)

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES Equipment Operating Description Type Design Condition Spares No. Qty.

Commercially 220 MW 1 Steam Turbine available advanced 12.4 MPa/534°C/534°C 1 0 steam turbine (1800 psig/ 993°F/993°F)

Hydrogen cooled, 240 MVA @ 0.9 p.f., 24 2 Steam Turbine Generator 1 0 static excitiation kV, 60 Hz, 3-phase 50% steam flow @ design 3 Steam Bypass One per HRSG 2 0 steam conditions 1,467 GJ/hr (1,390 Single pass, divided MMBtu/hr), Inlet water 4 Surface Condenser waterbox including temperature 16°C (60°F), 1 0 vacuum pumps Water temperature rise 11°C (20°F) 287

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 9 COOLING WATER SYSTEM Equipment Operating Description Type Design Condition Spares No. Qty.

Circulating Water 439,108 lpm @ 30 m 1 Vertical, wet pit 2 1 Pumps (116,000 gpm @ 100 ft) 11°C (51.5°F) wet bulb / 16°C Evaporative, (60°F) CWT / 27°C (80°F) HWT 2 Cooling Tower mechanical draft, multi- 1 0

/ 2437 GJ/hr (2310 MMBtu/hr) cell heat duty ACCOUNT 10 SLAG RECOVERY AND HANDLING Equipment Operating Description Type Design Condition Spares No. Qty.

1 Slag Quench Tank Water bath 223,339 liters (59,000 gal) 2 0 2 Slag Crusher Roll 12 tonne/hr (13 tph) 2 0 3 Slag Depressurizer Lock Hopper 12 tonne/hr (13 tph) 2 0 4 Slag Receiving Tank Horizontal, weir 132,489 liters (35,000 gal) 2 0 5 Black Water Overflow Tank Shop fabricated 60,567 liters (16,000 gal) 2 6 Slag Conveyor Drag chain 12 tonne/hr (13 tph) 2 0 7 Slag Separation Screen Vibrating 12 tonne/hr (13 tph) 2 0 8 Coarse Slag Conveyor Belt/bucket 12 tonne/hr (13 tph) 2 0 9 Fine Ash Settling Tank Vertical, gravity 189,271 liters (50,000 gal) 2 0 Horizontal 38 lpm @ 14 m H2O 10 Fine Ash Recycle Pumps 2 2 centrifugal (10 gpm @ 46 ft H2O) 11 Grey Water Storage Tank Field erected 60,567 liters (16,000 gal) 2 0 227 lpm @ 433 m H2O 12 Grey Water Pumps Centrifugal 2 2 (60 gpm @ 1,420 ft H2O)

Vertical, field 13 Slag Storage Bin 816 tonne (900 tons) 2 0 erected 14 Unloading Equipment Telescoping chute 100 tonne/hr (110 tph) 1 0 288

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 11 ACCESSORY ELECTRIC PLANT Equipment Operating Description Type Design Condition Spares No. Qty.

CTG Step-up 24 kV/345 kV, 260 MVA, 1 Oil-filled 2 0 Transformer 3-ph, 60 Hz STG Step-up 24 kV/345 kV, 240 MVA, 2 Oil-filled 1 0 Transformer 3-ph, 60 Hz High Voltage 345 kV/13.8 kV, 74 MVA, 3 Auxiliary Oil-filled 2 0 3-ph, 60 Hz Transformer Medium Voltage 24 kV/4.16 kV, 46 MVA, 4 Auxiliary Oil-filled 1 1 3-ph, 60 Hz Transformer Low Voltage 4.16 kV/480 V, 7 MVA, 5 Dry ventilated 1 1 Transformer 3-ph, 60 Hz CTG Isolated 6 Phase Bus Duct Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 2 0 and Tap Bus STG Isolated 7 Phase Bus Duct Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0 and Tap Bus Medium Voltage 8 Metal clad 4.16 kV, 3-ph, 60 Hz 1 1 Switchgear Low Voltage 9 Metal enclosed 480 V, 3-ph, 60 Hz 1 1 Switchgear Emergency Diesel Sized for emergency 10 750 kW, 480 V, 3-ph, 60 Hz 1 0 Generator shutdown ACCOUNT 12 INSTRUMENTATION AND CONTROLS Equipment Operating Description Type Design Condition Spares No. Qty.

Monitor/keyboard; DCS - Main Operator printer (laser Operator stations/printers and 1 1 0 Control color); Engineering engineering stations/printers printer (laser B&W)

Microprocessor with 2 DCS - Processor N/A 1 0 redundant input/output DCS - Data 3 Fiber optic Fully redundant, 25% spare 1 0 Highway 289

Cost and Performance Baseline for Fossil Energy Plants 3.4.11 Case 6 - Cost Estimating The cost estimating methodology was described previously in Section 2.6. Exhibit 3-98 shows the total plant capital cost summary organized by cost account and Exhibit 3-99 shows a more detailed breakdown of the capital costs along with owners costs, TOC and TASC.

Exhibit 3-100 shows the initial and annual O&M costs.

The estimated TOC of the Shell gasifier with CO2 capture is $3,904/kW. Process contingency represents 3.4 percent of the TOC and project contingency represents 11.4 percent. The COE, including CO2 TS&M costs of 5.7 mills/kWh, is 119.5 mills/kWh.

290

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-98 Case 6 Total Plant Cost Summary Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study TOTAL PLANT COST

SUMMARY

Case: Case 6 - Shell 500MW IGCC w/ CO2 Plant Size: 496.9 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING $13,881 $2,580 $10,765 $0 $0 $27,226 $2,471 $0 $5,939 $35,636 $72 2 COAL & SORBENT PREP & FEED $109,935 $8,758 $18,287 $0 $0 $136,980 $11,879 $0 $29,772 $178,630 $360 3 FEEDWATER & MISC. BOP SYSTEMS $9,471 $7,207 $9,699 $0 $0 $26,377 $2,492 $0 $6,717 $35,585 $72 4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries $144,815 $0 $61,614 $0 $0 $206,430 $18,447 $28,271 $38,955 $292,103 $588 4.2 Syngas Cooling (w/4.1) w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $173,504 $0 w/equip. $0 $0 $173,504 $16,818 $0 $19,032 $209,354 $421 4.4-4.9 Other Gasification Equipment $25,591 $9,849 $15,118 $0 $0 $50,557 $4,851 $0 $11,805 $67,213 $135 SUBTOTAL 4 $343,911 $9,849 $76,732 $0 $0 $430,492 $40,115 $28,271 $69,793 $568,670 $1,145 5A Gas Cleanup & Piping $91,097 $3,993 $77,814 $0 $0 $172,904 $16,706 $26,070 $43,284 $258,964 $521 5B CO2 REMOVAL & COMPRESSION $17,811 $0 $10,524 $0 $0 $28,335 $2,728 $0 $6,213 $37,276 $75 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,599 $261 6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6 $92,026 $806 $7,475 $0 $0 $100,307 $9,507 $9,861 $12,339 $132,014 $266 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,709 $0 $4,793 $0 $0 $38,502 $3,661 $0 $4,216 $46,379 $93 7.2-7.9 Ductwork and Stack $3,380 $2,410 $3,156 $0 $0 $8,946 $829 $0 $1,591 $11,367 $23 SUBTOTAL 7 $37,089 $2,410 $7,949 $0 $0 $47,448 $4,490 $0 $5,807 $57,745 $116 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $23,934 $0 $4,000 $0 $0 $27,935 $2,680 $0 $3,061 $33,676 $68 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $9,162 $818 $6,331 $0 $0 $16,312 $1,486 $0 $3,487 $21,285 $43 SUBTOTAL 8 $33,096 $818 $10,332 $0 $0 $44,246 $4,166 $0 $6,549 $54,961 $111 9 COOLING WATER SYSTEM $9,932 $9,472 $8,108 $0 $0 $27,512 $2,555 $0 $6,134 $36,202 $73 10 ASH/SPENT SORBENT HANDLING SYS $18,585 $1,433 $9,223 $0 $0 $29,241 $2,805 $0 $3,501 $35,547 $72 11 ACCESSORY ELECTRIC PLANT $30,536 $12,099 $23,664 $0 $0 $66,300 $5,703 $0 $13,663 $85,666 $172 12 INSTRUMENTATION & CONTROL $11,002 $2,024 $7,089 $0 $0 $20,115 $1,823 $1,006 $3,823 $26,766 $54 13 IMPROVEMENTS TO SITE $3,346 $1,972 $8,255 $0 $0 $13,572 $1,340 $0 $4,474 $19,386 $39 14 BUILDINGS & STRUCTURES $0 $6,461 $7,281 $0 $0 $13,741 $1,250 $0 $2,463 $17,455 $35 TOTAL COST $821,717 $69,882 $293,196 $0 $0 $1,184,795 $110,031 $65,208 $220,470 $1,580,505 $3,181 291

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-99 Case 6 Total Plant Cost Details Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $3,645 $0 $1,781 $0 $0 $5,427 $486 $0 $1,183 $7,095 $14 1.2 Coal Stackout & Reclaim $4,711 $0 $1,142 $0 $0 $5,853 $513 $0 $1,273 $7,639 $15 1.3 Coal Conveyors & Yd Crush $4,380 $0 $1,130 $0 $0 $5,510 $484 $0 $1,199 $7,192 $14 1.4 Other Coal Handling $1,146 $0 $261 $0 $0 $1,407 $123 $0 $306 $1,836 $4 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,580 $6,450 $0 $0 $9,030 $865 $0 $1,979 $11,874 $24 SUBTOTAL 1. $13,881 $2,580 $10,765 $0 $0 $27,226 $2,471 $0 $5,939 $35,636 $72 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $41,765 $2,509 $6,086 $0 $0 $50,360 $4,346 $0 $10,941 $65,647 $132 2.2 Prepared Coal Storage & Feed $1,978 $473 $310 $0 $0 $2,762 $236 $0 $600 $3,598 $7 2.3 Dry Coal Injection System $65,103 $756 $6,046 $0 $0 $71,905 $6,193 $0 $15,620 $93,718 $189 2.4 Misc.Coal Prep & Feed $1,088 $792 $2,373 $0 $0 $4,253 $391 $0 $929 $5,573 $11 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $4,228 $3,471 $0 $0 $7,700 $713 $0 $1,683 $10,095 $20 SUBTOTAL 2. $109,935 $8,758 $18,287 $0 $0 $136,980 $11,879 $0 $29,772 $178,630 $360 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,492 $4,279 $2,259 $0 $0 $9,029 $836 $0 $1,973 $11,839 $24 3.2 Water Makeup & Pretreating $701 $73 $392 $0 $0 $1,167 $111 $0 $383 $1,661 $3 3.3 Other Feedwater Subsystems $1,363 $461 $415 $0 $0 $2,238 $201 $0 $488 $2,928 $6 3.4 Service Water Systems $401 $827 $2,869 $0 $0 $4,097 $400 $0 $1,349 $5,845 $12 3.5 Other Boiler Plant Systems $2,154 $835 $2,069 $0 $0 $5,057 $480 $0 $1,107 $6,644 $13 3.6 FO Supply Sys & Nat Gas $313 $591 $551 $0 $0 $1,454 $140 $0 $319 $1,913 $4 3.7 Waste Treatment Equipment $981 $0 $598 $0 $0 $1,579 $154 $0 $520 $2,252 $5 3.8 Misc. Power Plant Equipment $1,066 $143 $547 $0 $0 $1,756 $170 $0 $578 $2,503 $5 SUBTOTAL 3. $9,471 $7,207 $9,699 $0 $0 $26,377 $2,492 $0 $6,717 $35,585 $72 4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (Shell) $144,815 $0 $61,614 $0 $0 $206,430 $18,447 $28,271 $38,955 $292,103 $588 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $173,504 $0 w/equip. $0 $0 $173,504 $16,818 $0 $19,032 $209,354 $421 4.4 LT Heat Recovery & FG Saturation $25,591 $0 $9,728 $0 $0 $35,319 $3,447 $0 $7,753 $46,519 $94 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Flare Stack System $0 $1,406 $572 $0 $0 $1,978 $190 $0 $433 $2,601 $5 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $8,443 $4,818 $0 $0 $13,261 $1,214 $0 $3,619 $18,094 $36 SUBTOTAL 4. $343,911 $9,849 $76,732 $0 $0 $430,492 $40,115 $28,271 $69,793 $568,670 $1,145 292

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-99 Case 6 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $70,179 $0 $59,549 $0 $0 $129,728 $12,546 $25,946 $33,644 $201,864 $406 5A.2 Elemental Sulfur Plant $10,017 $1,996 $12,924 $0 $0 $24,937 $2,422 $0 $5,472 $32,831 $66 5A.3 Mercury Removal $1,410 $0 $1,073 $0 $0 $2,483 $240 $124 $569 $3,417 $7 5A.4 Shift Reactors $7,366 $0 $2,965 $0 $0 $10,330 $990 $0 $2,264 $13,585 $27 5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 5A.5 Blowback Gas Systems $2,125 $358 $201 $0 $0 $2,684 $255 $0 $588 $3,526 $7 5A.6 Fuel Gas Piping $0 $814 $570 $0 $0 $1,384 $128 $0 $303 $1,815 $4 5A.9 HGCU Foundations $0 $824 $532 $0 $0 $1,356 $125 $0 $444 $1,925 $4 SUBTOTAL 5A. $91,097 $3,993 $77,814 $0 $0 $172,904 $16,706 $26,070 $43,284 $258,964 $521 5B CO2 COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $17,811 $0 $10,524 $0 $0 $28,335 $2,728 $0 $6,213 $37,276 $75 SUBTOTAL 5B. $17,811 $0 $10,524 $0 $0 $28,335 $2,728 $0 $6,213 $37,276 $75 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,599 $261 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6. $92,026 $806 $7,475 $0 $0 $100,307 $9,507 $9,861 $12,339 $132,014 $266 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,709 $0 $4,793 $0 $0 $38,502 $3,661 $0 $4,216 $46,379 $93 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,733 $1,236 $0 $0 $2,969 $260 $0 $646 $3,875 $8 7.4 Stack $3,380 $0 $1,270 $0 $0 $4,650 $445 $0 $510 $5,605 $11 7.9 HRSG,Duct & Stack Foundations $0 $677 $650 $0 $0 $1,328 $124 $0 $435 $1,887 $4 SUBTOTAL 7. $37,089 $2,410 $7,949 $0 $0 $47,448 $4,490 $0 $5,807 $57,745 $116 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $23,934 $0 $4,000 $0 $0 $27,935 $2,680 $0 $3,061 $33,676 $68 8.2 Turbine Plant Auxiliaries $165 $0 $378 $0 $0 $543 $53 $0 $60 $656 $1 8.3 Condenser & Auxiliaries $4,579 $0 $1,463 $0 $0 $6,042 $578 $0 $662 $7,282 $15 8.4 Steam Piping $4,418 $0 $3,108 $0 $0 $7,526 $647 $0 $2,043 $10,215 $21 8.9 TG Foundations $0 $818 $1,383 $0 $0 $2,201 $209 $0 $723 $3,132 $6 SUBTOTAL 8. $33,096 $818 $10,332 $0 $0 $44,246 $4,166 $0 $6,549 $54,961 $111 9 COOLING WATER SYSTEM 9.1 Cooling Towers $6,867 $0 $1,249 $0 $0 $8,116 $773 $0 $1,333 $10,222 $21 9.2 Circulating Water Pumps $1,791 $0 $127 $0 $0 $1,919 $162 $0 $312 $2,393 $5 9.3 Circ.Water System Auxiliaries $151 $0 $21 $0 $0 $172 $16 $0 $28 $217 $0 9.4 Circ.Water Piping $0 $6,288 $1,630 $0 $0 $7,918 $716 $0 $1,727 $10,360 $21 9.5 Make-up Water System $381 $0 $544 $0 $0 $925 $89 $0 $203 $1,217 $2 9.6 Component Cooling Water Sys $742 $888 $632 $0 $0 $2,262 $212 $0 $495 $2,968 $6 9.9 Circ.Water System Foundations $0 $2,296 $3,904 $0 $0 $6,200 $588 $0 $2,037 $8,825 $18 SUBTOTAL 9. $9,932 $9,472 $8,108 $0 $0 $27,512 $2,555 $0 $6,134 $36,202 $73 293

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-99 Case 6 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $16,178 $0 $7,978 $0 $0 $24,156 $2,321 $0 $2,648 $29,125 $59 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $546 $0 $594 $0 $0 $1,139 $111 $0 $187 $1,437 $3 10.7 Ash Transport & Feed Equipment $732 $0 $177 $0 $0 $908 $85 $0 $149 $1,142 $2 10.8 Misc. Ash Handling Equipment $1,130 $1,385 $414 $0 $0 $2,929 $279 $0 $481 $3,689 $7 10.9 Ash/Spent Sorbent Foundation $0 $48 $61 $0 $0 $109 $10 $0 $36 $155 $0 SUBTOTAL 10. $18,585 $1,433 $9,223 $0 $0 $29,241 $2,805 $0 $3,501 $35,547 $72 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $901 $0 $891 $0 $0 $1,792 $171 $0 $196 $2,159 $4 11.2 Station Service Equipment $4,510 $0 $406 $0 $0 $4,916 $453 $0 $537 $5,906 $12 11.3 Switchgear & Motor Control $8,338 $0 $1,516 $0 $0 $9,854 $914 $0 $1,615 $12,383 $25 11.4 Conduit & Cable Tray $0 $3,873 $12,777 $0 $0 $16,650 $1,610 $0 $4,565 $22,826 $46 11.5 Wire & Cable $0 $7,400 $4,862 $0 $0 $12,262 $891 $0 $3,288 $16,442 $33 11.6 Protective Equipment $0 $679 $2,471 $0 $0 $3,150 $308 $0 $519 $3,976 $8 11.7 Standby Equipment $224 $0 $219 $0 $0 $443 $42 $0 $73 $558 $1 11.8 Main Power Transformers $16,564 $0 $136 $0 $0 $16,699 $1,263 $0 $2,694 $20,656 $42 11.9 Electrical Foundations $0 $147 $386 $0 $0 $534 $51 $0 $175 $760 $2 SUBTOTAL 11. $30,536 $12,099 $23,664 $0 $0 $66,300 $5,703 $0 $13,663 $85,666 $172 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,086 $0 $725 $0 $0 $1,811 $171 $91 $311 $2,384 $5 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $250 $0 $160 $0 $0 $410 $39 $20 $94 $563 $1 12.7 Computer & Accessories $5,794 $0 $185 $0 $0 $5,979 $549 $299 $683 $7,510 $15 12.8 Instrument Wiring & Tubing $0 $2,024 $4,137 $0 $0 $6,161 $523 $308 $1,748 $8,740 $18 12.9 Other I & C Equipment $3,873 $0 $1,881 $0 $0 $5,753 $541 $288 $987 $7,570 $15 SUBTOTAL 12. $11,002 $2,024 $7,089 $0 $0 $20,115 $1,823 $1,006 $3,823 $26,766 $54 294

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-99 Case 6 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $105 $2,244 $0 $0 $2,349 $233 $0 $775 $3,356 $7 13.2 Site Improvements $0 $1,867 $2,481 $0 $0 $4,348 $429 $0 $1,433 $6,210 $12 13.3 Site Facilities $3,346 $0 $3,530 $0 $0 $6,876 $678 $0 $2,266 $9,820 $20 SUBTOTAL 13. $3,346 $1,972 $8,255 $0 $0 $13,572 $1,340 $0 $4,474 $19,386 $39 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,071 $2,950 $0 $0 $5,021 $462 $0 $822 $6,306 $13 14.3 Administration Building $0 $857 $622 $0 $0 $1,479 $132 $0 $242 $1,853 $4 14.4 Circulation Water Pumphouse $0 $161 $85 $0 $0 $246 $22 $0 $40 $308 $1 14.5 Water Treatment Buildings $0 $586 $572 $0 $0 $1,158 $105 $0 $189 $1,452 $3 14.6 Machine Shop $0 $439 $300 $0 $0 $739 $66 $0 $121 $926 $2 14.7 Warehouse $0 $709 $457 $0 $0 $1,166 $103 $0 $190 $1,460 $3 14.8 Other Buildings & Structures $0 $424 $330 $0 $0 $755 $67 $0 $164 $987 $2 14.9 Waste Treating Building & Str. $0 $949 $1,813 $0 $0 $2,762 $257 $0 $604 $3,623 $7 SUBTOTAL 14. $0 $6,461 $7,281 $0 $0 $13,741 $1,250 $0 $2,463 $17,455 $35 TOTAL COST $821,717 $69,882 $293,196 $0 $0 $1,184,795 $110,031 $65,208 $220,470 $1,580,505 $3,181 Owner's Costs Preproduction Costs 6 Months All Labor $13,300 $27 1 Month Maintenance Materials $2,951 $6 1 Month Non-fuel Consumables $378 $1 1 Month Waste Disposal $278 $1 25% of 1 Months Fuel Cost at 100% CF $1,621 $3 2% of TPC $31,610 $64 Total $50,138 $101 Inventory Capital 60 day supply of fuel and consumables at 100% CF $13,459 $27 0.5% of TPC (spare parts) $7,903 $16 Total $21,361 $43 Initial Cost for Catalyst and Chemicals $7,224 $15 Land $900 $2 Other Owner's Costs $237,076 $477 Financing Costs $42,674 $86 Total Overnight Costs (TOC) $1,939,878 $3,904 TASC Multiplier (IOU, high-risk, 35 year) 1.140 Total As-Spent Cost (TASC) $2,211,461 $4,451 295

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-100 Case 6 Initial and Annual Operating and Maintenance Costs INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 6 - Shell 500MW IGCC w/ CO2 Heat Rate-net (Btu/kWh): 10,924 MWe-net: 497 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant Skilled Operator 2.0 2.0 Operator 10.0 10.0 Foreman 1.0 1.0 Lab Tech's, etc. 3.0 3.0 TOTAL-O.J.'s 16.0 16.0 Annual Cost Annual Unit Cost

$ $/kW-net Annual Operating Labor Cost $6,313,507 $12.707 Maintenance Labor Cost $14,966,466 $30.122 Administrative & Support Labor $5,319,993 $10.707 Property Taxes and Insurance $31,610,092 $63.620 TOTAL FIXED OPERATING COSTS $58,210,058 $117.156 VARIABLE OPERATING COSTS

$/kWh-net Maintenance Material Cost $28,329,484 $0.00814 Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water (/1000 gallons) 0 4,056 1.08 $0 $1,281,009 $0.00037 Chemicals MU & WT Chem. (lbs) 0 24,163 0.17 $0 $1,221,101 $0.00035 Carbon (Mercury Removal) (lb) 117,815 161 1.05 $123,726 $49,490 $0.00001 COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000 Water Gas Shift Catalyst (ft3) 6,470 4.43 498.83 $3,227,388 $645,478 $0.00019 Selexol Solution (gal) 289,068 92 13.40 $3,873,002 $360,241 $0.00010 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 1.93 131.27 $0 $74,040 $0.00002 Subtotal Chemicals $7,224,116 $2,350,349 $0.00068 Other Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 $0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $0 $0.00000 Waste Disposal Spent Mercury Catalyst (lb.) 0 161 0.42 $0 $19,655 $0.00001 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 559 16.23 $0 $2,649,268 $0.00076 Subtotal-Waste Disposal $0 $2,668,923 $0.00077 By-products & Emissions Sulfur (ton) 0 140 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000 TOTAL VARIABLE OPERATING COSTS $7,224,116 $34,629,764 $0.00995 Fuel (ton) 0 5,583 38.18 $0 $62,251,620 $0.01788 296

Cost and Performance Baseline for Fossil Energy Plants 3.5 IGCC CASE

SUMMARY

The performance results of the six IGCC plant configurations modeled in this study are summarized in Exhibit 3-101.

Exhibit 3-101 Estimated Performance and Cost Results for IGCC Cases Integrated Gasification Combined Cycle GEE R+Q CoP E-Gas FSQ Shell PERFORMANCE Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 CO2 Capture 0% 90% 0% 90% 0% 90%

Gross Power Output (kWe) 747,800 734,000 738,200 703,700 737,000 673,400 Auxiliary Power Requirement (kWe) 125,750 190,750 113,140 190,090 108,020 176,540 Net Power Output (kWe) 622,050 543,250 625,060 513,610 628,980 496,860 Coal Flowrate (lb/hr) 466,901 487,011 459,958 484,212 436,646 465,264 Natural Gas Flowrate (lb/hr) N/A N/A N/A N/A N/A N/A HHV Thermal Input (kWth) 1,596,320 1,665,074 1,572,582 1,655,503 1,492,878 1,590,722 Net Plant HHV Efficiency (%) 39.0% 32.6% 39.7% 31.0% 42.1% 31.2%

Net Plant HHV Heat Rate (Btu/kWh) 8,756 10,458 8,585 10,998 8,099 10,924 Raw Water Withdrawal (gpm/MW net) 7.6 10.7 7.0 11.1 6.6 11.3 Process Water Discharge (gpm/MW net) 1.6 2.0 1.4 2.1 1.2 2.0 Raw Water Consumption (gpm/MW net) 6.0 8.7 5.5 9.0 5.3 9.3 CO2 Emissions (lb/MMBtu) 197 20 199 20 197 20 CO2 Emissions (lb/MWhgross) 1,434 152 1,448 158 1,361 161 CO2 Emissions (lb/MWhnet) 1,723 206 1,710 217 1,595 218 SO2 Emissions (lb/MMBtu) 0.0012 0.0022 0.0117 0.0022 0.0042 0.0021 SO2 Emissions (lb/MWhgross) 0.0090 0.0166 0.0852 0.0173 0.0290 0.0171 NOx Emissions (lb/MMBtu) 0.059 0.049 0.060 0.049 0.059 0.049 NOx Emissions (lb/MWhgross) 0.430 0.376 0.434 0.396 0.409 0.396 PM Emissions (lb/MMBtu) 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 PM Emissions (lb/MWhgross) 0.052 0.055 0.052 0.057 0.049 0.057 Hg Emissions (lb/TBtu) 0.571 0.571 0.571 0.571 0.571 0.571 Hg Emissions (lb/MWhgross) 4.16E-06 4.42E-06 4.15E-06 4.59E-06 3.95E-06 4.61E-06 COST Total Plant Cost (2007$/kW) 1,987 2,711 1,913 2,817 2,217 3,181 Total Overnight Cost (2007$/kW) 2,447 3,334 2,351 3,466 2,716 3,904 Bare Erected Cost 1,528 2,032 1,470 2,113 1,695 2,385 Home Office Expenses 144 191 138 199 156 221 Project Contingency 265 369 256 385 302 444 Process Contingency 50 119 50 120 63 131 Owner's Costs 460 623 438 649 500 723 Total Overnight Cost (2007$ x 1,000) 1,521,880 1,811,411 1,469,577 1,780,290 1,708,524 1,939,878 Total As Spent Capital (2007$/kW) 2,789 3,801 2,680 3,952 3,097 4,451 COE (mills/kWh, 2007$)1,2 76.3 105.6 74.0 110.3 81.3 119.4 CO2 TS&M Costs 0.0 5.2 0.0 5.5 0.0 5.6 Fuel Costs 14.3 17.1 14.0 18.0 13.3 17.9 Variable Costs 7.3 9.3 7.2 9.8 7.8 9.9 Fixed Costs 11.3 14.8 11.1 15.5 12.1 16.7 Capital Costs 43.4 59.1 41.7 61.5 48.2 69.2 LCOE (mills/kWh, 2007$)1,2 96.7 133.9 93.8 139.9 103.1 151.4 1

CF is 80% for all IGCC cases 2

COE and LCOE are defined in Section 2.7.

297

Cost and Performance Baseline for Fossil Energy Plants The components of TOC and the overall TASC of the six IGCC cases are shown in Exhibit 3-102. The following TOC observations are made with the caveat that the differences between cases are less than the estimate accuracy (-15%/+30%). However, all cases are evaluated using a common set of technical and economic assumptions allowing meaningful comparisons among the cases:

CoP has the lowest TOC cost among the non-capture cases. The E-Gas technology has several features that lend it to being lower cost, such as:

o The firetube syngas cooler is much smaller and less expensive than a radiant section. E-Gas can use a firetube boiler because the two-stage design reduces the gas temperature (slurry quench) and drops the syngas temperature into a range where a radiant cooler is not needed.

o The firetube syngas cooler sits next to the gasifier instead of above or below it, which reduces the height of the main gasifier structure. The E-Gas proprietary slag removal system, used instead of lock hoppers below the gasifier, also contributes to the lower structure height.

The TOC of the GEE gasifier is about 4 percent greater than CoP and Shell is about 16 percent higher.

Exhibit 3-102 Plant Capital Cost for IGCC Cases 7,000 TASC 6,000 Owner's Cost Process Contingency 5,000 Project Contingency TOC or TASC, $/kW (2007$)

Home Office Expense 4,451 Bare Erected Cost 3,952 3,904 4,000 3,801 3,334 3,466 3,097 3,000 2,789 2,680 2,716 2,447 2,351 2,000 1,000 0

TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC GEE GEE w/ CO2 Capture CoP CoP w/ CO2 Capture Shell Shell w/ CO2 Capture

The GEE gasifier is the low cost technology in the CO2 capture cases, with CoP about 4 percent higher and Shell about 17 percent higher. The greatest uncertainty in all of the capital cost estimates is for the Shell capture case, which is based on a water quench process that has been proposed by Shell in a patent application [63]. However, to date there have been no commercial applications of this configuration.

298

Cost and Performance Baseline for Fossil Energy Plants

The ASU cost represents on average 12 percent of the TOC (range from 10.5-12.9 percent). The ASU cost includes oxygen and nitrogen compression, and in the non-capture cases, also includes the cost of the CT extraction air heat exchanger. With nitrogen dilution used to the maximum extent possible, nitrogen compression costs are significant.

The TOC premium for adding CO2 capture averages 42 percent ($3,568/kW versus

$2,504/kW).

The COE is shown for the IGCC cases in Exhibit 3-103.

Exhibit 3-103 COE for IGCC Cases 160 CO2 TS&M Costs Fuel Costs 140 Variable Costs Fixed Costs 120 Capital Costs 5.7 5.6 5.3 17.9 100 COE, mills/kWh (2007$)

18.0 17.1 9.9 80 9.8 9.3 16.7 13.3 14.3 15.5 14.8 14.0 7.8 60 7.3 7.2 12.1 11.3 11.1 40 69.2 59.1 61.5 48.2 20 43.4 41.7 0

GEE GEE w/CO2 Capture CoP CoP w/ CO2 Capture Shell Shell w/ CO2 Capture The following observations can be made:

The COE is dominated by capital costs, at least 56 percent of the total in all cases.

In the non-capture cases the CoP gasifier has the lowest COE, but the differential with Shell is reduced (compared to the TOC) primarily because of the higher efficiency of the Shell gasifier. The Shell COE is 10 percent higher than CoP (compared to 16 percent higher TOC). The GEE gasifier COE is about 3 percent higher than CoP.

In the capture cases the variation in COE is small, however the order of the GEE and CoP gasifiers is reversed. The range is from 105.7 mills/kWh for GEE to 119.5 mills/kWh for Shell with CoP intermediate at 110.4 mills/kWh. The COE CO2 capture premium for the IGCC cases averages 45 percent (range of 39 to 49 percent).

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Cost and Performance Baseline for Fossil Energy Plants

The CO2 TS&M COE component comprises less than 5.5 percent of the total COE in all capture cases.

The effect of CF and coal price on COE is shown in Exhibit 3-104 and Exhibit 3-105, respectively.

The assumption implicit in Exhibit 3-104 is that each gasifier technology can achieve a CF of up to 90 percent with no additional capital equipment. The cost differential between technologies decreases as CF increases. At low CF the capital cost differential is more magnified and the spread between technologies increases slightly.

Exhibit 3-104 Capacity Factor Sensitivity of IGCC Cases 300 250 Coal = $1.64/MMBtu 200 COE, mills/kWh (2007$)

150 Shell w/CO2 Capture CoP w/CO2 Capture 100 GEE w/CO2 Capture Shell No Capture GEE No Capture 50 CoP No Capture 0

0 10 20 30 40 50 60 70 80 90 100 Capacity Factor, %

COE is relatively insensitive to fuel costs for the IGCC cases as shown in Exhibit 3-105. A tripling of coal price from 1 to $3/MMBtu results in an average COE increase of only about 19-25 percent for all cases.

As presented in Section 2.4 the cost of CO2 capture was calculated as an avoided cost. The results for the IGCC CO2 capture cases are shown in Exhibit 3-106. The first year cost of CO2 avoided using each analogous IGCC non-capture technology as the reference averages

$52.9/tonne ($48/ton) with a range of $43-$61.7/tonne ($39-$56/ton). The cost of CO2 avoided is higher when using SC PC without CO2 capture as the technology reference. Avoided costs average $75/tonne ($68/ton) with a range of $66.1-$86/tonne ($60-$78/ton). The avoided cost is elevated because SC PC without capture has a significantly lower COE than any IGCC technology.

300

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-105 Coal Price Sensitivity of IGCC Cases 160 140 120 100 COE, mills/kWh (2007$)

80 60 Shell w/CO2 Capture CoP w/CO2 Capture 40 GEE w/CO2 Capture Capacity factor = 80%

Shell No Capture 20 GEE No Capture CoP No Capture 0

0 0.5 1 1.5 2 2.5 3 3.5 4 Coal Price, $/MMBtu Exhibit 3-106 Cost of CO2 Avoided in IGCC Cases 100 Avoided Cost (Analogous Technology w/o Capture Reference) 90 86 Avoided Cost (SC PC w/o Capture Reference) 80 73 70 66 61 First Year CO2 Avoided Cost, $/tonne (2007$)

60 54 50 43 40 30 20 10 0

GEE CoP Shell 301

Cost and Performance Baseline for Fossil Energy Plants The following observations can be made regarding plant performance:

In the non-carbon capture cases the dry fed Shell gasifier has the highest net plant efficiency (42.1 percent), followed by the two-stage CoP slurry fed gasifier (39.7 percent) and the single-stage GEE gasifier (39.0 percent). The absolute values of the GEE and CoP gasifiers are close to the reported values per the vendors [59, 60]. The Shell efficiency is slightly lower than reported by the vendor in other recent presentations [62].

In the CO2 capture cases the efficiency of the three gasifiers ranges from 31.0 to 32.6 percent.

The dry fed Shell gasifier experiences the largest energy penalty (25.9 relative percent) primarily because addition of the steam required for the WGS reaction is provided as quench water to reduce the syngas temperature from 899°C (1,650°F) to 399°C (750°F).

Quench to 399°C (750°F) reduces the amount of heat recovered in the syngas cooler relative to the non-capture case where syngas recycle reduces the temperature to only 1,093°C (2,000°F) prior to the cooler. The CO2 capture scheme used in this study for the Shell process is similar to one described in a recent Shell patent application [63].

The CoP process experiences the second largest energy penalty (21.9 relative percent) primarily because, like the Shell case, a significant amount of water must be added to the syngas for the SGS reactions.

The energy penalty for the GEE gasifier with CO2 capture is 16.3 relative percent. The smaller energy penalty results from the large amount of water already in the syngas from the quench step prior to SGS. While the quench limits the efficiency in the non-capture case, it is the primary reason that the net efficiency is slightly greater than CoP and Shell in the CO2 capture case.

The assumed carbon conversion efficiency in this study for the three gasifiers results in differing amount of carbon in the slag. Exhibit 3-107 shows carbon conversion and slag carbon content. CO2 capture efficiency is reported based on the amount of carbon entering the system with the coal less the carbon exiting the gasifier with the slag.

Exhibit 3-107 Carbon Conversion Efficiency and Slag Carbon Content Gasifier Vendor Carbon Conversion, % Slag Carbon Content, wt%

GEE 98.0 11.62 CoP 99.2 5.00 Shell 99.5 3.18

Particulate emissions and Hg emissions are essentially the same for all six IGCC cases.

The environmental target for particulate emissions is 0.0071 lb/MMBtu, and it was assumed that the combination of particulate control used by each technology could meet this limit. Similarly, the carbon beds used for mercury control were uniformly assumed to achieve 95 percent removal. The small variation in Hg emissions is due to a similar small variation in coal feed rate among the six cases. In all cases the Hg emissions are substantially below the NSPS requirement of 20 x 10-6 lb/MWh. Had 90 percent been 302

Cost and Performance Baseline for Fossil Energy Plants chosen for the Hg removal efficiency, all six cases would still have had emissions less than half of the NSPS limit.

Based on vendor data, it was assumed that the advanced F class turbine would achieve 15 ppmv NOx emissions at 15 percent O2 for both standard syngas in the non-capture cases and for high hydrogen syngas in the CO2 capture cases. The NOx emissions are slightly lower in the three capture cases (compared to non-capture) because of the lower syngas volume generated in high hydrogen syngas cases.

The environmental target for SO2 emissions is 0.0128 lb/MMBtu. Vendor quotes confirmed that each of the AGR processes, Selexol, refrigerated MDEA and Sulfinol-M, could meet the limit. CoP E-Gas has the highest SO2 emissions (0.005 kg/GJ (0.012 lb/MMBtu)) of the six IGCC cases because refrigerated MDEA has the lowest H2S removal efficiency of the AGR technologies. The two-stage Selexol process used for each of the CO2 capture cases resulted in lower SO2 emissions because the unit was designed to meet the CO2 removal requirement.

Water withdrawal, process discharge, and water consumption, all normalized by net output, are presented in Exhibit 3-108. The following observations can be made:

Raw water usage for all cases is dominated by cooling tower makeup requirements, which accounts for 79-87 percent of raw water usage in non-capture cases and 73-75 percent in CO2 capture cases.

Normalized water withdrawal for the GEE non-capture case is 9 percent higher than the CoP non-capture case and 15 percent higher than the Shell non-capture case primarily because of the large quench water requirement. However, because much of the quench water is subsequently recovered as condensate as the syngas is cooled, the raw water consumption of the GEE process is only 9 percent higher than CoP and 13 percent higher than Shell.

The Shell non-capture case has the lowest normalized water withdrawal, but is approximately equal to CoP in normalized raw water consumption because very little water is available to recover for internal recycle in the Shell system. The GEE normalized raw water consumption is slightly higher than CoP and Shell primarily because the larger steam turbine output leads to higher cooling tower makeup requirements.

The normalized water withdrawal for the three CO2 capture cases varies by only 6 percent from the highest to the lowest. The variation between cases is small because each technology requires approximately the same amount of water in the syngas prior to the shift reactors. The difference in technologies is where and how the water is introduced.

Much of the water is introduced in the quench sections of the GEE and Shell cases while steam is added in the CoP case.

The normalized raw water consumption in the CO2 capture cases also shows little variation with GEE the lowest, CoP only 3.4 percent higher and Shell about 7 percent higher.

303

Cost and Performance Baseline for Fossil Energy Plants Exhibit 3-108 Raw Water Withdrawal and Consumption in IGCC Cases 12 Raw Water Withdrawal 11.3 11.1 10.7 Process Discharge Raw Water Consumption 10 9.3 9.0 8.7 8 7.6 Water, gpm/MWnet 7.0 6.6 6.0 6 5.5 5.3 4

2 0

GEE GEE w/CO2 CoP CoP w/ CO2 Shell Shell w/ CO2 Capture Capture Capture 304

Cost and Performance Baseline for Fossil Energy Plants

4. PULVERIZED COAL RANKINE CYCLE PLANTS Four PC fired (PC) Rankine cycle power plant configurations were evaluated and the results are presented in this section. Each design is based on a market-ready technology that is assumed to be commercially available in time for the plant startup date. All designs employ a one-on-one configuration comprised of a state-of-the art PC steam generator firing Illinois No. 6 coal and a steam turbine.

The PC cases are evaluated with and without CO2 capture on a common 550 MWe net basis.

The designs that include CO2 capture have a larger gross unit size to compensate for the higher auxiliary loads. The constant net output sizing basis is selected because it provides for a meaningful side-by-side comparison of the results. The boiler and steam turbine industry ability to match unit size to a custom specification has been commercially demonstrated enabling common net output comparison of the PC cases in this study. As discussed in Section 0, this was not possible in the IGCC cases because of the fixed output from the CT. However, the net output from the PC cases falls in the range of outputs from the IGCC cases, which average 518 MW for CO2 capture cases and 625 MW for non-capture cases.

Steam conditions for the Rankine cycle cases were selected based on a survey of boiler and steam turbine original equipment manufacturers (OEM), who were asked for the most advanced steam conditions that they would guarantee for a commercial project in the US with subcritical and SC PC units rated at nominal 550 MWe net capacities and firing Illinois No. 6 coal [64].

Based on the OEM responses, the following single-reheat steam conditions were selected for the study:

For subcritical cases (9 and 10) - 16.5 MPa/566°C/566°C (2,400 psig/1,050°F/1,050°F)

For SC cases (11 and 12) - 24.1 MPa/593°C/593°C (3,500 psig/1,100°F/1,100°F)

While the current DOE program for the ultra SC cycle materials development targets 732°C/760°C (1,350ºF/1,400ºF) at 34.5 MPa (5,000 psi) cycle conditions to be available by 2015, and a similar Thermie program in the European Union (EU) has targeted 700°C/720°C (1,292ºF/1,328ºF) at about 29.0 MPa (4,200 psi) [65], steam temperature selection for boilers depends upon fuel corrosiveness. Most of the contacted OEMs were of the opinion that the steam conditions in this range would be limited to low sulfur coal applications (such as PRB).

Their primary concern is that elevated temperature operation while firing high sulfur coal (such as Illinois No. 6) would result in an exponential increase of the material wastage rates of the highest temperature portions of the superheater and RH due to coal ash corrosion, requiring pressure parts replacement outages approximately every 10 or 15 years. This cost would offset the value of fuel savings and emissions reduction due to the higher efficiency. The availability/reliability of the more exotic materials required to support the elevated temperature environment for high sulfur/chlorine applications, while extensively demonstrated in the laboratory [66], has not been commercially demonstrated. In addition, the three most recently built SC units in North America have steam cycles similar to this studys design basis, namely Genesee Phase 3 in Canada, which started operations in 2004 (25.0 MPa/570°C/568°C [3,625 psia/1,058°F/1,054°F]), Council Bluffs 4 in the United States, which started operation in 2007 (25.4 MPa/566°C/593°C [3,690 psia/1,050°F/1,100°F]), and Oak Creek 1 and 2, which are currently under construction (24.1 MPa/566°C [3,500 psig/1,050°F]).

305

Cost and Performance Baseline for Fossil Energy Plants The evaluation basis details, including site ambient conditions, fuel composition and the emissions control basis, are provided in Section 2 of this report.

4.1 PC COMMON PROCESS AREAS The PC cases have process areas that are common to each plant configuration, such as coal receiving and storage, emissions control technologies, power generation, etc. As detailed descriptions of these process areas in each case section would be burdensome and repetitious, they are presented in this section for general background information. The performance features of these sections are then presented in the case-specific sections.

4.1.1 Coal and Sorbent Receiving and Storage The function of the coal portion of the Coal and Sorbent Receiving and Storage system for PC plants is identical to the IGCC facilities. It is to provide the equipment required for unloading, conveying, preparing, and storing the fuel delivered to the plant. The scope of the system is from the trestle bottom dumper and coal receiving hoppers up to the coal storage silos. The system is designed to support short-term operation at the 5 percent over pressure/valves wide open (OP/VWO) condition (16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months ) and long-term operation of 90 days or more at the maximum continuous rating (MCR).

The scope of the sorbent receiving and storage system includes truck roadways, turnarounds, unloading hoppers, conveyors and the day storage bin.

Operation Description - The coal is delivered to the site by 100-car unit trains comprised of 91 tonne (100 ton) rail cars. The unloading is done by a trestle bottom dumper, which unloads the coal into two receiving hoppers. Coal from each hopper is fed directly into a vibratory feeder.

The 8 cm x 0 (3" x 0) coal from the feeder is discharged onto a belt conveyor. Two conveyors with an intermediate transfer tower are assumed to convey the coal to the coal stacker, which transfer the coal to either the long-term storage pile or 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, which transfers the coal to the coal surge bin located in the crusher tower. The coal is reduced in size to 2.5 cm x 0 (1" x 0) by the coal crushers. The coal is then transferred by conveyor to the transfer tower. In the transfer tower the coal is routed to the tripper that loads the coal into one of the six boiler silos.

Limestone is delivered to the site using 23 tonne (25 ton) trucks. The trucks empty into a below grade hopper where a feeder transfers the limestone to a conveyor for delivery to the storage pile.

Limestone from the storage pile is transferred to a reclaim hopper and conveyed to a day bin.

4.1.2 Steam Generator and Ancillaries The steam generator for the subcritical PC plants is a drum-type, wall-fired, balanced draft, natural circulation, totally enclosed dry bottom furnace, with superheater, reheater, economizer and air-heater.

The steam generator for the SC plants is a once-through, spiral-wound, Benson-boiler, wall-fired, balanced draft type unit with a water-cooled dry bottom furnace. It includes superheater, reheater, economizer, and air heater.

306

Cost and Performance Baseline for Fossil Energy Plants It is assumed for the purposes of this study that the power plant is designed to be operated as a base-loaded unit but with some consideration for daily or weekly cycling.

The combustion systems for both subcritical and SC steam conditions are equipped with LNBs and OFA. It is assumed for the purposes of this study that the power plant is designed for operation as a base-load unit.

Scope The steam generator includes the following for both subcritical and SC PCs:

Drum-type evaporator Economizer OFA system (subcritical only)

Once-through type steam Spray type desuperheater Forced draft (FD) fans generator (SC only)

Startup circuit, including Soot blower system Primary air (PA) fans integral separators (SC only)

Water-cooled furnace, Air preheaters Induced draft (ID) fans dry bottom (Ljungstrom type)

Two-stage superheater Coal feeders and pulverizers Reheater (RH) Low NOx Coal burners and light oil igniters/

warm-up system The steam generator operates as follows:

Feedwater and Steam For the subcritical steam system FW enters the economizer, recovers heat from the combustion gases exiting the steam generator, and then passes to the boiler drum, from where it is distributed to the water wall circuits enclosing the furnace. After passing through the lower and upper furnace circuits and steam drum in sequence, the steam passes through the convection enclosure circuits to the primary superheater and then to the secondary superheater.

The steam then exits the steam generator en route to the HP turbine. Steam from the HP turbine returns to the steam generator as cold reheat and returns to the IP turbine as hot reheat.

For the SC steam system FW enters the bottom header of the economizer and passes upward through the economizer tube bank, through stringer tubes, which support the primary superheater, and discharges to the economizer outlet headers. From the outlet headers, water flows to the furnace hopper inlet headers via external downcomers. Water then flows upward through the furnace hopper and furnace wall tubes. From the furnace, water flows to the steam water separator. During low load operation (operation below the Benson point), the water from the separator is returned to the economizer inlet with the boiler recirculating pump. Operation at loads above the Benson point is once through.

307

Cost and Performance Baseline for Fossil Energy Plants Steam flows from the separator through the furnace roof to the convection pass enclosure walls, primary superheater, through the first stage of water attemperation, to the furnace platens. From the platens, the steam flows through the second stage of attemperation and then to the intermediate superheater. The steam then flows to the final superheater and on to the outlet pipe terminal. Two stages of spray attemperation are used to provide tight temperature control in all high temperature sections during rapid load changes.

Steam returning from the turbine passes through the primary reheater surface, then through crossover piping containing inter-stage attemperation. The crossover piping feeds the steam to the final reheater banks and then out to the turbine. Inter-stage attemperation is used to provide outlet temperature control during load changes.

Air and Combustion Products Combustion air from the FD fans is heated in Ljungstrom type air preheaters, recovering heat energy from the exhaust gases exiting the boiler. This air is distributed to the burner windbox as secondary air. Air for conveying PC to the burners is supplied by the PA fans. This air is heated in the Ljungstrom type air preheaters to permit drying of the PC, and a portion of the air from the PA fans bypasses the air preheaters to be used for regulating the outlet coal/air temperature leaving the mills.

The PC and air mixture flows to the coal nozzles at various elevations of the furnace. The hot combustion products rise to the top of the boiler and pass through the superheater and reheater sections. The gases then pass through the economizer and air preheater. The gases exit the steam generator at this point and flow to the SCR reactor, fabric filter, ID fan, FGD system, and stack.

Fuel Feed The crushed Illinois No. 6 bituminous coal is fed through feeders to each of the mills (pulverizers), where its size is reduced to approximately 72 percent passing 200 mesh and less than 0.5 percent remaining on 50 mesh [ 67]. The PC exits each mill via the coal piping and is distributed to the coal nozzles in the furnace walls using air supplied by the PA fans.

Ash Removal The furnace bottom comprises several hoppers, with a clinker grinder under each hopper. The hoppers are of welded steel construction, lined with refractory. The hopper design incorporates a water-filled seal trough around the upper periphery for cooling and sealing. Water and ash discharged from the hopper pass through the clinker grinder to an ash sluice system for conveyance to hydrobins, where the ash is dewatered before it is transferred to trucks for offsite disposal. The description of the balance of the bottom ash handling system is presented in Section 4.1.9. The steam generator incorporates fly ash hoppers under the economizer outlet and air heater outlet.

Burners A boiler of this capacity employs approximately 24 to 36 coal nozzles arranged at multiple elevations. Each burner is designed as a low-NOx configuration, with staging of the coal combustion to minimize NOx formation. In addition, OFA nozzles are provided to further stage combustion and thereby minimize NOx formation.

308

Cost and Performance Baseline for Fossil Energy Plants Oil-fired pilot torches are provided for each coal burner for ignition, warm-up and flame stabilization at startup and low loads.

Air Preheaters Each steam generator is furnished with two vertical-shaft Ljungstrom regenerative type air preheaters. These units are driven by electric motors through gear reducers.

Soot Blowers The soot-blowing system utilizes an array of 50 to 150 retractable nozzles and lances that clean the furnace walls and convection surfaces with jets of HP steam. The blowers are sequenced to provide an effective cleaning cycle depending on the coal quality and design of the furnace and convection surfaces. Electric motors drive the soot blowers through their cycles.

4.1.3 NOx Control System The plant is designed to achieve the environmental target of 0.07 lb NOx/MMBtu. Two measures are taken to reduce the NOx. The first is a combination of LNBs and the introduction of staged OFA in the boiler. The LNBs and OFA reduce the emissions to about 0.5 lb/MMBtu.

The second measure taken to reduce the NOx emissions is the installation of an SCR system prior to the air heater. SCR uses ammonia and a catalyst to reduce NOx to N2 and H2O. The SCR system consists of three subsystems: reactor vessel, ammonia storage and injection, and gas flow control. The SCR system is designed for 86 percent reduction with 2 ppmv ammonia slip at the end of the catalyst life. This, along with the LNBs, achieves the emission limit of 0.07 lb/MMBtu.

The SCR capital costs are included with the boiler costs, as is the cost for the initial load of catalyst.

Selective non-catalytic reduction (SNCR) was considered for this application. However, with the installation of the LNBs and OFA system, the boiler exhaust gas contains relatively small amounts of NOx, which makes removal of the quantity of NOx with SNCR to reach the emissions limit of 0.07 lb/MMBtu difficult. SNCR works better in applications that contain medium to high quantities of NOx and require removal efficiencies in the range of 40 to 60 percent. SCR, because of the catalyst used in the reaction, can achieve higher efficiencies with lower concentrations of NOx.

SCR Operation Description The reactor vessel is designed to allow proper retention time for the ammonia to contact the NOx in the boiler exhaust gas. Ammonia is injected into the gas immediately prior to entering the reactor vessel. The catalyst contained in the reactor vessel enhances the reaction between the ammonia and the NOx in the gas. Catalysts consist of various active materials such as titanium dioxide, vanadium pentoxide, and tungsten trioxide. The operating range for vanadium/titanium-based catalysts is 260°C (500°F) to 455°C (850°F). The boiler is equipped with economizer bypass to provide FG to the reactors at the desired temperature during periods of low flow rate, such as low load operation. Also included with the reactor vessel is soot-blowing equipment used for cleaning the catalyst.

The ammonia storage and injection system consists of the unloading facilities, bulk storage tank, vaporizers, dilution air skid, and injection grid.

309

Cost and Performance Baseline for Fossil Energy Plants The FG flow control consists of ductwork, dampers, and flow straightening devices required to route the boiler exhaust to the SCR reactor and then to the air heater. The economizer bypass and associated dampers for low load temperature control are also included.

4.1.4 Particulate Control The fabric filter (or baghouse) consists of two separate single-stage, in-line, multi-compartment units. Each unit is of high (0.9-1.5 m/min [3-5 ft/min]) air-to-cloth ratio design with a pulse-jet on-line cleaning system. The ash is collected on the outside of the bags, which are supported by steel cages. The dust cake is removed by a pulse of compressed air. The bag material is polyphenylensulfide (PPS) with intrinsic Teflon Polytetrafluoroethylene (PTFE) coating [ 68].

The bags are rated for a continuous temperature of 180°C (356°F) and a peak temperature of 210°C (410°F). Each compartment contains a number of gas passages with filter bags, and heated ash hoppers supported by a rigid steel casing. The fabric filter is provided with necessary control devices, inlet gas distribution devices, insulators, inlet and outlet nozzles, expansion joints, and other items as required.

4.1.5 Mercury Removal Mercury removal is based on a coal Hg content of 0.15 ppmd. The basis for the coal Hg concentration was discussed in Section 2.4. The combination of pollution control technologies used in the PC plants, SCR, fabric filters and FGD, result in significant co-benefit capture of mercury. The SCR promotes the oxidation of elemental mercury, which in turn enhances the mercury removal capability of the fabric filter and FGD unit. The mercury co-benefit capture is assumed to be 90 percent for this combination of control technologies as described in Section 2.4. Co-benefit capture alone is sufficient to meet current NSPS mercury limits so no activated carbon injection is included in the PC cases.

4.1.6 Flue Gas Desulfurization The FGD system is a wet limestone forced oxidation positive pressure absorber non-reheat unit, with wet-stack, and gypsum production. The function of the FGD system is to scrub the boiler exhaust gases to remove the SO2 prior to release to the environment, or entering into the Carbon Dioxide Removal (CDR) facility. Sulfur removal efficiency is 98 percent in the FGD unit for all cases. For Cases 10 and 12 with CO2 capture, the SO2 content of the scrubbed gases must be further reduced to approximately 10 ppmv to minimize formation of amine heat stable salts (HSS) during the CO2 absorption process. The CDR unit includes a polishing scrubber to reduce the FG SO2 concentration from about 44 ppmv at the FGD exit to the required 10 ppmv prior to the CDR absorber. The scope of the FGD system is from the outlet of the ID fans to the stack inlet (Cases 9 and 11) or to the CDR process inlet (Cases 10 and 12). The system description is divided into three sections:

Limestone Handling and Reagent Preparation

FGD Scrubber

Byproduct Dewatering 310

Cost and Performance Baseline for Fossil Energy Plants Reagent Preparation System The function of the limestone reagent preparation system is to grind and slurry the limestone delivered to the plant. The scope of the system is from the day bin up to the limestone feed system. The system is designed to support continuous base load operation.

Operation Description - Each day bin supplies a 100 percent capacity ball mill via a weigh feeder. The wet ball mill accepts the limestone and grinds the limestone to 90 to 95 percent passing 325 mesh (44 microns). Water is added at the inlet to the ball mill to create limestone slurry. The reduced limestone slurry is then discharged into a mill slurry tank. Mill recycle pumps, two per tank, pump the limestone water slurry to an assembly of hydrocyclones and distribution boxes. The slurry is classified into several streams, based on suspended solids content and size distribution.

The hydrocyclone underflow with oversized limestone is directed back to the mill for further grinding. The hydrocyclone overflow with correctly sized limestone is routed to a reagent storage tank. Reagent distribution pumps direct slurry from the tank to the absorber module.

FGD Scrubber The FG exiting the air preheater section of the boiler passes through one of two parallel fabric filter units, then through the ID fans and into the one 100 percent capacity absorber module. The absorber module is designed to operate with counter-current flow of gas and reagent. Upon entering the bottom of the absorber vessel, the gas stream is subjected to an initial quenching spray of reagent. The gas flows upward through the spray zone, which provides enhanced contact between gas and reagent. Multiple spray elevations with header piping and nozzles maintain a consistent reagent concentration in the spray zone. Continuing upward, the reagent-laden gas passes through several levels of moisture separators. These consist of chevron-shaped vanes that direct the gas flow through several abrupt changes in direction, separating the entrained droplets of liquid by inertial effects. The scrubbed FG exits at the top of the absorber vessel and is routed to the plant stack or CDR process.

The scrubbing slurry falls to the lower portion of the absorber vessel, which contains a large inventory of liquid. Oxidation air is added to promote the oxidation of calcium sulfite contained in the slurry to calcium sulfate (gypsum). Multiple agitators operate continuously to prevent settling of solids and enhance mixture of the oxidation air and the slurry. Recirculation pumps recirculate the slurry from the lower portion of the absorber vessel to the spray level. Spare recirculation pumps are provided to ensure availability of the absorber.

The absorber chemical equilibrium is maintained by continuous makeup of fresh reagent, and blowdown of byproduct solids via the bleed pumps. A spare bleed pump is provided to ensure availability of the absorber. The byproduct solids are routed to the byproduct dewatering system.

The circulating slurry is monitored for pH and density.

This FGD system is designed for wet stack operation. Scrubber bypass or reheat, which may be utilized at some older facilities to ensure the exhaust gas temperature is above the saturation temperature, is not employed in this reference plant design because new scrubbers have improved mist eliminator efficiency, and detailed flow modeling of the flue interior enables the placement of gutters and drains to intercept moisture that may be present and convey it to a drain. Consequently, raising the exhaust gas temperature above the FGD discharge temperature of 57°C (135°F) (non-CO2 capture cases) or 32°C (89°F) (CO2 capture cases) is not necessary.

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Cost and Performance Baseline for Fossil Energy Plants Byproduct Dewatering The function of the byproduct dewatering system is to dewater the bleed slurry from the FGD absorber modules. The dewatering process selected for this plant is gypsum dewatering producing wallboard grade gypsum. The scope of the system is from the bleed pump discharge connections to the gypsum storage pile.

Operation Description - The recirculating reagent in the FGD absorber vessel accumulates dissolved and suspended solids on a continuous basis as byproducts from the SO2 absorption process. Maintenance of the quality of the recirculating slurry requires that a portion be withdrawn and replaced by fresh reagent. This is accomplished on a continuous basis by the bleed pumps pulling off byproduct solids and the reagent distribution pumps supplying fresh reagent to the absorber.

Gypsum (calcium sulfate) is produced by the injection of oxygen into the calcium sulfite produced in the absorber tower sump. The bleed from the absorber contains approximately 20 wt% gypsum. The absorber slurry is pumped by an absorber bleed pump to a primary dewatering hydrocyclone cluster. The primary hydrocyclone performs two process functions.

The first function is to dewater the slurry from 20 wt% to 50 wt% solids. The second function of the primary hydrocyclone is to perform a CaCO3 and CaSO4*2H2O separation. This process ensures a limestone stoichiometry in the absorber vessel of 1.10 and an overall limestone stoichiometry of 1.05. This system reduces the overall operating cost of the FGD system. The underflow from the hydrocyclone flows into the filter feed tank, from which it is pumped to a horizontal belt vacuum filter. Two 100 percent filter systems are provided for redundant capacity.

Hydrocyclones The hydrocyclone is a simple and reliable device (no moving parts) designed to increase the slurry concentration in one step to approximately 50 wt%. This high slurry concentration is necessary to optimize operation of the vacuum belt filter.

The hydrocyclone feed enters tangentially and experiences centrifugal motion so that the heavy particles move toward the wall and flow out the bottom. Some of the lighter particles collect at the center of the cyclone and flow out the top. The underflow is thus concentrated from 20 wt%

at the feed to 50 wt%.

Multiple hydrocyclones are used to process the bleed stream from the absorber. The hydrocyclones are configured in a cluster with a common feed header. The system has two hydrocyclone clusters, each with five 15 cm (6 inch) diameter units. Four cyclones are used to continuously process the bleed stream at design conditions, and one cyclone is spare.

Cyclone overflow and underflow are collected in separate launders. The overflow from the hydrocyclones still contains about 5 wt% solids, consisting of gypsum, fly ash, and limestone residues and is sent back to the absorber. The underflow of the hydrocyclones flows into the filter feed tank from where it is pumped to the horizontal belt vacuum filters.

Horizontal Vacuum Belt Filters The secondary dewatering system consists of horizontal vacuum belt filters. The pre-concentrated gypsum slurry (50 wt%) is pumped to an overflow pan through which the slurry flows onto the vacuum belt. As the vacuum is pulled, a layer of cake is formed. The cake is 312

Cost and Performance Baseline for Fossil Energy Plants dewatered to approximately 90 wt% solids as the belt travels to the discharge. At the discharge end of the filter, the filter cloth is turned over a roller where the solids are dislodged from the filter cloth. This cake falls through a chute onto the pile prior to the final byproduct uses. The required vacuum is provided by a vacuum pump. The filtrate is collected in a filtrate tank that provides surge volume for use of the filtrate in grinding the limestone. Filtrate that is not used for limestone slurry preparation is returned to the absorber.

4.1.7 Carbon Dioxide Recovery Facility A Carbon Dioxide Recovery (CDR) facility is used in Cases 10 and 12 to remove 90 percent of the CO2 in the flue gas exiting the FGD unit, purify it, and compress it to a SC condition. The flue gas exiting the FGD unit contains about 1 percent more CO2 than the raw flue gas because of the CO2 liberated from the limestone in the FGD absorber vessel. The CDR is comprised of the flue gas supply, SO2 polishing, CO2 absorption, solvent stripping and reclaiming, and CO2 compression and drying.

The CO2 absorption/stripping/solvent reclaim process for Cases 10 and 12 is based on the Fluor Econamine FG PlusSM technology [69, 70]. A typical flowsheet is shown in Exhibit 4-1. The Econamine FG Plus process uses a formulation of MEA and a proprietary corrosion inhibitor to recover CO2 from the flue gas. This process is designed to recover high-purity CO2 from LP streams that contain oxygen, such as flue gas from coal-fired power plants, GT exhaust gas, and other waste gases. The Econamine process used in this study differs from previous studies, including the 2003 IEA study, [71] in the following ways:

The complexity of the control and operation of the plant is significantly decreased

Solvent consumption is decreased

Hard to dispose waste from the plant is greatly reduced The above are achieved at the expense of a slightly higher steam requirement in the stripper (3,556 kJ/kg) [1,530 Btu/lb] versus 3,242 kJ/kg [1,395 Btu/lb] used in the IEA study) [72].

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Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-1 Fluor Econamine FG PlusSM Typical Flow Diagram 314

Cost and Performance Baseline for Fossil Energy Plants SO2 Polishing and FG Cooling and Supply To minimize the accumulation of HSS, the incoming flue gas must have an SO2 concentration of 10 ppmv or less. The gas exiting the FGD system passes through an SO2 polishing step to achieve this objective. The polishing step consists of a non-plugging, low-differential-pressure, spray-baffle-type scrubber using a 20 wt% solution of sodium hydroxide (NaOH). A removal efficiency of about 75 percent is necessary to reduce SO2 emissions from the FGD outlet to 10 ppmv as required by the Econamine process. The polishing scrubber proposed for this application has been demonstrated in numerous industrial applications throughout the world and can achieve removal efficiencies of over 95 percent if necessary.

The polishing scrubber also serves as the flue gas cooling system. Cooling water from the PC plant is used to reduce the flue gas temperature to below the adiabatic saturation temperature resulting in a reduction of the flue gas moisture content. Flue gas is cooled beyond the CO2 absorption process requirements to 32°C (90°F) to account for the subsequent temperature increase of about 17°C (30°F) in the flue gas blower. Downstream from the Polishing Scrubber flue gas pressure is boosted in the FG Blowers by approximately 0.014 MPa (2 psi) to overcome pressure drop in the CO2 absorber tower.

Circulating Water System Cooling water is provided from the PC plant CWS and returned to the PC plant cooling tower.

The CDR facility requires a significant amount of cooling water for flue gas cooling, water wash cooling, absorber intercooling, reflux condenser duty, reclaimer cooling, the lean solvent cooler, and CO2 compression interstage cooling. The cooling water requirements for the CDR facility in the two PC capture cases range from 1,173,350-1,286,900 lpm (310,000-340,000 gpm), which greatly exceeds the PC plant cooling water requirement of 643,450-757,000 lpm (170,000-200,000 gpm).

CO2 Absorption Section The cooled flue gas enters the bottom of the CO2 Absorber and flows up through the tower countercurrent to a stream of lean MEA-based solvent. Approximately 90 percent of the CO2 in the feed gas is absorbed into the lean solvent, and the rest leaves the top of the absorber section and flows into the water wash section of the tower. The lean solvent enters the top of the absorber section, absorbs the CO2 from the FG and leaves the bottom of the absorber with the absorbed CO2. The FG Plus process also includes solvent intercooling. The semi-rich solvent is extracted from the column, cooled using cooling water, and returned to the absorber section just below the extraction point. The CO2 carrying capacity of the solvent is increased at lower temperature, which reduces the solvent circulation rate.

Water Wash Section The purpose of the Water Wash section is to minimize solvent losses due to mechanical entrainment and evaporation. The flue gas from the top of the CO2 Absorption section is contacted with a re-circulating stream of water for the removal of most of the lean solvent. The scrubbed gases, along with unrecovered solvent, exit the top of the wash section for discharge to the atmosphere via the vent stack. The water stream from the bottom of the wash section is collected on a chimney tray. A portion of the water collected on the chimney tray spills over to 315

Cost and Performance Baseline for Fossil Energy Plants the absorber section as water makeup for the amine with the remainder pumped via the Wash Water Pump, cooled by the Water Wash Cooler, and recirculated to the top of the CO2 Absorber.

The wash water level is maintained by wash water makeup.

Rich/Lean Amine Heat Exchange System The rich solvent from the bottom of the CO2 Absorber is preheated by the lean solvent from the Solvent Stripper in the Lean/Rich Cross Exchanger. The heated rich solvent is routed to the Solvent Stripper for removal of the absorbed CO2. The stripped solvent from the bottom of the Solvent Stripper is pumped via the Lean Solvent Pump to the Lean Solvent Cooler. A slipstream of the lean solvent is then sent through the Amine Filter Package to prevent buildup of contaminants in the solution. The filtered lean solvent is mixed with the remaining lean solvent from the Lean Solvent Cooler and sent to the CO2 Absorber, completing the circulating solvent circuit.

Solvent Stripper The purpose of the Solvent Stripper is to separate the CO2 from the rich solvent feed exiting the bottom of the CO2 Absorber. The rich solvent is collected on a chimney tray below the bottom packed section of the Stripper and routed to the Reboiler where the rich solvent is heated by steam, stripping the CO2 from the solution. Steam is provided from the crossover pipe between the IP and LP sections of the steam turbine and is 0.5 MPa (74 psia) and 152°C (306°F) for the two PC cases. The hot wet vapor from the top of the stripper containing CO2, steam, and solvent vapor, is partially condensed in the Reflux Condenser by cross exchanging the hot wet vapor with cooling water. The partially condensed stream then flows to the Reflux Drum where the vapor and liquid are separated. The uncondensed CO2-rich gas is then delivered to the CO2 product compressor. The condensed liquid from the Reflux Drum is pumped via the Reflux Pump where a portion of condensed overhead liquid is combined with the lean solvent entering the CO2 Absorber. The rest of the pumped liquid is routed back to the Solvent Stripper as reflux, which aids in limiting the amount of solvent vapors entering the stripper overhead system.

Solvent Reclaimer The low temperature reclaimer technology is a recent development for the FG Plus technology.

A small slipstream of the lean solvent is fed to the Solvent Reclaimer for the removal of high-boiling nonvolatile impurities including HSS, volatile acids and iron products from the circulating solvent solution. Reclaiming occurs in two steps, the first is an ion-exchange process.

There is a small amount of degradation products that cannot be removed via ion-exchange, and a second atmospheric pressure reclaiming process is used to remove the degradation products. The solvent reclaimer system reduces corrosion, foaming and fouling in the solvent system. The reclaimed solvent is returned to the Solvent Stripper and the spent solvent is pumped via the Solvent Reclaimer Drain Pump to the Solvent Reclaimer Drain Tank for disposal. The quantity of spent solvent is greatly reduced from the previously used thermal reclaimer systems.

Steam Condensate Steam condensate from the Solvent Stripper Reclaimer accumulates in the Solvent Reclaimer Condensate Drum and is level controlled to the Solvent Reboiler Condensate Drum. Steam condensate from the Solvent Stripper Reboilers is also collected in the Solvent Reboiler 316

Cost and Performance Baseline for Fossil Energy Plants Condensate Drum and returned to the steam cycle between BFW heaters 4 and 5 via the Solvent Reboiler Condensate Pumps.

Corrosion Inhibitor System A proprietary corrosion inhibitor is intermittently injected into the CO2 Absorber rich solvent bottoms outlet line. This additive is to help control the rate of corrosion throughout the CO2 recovery plant system.

Gas Compression and Drying System In the compression section, the CO2 is compressed to 15.3 MPa (2,215 psia) by a six-stage centrifugal compressor. The discharge pressures of the stages were balanced to give reasonable power distribution and discharge temperatures across the various stages as shown in Exhibit 4-2.

Exhibit 4-2 CO2 Compressor Interstage Pressures Outlet Pressure, Stage MPa (psia) 1 0.36 (52) 2 0.78 (113) 3 1.71 (248) 4 3.76 (545) 5 8.27 (1,200) 6 15.3 (2,215)

Power consumption for this large compressor was estimated assuming a polytropic efficiency of 86 percent and a mechanical efficiency of 98 percent for all stages. During compression to 15.3 MPa (2,215 psia) in the multiple-stage, intercooled compressor, the CO2 stream is dehydrated to a dewpoint of -40ºC (-40°F) with triethylene glycol. The virtually moisture-free SC CO2 stream is delivered to the plant battery limit as sequestration ready. CO2 TS&M costs were estimated and included in LCOE and COE using the methodology described in Section 2.7.

Several alternatives to rejecting the heat of CO2 compression to cooling water were investigated in a separate study [73]. The first alternative consisted of using a portion of the heat to pre-heat BFW while the remaining heat was still rejected to cooling water. This configuration resulted in an increase in efficiency of 0.3 percentage points (absolute). The second alternative modified the CO2 compression intercooling configuration to enable integration into a LiBr-H2O absorption refrigeration system, where water is the refrigerant. In the CO2 compression section, the single intercooler between each compression stage was replaced with one kettle reboiler and two counter current shell and tube heat exchangers. The kettle reboiler acts as the generator that rejects heat from CO2 compression to the LiBr-H2O solution to enable the separation of the refrigerant from the brine solution. The second heat exchanger rejects heat to the cooling water.

The evaporator heat exchanger acts as the refrigerator and cools the CO2 compression stream by vaporizing the refrigerant. Only five stages of CO2 compression were necessary for Approach 2.

The compression ratios were increased from the reference cases to create a compressor outlet 317

Cost and Performance Baseline for Fossil Energy Plants temperature of at least 200°F to maintain a temperature gradient of 10°F in the kettle reboiler.

This configuration resulted in an efficiency increase of 0.1 percentage points (absolute).

It was concluded that the small increase in efficiency did not justify the added cost and complexity of the two configurations and hence they were not incorporated into the base design.

4.1.8 Power Generation The steam turbine is designed for long-term operation (90 days or more) at MCR with throttle control valves 95 percent open. It is also capable of a short-term 5 percent OP/VWO condition (16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months ).

For the subcritical cases, the steam turbine is a tandem compound type, consisting of HP-IP-two LP (double flow) sections enclosed in three casings, designed for condensing single reheat operation, and equipped with non-automatic extractions and four-flow exhaust. The turbine drives a hydrogen-cooled generator. The turbine has DC motor-operated lube oil pumps, and main lube oil pumps, which are driven off the turbine shaft [74]. The exhaust pressure is 50.8 cm (2 in) Hg in the single pressure condenser. There are seven extraction points. The condenser is two-shell, transverse, single pressure with divided waterbox for each shell.

The steam-turbine generator systems for the SC plants are similar in design to the subcritical systems. The differences include steam cycle conditions and eight extractions points versus seven for the subcritical design.

Turbine bearings are lubricated by a closed-loop, water-cooled pressurized oil system. Turbine shafts are sealed against air in-leakage or steam blowout using a labyrinth gland arrangement connected to a LP steam seal system. The generator stator is cooled with a CL water system consisting of circulating pumps, shell and tube or plate and frame type heat exchangers, filters, and deionizers, all skid-mounted. The generator rotor is cooled with a hydrogen gas recirculation system using fans mounted on the generator rotor shaft.

Operation Description - The turbine stop valves, control valves, reheat stop valves, and intercept valves are controlled by an electro-hydraulic control system. Main steam from the boiler passes through the stop valves and control valves and enters the turbine at 16.5 MPa/566°C (2,400 psig/1,050ºF) for the subcritical cases and 24.1MPa /593°C (3,500psig/1,100°F) for the SC cases. The steam initially enters the turbine near the middle of the HP span, flows through the turbine, and returns to the boiler for reheating. The reheat steam flows through the reheat stop valves and intercept valves and enters the IP section at 566°C (1,050ºF) in the subcritical cases and 593°C (1,100°F) in the SC cases. After passing through the IP section, the steam enters a crossover pipe, which transports the steam to the two LP sections.

The steam divides into four paths and flows through the LP sections exhausting downward into the condenser.

The turbine is designed to operate at constant inlet steam pressure over the entire load range.

4.1.9 Balance of Plant The balance of plant components consist of the condensate, FW, main and reheat steam, extraction steam, ash handling, ducting and stack, waste treatment and miscellaneous systems as described below.

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Cost and Performance Baseline for Fossil Energy Plants Condensate The function of the condensate system is to pump condensate from the condenser hotwell to the deaerator, through the gland steam condenser and the LP FW heaters. Each system consists of one main condenser; two variable speed electric motor-driven vertical condensate pumps each sized for 50 percent capacity; one gland steam condenser; four LP heaters; and one deaerator with 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 downstream of the gland steam condenser to maintain minimum flow requirements for the gland steam condenser and the condensate pumps.

LP FW heaters 1 through 4 are 50 percent capacity, parallel flow, and are located in the condenser neck. All remaining FW heaters are 100 percent capacity shell and U-tube heat exchangers. Each LP FW heater is provided with inlet/outlet isolation valves and a full capacity bypass. LP FW heater drains cascade down to the next lowest extraction pressure heater and finally discharge into the condenser. Pneumatic level control valves control normal drain levels in the heaters. High heater level dump lines discharging to the condenser are provided for each heater for turbine water induction protection. Pneumatic level control valves control dump line flow.

Feedwater The function of the FW system is to pump the FW from the deaerator storage tank through the HP FW heaters to the economizer. One turbine-driven BFW pump sized at 100 percent capacity is provided to pump FW through the HP FW heaters. One 25 percent motor-driven BFW pump is provided for startup. The pumps are provided with inlet and outlet isolation valves, and individual minimum flow recirculation lines discharging back to the deaerator storage tank. The recirculation flow is controlled by automatic recirculation valves, which are a combination check valve in the main line and in the bypass, bypass control valve, and flow sensing element. The suction of the boiler feed pump is equipped with startup strainers, which are utilized during initial startup and following major outages or system maintenance.

Each HP FW heater is provided with inlet/outlet isolation valves and a full capacity bypass. FW heater drains cascade down to the next lowest extraction pressure heater and finally discharge into the deaerator. Pneumatic level control valves control normal drain level in the heaters.

High heater level dump lines discharging to the condenser are provided for each heater for turbine water induction protection. Dump line flow is controlled by pneumatic level control valves.

The deaerator is a horizontal, spray tray type with internal direct contact stainless steel (SS) vent condenser and storage tank. The boiler feed pump turbine is driven by main steam up to 60 percent plant load. Above 60 percent load, extraction from the IP turbine exhaust (1.05 MPa/395°C [153 psig/743°F]) provides steam to the boiler feed pump steam turbine.

Main and Reheat Steam The function of the main steam system is to convey main steam from the boiler superheater outlet to the HP turbine stop valves. The function of the reheat system is to convey steam from the HP turbine exhaust to the boiler reheater and from the boiler reheater outlet to the IP turbine stop valves.

319

Cost and Performance Baseline for Fossil Energy Plants Main steam exits the boiler superheater through a motor-operated stop/check valve and a motor-operated gate valve and is routed in a single line feeding the HP turbine. A branch line off the IP turbine exhaust feeds the boiler feed water pump turbine during unit operation starting at approximately 60 percent load.

Cold reheat steam exits the HP turbine, flows through a motor-operated isolation gate valve and a flow control valve, and enters the boiler reheater. Hot reheat steam exits the boiler reheater through a motor-operated gate valve and is routed to the IP turbine. A branch connection from the cold reheat piping supplies steam to FW heater 7.

Extraction Steam The function of the extraction steam system is to convey steam from turbine extraction points through the following routes:

From HP turbine exhaust (cold reheat) to heater 7 From IP turbine extraction to heater 6 and the deaerator (heater 5)

From LP turbine extraction to heaters 1, 2, 3, and 4 The turbine is protected from overspeed on turbine trip, from flash steam reverse flow from the heaters through the extraction piping to the turbine. This protection is provided by positive closing, balanced disc non-return valves located in all extraction lines except the lines to the LP FW heaters in the condenser neck. The extraction non-return valves are located only in horizontal runs of piping and as close to the turbine as possible.

The turbine trip signal automatically trips the non-return valves through relay dumps. The remote manual control for each heater level control system is used to release the non-return valves to normal check valve service when required to restart the system.

Circulating Water System It is assumed that the plant is serviced by a public water facility and has access to groundwater for use as makeup cooling water with minimal pretreatment. All filtration and treatment of the circulating water are conducted on site. A mechanical draft, wood frame, counter-flow cooling tower is provided for the circulating water heat sink. Two 50 percent CWPs are provided. The CWS provides cooling water to the condenser, the auxiliary cooling water system, and the CDR facility in capture cases.

The auxiliary cooling water system is a CL system. Plate and frame heat exchangers with circulating water as the cooling medium are provided. This system provides cooling water to the lube oil coolers, turbine generator, boiler feed pumps, etc. All pumps, vacuum breakers, air release valves, instruments, controls, etc. are included for a complete operable system.

The CDR system in Cases 10 and 12 requires a substantial amount of cooling water that is provided by the PC plant CWS. The additional cooling load imposed by the CDR is reflected in the significantly larger CWPs and cooling tower in those cases.

Ash Handling System The function of the ash handling system is to provide the equipment required for conveying, preparing, storing, and disposing of the fly ash and bottom ash produced on a daily basis by the boiler. The scope of the system is from the baghouse hoppers, air heater and economizer hopper 320

Cost and Performance Baseline for Fossil Energy Plants collectors, and bottom ash hoppers to the hydrobins (for bottom ash) and truck filling stations (for fly ash). The system is designed to support short-term operation at the 5 percent OP/VWO condition (16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months ) and long-term operation at the 100 percent guarantee point (90 days or more).

The fly ash collected in the baghouse and the air heaters is conveyed to the fly ash storage silo.

A pneumatic transport system using LP air from a blower provides the transport mechanism for the fly ash. Fly ash is discharged through a wet unloader, which conditions the fly ash and conveys it through a telescopic unloading chute into a truck for disposal.

The bottom ash from the boiler is fed into a clinker grinder. The clinker grinder is provided to break up any clinkers that may form. From the clinker grinders the bottom ash is sluiced to hydrobins for dewatering and offsite removal by truck.

Ash from the economizer hoppers and pyrites (rejected from the coal pulverizers) is conveyed using water to the economizer/pyrites transfer tank. This material is then sluiced on a periodic basis to the hydrobins.

Ducting and Stack One stack is provided with a single fiberglass-reinforced plastic (FRP) liner. The stack is constructed of reinforced concrete. The stack is 152 m (500 ft) high for adequate particulate dispersion.

Waste Treatment/Miscellaneous Systems An onsite water treatment facility treats all runoff, cleaning wastes, blowdown, and backwash to within the U.S. EPA standards for suspended solids, oil and grease, pH, and miscellaneous metals. 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 dewatering. 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, dry lime feeder, lime slurry tank, slurry tank mixer, and lime slurry feed pumps.

The oxidation system consists of an air compressor, which injects air through a sparger pipe into the second-stage neutralization tank. The flocculation tank is fiberglass with a variable speed agitator. A polymer dilution and feed system is also provided for flocculation. The clarifier is a plate-type, with the sludge pumped to the dewatering system. The sludge is dewatered in filter presses and disposed offsite. Trucking and disposal costs are included in the cost estimate. The filtrate from the sludge dewatering is returned to the raw waste sump.

Miscellaneous systems consisting of fuel oil, service air, instrument air, and service water are provided. A 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.

321

Cost and Performance Baseline for Fossil Energy Plants Buildings and Structures 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 Fuel oil pump house Guard house Boiler building Coal crusher building Runoff water pump house Administration and Continuous emissions Industrial waste treatment service building monitoring building building Makeup water and Pump house and electrical FGD system buildings pretreatment building equipment building 4.1.10 Accessory Electric Plant The accessory electric plant consists of switchgear and control equipment, generator equipment, station service equipment, conduit and cable trays, and wire and cable. It also includes the main power transformer, required foundations, and standby equipment.

4.1.11 Instrumentation and Control An integrated plant-wide control and monitoring DCS is provided. The DCS is a redundant microprocessor-based, functionally distributed system. The control room houses an array of multiple video monitor and keyboard units. The monitor/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.

4.2 SUBCRITICAL PC CASES This section contains an evaluation of plant designs for Cases 9 and 10, which are based on a subcritical PC plant with a nominal net output of 550 MWe. Both plants use a single reheat 16.5 MPa/566°C/566°C (2400 psig/1050°F/1050°F) cycle. The only difference between the two plants is that Case 10 includes CO2 capture while Case 9 does not.

The balance of Section 4.2 is organized as follows:

Process and System Description provides an overview of the technology operation as applied to Case 9. The systems that are common to all PC cases were covered in Section 4.1 and only features that are unique to Case 9 are discussed further in this section.

Key Assumptions is a summary of study and modeling assumptions relevant to Cases 9 and 10.

Sparing Philosophy is provided for both Cases 9 and 10.

322

Cost and Performance Baseline for Fossil Energy Plants

Performance Results provides the main modeling results from Case 9, including the performance summary, environmental performance, carbon/sulfur balances, water balance, mass and energy balance diagrams and energy balance table.

Equipment List provides an itemized list of major equipment for Case 9 with account codes that correspond to the cost accounts in the Cost Estimates section.

Cost Estimates provides a summary of capital and operating costs for Case 9.

Process and System Description, Performance Results, Equipment List and Cost Estimates are discussed for Case 10.

4.2.1 Process Description In this section the subcritical PC process without CO2 capture is described. The system description follows the BFD in Exhibit 4-3 and stream numbers reference the same Exhibit. The tables in Exhibit 4-4 provide process data for the numbered streams in the BFD.

Coal (stream 8) and PA (stream 4) are introduced into the boiler through the wall-fired burners.

Additional combustion air, including the OFA, is provided by the FD fans (stream 1). The boiler operates at a slight negative pressure so air leakage is into the boiler, and the infiltration air is accounted for in stream 7. Streams 3 and 6 show Ljungstrom air preheater leakages from the FD and PA fan outlet streams to the boiler exhaust.

FG exits the boiler through the SCR reactor (stream 10) and is cooled to 169°C (337°F) in the combustion air preheater before passing through a fabric filter for particulate removal (stream 12). An ID fan increases the FG temperature to 181°C (357°F) and provides the motive force for the FG (stream 13) to pass through the FGD unit. FGD inputs and outputs include makeup water (stream 15), oxidation air (stream 16), limestone slurry (stream 14) and product gypsum (stream 17). The clean, saturated FG exiting the FGD unit (stream 18) passes to the plant stack and is discharged to atmosphere.

323

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-3 Case 9 Block Flow Diagram, Subcritical Unit without CO2 Capture 324

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-4 Case 9 Stream Table, Subcritical Unit without CO2 Capture 1 2 3 4 5 6 7 8 9 10 11 12 V-L Mole Fraction Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1447 0.0000 0.1447 H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0868 0.0000 0.0868 N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7325 0.0000 0.7325 O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0250 0.0000 0.0250 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 V-L Flowrate (kgmol/hr) 51,817 51,817 1,535 15,918 15,918 2,191 1,195 0 0 72,904 0 72,904 V-L Flowrate (kg/hr) 1,495,285 1,495,285 44,287 459,336 459,336 63,217 34,480 0 0 2,168,255 0 2,168,255 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 198,391 3,848 15,390 15,390 0 Temperature (°C) 15 19 19 15 25 25 15 15 15 169 15 169 Pressure (MPa, abs) 0.10 0.11 0.11 0.10 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10 Enthalpy (kJ/kg)A 30.23 34.36 34.36 30.23 40.78 40.78 30.23 --- --- 327.06 --- 308.70 Density (kg/m3) 1.2 1.2 1.2 1.2 1.3 1.3 1.2 --- --- 0.8 --- 0.8 V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 28.857 28.857 --- --- 29.741 --- 29.741 V-L Flowrate (lbmol/hr) 114,237 114,237 3,383 35,092 35,092 4,830 2,634 0 0 160,726 0 160,726 V-L Flowrate (lb/hr) 3,296,540 3,296,540 97,637 1,012,663 1,012,663 139,369 76,015 0 0 4,780,183 0 4,780,183 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 437,378 8,482 33,929 33,929 0 Temperature (°F) 59 66 66 59 78 78 59 59 59 337 59 337 Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16.1 14.7 14.7 14.7 14.4 14.7 14.2 Enthalpy (Btu/lb)A 13.0 14.8 14.8 13.0 17.5 17.5 13.0 --- --- 140.6 --- 132.7 Density (lb/ft 3) 0.076 0.078 0.078 0.076 0.081 0.081 0.076 --- --- 0.050 --- 0.049 A - Reference conditions are 32.02 F & 0.089 PSIA 325

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-4 Case 9 Stream Table, Subcritical Unit without CO2 Capture (Continued) 13 14 15 16 17 18 19 20 21 22 23 V-L Mole Fraction Ar 0.0087 0.0000 0.0000 0.0128 0.0000 0.0082 0.0000 0.0000 0.0000 0.0000 0.0000 CO2 0.1447 0.0000 0.0000 0.0005 0.0004 0.1350 0.0000 0.0000 0.0000 0.0000 0.0000 H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2O 0.0868 1.0000 1.0000 0.0062 0.9995 0.1517 1.0000 1.0000 1.0000 1.0000 1.0000 N2 0.7325 0.0000 0.0000 0.7506 0.0000 0.6808 0.0000 0.0000 0.0000 0.0000 0.0000 O2 0.0250 0.0000 0.0000 0.2300 0.0000 0.0243 0.0000 0.0000 0.0000 0.0000 0.0000 SO2 0.0021 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 V-L Flowrate (kgmol/hr) 72,904 2,530 10,275 775 188 79,300 93,366 85,851 85,851 76,805 77,739 V-L Flowrate (kg/hr) 2,168,255 45,571 185,106 22,509 3,383 2,287,903 1,682,017 1,546,628 1,546,628 1,383,663 1,400,483 Solids Flowrate (kg/hr) 0 19,690 0 0 30,645 0 0 0 0 0 0 Temperature (°C) 181 15 15 167 57 57 566 363 566 38 39 Pressure (MPa, abs) 0.11 0.10 0.10 0.31 0.10 0.10 16.65 4.28 3.90 0.01 1.69 Enthalpy (kJ/kg)A 320.79 --- -46.80 177.65 --- 297.69 3,472.33 3,120.82 3,594.06 2,016.19 165.31 Density (kg/m3) 0.8 --- 1,003.1 2.5 --- 1.1 47.7 15.7 10.3 0.1 993.3 V-L Molecular Weight 29.741 --- 18.015 29.029 --- 28.851 18.015 18.015 18.015 18.015 18.015 V-L Flowrate (lbmol/hr) 160,726 5,577 22,652 1,709 414 174,826 205,837 189,269 189,269 169,326 171,384 V-L Flowrate (lb/hr) 4,780,183 100,467 408,090 49,625 7,459 5,043,963 3,708,212 3,409,730 3,409,730 3,050,454 3,087,536 Solids Flowrate (lb/hr) 0 43,410 0 0 67,561 0 0 0 0 0 0 Temperature (°F) 357 59 59 333 135 135 1,050 686 1,050 101 103 Pressure (psia) 15.3 15.0 14.7 45.0 14.8 14.8 2,415.0 620.5 565.5 1.0 245.0 Enthalpy (Btu/lb)A 137.9 --- -20.1 76.4 --- 128.0 1,492.8 1,341.7 1,545.2 866.8 71.1 Density (lb/ft 3) 0.052 --- 62.622 0.154 --- 0.067 2.977 0.983 0.643 0.004 62.010 326

Cost and Performance Baseline for Fossil Energy Plants 4.2.2 Key System Assumptions System assumptions for Cases 9 and 10, subcritical PC with and without CO2 capture, are compiled in Exhibit 4-5.

Exhibit 4-5 Subcritical PC Plant Study Configuration Matrix Case 9 Case 10 w/o CO2 Capture w/CO2 Capture 16.5/566/566 16.5/566/566 Steam Cycle, MPa/°C/°C (psig/°F/°F)

(2400/1050/1050) (2400/1050/1050)

Coal Illinois No. 6 Illinois No. 6 Condenser pressure, mm Hg (in Hg) 50.8 (2) 50.8 (2)

Boiler Efficiency, % 88 88 Cooling water to condenser, °C (ºF) 16 (60) 16 (60)

Cooling water from condenser, °C (ºF) 27 (80) 27 (80)

Stack temperature, °C (°F) 57 (135) 32 (89)

Wet Limestone Wet Limestone SO2 Control Forced Oxidation Forced Oxidation FGD Efficiency, % (A) 98 98 (B, C)

LNB w/OFA and LNB w/OFA and NOx Control SCR SCR SCR Efficiency, % (A) 86 86 Ammonia Slip (end of catalyst life),

2 2 ppmv Particulate Control Fabric Filter Fabric Filter Fabric Filter efficiency, % (A) 99.8 99.8 Ash Distribution, Fly/Bottom 80% / 20% 80% / 20%

Mercury Control Co-benefit Capture Co-benefit Capture Mercury removal efficiency, % (A) 90 90 CO2 Control N/A Econamine Overall CO2 Capture (A) N/A 90.2%

Off-site Saline CO2 Sequestration N/A Formation A. Removal efficiencies are based on the FG content B. An SO2 polishing step is included to meet more stringent SOx content limits in the FG (< 10 ppmv) to reduce formation of amine HSS during the CO2 absorption process C. SO2 exiting the post-FGD polishing step is absorbed in the CO2 capture process making stack emissions negligible Balance of Plant - Cases 9 and 10 The balance of plant assumptions are common to all cases and are presented in Exhibit 4-6.

327

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-6 Balance of Plant Assumptions Cooling system Recirculating Wet Cooling Tower Fuel and Other storage Coal 30 days Ash 30 days Gypsum 30 days Limestone 30 days Plant Distribution Voltage Motors below 1 hp 110/220 volt Motors between 1 hp and 250 hp 480 volt Motors between 250 hp and 4,160 volt 5,000 hp Motors above 5,000 hp 13,800 volt Steam and GT generators 24,000 volt Grid Interconnection voltage 345 kV Water and Waste Water Makeup Water The water supply is 50 percent from a local POTW and 50 percent from groundwater, and is assumed to be in sufficient quantities to meet plant makeup requirements.

Makeup for potable, process, and DI water is drawn from municipal sources.

Process Wastewater Storm water that contacts equipment surfaces is collected and treated for discharge through a permitted discharge.

Sanitary Waste Disposal Design includes a packaged domestic sewage treatment plant with effluent discharged to the industrial wastewater treatment system. Sludge is hauled off site. Packaged plant is sized for 5.68 cubic meters per day (1,500 gallons per day)

Water Discharge Most of the process wastewater is recycled to the cooling tower basin. Blowdown will be treated for chloride and metals, and discharged.

328

Cost and Performance Baseline for Fossil Energy Plants 4.2.3 Sparing Philosophy Single trains are used throughout the design with exceptions where equipment capacity requires an additional train. There is no redundancy other than normal sparing of rotating equipment.

The plant design consists of the following major subsystems:

One dry-bottom, wall-fired PC subcritical boiler (1 x 100%)

Two SCR reactors (2 x 50%)

Two single-stage, in-line, multi-compartment fabric filters (2 x 50%)

One wet limestone forced oxidation positive pressure absorber (1 x 100%)

One steam turbine (1 x 100%)

For Case 10 only, two parallel Econamine CO2 absorption systems, with each system consisting of two absorbers, strippers and ancillary equipment (2 x 50%)

4.2.4 Case 9 Performance Results The plant produces a net output of 550 MWe at a net plant efficiency of 36.8 percent (HHV basis). Overall performance for the plant is summarized in Exhibit 4-7, which includes auxiliary power requirements.

329

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-7 Case 9 Plant Performance Summary POWER

SUMMARY

(Gross Power at Generator Terminals, kWe)

Steam Turbine Power 582,600 TOTAL (STEAM TURBINE) POWER, kWe 582,600 AUXILIARY LOAD

SUMMARY

, kWe Coal Handling and Conveying 450 Pulverizers 2,970 Sorbent Handling & Reagent Preparation 950 Ash Handling 570 Primary Air Fans 1,400 Forced Draft Fans 1,780 Induced Draft Fans 7,540 SCR 50 Baghouse 70 Wet FGD 3,180 2,3 Miscellaneous Balance of Plant 2,000 Steam Turbine Auxiliaries 400 Condensate Pumps 890 Circulating Water Pump 5,250 Ground Water Pumps 530 Cooling Tower Fans 2,720 Transformer Losses 1,830 TOTAL AUXILIARIES, kWe 32,580 NET POWER, kWe 550,020 Net Plant Efficiency (HHV) 36.8%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,788 (9,277) 6 6 CONDENSER COOLING DUTY 10 kJ/hr (10 Btu/hr) 2,566 (2,432)

CONSUMABLES As-Received Coal Feed, kg/hr (lb/hr) 198,391 (437,378)

Limestone Sorbent Feed, kg/hr (lb/hr) 19,691 (43,410) 1 Thermal Input, kWt 1,495,379 3

Raw Water Withdrawal, m /min (gpm) 22.3 (5,896) 3 Raw Water Consumption, m /min (gpm) 17.7 (4,680)

1. HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)

2. Boiler feed pumps are turbine driven

3. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads 330

Cost and Performance Baseline for Fossil Energy Plants Environmental Performance The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 2.4. A summary of the plant air emissions for Case 9 is presented in Exhibit 4-8.

Exhibit 4-8 Case 9 Air Emissions Tonne/year kg/GJ kg/MWh (ton/year)

(lb/106 Btu) (lb/MWh) 85% CF SO2 0.037 (0.086) 1,479 (1,630) 0.341 (.75)

NOx 0.030 (0.070) 1,206 (1,330) 0.278 (.613)

Particulates 0.006 (0.0130) 224 (247) 0.052 (.114) 4.91E-7 0.020 (0.022)

Hg 4.54E-6 (1.00E-5)

(1.14E-6) 3,507,605 CO2 87.5 (203.5) 809 (1,783)

(3,866,472)

CO21 856 (1,888) 1 CO2 emissions based on net power instead of gross power SO2 emissions are controlled using a wet limestone forced oxidation scrubber that achieves a removal efficiency of 98 percent. The byproduct calcium sulfate is dewatered and stored on site.

The wallboard grade material can potentially be marketed and sold, but since it is highly dependent on local market conditions, no byproduct credit was taken. The saturated FG exiting the scrubber is vented through the plant stack.

NOx emissions are controlled to about 0.5 lb/106 Btu through the use of LNBs and OFA. An SCR unit then further reduces the NOx concentration by 86 percent to 0.07 lb/106 Btu.

Particulate emissions are controlled using a pulse jet fabric filter, which operates at an efficiency of 99.8 percent.

Co-benefit capture results in a 90 percent reduction of mercury emissions.

CO2 emissions represent the uncontrolled discharge from the process.

The carbon balance for the plant is shown in Exhibit 4-9. The carbon input to the plant consists of carbon in the coal, carbon in the air, and carbon in the limestone reagent used in the FGD.

Carbon in the air is not neglected here since the Aspen model accounts for air components throughout. Carbon leaves the plant mostly as CO2 through the stack but also leaves as gypsum.

331

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-9 Case 9 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 126,464 (278,805) Stack Gas 128,563 (283,434)

Air (CO2) 275 (607) FGD Product 174 (383)

FGD Reagent 1,998 (4,405)

Total 128,737 (283,817) Total 128,737 (283,817)

Exhibit 4-10 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered from the FGD as gypsum and sulfur emitted in the stack gas.

Exhibit 4-10 Case 9 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 4,973 (10,963) Stack Gas 99 (219)

FGD Product 4,873 (10,743)

Total 4,973 (10,963) Total 4,973 (10,963)

Exhibit 4-11 shows the water balance for Case 9. Water demand represents the total amount of water required for a particular process. Some water is recovered within the process and is re-used as internal recycle. The difference between demand and recycle is raw water withdrawal.

Raw water withdrawal is defined as the water removed from the ground or diverted from a surface-water source for use in the plant and was assumed to be provided 50 percent by a POTW and 50 percent from groundwater. Raw water withdrawal can be represented by the water metered from a raw water source and used in the plant processes for any and all purposes, such as FDG makeup, BFW makeup, and cooling tower makeup. The difference between water withdrawal and process water discharge is defined as water consumption and can be represented by the portion of the raw water withdrawn that is evaporated, transpired, incorporated into products or otherwise not returned to the water source from which it was withdrawn. Water consumption represents the net impact of the plant process on the water source.

332

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-11 Case 9 Water Balance Process Water Internal Raw Water Water Raw Water Demand, Recycle, Withdrawal, Water Use Discharge, Consumption, m3/min m3/min m3/min m3/min m3/min (gpm)

(gpm) (gpm) (gpm)

(gpm)

FGD Makeup 3.9 (1,017) 0.0 (0) 3.9 (1,017) 0.0 (0) 3.9 (1,017)

BFW Makeup 0.3 (74) 0.0 (0) 0.3 (74) 0.0 (0) 0.3 (74)

Cooling Tower 20.5 (5,404) 2.3 (600) 18.2 (4,804) 4.6 (1,215) 13.6 (3,589)

Total 24.6 (6,495) 2.3 (600) 22.3 (5,896) 4.6 (1,215) 17.7 (4,680)

Heat and Mass Balance Diagrams A heat and mass balance diagram is shown for the Case 9 PC boiler, the FGD unit, and steam cycle as shown in Exhibit 4-12 and Exhibit 4-13.

An overall plant energy balance is provided in tabular form in Exhibit 4-14. The power out is the steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 4-7) is calculated by multiplying the power out by a generator efficiency of 98.6 percent.

333

Cost and Performance Baseline for Fossil Energy Plants This page intentionally left blank 334

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-12 Case 9 Heat and Mass Balance, Subcritical PC Boiler without CO2 Capture MAKE-UP OXIDATION LEGEND WATER AIR 408,090 W 49,625 W Air 59.0 T 15 16 332.9 T 14.7 P 45.0 P Coal/Ash Slurry Nitrogen 13 Oxygen Baghouse 12 FGD 4,780,183 W ID FANS 357.4 T Sour Gas 337.0 T 15.3 P 14.2 P 137.9 H ASH 132.7 H Sour Water 11 33,929 W 143,877 W 75,020 W 14 17 59.0 T 135.0 T Steam 4,814,113 W 15.0 P 14.8 P 337.0 T 10 14.4 P 140.6 H Synthesis Gas LIMESTONE GYPSUM SLURRY 5,043,963 W Water Throttle Steam 19 135.0 T 18 To HP Turbine 14.8 P 3,708,212 W 128.0 H 1,050.0 T Lime/Ash 2,415.0 P 1,492.8 H Flue Gas 21 Single Reheat To IP Turbine P ABSOLUTE PRESSURE, PSIA 3,409,730 W F TEMPERATURE, °F 1,050.0 T W FLOWRATE, LBM/HR 565.5 P H ENTHALPY, BTU/LBM 1,545.2 H MWE POWER, MEGAWATTS ELECTRICAL AMMONIA SCR NOTES:

INFILTRATION 7 AIR 76,015 W 59.0 T 66.4 T 1. ENTHALPY REFERENCE POINT IS NATURAL STATE 14.7 P 15.3 P AT 32 °F AND 0.08865 PSIA 13.0 H 14.8 H Pulverized 20 3,409,730 W AIR 1 2

Coal 686.0 T 620.5 P 3,296,540 W 59.0 T FORCED 3 Boiler 1,341.7 H 14.7 P DRAFT FANS PLANT PERFORMANCE

SUMMARY

13.0 H Single Reheat Gross Plant Power: 583 MWe Extraction from Auxiliary Load: 33 MWe HP Turbine STACK Net Plant Power: 550 MWe 6 Net Plant Efficiency, HHV: 36.8%

Net Plant Heat Rate: 9,277 BTU/KWe 5

AIR 4 1,012,663 W 77.8 T 59.0 T PRIMARY 16.1 P 14.7 P AIR FANS 17.5 H DOE/NETL 13.0 H 9 From Feedwater SC PC PLANT 8 Heaters CASE 9 437,378 W 3,708,212 W COAL 484.4 T 3,100.5 P HEAT AND MATERIAL FLOW DIAGRAM ASH 469.5 H 8,482 W BITUMINOUS BASELINE STUDY CASE 9 SUBCRITICAL PULVERIZED COAL BOILER AND GAS CLEANUP SYSTEMS DWG. NO. PAGES BB-HMB-CS-9-PG-1 1 OF 2 335

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-13 Case 9 Heat and Mass Balance, Subcritical Steam Cycle LEGEND Air 3,442,057 W Coal/Char/

1,048.6 T 565.5 P Slurry/Slag 1,544.4 H Nitrogen Oxygen 19 3,037,555 W 154,414 W 3,708,212 W 734.9 T 2,883,141 W 734.9 T Sour Gas 1,050.0 T 164.3 P 734.9 T 164.3 P 2,415.0 P 1,393.4 H 164.3 P 1,393.4 H 1,492.8 H 1,393.4 H Sour Water Throttle Steam BOILER FEED HP IP LP TURBINE GENERATOR PUMP TURBINE Steam TURBINE TURBINE DRIVES Steam Turbine Makeup 37,082 W Synthesis Gas 41.6 P 5.0 P 59.0 T 167.7 P 2,415.0 P 350.5 P 167.7 P 64.2 P 1,850.0 P 11.8 P 154,414 W 14.7 P 2,388,619 W 27.1 H 126.1 T 101.1 T 1.0 P 2.0 P Water 1,097.1 H 1,017.1 H 620.5 P 620.5 P 2,415.0 P 620.5 P Single Reheat Extraction CONDENSER From Boiler STEAM SEAL REGULATOR 3,301 W 21 3,409,730 W Single Reheat 712.8 T P ABSOLUTE PRESSURE, PSIA 1,050.0 T 565.5 P Extraction to 167.7 P HOT WELL F TEMPERATURE, °F 1,381.9 H W FLOWRATE, LBM/HR 1,545.2 H Boiler 6,805 W 2,793 W 712.8 T 712.8 T H ENTHALPY, BTU/LBM 20 167.7 P 167.7 P 3,087,536 W MWE POWER, MEGAWATTS ELECTRICAL 1,381.9 H 1,381.9 H 101.1 T 3,409,730 W 1.0 P 686.0 T 69.1 H NOTES:

620.5 P 1,341.7 H CONDENSATE 1. ENTHALPY REFERENCE POINT IS NATURAL STATE PUMPS AT 32 °F AND 0.08865 PSIA 101.4 T 250.0 P 70.0 H 254,026 W 226,208 W 177,524 W 80,030 W 187,193 W 103,223 W 130,880 W 682.6 T 915.9 T 728.1 T 524.8 T 439.2 T 228.6 T 157.8 T 589.7 P 323.0 P 130.0 P 57.3 P 37.1 P 10.5 P 4.5 P 1,391.5 H 1,294.9 H 3,708,212 W 1,341.7 H 3,708,212 W 1,480.7 H 1,255.2 H 1,159.5 H 1,120.2 H GLAND SEAL PLANT PERFORMANCE

SUMMARY

484.4 T 3,087,536 W 3,087,536 W 3,087,536 W 3,087,536 W 426.2 T CONDENSER 3,100.5 P 284.7 T 257.7 T 190.5 T 152.8 T To Boiler 3,105.5 P P-1048 469.5 H FWH 7 FWH 6 220.0 P 230.0 P 235.0 P 240.0 P P-1028 2,793 W 406.0 H 253.9 H FWH 4 226.5 H FWH 3 158.8 H FWH 2 121.2 H FWH 1 212.0 T Gross Plant Power: 583 MWe 23 14.7 P Auxiliary Load: 33 MWe 3,087,536 W 179.9 H Net Plant Power: 550 MWe 102.5 T Net Plant Efficiency, HHV: 36.8%

DEAERATOR 245.0 P 71.1 H Net Plant Heat Rate: 9,277 BTU/KWe 254,026 W 480,234 W 80,030 W 267,224 W 370,446 W 436.2 T 364.6 T 267.7 T 200.5 T 162.8 T 501,326 W 366.7 P 323.0 P 40.3 P 11.7 P 5.1 P 112.5 T 414.3 H 337.0 H 236.3 H 168.3 H 130.6 H 1.4 P 80.4 H DOE/NETL 3,708,212 W 354.6 T 347.3 T 130.0 P SC PC PLANT 3,110.5 P 318.5 H CASE 9 330.9 H BOILER FEED PUMPS HEAT AND MATERIAL FLOW DIAGRAM BITUMINOUS BASELINE STUDY CASE 9 SUBCRITICAL PULVERIZED COAL POWER BLOCK SYSTEMS DWG. NO. PAGES BB-HMB-CS-9-PG-2 2 OF 2 336

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-14 Case 9 Overall Energy Balance (0°C [32°F] Reference)

Sensible +

HHV Power Total Latent Heat In GJ/hr (MMBtu/hr)

Coal 5,383 (5,102) 4.5 (4.3) 5,388 (5,107)

Air 60.1 (57.0) 60.1 (57.0)

Raw Water Withdrawal 84.0 (79.6) 84.0 (79.6)

Limestone 0.22 (0.21) 0.22 (0.21)

Auxiliary Power 117 (111) 117 (111)

Totals 5,383 (5,102) 148.8 (141.1) 117 (111) 5,649 (5,355)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.5 (0.4) 0.5 (0.4)

Fly Ash + FGD Ash 1.9 (1.8) 1.9 (1.8)

Flue Gas 681 (646) 681 (646)

Condenser 2,566 (2,432) 2,566 (2,432)

Cooling Tower Blowdown 34.2 (32.4) 34.2 (32.4)

Process Losses* 269 (255) 269 (255)

Power 2,097 (1,988) 2,097 (1,988)

Totals 0 (0) 3,552 (3,367) 2,097 (1,988) 5,649 (5,355)

Process losses are estimated to match the heat input to the plant. Process losses include losses from: turbines, gas cooling, etc.

337

Cost and Performance Baseline for Fossil Energy Plants 4.2.5 Case 9 - Major Equipment List Major equipment items for the subcritical PC plant with no CO2 capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section 4.2.6. In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 COAL AND SORBENT HANDLING Equipment Operating Description Type Design Condition Spares No. Qty.

Bottom Trestle Dumper and 1 N/A 181 tonne (200 ton) 2 0 Receiving Hoppers 2 Feeder Belt 572 tonne/hr (630 tph) 2 0 3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0 4 Transfer Tower No. 1 Enclosed N/A 1 0 5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0 As-Received Coal Sampling 6 Two-stage N/A 1 0 System 7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0 8 Reclaim Hopper N/A 45 tonne (50 ton) 2 1 9 Feeder Vibratory 163 tonne/hr (180 tph) 2 1 10 Conveyor No. 3 Belt w/ tripper 327 tonne/hr (360 tph) 1 0 11 Crusher Tower N/A N/A 1 0 12 Coal Surge Bin w/ Vent Filter Dual outlet 163 tonne (180 ton) 2 0 Impactor 8 cm x 0 - 3 cm x 0 13 Crusher 2 0 reduction (3 in x 0 1/4 in x 0)

As-Fired Coal Sampling 14 Swing hammer N/A 1 1 System 15 Conveyor No. 4 Belt w/tripper 327 tonne/hr (360 tph) 1 0 16 Transfer Tower No. 2 Enclosed N/A 1 0 17 Conveyor No. 5 Belt w/ tripper 327 tonne/hr (360 tph) 1 0 Coal Silo w/ Vent Filter and 18 Field erected 726 tonne (800 ton) 3 0 Slide Gates Limestone Truck Unloading 19 N/A 36 tonne (40 ton) 1 0 Hopper 20 Limestone Feeder Belt 82 tonne/hr (90 tph) 1 0 21 Limestone Conveyor No. L1 Belt 82 tonne/hr (90 tph) 1 0 22 Limestone Reclaim Hopper N/A 18 tonne (20 ton) 1 0 23 Limestone Reclaim Feeder Belt 64 tonne/hr (70 tph) 1 0 24 Limestone Conveyor No. L2 Belt 64 tonne/hr (70 tph) 1 0 25 Limestone Day Bin w/ actuator 263 tonne (290 ton) 2 0 338

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED Equipment Operating Description Type Design Condition Spares No. Qty.

1 Coal Feeder Gravimetric 36 tonne/hr (40 tph) 6 0 Ball type or 2 Coal Pulverizer 36 tonne/hr (40 tph) 6 0 equivalent 3 Limestone Weigh Feeder Gravimetric 22 tonne/hr (24 tph) 1 1 4 Limestone Ball Mill Rotary 22 tonne/hr (24 tph) 1 1 Limestone Mill Slurry Tank 5 N/A 83,279 liters (22,000 gal) 1 1 with Agitator Limestone Mill Recycle Horizontal 1,401 lpm @ 12m H2O (370 gpm 6 1 1 Pumps centrifugal @ 40 ft H2O) 4 active 7 Hydroclone Classifier cyclones in a 5 341 lpm (90 gpm) per cyclone 1 1 cyclone bank 8 Distribution Box 2-way N/A 1 1 Limestone Slurry Storage 9 Field erected 469,391 liters (124,000 gal) 1 1 Tank with Agitator Limestone Slurry Feed Horizontal 984 lpm @ 9m H2O (260 gpm @

10 1 1 Pumps centrifugal 30 ft H2O) 339

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment Operating Description Type Design Condition Spares No. Qty.

Demineralized Water Vertical, cylindrical, 1 1,112,911 liters (294,000 gal) 2 0 Storage Tank outdoor 25,741 lpm @ 213 m H2O (6,800 2 Condensate Pumps Vertical canned 1 1 gpm @ 700 ft H2O)

Deaerator and Storage 1,850,203 kg/hr (4,079,000 lb/hr),

3 Horizontal spray type 1 0 Tank 5 min. tank Boiler Feed Barrel type, multi-stage, 31,040 lpm @ 2,530 m H2O 4 1 1 Pump/Turbine centrifugal (8,200 gpm @ 8,300 ft H2O)

Startup Boiler Feed Barrel type, multi-stage, 9,085 lpm @ 2,530 m H2O (2,400 5 Pump, Electric Motor 1 0 centrifugal gpm @ 8,300 ft H2O)

Driven LP Feedwater Heater 6 Horizontal U-tube 771,107 kg/hr (1,700,000 lb/hr) 2 0 1A/1B LP Feedwater Heater 7 Horizontal U-tube 771,107 kg/hr (1,700,000 lb/hr) 2 0 2A/2B LP Feedwater Heater 8 Horizontal U-tube 771,107 kg/hr (1,700,000 lb/hr) 2 0 3A/3B LP Feedwater Heater 9 Horizontal U-tube 771,107 kg/hr (1,700,000 lb/hr) 2 0 4A/4B 10 HP Feedwater Heater 6 Horizontal U-tube 1,850,657 kg/hr (4,080,000 lb/hr) 1 0 11 HP Feedwater Heater 7 Horizontal U-tube 1,850,657 kg/hr (4,080,000 lb/hr) 1 0 Shop fabricated, water 18,144 kg/hr, 2.8 MPa, 343°C 12 Auxiliary Boiler 1 0 tube (40,000 lb/hr, 400 psig, 650°F)

No. 2 fuel oil for light 13 Fuel Oil System 1,135,624 liter (300,000 gal) 1 0 off Service Air 28 m3/min @ 0.7 MPa (1,000 14 Flooded Screw 2 1 Compressors scfm @ 100 psig) 15 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1 Closed Cycle Cooling 16 Shell and tube 53 GJ/hr (50 MMBtu/hr) each 2 0 Heat Exchangers Closed Cycle Cooling 20,820 lpm @ 30 m H2O (5,500 17 Horizontal centrifugal 2 1 Water Pumps gpm @ 100 ft H2O)

Engine-Driven Fire Vertical turbine, diesel 3,785 lpm @ 88 m H2O (1,000 18 1 1 Pump engine gpm @ 290 ft H2O)

Fire Service Booster Two-stage horizontal 2,650 lpm @ 64 m H2O (700 gpm 19 1 1 Pump centrifugal @ 210 ft H2O)

Stainless steel, single 6,549 lpm @ 18 m H2O (1,730 20 Raw Water Pumps 2 1 suction gpm @ 60 ft H2O)

Stainless steel, single 2,612 lpm @ 268 m H2O (690 21 Ground Water Pumps 5 1 suction gpm @ 880 ft H2O)

Stainless steel, single 2,006 lpm @ 49 m H2O (530 gpm 22 Filtered Water Pumps 2 1 suction @ 160 ft H2O) 23 Filtered Water Tank Vertical, cylindrical 1,919,204 liter (507,000 gal) 1 0 Multi-media filter, Makeup Water cartridge filter, RO 24 606 lpm (160 gpm) 1 1 Demineralizer membrane assembly, electrodeionization unit Liquid Waste Treatment 25 -- 10 years, 24-hour storm 1 0 System 340

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 4 BOILER AND ACCESSORIES Equipment Operating Description Type Design Condition Spares No. Qty.

1,850,657 kg/hr steam @ 17.9 Subcritical, drum MPa/574°C/574°C (4,080,000 1 Boiler wall-fired, low NOx 1 0 lb/hr steam @ 2,600 burners, overfire air psig/1,065°F/1,065°F) 252,651 kg/hr, 3,446 m3/min @

2 Primary Air Fan Centrifugal 123 cm WG (557,000 lb/hr, 2 0 121,700 acfm @ 48 in. WG) 822,363 kg/hr, 11,222 m3/min @

3 Forced Draft Fan Centrifugal 47 cm WG (1,813,000 lb/hr, 2 0 396,300 acfm @ 19 in. WG) 1,192,494 kg/hr, 25,114 m3/min 4 Induced Draft Fan Centrifugal @ 91 cm WG (2,629,000 lb/hr, 2 0 886,900 acfm @ 36 in. WG)

Space for spare 5 SCR Reactor Vessel 2,385,896 kg/hr (5,260,000 lb/hr) 2 0 layer 6 SCR Catalyst -- -- 3 0 142 m3/min @ 108 cm WG 7 Dilution Air Blower Centrifugal 2 1 (5,000 acfm @ 42 in. WG) 8 Ammonia Storage Horizontal tank 155,202 liter (41,000 gal) 5 0 Ammonia Feed 30 lpm @ 91 m H2O (8 gpm @

9 Centrifugal 2 1 Pump 300 ft H2O) 341

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 5 FLUE GAS CLEANUP Equipment Operating Description Type Design Condition Spares No. Qty.

Single stage, high-ratio with pulse-jet 1,192,494 kg/hr (2,629,000 lb/hr) 1 Fabric Filter 2 0 online cleaning 99.8% efficiency system Counter-current 2 Absorber Module 47,912 m3/min (1,692,000 acfm) 1 0 open spray Horizontal 166,558 lpm @ 64 m H2O 3 Recirculation Pumps 5 1 centrifugal (44,000 gpm @ 210 ft H2O)

Horizontal 4,240 lpm (1,120 gpm) at 20 wt%

4 Bleed Pumps 2 1 centrifugal solids 84 m3/min @ 0.3 MPa (2,960 5 Oxidation Air Blowers Centrifugal 2 1 acfm @ 37 psia) 6 Agitators Side entering 50 hp 5 1 Radial assembly, 7 Dewatering Cyclones 1,060 lpm (280 gpm) per cyclone 2 0 5 units each 34 tonne/hr (37 tph) of 50 wt %

8 Vacuum Filter Belt Horizontal belt 2 1 slurry Filtrate Water Return Horizontal 644 lpm @ 12 m H2O (170 gpm 9 1 1 Pumps centrifugal @ 40 ft H2O)

Filtrate Water Return 10 Vertical, lined 416,395 lpm (110,000 gal) 1 0 Storage Tank Process Makeup Water Horizontal 3,407 lpm @ 21 m H2O (900 gpm 11 1 1 Pumps centrifugal @ 70 ft H2O)

ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES N/A 342

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 7 HRSG, DUCTING & STACK Equipment Operating Description Type Design Condition Spares No. Qty.

Reinforced concrete 152 m (500 ft) high x 1 Stack 1 0 with FRP liner 5.8 m (19 ft) diameter ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES Equipment Operating Description Type Design Condition Spares No. Qty.

613 MW Commercially 16.5 MPa/566°C/566°C 1 Steam Turbine available advanced 1 0 (2400.3 psig/

steam turbine 1050°F/1050°F)

Hydrogen cooled, 680 MVA @ 0.9 p.f., 24 2 Steam Turbine Generator 1 0 static excitation kV, 60 Hz, 3-phase 2,828 GJ/hr (2,680 Single pass, divided MMBtu/hr), Inlet water 3 Surface Condenser waterbox including temperature 16°C (60°F), 1 0 vacuum pumps Water temperature rise 11°C (20°F)

ACCOUNT 9 COOLING WATER SYSTEM Equipment Operating Description Type Design Condition Spares No. Qty.

Circulating Water 526,200 lpm @ 30 m 1 Vertical, wet pit 2 1 Pumps (139,000 gpm @ 100 ft) 11°C (51.5°F) wet bulb / 16°C Evaporative, (60°F) CWT / 27°C (80°F) HWT 2 Cooling Tower mechanical draft, multi- 1 0

/ 2944 GJ/hr (2790 MMBtu/hr) cell heat duty 343

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING Equipment Operating Description Type Design Condition Spares No. Qty.

Economizer Hopper (part of 1 -- -- 4 0 boiler scope of supply)

Bottom Ash Hopper (part of 2 -- -- 2 0 boiler scope of supply) 3 Clinker Grinder -- 4.5 tonne/hr (5 tph) 1 1 Pyrites Hopper (part of 4 pulverizer scope of supply -- -- 6 0 included with boiler) 5 Hydroejectors -- -- 12 Economizer /Pyrites Transfer 6 -- -- 1 0 Tank 151 lpm @ 17 m H2O (40 gpm 7 Ash Sluice Pumps Vertical, wet pit 1 1

@ 56 ft H2O) 7,571 lpm @ 9 m H2O (2000 8 Ash Seal Water Pumps Vertical, wet pit 1 1 gpm @ 28 ft H2O) 9 Hydrobins -- 151 lpm (40 gpm) 1 1 Baghouse Hopper (part of 10 -- -- 24 0 baghouse scope of supply)

Air Heater Hopper (part of 11 -- -- 10 0 boiler scope of supply) 16 m3/min @ 0.2 MPa (550 12 Air Blower -- 1 1 scfm @ 24 psi)

Reinforced 13 Fly Ash Silo 998 tonne (1,100 ton) 2 0 concrete 14 Slide Gate Valves -- -- 2 0 15 Unloader -- -- 1 0 16 Telescoping Unloading Chute -- 91 tonne/hr (100 tph) 1 0 344

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 11 ACCESSORY ELECTRIC PLANT Equipment Operating Description Type Design Condition Spares No. Qty.

24 kV/345 kV, 650 MVA, 3-1 STG Transformer Oil-filled 1 0 ph, 60 Hz Auxiliary 24 kV/4.16 kV, 34 MVA, 3-2 Oil-filled 1 1 Transformer ph, 60 Hz Low Voltage 4.16 kV/480 V, 5 MVA, 3-ph, 3 Dry ventilated 1 1 Transformer 60 Hz STG Isolated 4 Phase Bus Duct Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0 and Tap Bus Medium Voltage 5 Metal clad 4.16 kV, 3-ph, 60 Hz 1 1 Switchgear Low Voltage 6 Metal enclosed 480 V, 3-ph, 60 Hz 1 1 Switchgear Emergency Diesel Sized for emergency 7 750 kW, 480 V, 3-ph, 60 Hz 1 0 Generator shutdown ACCOUNT 12 INSTRUMENTATION AND CONTROL Equipment Operating Description Type Design Condition Spares No. Qty.

Monitor/keyboard; DCS - Main Operator printer (laser Operator stations/printers and 1 1 0 Control color); Engineering engineering stations/printers printer (laser B&W)

Microprocessor with 2 DCS - Processor N/A 1 0 redundant input/output DCS - Data 3 Fiber optic Fully redundant, 25% spare 1 0 Highway 345

Cost and Performance Baseline for Fossil Energy Plants 4.2.6 Case 9 - Cost Estimating The cost estimating methodology was described previously in Section 2.6. Exhibit 4-15 shows the total plant capital cost summary organized by cost account and Exhibit 4-16 shows a more detailed breakdown of the capital costs along with owners costs, TOC and TASC. Exhibit 4-17 shows the initial and annual O&M costs.

The estimated TOC of the subcritical PC boiler with no CO2 capture is $1,996/kW. No process contingency is included in this case because all elements of the technology are commercially proven. The project contingency is 9.1 percent of the TOC. The COE is 59.4 mills/kWh.

346

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-15 Case 9 Total Plant Cost Summary Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study TOTAL PLANT COST

SUMMARY

Case: Case 9 - 1x550 MWnet SubCritical PC Plant Size: 550 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING $17,068 $4,598 $10,229 $0 $0 $31,895 $2,862 $0 $5,214 $39,970 $73 2 COAL & SORBENT PREP & FEED $11,494 $665 $2,916 $0 $0 $15,075 $1,321 $0 $2,459 $18,855 $34 3 FEEDWATER & MISC. BOP SYSTEMS $39,707 $0 $19,059 $0 $0 $58,766 $5,391 $0 $10,518 $74,674 $136 4 PC BOILER 4.1 PC Boiler & Accessories $134,824 $0 $86,704 $0 $0 $221,527 $21,582 $0 $24,311 $267,420 $486 4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4-4.9 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4 $134,824 $0 $86,704 $0 $0 $221,527 $21,582 $0 $24,311 $267,420 $486 5 FLUE GAS CLEANUP $83,799 $0 $28,488 $0 $0 $112,287 $10,747 $0 $12,303 $135,338 $246 5B CO2 REMOVAL & COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 6.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 6 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 7.2-7.9 HRSG Accessories, Ductwork and Stack $18,242 $1,049 $12,388 $0 $0 $31,679 $2,908 $0 $4,516 $39,104 $71 SUBTOTAL 7 $18,242 $1,049 $12,388 $0 $0 $31,679 $2,908 $0 $4,516 $39,104 $71 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $49,912 $0 $6,242 $0 $0 $56,154 $5,380 $0 $6,153 $67,688 $123 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $23,604 $1,092 $12,657 $0 $0 $37,354 $3,294 $0 $5,668 $46,316 $84 SUBTOTAL 8 $73,516 $1,092 $18,900 $0 $0 $93,508 $8,674 $0 $11,822 $114,004 $207 9 COOLING WATER SYSTEM $13,230 $6,710 $12,250 $0 $0 $32,189 $3,030 $0 $4,784 $40,003 $73 10 ASH/SPENT SORBENT HANDLING SYS $4,573 $145 $6,114 $0 $0 $10,833 $1,042 $0 $1,222 $13,096 $24 11 ACCESSORY ELECTRIC PLANT $17,808 $6,355 $18,529 $0 $0 $42,692 $3,765 $0 $5,747 $52,203 $95 12 INSTRUMENTATION & CONTROL $8,665 $0 $8,786 $0 $0 $17,451 $1,582 $0 $2,338 $21,371 $39 13 IMPROVEMENTS TO SITE $2,974 $1,710 $5,995 $0 $0 $10,679 $1,054 $0 $2,347 $14,079 $26 14 BUILDINGS & STRUCTURES $0 $23,479 $22,248 $0 $0 $45,727 $4,125 $0 $12,463 $62,315 $113 TOTAL COST $425,899 $45,804 $252,606 $0 $0 $724,309 $68,082 $0 $100,043 $892,433 $1,622 347

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-16 Case 9 Total Plant Cost Details Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $3,508 $0 $1,602 $0 $0 $5,110 $457 $0 $835 $6,402 $12 1.2 Coal Stackout & Reclaim $4,533 $0 $1,027 $0 $0 $5,561 $487 $0 $907 $6,954 $13 1.3 Coal Conveyors $4,215 $0 $1,016 $0 $0 $5,231 $458 $0 $853 $6,543 $12 1.4 Other Coal Handling $1,103 $0 $235 $0 $0 $1,338 $117 $0 $218 $1,673 $3 1.5 Sorbent Receive & Unload $140 $0 $42 $0 $0 $183 $16 $0 $30 $229 $0 1.6 Sorbent Stackout & Reclaim $2,269 $0 $416 $0 $0 $2,685 $234 $0 $438 $3,357 $6 1.7 Sorbent Conveyors $810 $175 $199 $0 $0 $1,183 $102 $0 $193 $1,479 $3 1.8 Other Sorbent Handling $489 $115 $257 $0 $0 $860 $76 $0 $140 $1,077 $2 1.9 Coal & Sorbent Hnd.Foundations $0 $4,308 $5,435 $0 $0 $9,743 $915 $0 $1,599 $12,257 $22 SUBTOTAL 1. $17,068 $4,598 $10,229 $0 $0 $31,895 $2,862 $0 $5,214 $39,970 $73 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $2,014 $0 $393 $0 $0 $2,407 $210 $0 $393 $3,009 $5 2.2 Coal Conveyor to Storage $5,158 $0 $1,126 $0 $0 $6,284 $549 $0 $1,025 $7,858 $14 2.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.5 Sorbent Prep Equipment $3,857 $166 $801 $0 $0 $4,824 $420 $0 $787 $6,031 $11 2.6 Sorbent Storage & Feed $465 $0 $178 $0 $0 $643 $57 $0 $105 $805 $1 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $499 $419 $0 $0 $917 $85 $0 $150 $1,153 $2 SUBTOTAL 2. $11,494 $665 $2,916 $0 $0 $15,075 $1,321 $0 $2,459 $18,855 $34 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $16,257 $0 $5,611 $0 $0 $21,868 $1,915 $0 $3,567 $27,351 $50 3.2 Water Makeup & Pretreating $4,751 $0 $1,529 $0 $0 $6,280 $594 $0 $1,375 $8,248 $15 3.3 Other Feedwater Subsystems $5,318 $0 $2,248 $0 $0 $7,566 $678 $0 $1,237 $9,480 $17 3.4 Service Water Systems $931 $0 $507 $0 $0 $1,438 $135 $0 $315 $1,888 $3 3.5 Other Boiler Plant Systems $6,259 $0 $6,179 $0 $0 $12,438 $1,181 $0 $2,043 $15,662 $28 3.6 FO Supply Sys & Nat Gas $256 $0 $320 $0 $0 $575 $54 $0 $94 $724 $1 3.7 Waste Treatment Equipment $3,221 $0 $1,836 $0 $0 $5,057 $492 $0 $1,110 $6,659 $12 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,715 $0 $829 $0 $0 $3,544 $341 $0 $777 $4,662 $8 SUBTOTAL 3. $39,707 $0 $19,059 $0 $0 $58,766 $5,391 $0 $10,518 $74,674 $136 4 PC BOILER & ACCESSORIES 4.1 PC Boiler & Accessories $134,824 $0 $86,704 $0 $0 $221,527 $21,582 $0 $24,311 $267,420 $486 4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4. $134,824 $0 $86,704 $0 $0 $221,527 $21,582 $0 $24,311 $267,420 $486 348

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-16 Case 9 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 5 FLUE GAS CLEANUP 5.1 Absorber Vessels & Accessories $58,362 $0 $12,564 $0 $0 $70,926 $6,762 $0 $7,769 $85,456 $155 5.2 Other FGD $3,046 $0 $3,451 $0 $0 $6,497 $631 $0 $713 $7,840 $14 5.3 Bag House & Accessories $16,493 $0 $10,467 $0 $0 $26,959 $2,598 $0 $2,956 $32,513 $59 5.4 Other Particulate Removal Materials $1,116 $0 $1,194 $0 $0 $2,310 $224 $0 $253 $2,788 $5 5.5 Gypsum Dewatering System $4,783 $0 $812 $0 $0 $5,595 $533 $0 $613 $6,741 $12 5.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5.9 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5. $83,799 $0 $28,488 $0 $0 $112,287 $10,747 $0 $12,303 $135,338 $246 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5B. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $9,097 $0 $5,845 $0 $0 $14,942 $1,303 $0 $2,437 $18,682 $34 7.4 Stack $9,145 $0 $5,351 $0 $0 $14,496 $1,396 $0 $1,589 $17,481 $32 7.9 Duct & Stack Foundations $0 $1,049 $1,192 $0 $0 $2,241 $210 $0 $490 $2,941 $5 SUBTOTAL 7. $18,242 $1,049 $12,388 $0 $0 $31,679 $2,908 $0 $4,516 $39,104 $71 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $49,912 $0 $6,242 $0 $0 $56,154 $5,380 $0 $6,153 $67,688 $123 8.2 Turbine Plant Auxiliaries $348 $0 $746 $0 $0 $1,094 $107 $0 $120 $1,321 $2 8.3 Condenser & Auxiliaries $7,251 $0 $2,295 $0 $0 $9,545 $913 $0 $1,046 $11,504 $21 8.4 Steam Piping $16,005 $0 $7,891 $0 $0 $23,896 $2,008 $0 $3,886 $29,790 $54 8.9 TG Foundations $0 $1,092 $1,726 $0 $0 $2,818 $267 $0 $617 $3,701 $7 SUBTOTAL 8. $73,516 $1,092 $18,900 $0 $0 $93,508 $8,674 $0 $11,822 $114,004 $207 349

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-16 Case 9 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 9 COOLING WATER SYSTEM 9.1 Cooling Towers $9,783 $0 $3,046 $0 $0 $12,829 $1,227 $0 $1,406 $15,461 $28 9.2 Circulating Water Pumps $2,033 $0 $128 $0 $0 $2,161 $182 $0 $234 $2,578 $5 9.3 Circ.Water System Auxiliaries $531 $0 $71 $0 $0 $602 $57 $0 $66 $725 $1 9.4 Circ.Water Piping $0 $4,210 $4,080 $0 $0 $8,290 $776 $0 $1,360 $10,427 $19 9.5 Make-up Water System $462 $0 $618 $0 $0 $1,080 $103 $0 $177 $1,361 $2 9.6 Component Cooling Water Sys $421 $0 $335 $0 $0 $755 $72 $0 $124 $951 $2 9.9 Circ.Water System Foundations & Structures $0 $2,500 $3,972 $0 $0 $6,471 $612 $0 $1,417 $8,500 $15 SUBTOTAL 9. $13,230 $6,710 $12,250 $0 $0 $32,189 $3,030 $0 $4,784 $40,003 $73 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $612 $0 $1,885 $0 $0 $2,497 $245 $0 $274 $3,017 $5 10.7 Ash Transport & Feed Equipment $3,961 $0 $4,058 $0 $0 $8,019 $767 $0 $879 $9,664 $18 10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.9 Ash/Spent Sorbent Foundation $0 $145 $171 $0 $0 $317 $30 $0 $69 $416 $1 SUBTOTAL 10. $4,573 $145 $6,114 $0 $0 $10,833 $1,042 $0 $1,222 $13,096 $24 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $1,602 $0 $260 $0 $0 $1,862 $173 $0 $153 $2,187 $4 11.2 Station Service Equipment $2,904 $0 $954 $0 $0 $3,858 $361 $0 $316 $4,535 $8 11.3 Switchgear & Motor Control $3,339 $0 $567 $0 $0 $3,906 $362 $0 $427 $4,695 $9 11.4 Conduit & Cable Tray $0 $2,093 $7,238 $0 $0 $9,331 $903 $0 $1,535 $11,769 $21 11.5 Wire & Cable $0 $3,950 $7,625 $0 $0 $11,575 $975 $0 $1,882 $14,432 $26 11.6 Protective Equipment $270 $0 $918 $0 $0 $1,188 $116 $0 $130 $1,434 $3 11.7 Standby Equipment $1,279 $0 $29 $0 $0 $1,308 $120 $0 $143 $1,571 $3 11.8 Main Power Transformers $8,414 $0 $172 $0 $0 $8,587 $652 $0 $924 $10,162 $18 11.9 Electrical Foundations $0 $312 $765 $0 $0 $1,077 $103 $0 $236 $1,416 $3 SUBTOTAL 11. $17,808 $6,355 $18,529 $0 $0 $42,692 $3,765 $0 $5,747 $52,203 $95 12 INSTRUMENTATION & CONTROL 12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $446 $0 $267 $0 $0 $713 $67 $0 $117 $898 $2 12.7 Distributed Control System Equipment $4,504 $0 $787 $0 $0 $5,291 $491 $0 $578 $6,360 $12 12.8 Instrument Wiring & Tubing $2,442 $0 $4,844 $0 $0 $7,285 $621 $0 $1,186 $9,092 $17 12.9 Other I & C Equipment $1,273 $0 $2,888 $0 $0 $4,161 $403 $0 $456 $5,021 $9 SUBTOTAL 12. $8,665 $0 $8,786 $0 $0 $17,451 $1,582 $0 $2,338 $21,371 $39 350

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-16 Case 9 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $50 $1,000 $0 $0 $1,050 $104 $0 $231 $1,385 $3 13.2 Site Improvements $0 $1,660 $2,061 $0 $0 $3,721 $367 $0 $818 $4,906 $9 13.3 Site Facilities $2,974 $0 $2,933 $0 $0 $5,908 $582 $0 $1,298 $7,788 $14 SUBTOTAL 13. $2,974 $1,710 $5,995 $0 $0 $10,679 $1,054 $0 $2,347 $14,079 $26 14 BUILDINGS & STRUCTURES 14.1 Boiler Building $0 $8,519 $7,491 $0 $0 $16,010 $1,439 $0 $4,362 $21,811 $40 14.2 Turbine Building $0 $12,310 $11,473 $0 $0 $23,784 $2,144 $0 $6,482 $32,409 $59 14.3 Administration Building $0 $587 $621 $0 $0 $1,208 $110 $0 $329 $1,647 $3 14.4 Circulation Water Pumphouse $0 $168 $134 $0 $0 $302 $27 $0 $82 $411 $1 14.5 Water Treatment Buildings $0 $603 $549 $0 $0 $1,152 $104 $0 $314 $1,570 $3 14.6 Machine Shop $0 $393 $264 $0 $0 $657 $58 $0 $179 $893 $2 14.7 Warehouse $0 $266 $267 $0 $0 $533 $48 $0 $145 $727 $1 14.8 Other Buildings & Structures $0 $217 $185 $0 $0 $403 $36 $0 $110 $548 $1 14.9 Waste Treating Building & Str. $0 $416 $1,263 $0 $0 $1,680 $159 $0 $460 $2,299 $4 SUBTOTAL 14. $0 $23,479 $22,248 $0 $0 $45,727 $4,125 $0 $12,463 $62,315 $113 TOTAL COST $425,899 $45,804 $252,606 $0 $0 $724,309 $68,082 $0 $100,043 $892,433 $1,622 Owner's Costs Preproduction Costs 6 Months All Labor $7,104 $13 1 Month Maintenance Materials $859 $2 1 Month Non-fuel Consumables $956 $2 1 Month Waste Disposal $251 $0 25% of 1 Months Fuel Cost at 100% CF $1,524 $3 2% of TPC $17,849 $32 Total $28,543 $52 Inventory Capital 60 day supply of fuel and consumables at 100% CF $13,824 $25 0.5% of TPC (spare parts) $4,462 $8 Total $18,287 $33 Initial Cost for Catalyst and Chemicals $0 $0 Land $900 $2 Other Owner's Costs $133,865 $243 Financing Costs $24,096 $44 Total Overnight Costs (TOC) $1,098,124 $1,996 TASC Multiplier (IOU, low-risk, 35 year) 1.134 Total As-Spent Cost (TASC) $1,245,272 $2,264 351

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-17 Case 9 Initial and Annual Operating and Maintenance Costs INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 9 - 1x550 MWnet SubCritical PC Heat Rate-net (Btu/kWh): 9,276 MWe-net: 550 Capacity Factor (%): 85 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. 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-O.J.'s 14.0 14.0 Annual Cost Annual Unit Cost

$ $/kW-net Annual Operating Labor Cost $5,524,319 $10.043 Maintenance Labor Cost $5,842,145 $10.621 Administrative & Support Labor $2,841,616 $5.166 Property Taxes and Insurance $17,848,664 $32.449 TOTAL FIXED OPERATING COSTS $32,056,744 $58.280 VARIABLE OPERATING COSTS

$/kWh-net Maintenance Material Cost $8,763,218 $0.00214 Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water (/1000 gallons) 0 4,245.12 1.08 $0 $1,424,619 $0.00035 Chemicals MU & WT Chem.(lbs) 0 20,549 0.17 $0 $1,103,371 $0.00027 Limestone (ton) 0 521 21.63 $0 $3,496,290 $0.00085 Carbon (Mercury Removal) (lb) 0 0 1.05 $0 $0 $0.00000 MEA Solvent (ton) 0 0 2,249.89 $0 $0 $0.00000 NaOH (tons) 0 0 433.68 $0 $0 $0.00000 H2SO4 (tons) 0 0 138.78 $0 $0 $0.00000 Corrosion Inhibitor 0 0 0.00 $0 $0 $0.00000 Activated Carbon (lb) 0 0 1.05 $0 $0 $0.00000 Ammonia (19% NH3) ton 0 78 129.80 $0 $3,136,289 $0.00077 Subtotal Chemicals $0 $7,735,950 $0.00189 Other Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 SCR Catalyst (m3) w/equip. 0.33 5,775.94 $0 $592,641 $0.00014 Emission Penalties 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $592,641 $0.00014 Waste Disposal Fly Ash (ton) 0 407 16.23 $0 $2,049,540 $0.00050 Bottom Ash (ton) 0 102 16.23 $0 $512,385 $0.00013 Subtotal-Waste Disposal $0 $2,561,926 $0.00063 By-products & Emissions Gypsum (tons) 0 811 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000 TOTAL VARIABLE OPERATING COSTS $0 $21,078,354 $0.00515 Fuel (ton) 0 5,248 38.18 $0 $62,175,757 $0.01518 352

Cost and Performance Baseline for Fossil Energy Plants 4.2.7 Case 10 - PC Subcritical Unit with CO2 Capture The plant configuration for Case 10, subcritical PC, is the same as Case 9 with the exception that the Econamine technology was added for CO2 capture. The nominal net output was maintained at 550 MW by increasing the boiler size and turbine/generator size to account for the greater auxiliary load imposed by the CDR facility. Unlike the IGCC cases where gross output was fixed by the available size of the CTs, the PC cases utilize boilers and steam turbines that can be procured at nearly any desired output making it possible to maintain a constant net output.

The process description for Case 10 is essentially the same as Case 9 with one notable exception, the addition of CO2 capture. A BFD and stream tables for Case 10 are shown in Exhibit 4-18 and Exhibit 4-19, respectively. Since the CDR facility process description was provided in Section 4.1.7, it is not repeated here.

4.2.8 Case 10 Performance Results The Case 10 modeling assumptions were presented previously in Section 4.2.2.

The plant produces a net output of 550 MW at a net plant efficiency of 26.2 percent (HHV basis). Overall plant performance is summarized in Exhibit 4-20, which includes auxiliary power requirements. The CDR facility, including CO2 compression, accounts for over half of the auxiliary plant load. The CWS (CWPs and cooling tower fan) accounts for over 14 percent of the auxiliary load, largely due to the high cooling water demand of the CDR facility.

353

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-18 Case 10 Block Flow Diagram, Subcritical Unit with CO2 Capture 354

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-19 Case 10 Stream Table, Subcritical Unit with CO2 Capture 1 2 3 4 5 6 7 8 9 10 11 12 13 14 V-L Mole Fraction Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087 0.0000 CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450 0.0000 H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870 1.0000 N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324 0.0000 O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247 0.0000 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 V-L Flowrate (kgmol/hr) 72,691 72,691 2,163 22,330 22,330 3,063 1,680 0 0 102,289 0 102,289 102,289 3,643 V-L Flowrate (kg/hr) 2,097,642 2,097,642 62,415 644,374 644,374 88,396 48,482 0 0 3,042,405 0 3,042,405 3,042,405 65,636 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 278,956 5,410 21,640 21,640 0 0 28,403 Temperature (°C) 15 19 19 15 25 25 15 15 15 169 15 169 182 15 Pressure (MPa, abs) 0.10 0.11 0.11 0.10 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11 0.10 Enthalpy (kJ/kg)A 30.23 34.36 34.36 30.23 40.78 40.78 30.23 --- --- 327.39 --- 308.96 322.83 ---

Density (kg/m3) 1.2 1.2 1.2 1.2 1.3 1.3 1.2 --- --- 0.8 --- 0.8 0.8 ---

V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 28.857 28.857 --- --- 29.743 --- 29.743 29.743 ---

V-L Flowrate (lbmol/hr) 160,256 160,256 4,768 49,229 49,229 6,753 3,704 0 0 225,509 0 225,509 225,509 8,032 V-L Flowrate (lb/hr) 4,624,510 4,624,510 137,601 1,420,601 1,420,601 194,880 106,884 0 0 6,707,354 0 6,707,354 6,707,354 144,703 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 614,994 11,927 47,708 47,708 0 0 62,618 Temperature (°F) 59 66 66 59 78 78 59 59 59 337 59 337 360 59 Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.4 15.0 Enthalpy (Btu/lb)A 13.0 14.8 14.8 13.0 17.5 17.5 13.0 --- --- 140.8 --- 132.8 138.8 ---

Density (lb/ft 3) 0.076 0.078 0.078 0.076 0.081 0.081 0.076 --- --- 0.050 --- 0.049 0.052 ---

A - Reference conditions are 32.02 F & 0.089 PSIA 355

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-19 Case 10 Stream Table, Subcritical Unit with CO2 Capture (Continued) 15 16 17 18 19 20 21 22 23 24 25 26 27 28 V-L Mole Fraction Ar 0.0000 0.0128 0.0000 0.0081 0.0108 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO2 0.0000 0.0005 0.0004 0.1350 0.0179 0.9961 0.9985 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2O 1.0000 0.0062 0.9996 0.1537 0.0383 0.0039 0.0015 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 N2 0.0000 0.7506 0.0000 0.6793 0.9013 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O2 0.0000 0.2300 0.0000 0.0238 0.0316 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 V-L Flowrate (kgmol/hr) 14,732 1,049 269 111,453 83,996 13,598 13,566 48,632 48,632 131,223 121,115 121,115 60,504 61,816 V-L Flowrate (kg/hr) 265,393 30,461 4,845 3,213,261 2,366,318 597,086 596,497 876,112 876,112 2,364,021 2,181,912 2,181,912 1,089,994 1,113,634 Solids Flowrate (kg/hr) 0 0 43,806 0 0 0 0 0 0 0 0 0 0 0 Temperature (°C) 15 181 58 58 32 21 35 296 151 566 363 566 38 39 Pressure (MPa, abs) 0.10 0.31 0.10 0.10 0.10 0.16 15.27 0.51 0.90 16.65 4.28 3.90 0.01 1.69 Enthalpy (kJ/kg)A -46.80 191.62 --- 301.43 93.86 19.49 -211.71 3,054.75 636.27 3,472.33 3,120.82 3,594.06 2,028.64 165.87 Density (kg/m3) 1,003.1 2.4 --- 1.1 1.1 2.9 795.9 2.0 916.0 47.7 15.7 10.3 0.1 993.3 V-L Molecular Weight 18.015 29.029 --- 28.831 28.172 43.908 43.971 18.015 18.015 18.015 18.015 18.015 18.015 18.015 V-L Flowrate (lbmol/hr) 32,478 2,313 593 245,711 185,179 29,979 29,907 107,214 107,214 289,297 267,012 267,012 133,388 136,281 V-L Flowrate (lb/hr) 585,092 67,154 10,682 7,084,027 5,216,839 1,316,349 1,315,051 1,931,497 1,931,497 5,211,774 4,810,293 4,810,293 2,403,024 2,455,142 Solids Flowrate (lb/hr) 0 0 96,577 0 0 0 0 0 0 0 0 0 0 0 Temperature (°F) 59 357 136 136 89 69 95 565 304 1,050 686 1,050 101 103 Pressure (psia) 14.7 45.0 14.9 14.9 14.7 23.5 2,214.5 73.5 130.0 2,415.0 620.5 565.5 1.0 245.0 Enthalpy (Btu/lb)A -20.1 82.4 --- 129.6 40.4 8.4 -91.0 1,313.3 273.5 1,492.8 1,341.7 1,545.2 872.2 71.3 Density (lb/ft 3) 62.622 0.149 --- 0.067 0.070 0.184 49.684 0.122 57.183 2.977 0.983 0.643 0.004 62.007 356

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-20 Case 10 Plant Performance Summary POWER

SUMMARY

(Gross Power at Generator Terminals, kWe)

Steam Turbine Power 672,700 TOTAL (STEAM TURBINE) POWER, kWe 672,700 AUXILIARY LOAD

SUMMARY

, kWe Coal Handling and Conveying 540 Pulverizers 4,180 Sorbent Handling & Reagent Preparation 1,370 Ash Handling 800 Primary Air Fans 1,960 Forced Draft Fans 2,500 Induced Draft Fans 12,080 SCR 70 Baghouse 100 Wet FGD 4,470 Econamine FG Plus Auxiliaries 22,400 CO2 Compression 48,790 2,3 Miscellaneous Balance of Plant 2,000 Steam Turbine Auxiliaries 400 Condensate Pumps 700 Circulating Water Pumps 11,190 Ground Water Pumps 1,020 Cooling Tower Fans 5,820 Transformer Losses 2,350 TOTAL AUXILIARIES, kWe 122,740 NET POWER, kWe 549,960 Net Plant Efficiency (HHV) 26.2%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 13,764 (13,046)

CONDENSER COOLING DUTY 106 kJ/hr (106 Btu/hr) 2,034 (1,928)

CONSUMABLES As-Received Coal Feed, kg/hr (lb/hr) 278,956 (614,994)

Limestone Sorbent Feed, kg/hr (lb/hr) 28,404 (62,618) 1 Thermal Input, kWt 2,102,643 3

Raw Water Withdrawal, m /min (gpm) 42.5 (11,224) 3 Raw Water Consumption, m /min (gpm) 32.6 (8,620)

1. HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)

2. Boiler feed pumps are turbine driven

3. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads.

357

Cost and Performance Baseline for Fossil Energy Plants Environmental Performance The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 2.4. A summary of the plant air emissions for Case 10 is presented in Exhibit 4-21.

Exhibit 4-21 Case 10 Air Emissions Tonne/year kg/GJ kg/MWh (ton/year)

(lb/106 Btu) (lb/MWh) 85% CF SO2 0.001 (0.002) 40 (44) 0.008 (.02)

NOx 0.030 (0.070) 1,696 (1,870) 0.339 (.747)

Particulates 0.006 (0.0130) 315 (347) 0.063 (.139)

Hg 4.91E-7 (1.14E-6) 0.028 (0.031) 5.53E-6 (1.22E-5)

CO2 8.8 (20.4) 493,198 (543,658) 98 (217)

CO21 120 (266) 1 CO2 emissions based on net power instead of gross power SO2 emissions are controlled using a wet limestone forced oxidation scrubber that achieves a removal efficiency of 98 percent. The byproduct calcium sulfate is dewatered and stored on site.

The wallboard grade material can potentially be marketed and sold, but since it is highly dependent on local market conditions, no byproduct credit was taken. The SO2 emissions are further reduced to 10 ppmv using a NaOH based polishing scrubber in the CDR facility. The remaining low concentration of SO2 is essentially completely removed in the CDR absorber vessel resulting in very low SO2 emissions.

NOx emissions are controlled to about 0.5 lb/106 Btu through the use of LNBs and OFA. An SCR unit then further reduces the NOx concentration by 86 percent to 0.07 lb/106 Btu.

Particulate emissions are controlled using a pulse jet fabric filter, which operates at an efficiency of 99.8 percent.

Co-benefit capture results in a 90 percent reduction of mercury emissions.

Ninety percent of the CO2 in the FG is removed in CDR facility.

The carbon balance for the plant is shown in Exhibit 4-22. The carbon input to the plant consists of carbon in the coal in addition to carbon in the air and limestone for the FGD. Carbon in the air is not neglected here since the Aspen model accounts for air components throughout. Carbon leaves the plant as CO2 in the stack gas, carbon in the FGD product, and the captured CO2 product. The CO2 capture efficiency is defined by the following fraction:

1-[(Stack Gas Carbon-Air Carbon)/(Total Carbon In-Air Carbon)] or

[1-(39,853-850)/(399,230-850) *100] or 90.2 percent 358

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-22 Case 10 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 177,820 (392,026) Stack Gas 18,077 (39,853)

Air (CO2) 386 (850) FGD Product 317 (699)

FGD Reagent 2,882 (6,354) CO2 Product 162,694 (358,679)

Total 181,088 (399,230) Total 181,088 (399,230)

Exhibit 4-23 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered from the FGD as gypsum, sulfur emitted in the stack gas, and sulfur removed in the polishing scrubber.

Exhibit 4-23 Case 10 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 6,992 (15,414) FGD Product 6,852 (15,106)

Stack Gas 3 (6)

Econamine Polishing 137 (302)

Scrubber/HSS Total 6,992 (15,414) Total 6,992 (15,414)

Exhibit 4-24 shows the overall water balance for the plant. The exhibit is presented in an identical manner as was for Case 9.

Exhibit 4-24 Case 10 Water Balance Process Water Internal Raw Water Water Raw Water Demand, Recycle, Withdrawal, Water Use Discharge, Consumption, m3/min m3/min m3/min m3/min m3/min (gpm)

(gpm) (gpm) (gpm)

(gpm)

Econamine 0.2 (39) 0.0 (0) 0.2 (39) 0.0 (0) 0.2 (39)

FGD Makeup 5.5 (1,460) 0.0 (0) 5.5 (1,460) 0.0 (0) 5.5 (1,460)

BFW Makeup 0.4 (104) 0.0 (0) 0.4 (104) 0.0 (0) 0.4 (104)

Cooling Tower 43.8 (11,580) 7.4 (1,959) 36.4 (9,621) 9.9 (2,604) 26.6 (7,017)

Total 49.9 (13,182) 7.4 (1,959) 42.5 (11,224) 9.9 (2,604) 32.6 (8,620) 359

Cost and Performance Baseline for Fossil Energy Plants Heat and Mass Balance Diagrams A heat and mass balance diagram is shown for the Case 10 PC boiler, the FGD unit, CDR system and steam cycle in Exhibit 4-25 and Exhibit 4-26. An overall plant energy balance is provided in tabular form in Exhibit 4-27.

The power out is the steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 4-20) is calculated by multiplying the power out by a generator efficiency of 98.4 percent. The Econamine process heat out stream represents heat rejected to cooling water and ultimately to ambient via the cooling tower. The same is true of the condenser heat out stream. The CO2 compressor intercooler load is included in the Econamine process heat out stream.

360

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-25 Case 10 Heat and Mass Balance, Subcritical PC Boiler with CO2 Capture 361

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-26 Case 10 Heat and Mass Balance, Subcritical Steam Cycle LEGEND Econamine Air Steam 4,842,620 W 1,931,497 W Coal/Char/

1,049.0 T 565.5 P 564.7 T 73.5 P Slurry/Slag 1,544.6 H 1,313.3 H Nitrogen Oxygen 24 4,325,282 W 284,197 W 5,211,774 W 564.7 T 2,109,588 W 564.7 T Sour Gas 1,050.0 T 73.5 P 564.7 T 73.5 P 2,415.0 P 1,313.3 H 73.5 P 1,313.3 H 1,492.8 H 1,313.3 H Sour Water Throttle Steam BOILER FEED HP IP LP TURBINE GENERATOR PUMP TURBINE Steam TURBINE TURBINE DRIVES Steam Turbine Makeup 52,118 W Synthesis Gas 41.6 P 5.0 P 48.0 T 2,415.0 P 350.5 P 75.0 P 64.2 P 1,850.0 P 75.0 P 11.8 P 284,197 W 11.4 P 1,715,276 W 16.1 H 126.1 T 101.1 T 1.0 P 2.0 P Water 1,088.1 H 1,020.0 H 620.5 P 620.5 P 2,415.0 P 620.5 P Single Reheat Extraction CONDENSER From Boiler STEAM SEAL REGULATOR 3,301 W 26 4,810,293 W Single Reheat 634.8 T P ABSOLUTE PRESSURE, PSIA 1,050.0 T 565.5 P Extraction to 75.0 P HOT WELL F TEMPERATURE, °F 1,347.9 H W FLOWRATE, LBM/HR 1,545.2 H Boiler 3,145 W 2,793 W 634.8 T 634.8 T H ENTHALPY, BTU/LBM 25 75.0 P 75.0 P 2,455,142 W MWE POWER, MEGAWATTS ELECTRICAL 1,347.9 H 1,347.9 H 101.1 T 4,810,293 W 1.0 P 686.0 T Econamine NOTES:

69.1 H 620.5 P Condensate 1,341.7 H 1,931,497 W 304.0 T CONDENSATE 1. ENTHALPY REFERENCE POINT IS NATURAL STATE 130.0 P 273.5 H PUMPS AT 32 °F AND 0.08865 PSIA 101.4 T 250.0 P 70.0 H 357,025 W 493,596 W 26,631 W 63,337 W 148,243 W 81,833 W 104,045 W 682.6 T 916.3 T 577.8 T 535.0 T 448.7 T 236.1 T 157.8 T 589.7 P 323.0 P 70.0 P 57.3 P 37.1 P 10.5 P 4.5 P 1,300.0 H 5,211,774 W 1,341.7 H 5,211,774 W 1,480.9 H 1,320.0 H 1,259.8 H 1,163.0 H 1,116.3 H GLAND SEAL PLANT PERFORMANCE

SUMMARY

484.4 T 2,455,142 W 2,455,142 W 2,455,142 W 2,455,142 W 426.2 T CONDENSER 3,100.5 P 284.7 T 257.7 T 190.5 T 152.8 T To Boiler 3,105.5 P P-1048 469.5 H FWH 7 FWH 6 220.0 P 230.0 P 235.0 P 240.0 P P-1028 2,793 W 406.0 H 253.9 H FWH 4 226.5 H FWH 3 158.8 H FWH 2 121.2 H FWH 1 212.0 T Gross Plant Power: 673 MWe 28 14.7 P Auxiliary Load: 123 MWe 2,455,142 W 179.9 H Net Plant Power: 550 MWe 102.8 T Net Plant Efficiency, HHV: 26.2%

DEAERATOR 245.0 P 71.3 H Net Plant Heat Rate: 13,046 BTU/KWe 357,025 W 850,621 W 63,337 W 211,580 W 293,413 W 436.2 T 319.4 T 267.7 T 200.5 T 162.8 T 397,457 W 366.7 P 323.0 P 40.3 P 11.7 P 5.1 P 112.8 T 414.3 H 289.8 H 236.3 H 168.3 H 130.6 H 1.4 P 80.6 H DOE/NETL 5,211,774 W 309.4 T 302.9 T 70.0 P SC PC PLANT 3,110.5 P 272.3 H CASE 10 284.6 H BOILER FEED PUMPS HEAT AND MATERIAL FLOW DIAGRAM BITUMINOUS BASELINE STUDY CASE 10 SUBCRITICAL PULVERIZED COAL POWER BLOCK SYSTEMS DWG. NO. PAGES BB-HMB-CS-10-PG-2 2 OF 2 362

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-27 Case 10 Overall Energy Balance (0°C [32°F] Reference)

Sensible +

HHV Power Total Latent Heat In GJ/hr (MMBtu/hr)

Coal 7,570 (7,175) 6.3 (6.0) 7,576 (7,181)

Air 84.3 (79.9) 84.3 (79.9)

Raw Water Makeup 159.9 (151.5) 159.9 (151.5)

Limestone 0.32 (0.30) 0.32 (0.30)

Auxiliary Power 442 (419) 442 (419)

Totals 7,570 (7,175) 250.9 (237.8) 442 (419) 8,262 (7,831)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.7 (0.6) 0.7 (0.6)

Fly Ash + FGD Ash 2.6 (2.5) 2.6 (2.5)

Flue Gas 222 (211) 222 (211)

Condenser 2,034 (1,928) 2,034 (1,928)

CO2 -126 (-120) -126 (-120)

Cooling Tower 73.2 (69.4) 73.2 (69.4)

Blowdown Econamine Losses 3,585 (3,398) 3,585 (3,398)

Process Losses* 49.6 (47.0) 49.6 (47.0)

Power 2,422 (2,295) 2,422 (2,295)

Totals 0 (0) 5,841 (5,536) 2,422 (2,295) 8,262 (7,831)

Process losses are estimated to match the heat input to the plant. Process losses include losses from: turbines, gas cooling, etc.

363

Cost and Performance Baseline for Fossil Energy Plants 4.2.9 Case 10 - Major Equipment List Major equipment items for the subcritical PC plant with CO2 capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section 4.2.10. In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 FUEL AND SORBENT HANDLING Equipment Operating Description Type Design Condition Spares No. Qty.

Bottom Trestle Dumper and 1 N/A 181 tonne (200 ton) 2 0 Receiving Hoppers 2 Feeder Belt 572 tonne/hr (630 tph) 2 0 3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0 4 Transfer Tower No. 1 Enclosed N/A 1 0 5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0 As-Received Coal Sampling 6 Two-stage N/A 1 0 System 7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0 8 Reclaim Hopper N/A 54 tonne (60 ton) 2 1 9 Feeder Vibratory 227 tonne/hr (250 tph) 2 1 10 Conveyor No. 3 Belt w/ tripper 463 tonne/hr (510 tph) 1 0 11 Crusher Tower N/A N/A 1 0 12 Coal Surge Bin w/ Vent Filter Dual outlet 227 tonne (250 ton) 2 0 Impactor 8 cm x 0 - 3 cm x 0 13 Crusher 2 0 reduction (3 in x 0 1/4 in x 0)

As-Fired Coal Sampling 14 Swing hammer N/A 1 1 System 15 Conveyor No. 4 Belt w/tripper 463 tonne/hr (510 tph) 1 0 16 Transfer Tower No. 2 Enclosed N/A 1 0 17 Conveyor No. 5 Belt w/ tripper 463 tonne/hr (510 tph) 1 0 Coal Silo w/ Vent Filter and 18 Field erected 998 tonne (1,100 ton) 3 0 Slide Gates Limestone Truck Unloading 19 N/A 36 tonne (40 ton) 1 0 Hopper 20 Limestone Feeder Belt 118 tonne/hr (130 tph) 1 0 21 Limestone Conveyor No. L1 Belt 118 tonne/hr (130 tph) 1 0 22 Limestone Reclaim Hopper N/A 27 tonne (30 ton) 1 0 23 Limestone Reclaim Feeder Belt 91 tonne/hr (100 tph) 1 0 24 Limestone Conveyor No. L2 Belt 91 tonne/hr (100 tph) 1 0 25 Limestone Day Bin w/ actuator 372 tonne (410 ton) 2 0 364

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED Equipment Operating Description Type Design Condition Spares No. Qty.

1 Coal Feeder Gravimetric 54 tonne/hr (60 tph) 6 0 Ball type or 2 Coal Pulverizer 54 tonne/hr (60 tph) 6 0 equivalent 3 Limestone Weigh Feeder Gravimetric 31 tonne/hr (34 tph) 1 1 4 Limestone Ball Mill Rotary 31 tonne/hr (34 tph) 1 1 Limestone Mill Slurry Tank 5 N/A 121,133 liters (32,000 gal) 1 1 with Agitator Limestone Mill Recycle Horizontal 2,006 lpm @ 12m H2O (530 gpm 6 1 1 Pumps centrifugal @ 40 ft H2O) 4 active 7 Hydroclone Classifier cyclones in a 5 492 lpm (130 gpm) per cyclone 1 1 cyclone bank 8 Distribution Box 2-way N/A 1 1 Limestone Slurry Storage 9 Field erected 673,803 liters (178,000 gal) 1 1 Tank with Agitator Limestone Slurry Feed Horizontal 1,401 lpm @ 9m H2O (370 gpm 10 1 1 Pumps centrifugal @ 30 ft H2O) 365

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment Operating Description Type Design Condition Spares No. Qty.

Demineralized Water Vertical, cylindrical, 1 1,563,375 liters (413,000 gal) 2 0 Storage Tank outdoor 20,441 lpm @ 213 m H2O (5,400 2 Condensate Pumps Vertical canned 1 1 gpm @ 700 ft H2O)

Deaerator and Storage 2,600,445 kg/hr (5,733,000 lb/hr),

3 Horizontal spray type 1 0 Tank 5 min. tank Boiler Feed Barrel type, multi-stage, 43,532 lpm @ 2,591 m H2O 4 1 1 Pump/Turbine centrifugal (11,500 gpm @ 8,500 ft H2O)

Startup Boiler Feed Barrel type, multi-stage, 12,870 lpm @ 2,591 m H2O 5 Pump, Electric Motor 1 0 centrifugal (3,400 gpm @ 8,500 ft H2O)

Driven LP Feedwater Heater 6 Horizontal U-tube 612,350 kg/hr (1,350,000 lb/hr) 2 0 1A/1B LP Feedwater Heater 7 Horizontal U-tube 612,350 kg/hr (1,350,000 lb/hr) 2 0 2A/2B LP Feedwater Heater 8 Horizontal U-tube 612,350 kg/hr (1,350,000 lb/hr) 2 0 3A/3B LP Feedwater Heater 9 Horizontal U-tube 612,350 kg/hr (1,350,000 lb/hr) 2 0 4A/4B 10 HP Feedwater Heater 6 Horizontal U-tube 2,599,084 kg/hr (5,730,000 lb/hr) 1 0 11 HP Feedwater Heater 7 Horizontal U-tube 2,599,084 kg/hr (5,730,000 lb/hr) 1 0 Shop fabricated, water 18,144 kg/hr, 2.8 MPa, 343°C 12 Auxiliary Boiler 1 0 tube (40,000 lb/hr, 400 psig, 650°F)

No. 2 fuel oil for light 13 Fuel Oil System 1,135,624 liter (300,000 gal) 1 0 off Service Air 28 m3/min @ 0.7 MPa (1,000 14 Flooded Screw 2 1 Compressors scfm @ 100 psig) 15 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1 Closed Cycle Cooling 16 Shell and tube 53 GJ/hr (50 MMBtu/hr) each 2 0 Heat Exchangers Closed Cycle Cooling 20,820 lpm @ 30 m H2O (5,500 17 Horizontal centrifugal 2 1 Water Pumps gpm @ 100 ft H2O)

Engine-Driven Fire Vertical turbine, diesel 3,785 lpm @ 88 m H2O (1,000 18 1 1 Pump engine gpm @ 290 ft H2O)

Fire Service Booster Two-stage horizontal 2,650 lpm @ 64 m H2O (700 gpm 19 1 1 Pump centrifugal @ 210 ft H2O)

Stainless steel, single 12,265 lpm @ 18 m H2O (3,240 20 Raw Water Pumps 2 1 suction gpm @ 60 ft H2O)

Stainless steel, single 4,921 lpm @ 268 m H2O (1,300 21 Ground Water Pumps 5 1 suction gpm @ 880 ft H2O)

Stainless steel, single 2,953 lpm @ 49 m H2O (780 gpm 22 Filtered Water Pumps 2 1 suction @ 160 ft H2O) 23 Filtered Water Tank Vertical, cylindrical 2,839,059 liter (750,000 gal) 1 0 Multi-media filter, Makeup Water cartridge filter, RO 24 1,022 lpm (270 gpm) 1 1 Demineralizer membrane assembly, electrodeionization unit Liquid Waste Treatment 25 -- 10 years, 24-hour storm 1 0 System 366

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 4 BOILER AND ACCESSORIES Equipment Operating Description Type Design Condition Spares No. Qty.

2,599,084 kg/hr steam @ 17.9 Subcritical, drum MPa/574°C/574°C (5,730,000 1 Boiler wall-fired, low NOx 1 0 lb/hr steam @ 2,600 burners, overfire air psig/1,065°F/1,065°F) 354,256 kg/hr, 4,837 m3/min @

2 Primary Air Fan Centrifugal 123 cm WG (781,000 lb/hr, 2 0 170,800 acfm @ 48 in. WG) 1,153,485 kg/hr, 15,744 m3/min 3 Forced Draft Fan Centrifugal @ 47 cm WG (2,543,000 lb/hr, 2 0 556,000 acfm @ 19 in. WG) 1,673,302 kg/hr, 35,314 m3/min 4 Induced Draft Fan Centrifugal @ 104 cm WG (3,689,000 lb/hr, 2 0 1,247,100 acfm @ 41 in. WG)

Space for spare 5 SCR Reactor Vessel 3,347,512 kg/hr (7,380,000 lb/hr) 2 0 layer 6 SCR Catalyst -- -- 3 0 198 m3/min @ 108 cm WG 7 Dilution Air Blower Centrifugal 2 1 (7,000 acfm @ 42 in. WG) 8 Ammonia Storage Horizontal tank 219,554 liter (58,000 gal) 5 0 Ammonia Feed 42 lpm @ 91 m H2O (11 gpm @

9 Centrifugal 2 1 Pump 300 ft H2O) 367

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 5 FLUE GAS CLEANUP Equipment Operating Description Type Design Condition Spares No. Qty.

Single stage, high-ratio with pulse-jet 1,673,302 kg/hr (3,689,000 lb/hr) 1 Fabric Filter 2 0 online cleaning 99.8% efficiency system Counter-current 2 Absorber Module 66,913 m3/min (2,363,000 acfm) 1 0 open spray Horizontal 230,910 lpm @ 64 m H2O 3 Recirculation Pumps 5 1 centrifugal (61,000 gpm @ 210 ft H2O)

Horizontal 6,095 lpm (1,610 gpm) at 20 wt%

4 Bleed Pumps 2 1 centrifugal solids 117 m3/min @ 0.3 MPa (4,130 5 Oxidation Air Blowers Centrifugal 2 1 acfm @ 37 psia) 6 Agitators Side entering 50 hp 5 1 Radial assembly, 7 Dewatering Cyclones 1,514 lpm (400 gpm) per cyclone 2 0 5 units each 48 tonne/hr (53 tph) of 50 wt %

8 Vacuum Filter Belt Horizontal belt 2 1 slurry Filtrate Water Return Horizontal 908 lpm @ 12 m H2O (240 gpm 9 1 1 Pumps centrifugal @ 40 ft H2O)

Filtrate Water Return 10 Vertical, lined 605,666 lpm (160,000 gal) 1 0 Storage Tank Process Makeup Water Horizontal 4,883 lpm @ 21 m H2O (1,290 11 1 1 Pumps centrifugal gpm @ 70 ft H2O) 368

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 5B CARBON DIOXIDE RECOVERY Equipment Operating Description Type Design Condition Spares No. Qty.

Econamine FG Amine-based CO2 1,767,196 kg/h (3,896,000 lb/h) 1 2 0 Plus capture technology 20.6 wt % CO2 concentration Econamine 18,435 lpm @ 52 m H2O (4,870 2 Condensate Centrifugal 1 1 gpm @ 170 ft H2O)

Pump CO2 Integrally geared, 327,872 kg/h @ 15.3 MPa 3 2 0 Compressor multi-stage centrifugal (722,834 lb/h @ 2,215 psia)

ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES N/A ACCOUNT 7 HRSG, DUCTING & STACK Equipment Operating Description Type Design Condition Spares No. Qty.

Reinforced concrete 152 m (500 ft) high x 1 Stack 1 0 with FRP liner 5.8 m (19 ft) diameter ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES Equipment Operating Description Type Design Condition Spares No. Qty.

708 MW Commercially 16.5 MPa/566°C/566°C 1 Steam Turbine available advanced 1 0 (2400.3 psig/

steam turbine 1050°F/1050°F)

Hydrogen cooled, 790 MVA @ 0.9 p.f., 24 2 Steam Turbine Generator 1 0 static excitation kV, 60 Hz, 3-phase 2,237 GJ/hr (2,120 Single pass, divided MMBtu/hr), Inlet water 3 Surface Condenser waterbox including temperature 16°C (60°F), 1 0 vacuum pumps Water temperature rise 11°C (20°F) 369

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 9 COOLING WATER SYSTEM Equipment Operating Description Type Design Condition Spares No. Qty.

Circulating Water 1,128,100 lpm @ 30 m 1 Vertical, wet pit 2 1 Pumps (298,000 gpm @ 100 ft) 11°C (51.5°F) wet bulb / 16°C Evaporative, (60°F) CWT / 27°C (80°F) HWT 2 Cooling Tower mechanical draft, multi- 1 0

/ 6299 GJ/hr (5970 MMBtu/hr) cell heat duty 370

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING Equipment Operating Description Type Design Condition Spares No. Qty.

Economizer Hopper (part of 1 -- -- 4 0 boiler scope of supply)

Bottom Ash Hopper (part of 2 -- -- 2 0 boiler scope of supply) 3 Clinker Grinder -- 6.4 tonne/hr (7 tph) 1 1 Pyrites Hopper (part of 4 pulverizer scope of supply -- -- 6 0 included with boiler) 5 Hydroejectors -- -- 12 Economizer /Pyrites Transfer 6 -- -- 1 0 Tank 227 lpm @ 17 m H2O (60 gpm 7 Ash Sluice Pumps Vertical, wet pit 1 1

@ 56 ft H2O) 7,571 lpm @ 9 m H2O (2000 8 Ash Seal Water Pumps Vertical, wet pit 1 1 gpm @ 28 ft H2O) 9 Hydrobins -- 227 lpm (60 gpm) 1 1 Baghouse Hopper (part of 10 -- -- 24 0 baghouse scope of supply)

Air Heater Hopper (part of 11 -- -- 10 0 boiler scope of supply) 22 m3/min @ 0.2 MPa (770 12 Air Blower -- 1 1 scfm @ 24 psi)

Reinforced 13 Fly Ash Silo 1,451 tonne (1,600 ton) 2 0 concrete 14 Slide Gate Valves -- -- 2 0 15 Unloader -- -- 1 0 16 Telescoping Unloading Chute -- 136 tonne/hr (150 tph) 1 0 371

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 11 ACCESSORY ELECTRIC PLANT Equipment Operating Description Type Design Condition Spares No. Qty.

24 kV/345 kV, 650 MVA, 3-1 STG Transformer Oil-filled 1 0 ph, 60 Hz Auxiliary 24 kV/4.16 kV, 134 MVA, 3-2 Oil-filled 1 1 Transformer ph, 60 Hz Low Voltage 4.16 kV/480 V, 20 MVA, 3-3 Dry ventilated 1 1 Transformer ph, 60 Hz STG Isolated 4 Phase Bus Duct Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0 and Tap Bus Medium Voltage 5 Metal clad 4.16 kV, 3-ph, 60 Hz 1 1 Switchgear Low Voltage 6 Metal enclosed 480 V, 3-ph, 60 Hz 1 1 Switchgear Emergency Diesel Sized for emergency 7 750 kW, 480 V, 3-ph, 60 Hz 1 0 Generator shutdown ACCOUNT 12 INSTRUMENTATION AND CONTROL Equipment Operating Description Type Design Condition Spares No. Qty.

Monitor/keyboard; DCS - Main Operator printer (laser Operator stations/printers and 1 1 0 Control color); Engineering engineering stations/printers printer (laser B&W)

Microprocessor with 2 DCS - Processor N/A 1 0 redundant input/output DCS - Data 3 Fiber optic Fully redundant, 25% spare 1 0 Highway 372

Cost and Performance Baseline for Fossil Energy Plants 4.2.10 Case 10 - Cost Estimating The cost estimating methodology was described previously in Section 2.7. Exhibit 4-28 shows the total plant capital cost summary organized by cost account and Exhibit 4-29 shows a more detailed breakdown of the capital costs along with owners costs, TOC, and TASC. Exhibit 4-30 shows the initial and annual O&M costs.

The estimated TOC of the subcritical PC boiler with CO2 capture is $3,610/kW. Process contingency represents 2.9 percent of the TOC and project contingency represents 10.2 percent.

The COE, including CO2 TS&M costs of 5.9 mills/kWh, is 109.7 mills/kWh.

373

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-28 Case 10 Total Plant Cost Summary Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study TOTAL PLANT COST

SUMMARY

Case: Case 10 - 1x550 MWnet SubCritical PC w/ CO2 Capture Plant Size: 550.0 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING $21,191 $5,688 $12,662 $0 $0 $39,542 $3,548 $0 $6,463 $49,553 $90 2 COAL & SORBENT PREP & FEED $14,465 $844 $3,675 $0 $0 $18,984 $1,664 $0 $3,097 $23,744 $43 3 FEEDWATER & MISC. BOP SYSTEMS $52,748 $0 $25,315 $0 $0 $78,063 $7,174 $0 $14,102 $99,339 $181 4 PC BOILER 4.1 PC Boiler & Accessories $171,007 $0 $109,973 $0 $0 $280,980 $27,374 $0 $30,835 $339,189 $617 4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4-4.9 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4 $171,007 $0 $109,973 $0 $0 $280,980 $27,374 $0 $30,835 $339,189 $617 5 FLUE GAS CLEANUP $107,581 $0 $36,768 $0 $0 $144,350 $13,816 $0 $15,817 $173,983 $316 5B CO2 REMOVAL & COMPRESSION $247,434 $0 $75,421 $0 $0 $322,855 $30,869 $56,959 $82,137 $492,819 $896 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 6.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 6 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 7.2-7.9 HRSG Accessories, Ductwork and Stack $19,509 $1,069 $13,214 $0 $0 $33,792 $3,095 $0 $4,848 $41,735 $76 SUBTOTAL 7 $19,509 $1,069 $13,214 $0 $0 $33,792 $3,095 $0 $4,848 $41,735 $76 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $55,209 $0 $6,905 $0 $0 $62,114 $5,951 $0 $6,806 $74,871 $136 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $26,840 $1,213 $15,303 $0 $0 $43,356 $3,796 $0 $6,701 $53,853 $98 SUBTOTAL 8 $82,049 $1,213 $22,207 $0 $0 $105,470 $9,747 $0 $13,507 $128,724 $234 9 COOLING WATER SYSTEM $22,313 $10,599 $19,714 $0 $0 $52,626 $4,953 $0 $7,745 $65,324 $119 10 ASH/SPENT SORBENT HANDLING SYS $5,525 $176 $7,387 $0 $0 $13,088 $1,258 $0 $1,477 $15,823 $29 11 ACCESSORY ELECTRIC PLANT $25,948 $11,057 $31,311 $0 $0 $68,316 $6,043 $0 $9,343 $83,703 $152 12 INSTRUMENTATION & CONTROL $9,942 $0 $10,082 $0 $0 $20,024 $1,816 $1,001 $2,805 $25,646 $47 13 IMPROVEMENTS TO SITE $3,344 $1,922 $6,739 $0 $0 $12,006 $1,184 $0 $2,638 $15,828 $29 14 BUILDINGS & STRUCTURES $0 $25,775 $24,432 $0 $0 $50,207 $4,529 $0 $8,210 $62,947 $114 TOTAL COST $783,055 $58,343 $398,903 $0 $0 $1,240,301 $117,071 $57,960 $203,025 $1,618,357 $2,942 374

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-29 Case 10 Total Plant Cost Details Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $4,333 $0 $1,979 $0 $0 $6,313 $564 $0 $1,031 $7,908 $14 1.2 Coal Stackout & Reclaim $5,600 $0 $1,269 $0 $0 $6,869 $601 $0 $1,120 $8,590 $16 1.3 Coal Conveyors $5,207 $0 $1,255 $0 $0 $6,462 $566 $0 $1,054 $8,083 $15 1.4 Other Coal Handling $1,362 $0 $290 $0 $0 $1,653 $144 $0 $270 $2,067 $4 1.5 Sorbent Receive & Unload $178 $0 $54 $0 $0 $231 $20 $0 $38 $289 $1 1.6 Sorbent Stackout & Reclaim $2,869 $0 $526 $0 $0 $3,395 $296 $0 $554 $4,244 $8 1.7 Sorbent Conveyors $1,024 $221 $251 $0 $0 $1,496 $129 $0 $244 $1,869 $3 1.8 Other Sorbent Handling $618 $145 $324 $0 $0 $1,088 $96 $0 $178 $1,361 $2 1.9 Coal & Sorbent Hnd.Foundations $0 $5,322 $6,714 $0 $0 $12,036 $1,130 $0 $1,975 $15,141 $28 SUBTOTAL 1. $21,191 $5,688 $12,662 $0 $0 $39,542 $3,548 $0 $6,463 $49,553 $90 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $2,523 $0 $492 $0 $0 $3,014 $263 $0 $492 $3,768 $7 2.2 Coal Conveyor to Storage $6,459 $0 $1,410 $0 $0 $7,869 $688 $0 $1,283 $9,840 $18 2.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.5 Sorbent Prep Equipment $4,894 $211 $1,016 $0 $0 $6,121 $533 $0 $998 $7,652 $14 2.6 Sorbent Storage & Feed $590 $0 $226 $0 $0 $815 $72 $0 $133 $1,021 $2 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $633 $531 $0 $0 $1,164 $108 $0 $191 $1,463 $3 SUBTOTAL 2. $14,465 $844 $3,675 $0 $0 $18,984 $1,664 $0 $3,097 $23,744 $43 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $20,624 $0 $7,119 $0 $0 $27,743 $2,430 $0 $4,526 $34,699 $63 3.2 Water Makeup & Pretreating $7,503 $0 $2,415 $0 $0 $9,919 $938 $0 $2,171 $13,028 $24 3.3 Other Feedwater Subsystems $6,747 $0 $2,851 $0 $0 $9,599 $860 $0 $1,569 $12,027 $22 3.4 Service Water Systems $1,471 $0 $800 $0 $0 $2,271 $214 $0 $497 $2,982 $5 3.5 Other Boiler Plant Systems $8,081 $0 $7,979 $0 $0 $16,060 $1,526 $0 $2,638 $20,224 $37 3.6 FO Supply Sys & Nat Gas $278 $0 $348 $0 $0 $626 $59 $0 $103 $788 $1 3.7 Waste Treatment Equipment $5,087 $0 $2,900 $0 $0 $7,987 $777 $0 $1,753 $10,517 $19 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,955 $0 $903 $0 $0 $3,858 $371 $0 $846 $5,075 $9 SUBTOTAL 3. $52,748 $0 $25,315 $0 $0 $78,063 $7,174 $0 $14,102 $99,339 $181 4 PC BOILER 4.1 PC Boiler & Accessories $171,007 $0 $109,973 $0 $0 $280,980 $27,374 $0 $30,835 $339,189 $617 4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4. $171,007 $0 $109,973 $0 $0 $280,980 $27,374 $0 $30,835 $339,189 $617 375

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-29 Case 10 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 5 FLUE GAS CLEANUP 5.1 Absorber Vessels & Accessories $74,713 $0 $16,084 $0 $0 $90,797 $8,656 $0 $9,945 $109,399 $199 5.2 Other FGD $3,899 $0 $4,418 $0 $0 $8,317 $807 $0 $912 $10,037 $18 5.3 Bag House & Accessories $21,582 $0 $13,697 $0 $0 $35,279 $3,400 $0 $3,868 $42,546 $77 5.4 Other Particulate Removal Materials $1,461 $0 $1,563 $0 $0 $3,023 $293 $0 $332 $3,648 $7 5.5 Gypsum Dewatering System $5,926 $0 $1,007 $0 $0 $6,933 $660 $0 $759 $8,352 $15 5.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5.9 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5. $107,581 $0 $36,768 $0 $0 $144,350 $13,816 $0 $15,817 $173,983 $316 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $218,463 $0 $66,332 $0 $0 $284,795 $27,229 $56,959 $73,796 $442,779 $805 5B.2 CO2 Compression & Drying $28,971 $0 $9,089 $0 $0 $38,060 $3,640 $0 $8,340 $50,040 $91 SUBTOTAL 5B. $247,434 $0 $75,421 $0 $0 $322,855 $30,869 $56,959 $82,137 $492,819 $896 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $10,193 $0 $6,549 $0 $0 $16,743 $1,460 $0 $2,730 $20,933 $38 7.4 Stack $9,316 $0 $5,451 $0 $0 $14,766 $1,422 $0 $1,619 $17,807 $32 7.9 Duct & Stack Foundations $0 $1,069 $1,214 $0 $0 $2,283 $214 $0 $499 $2,996 $5 SUBTOTAL 7. $19,509 $1,069 $13,214 $0 $0 $33,792 $3,095 $0 $4,848 $41,735 $76 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $55,209 $0 $6,905 $0 $0 $62,114 $5,951 $0 $6,806 $74,871 $136 8.2 Turbine Plant Auxiliaries $387 $0 $828 $0 $0 $1,215 $119 $0 $133 $1,467 $3 8.3 Condenser & Auxiliaries $6,154 $0 $2,549 $0 $0 $8,702 $835 $0 $954 $10,490 $19 8.4 Steam Piping $20,300 $0 $10,009 $0 $0 $30,310 $2,547 $0 $4,928 $37,784 $69 8.9 TG Foundations $0 $1,213 $1,917 $0 $0 $3,130 $296 $0 $685 $4,111 $7 SUBTOTAL 8. $82,049 $1,213 $22,207 $0 $0 $105,470 $9,747 $0 $13,507 $128,724 $234 9 COOLING WATER SYSTEM 9.1 Cooling Towers $16,661 $0 $5,188 $0 $0 $21,850 $2,090 $0 $2,394 $26,333 $48 9.2 Circulating Water Pumps $3,467 $0 $260 $0 $0 $3,727 $315 $0 $404 $4,446 $8 9.3 Circ.Water System Auxiliaries $839 $0 $112 $0 $0 $951 $90 $0 $104 $1,146 $2 9.4 Circ.Water Piping $0 $6,653 $6,448 $0 $0 $13,101 $1,226 $0 $2,149 $16,476 $30 9.5 Make-up Water System $680 $0 $909 $0 $0 $1,589 $152 $0 $261 $2,002 $4 9.6 Component Cooling Water Sys $665 $0 $529 $0 $0 $1,194 $113 $0 $196 $1,503 $3 9.9 Circ.Water System Foundations & Structures $0 $3,946 $6,269 $0 $0 $10,214 $966 $0 $2,236 $13,417 $24 SUBTOTAL 9. $22,313 $10,599 $19,714 $0 $0 $52,626 $4,953 $0 $7,745 $65,324 $119 376

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-29 Case 10 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $739 $0 $2,278 $0 $0 $3,017 $296 $0 $331 $3,645 $7 10.7 Ash Transport & Feed Equipment $4,786 $0 $4,902 $0 $0 $9,688 $926 $0 $1,061 $11,676 $21 10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.9 Ash/Spent Sorbent Foundation $0 $176 $207 $0 $0 $383 $36 $0 $84 $502 $1 SUBTOTAL 10. $5,525 $176 $7,387 $0 $0 $13,088 $1,258 $0 $1,477 $15,823 $29 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $1,742 $0 $283 $0 $0 $2,025 $188 $0 $166 $2,379 $4 11.2 Station Service Equipment $5,148 $0 $1,691 $0 $0 $6,839 $639 $0 $561 $8,039 $15 11.3 Switchgear & Motor Control $5,918 $0 $1,006 $0 $0 $6,924 $642 $0 $757 $8,322 $15 11.4 Conduit & Cable Tray $0 $3,710 $12,830 $0 $0 $16,540 $1,601 $0 $2,721 $20,862 $38 11.5 Wire & Cable $0 $7,001 $13,516 $0 $0 $20,517 $1,729 $0 $3,337 $25,582 $47 11.6 Protective Equipment $270 $0 $918 $0 $0 $1,188 $116 $0 $130 $1,434 $3 11.7 Standby Equipment $1,370 $0 $31 $0 $0 $1,401 $128 $0 $153 $1,682 $3 11.8 Main Power Transformers $11,500 $0 $191 $0 $0 $11,691 $886 $0 $1,258 $13,835 $25 11.9 Electrical Foundations $0 $345 $846 $0 $0 $1,191 $114 $0 $261 $1,566 $3 SUBTOTAL 11. $25,948 $11,057 $31,311 $0 $0 $68,316 $6,043 $0 $9,343 $83,703 $152 12 INSTRUMENTATION & CONTROL 12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $512 $0 $307 $0 $0 $819 $77 $41 $141 $1,077 $2 12.7 Distributed Control System Equipment $5,168 $0 $903 $0 $0 $6,071 $563 $304 $694 $7,632 $14 12.8 Instrument Wiring & Tubing $2,802 $0 $5,558 $0 $0 $8,359 $712 $418 $1,423 $10,913 $20 12.9 Other I & C Equipment $1,460 $0 $3,314 $0 $0 $4,774 $463 $239 $548 $6,024 $11 SUBTOTAL 12. $9,942 $0 $10,082 $0 $0 $20,024 $1,816 $1,001 $2,805 $25,646 $47 377

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-29 Case 10 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $56 $1,124 $0 $0 $1,180 $117 $0 $260 $1,557 $3 13.2 Site Improvements $0 $1,866 $2,318 $0 $0 $4,184 $413 $0 $919 $5,516 $10 13.3 Site Facilities $3,344 $0 $3,298 $0 $0 $6,642 $655 $0 $1,459 $8,756 $16 SUBTOTAL 13. $3,344 $1,922 $6,739 $0 $0 $12,006 $1,184 $0 $2,638 $15,828 $29 14 BUILDINGS & STRUCTURES 14.1 Boiler Building $0 $9,158 $8,054 $0 $0 $17,212 $1,547 $0 $2,814 $21,573 $39 14.2 Turbine Building $0 $13,420 $12,507 $0 $0 $25,927 $2,337 $0 $4,240 $32,503 $59 14.3 Administration Building $0 $646 $684 $0 $0 $1,330 $121 $0 $218 $1,668 $3 14.4 Circulation Water Pumphouse $0 $176 $140 $0 $0 $317 $28 $0 $52 $397 $1 14.5 Water Treatment Buildings $0 $952 $868 $0 $0 $1,819 $164 $0 $297 $2,281 $4 14.6 Machine Shop $0 $432 $290 $0 $0 $723 $64 $0 $118 $905 $2 14.7 Warehouse $0 $293 $294 $0 $0 $587 $53 $0 $96 $736 $1 14.8 Other Buildings & Structures $0 $239 $204 $0 $0 $443 $40 $0 $72 $555 $1 14.9 Waste Treating Building & Str. $0 $458 $1,391 $0 $0 $1,849 $176 $0 $304 $2,329 $4 SUBTOTAL 14. $0 $25,775 $24,432 $0 $0 $50,207 $4,529 $0 $8,210 $62,947 $114 TOTAL COST $783,055 $58,343 $398,903 $0 $0 $1,240,301 $117,071 $57,960 $203,025 $1,618,357 $2,942 Owner's Costs Preproduction Costs 6 Months All Labor $10,547 $19 1 Month Maintenance Materials $1,534 $3 1 Month Non-fuel Consumables $1,789 $3 1 Month Waste Disposal $353 $1 25% of 1 Months Fuel Cost at 100% CF $2,143 $4 2% of TPC $32,367 $59 Total $48,733 $89 Inventory Capital 60 day supply of fuel and consumables at 100% CF $20,189 $37 0.5% of TPC (spare parts) $8,092 $15 Total $28,281 $51 Initial Cost for Catalyst and Chemicals $2,712 $5 Land $900 $2 Other Owner's Costs $242,754 $441 Financing Costs $43,696 $79 Total Overnight Costs (TOC) $1,985,432 $3,610 TASC Multiplier (IOU, high-risk, 35 year) 1.140 Total As-Spent Cost (TASC) $2,263,393 $4,115 378

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-30 Case 10 Initial and Annual Operating and Maintenance Costs INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 10 - 1x550 MWnet SubCritical PC w/ CO2 Capture Heat Rate-net (Btu/kWh): 13,044 MWe-net: 550 Capacity Factor (%): 85 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant Skilled Operator 2.0 2.0 Operator 11.3 11.3 Foreman 1.0 1.0 Lab Tech's, etc. 2.0 2.0 TOTAL-O.J.'s 16.3 16.3 Annual Cost Annual Unit Cost

$ $/kW-net Annual Operating Labor Cost $6,444,907 $11.718 Maintenance Labor Cost $10,429,543 $18.962 Administrative & Support Labor $4,218,612 $7.670 Property Taxes and Insurance $32,367,148 $58.848 TOTAL FIXED OPERATING COSTS $53,460,210 $97.199 VARIABLE OPERATING COSTS

$/kWh-net Maintenance Material Cost $15,644,314 $0.00382 Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water(/1000 gallons) 0 8,081 1.08 $0 $2,711,996 $0.00066 Chemicals MU & WT Chem.(lbs) 0 39,119 0.17 $0 $2,100,447 $0.00051 Limestone (ton) 0 751 21.63 $0 $5,043,346 $0.00123 Carbon (Mercury Removal) (lb) 0 0 1.05 $0 $0 $0.00000 MEA Solvent (ton) 1,117 1.58 2,249.89 $2,513,263 $1,105,563 $0.00027 NaOH (tons) 79 7.89 433.68 $34,221 $1,061,704 $0.00026 H2SO4 (tons) 75 7.53 138.78 $10,450 $324,217 $0.00008 Corrosion Inhibitor 0 0 0.00 $154,511 $7,358 $0.00000 Activated Carbon (lb) 0 1,892 1.05 $0 $616,433 $0.00015 Ammonia (19% NH3) ton 0 110 129.80 $0 $4,446,378 $0.00109 Subtotal Chemicals $2,712,445 $14,705,446 $0.00359 Other Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 SCR Catalyst (m3) w/equip. 0.46 5,775.94 $0 $831,516 $0.00020 Emission Penalties 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $831,516 $0.00020 Waste Disposal Fly Ash (ton) 0 572 16.23 $0 $2,881,846 $0.00070 Bottom Ash (ton) 0 143 16.23 $0 $720,462 $0.00018 Subtotal-Waste Disposal $0 $3,602,308 $0.00088 By-products & Emissions Gypsum (tons) 0 1,159 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000 TOTAL VARIABLE OPERATING COSTS $2,712,445 $37,495,580 $0.00916 Fuel(ton) 0 7,380 38.18 $0 $87,425,787 $0.02135 379

Cost and Performance Baseline for Fossil Energy Plants 4.3 SUPERCRITICAL PC CASES This section contains an evaluation of plant designs for Cases 11 and 12, which are based on a SC PC plant with a nominal net output of 550 MWe. Both plants use a single reheat 24.1 MPa/593°C/593°C (3,500 psig/1,100°F/1,100°F) cycle. The only difference between the two plants is that Case 12 includes CO2 capture while Case 11 does not.

The balance of Section 4.3 is organized in an analogous manner to the subcritical PC section:

Process and System Description for Case 11

Key Assumptions for Cases 11 and 12

Sparing Philosophy for Cases 11 and 12

Performance Results for Case 11

Equipment List for Case 11

Cost Estimates for Case 11

Process and System Description, Performance Results, Equipment List and Cost Estimates for Case 12 4.3.1 Process Description In this section the SC PC process without CO2 capture is described. The system description is nearly identical to the subcritical PC case without CO2 capture but is repeated here for completeness. The description follows the BFD in Exhibit 4-31 and stream numbers reference the same Exhibit. The tables in Exhibit 4-32 provide process data for the numbered streams in the BFD.

Coal (stream 8) and PA (stream 4) are introduced into the boiler through the wall-fired burners.

Additional combustion air, including the OFA, is provided by the FD fans (stream 1). The boiler operates at a slight negative pressure so air leakage is into the boiler, and the infiltration air is accounted for in stream 5. Streams 3 and 6 show Ljungstrom air preheater leakages from the FD and PA fan outlet streams to the boiler exhaust.

FG exits the boiler through the SCR reactor (stream 10) and is cooled to 169°C (337°F) in the combustion air preheater before passing through a fabric filter for particulate removal (stream 12). An ID fan increases the FG temperature to 181°C (357°F) and provides the motive force for the FG (stream 13) to pass through the FGD unit. FGD inputs and outputs include makeup water (stream 15), oxidation air (stream 16), limestone slurry (stream 14), and product gypsum (stream 17). The clean, saturated FG exiting the FGD unit (stream 18) passes to the plant stack and is discharged to the atmosphere.

380

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-31 Case 11 Block Flow Diagram, Supercritical Unit without CO2 Capture 381

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-32 Case 11 Stream Table, Supercritical Unit without CO2 Capture 1 2 3 4 5 6 7 8 9 10 11 12 V-L Mole Fraction Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 V-L Flowrate (kgmol/hr) 48,414 48,414 1,434 14,872 14,872 2,047 1,119 0 0 68,126 0 68,126 V-L Flowrate (kg/hr) 1,397,067 1,397,067 41,378 429,164 429,164 59,064 32,284 0 0 2,026,262 0 2,026,262 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 185,759 3,603 14,410 14,410 0 Temperature (°C) 15 19 19 15 25 25 15 15 15 169 15 169 Pressure (MPa, abs) 0.10 0.11 0.11 0.10 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10 Enthalpy (kJ/kg)A 30.23 34.36 34.36 30.23 40.78 40.78 30.23 --- --- 327.37 --- 308.94 Density (kg/m3) 1.2 1.2 1.2 1.2 1.3 1.3 1.2 --- --- 0.8 --- 0.8 V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 28.857 28.857 --- --- 29.743 --- 29.743 V-L Flowrate (lbmol/hr) 106,734 106,734 3,161 32,787 32,787 4,512 2,466 0 0 150,191 0 150,191 V-L Flowrate (lb/hr) 3,080,006 3,080,006 91,224 946,145 946,145 130,215 71,175 0 0 4,467,142 0 4,467,142 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 409,528 7,942 31,769 31,769 0 Temperature (°F) 59 66 66 59 78 78 59 59 59 337 59 337 Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16.1 14.7 14.7 14.7 14.4 14.7 14.2 Enthalpy (Btu/lb)A 13.0 14.8 14.8 13.0 17.5 17.5 13.0 --- --- 140.7 --- 132.8 Density (lb/ft 3) 0.076 0.078 0.078 0.076 0.081 0.081 0.076 --- --- 0.050 --- 0.049 A - Reference conditions are 32.02 F & 0.089 PSIA 382

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-32 Case 11 Stream Table, Supercritical Unit without CO2 Capture (Continued) 13 14 15 16 17 18 19 20 21 22 23 V-L Mole Fraction Ar 0.0087 0.0000 0.0000 0.0128 0.0000 0.0082 0.0000 0.0000 0.0000 0.0000 0.0000 CO2 0.1450 0.0000 0.0000 0.0005 0.0004 0.1353 0.0000 0.0000 0.0000 0.0000 0.0000 H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2O 0.0870 1.0000 1.0000 0.0062 0.9995 0.1517 1.0000 1.0000 1.0000 1.0000 1.0000 N2 0.7324 0.0000 0.0000 0.7506 0.0000 0.6808 0.0000 0.0000 0.0000 0.0000 0.0000 O2 0.0247 0.0000 0.0000 0.2300 0.0000 0.0240 0.0000 0.0000 0.0000 0.0000 0.0000 SO2 0.0021 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 V-L Flowrate (kgmol/hr) 68,126 2,369 9,597 726 176 74,091 92,389 76,591 76,591 69,891 69,891 V-L Flowrate (kg/hr) 2,026,262 42,682 172,898 21,076 3,168 2,137,881 1,664,421 1,379,803 1,379,803 1,259,099 1,259,099 Solids Flowrate (kg/hr) 0 18,437 0 0 28,694 0 0 0 0 0 0 Temperature (°C) 181 15 15 167 57 57 593 354 593 38 39 Pressure (MPa, abs) 0.11 0.10 0.10 0.31 0.10 0.10 24.23 4.90 4.52 0.01 1.69 Enthalpy (kJ/kg)A 321.02 --- -46.80 177.65 --- 297.66 3,476.62 3,082.88 3,652.22 1,985.85 165.59 Density (kg/m3) 0.8 --- 1,003.1 2.5 --- 1.1 69.2 18.7 11.6 0.1 993.3 V-L Molecular Weight 29.743 --- 18.015 29.029 --- 28.855 18.015 18.015 18.015 18.015 18.015 V-L Flowrate (lbmol/hr) 150,191 5,223 21,158 1,601 387 163,343 203,684 168,854 168,854 154,082 154,082 V-L Flowrate (lb/hr) 4,467,142 94,099 381,174 46,465 6,985 4,713,221 3,669,421 3,041,946 3,041,946 2,775,839 2,775,839 Solids Flowrate (lb/hr) 0 40,646 0 0 63,259 0 0 0 0 0 0 Temperature (°F) 357 59 59 333 135 135 1,100 669 1,100 101 103 Pressure (psia) 15.3 15.0 14.7 45.0 14.8 14.8 3,514.7 710.8 655.8 1.0 245.0 Enthalpy (Btu/lb)A 138.0 --- -20.1 76.4 --- 128.0 1,494.7 1,325.4 1,570.2 853.8 71.2 Density (lb/ft 3) 0.052 --- 62.622 0.154 --- 0.067 4.319 1.165 0.722 0.004 62.009 383

Cost and Performance Baseline for Fossil Energy Plants 4.3.2 Key System Assumptions System assumptions for Cases 11 and 12, SC PC with and without CO2 capture, are compiled in Exhibit 4-33.

Exhibit 4-33 Supercritical PC Plant Study Configuration Matrix Case 11 Case 12 w/o CO2 Capture w/CO2 Capture 24.1/593/593 24.1/593/593 Steam Cycle, MPa/°C/°C (psig/°F/°F)

(3500/1100/1100) (3500/1100/1100)

Coal Illinois No. 6 Illinois No. 6 Condenser pressure, mm Hg (in Hg) 50.8 (2) 50.8 (2)

Boiler Efficiency, % 88 88 Cooling water to condenser, °C (ºF) 16 (60) 16 (60)

Cooling water from condenser, °C (ºF) 27 (80) 27 (80)

Stack temperature, °C (°F) 57 (135) 32 (89)

Wet Limestone Wet Limestone SO2 Control Forced Oxidation Forced Oxidation FGD Efficiency, % (A) 98 98 (B, C)

LNB w/OFA and LNB w/OFA and NOx Control SCR SCR SCR Efficiency, % (A) 86 86 Ammonia Slip (end of catalyst life),

2 2 ppmv Particulate Control Fabric Filter Fabric Filter Fabric Filter efficiency, % (A) 99.8 99.8 Ash Distribution, Fly/Bottom 80% / 20% 80% / 20%

Mercury Control Co-benefit Capture Co-benefit Capture Mercury removal efficiency, % (A) 90 90 CO2 Control N/A Econamine Overall CO2 Capture (A) N/A 90.2%

Off-site Saline CO2 Sequestration N/A Formation A. Removal efficiencies are based on the FG content B. An SO2 polishing step is included to meet more stringent SOx content limits in the FG (< 10 ppmv) to reduce formation of amine HSS during the CO2 absorption process C. SO2 exiting the post-FGD polishing step is absorbed in the CO2 capture process making stack emissions negligible Balance of Plant - Cases 11 and 12 The balance of plant assumptions are common to all cases and were presented previously in Exhibit 4-6.

384

Cost and Performance Baseline for Fossil Energy Plants 4.3.3 Sparing Philosophy Single trains are used throughout the design with exceptions where equipment capacity requires an additional train. There is no redundancy other than normal sparing of rotating equipment.

The plant design consists of the following major subsystems:

One dry-bottom, wall-fired PC SC boiler (1 x 100%)

Two SCR reactors (2 x 50%)

Two single-stage, in-line, multi-compartment fabric filters (2 x 50%)

One wet limestone forced oxidation positive pressure absorber (1 x 100%)

One steam turbine (1 x 100%)

For Case 12 only, two parallel Econamine CO2 absorption systems, with each system consisting of two absorbers, strippers, and ancillary equipment (2 x 50%)

4.3.4 Case 11 Performance Results The plant produces a net output of 550 MWe at a net plant efficiency of 39.3 percent (HHV basis).

Overall performance for the plant is summarized in Exhibit 4-34, which includes auxiliary power requirements.

385

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-34 Case 11 Plant Performance Summary POWER

SUMMARY

(Gross Power at Generator Terminals, kWe)

Steam Turbine Power 580,400 TOTAL (STEAM TURBINE) POWER, kWe 580,400 AUXILIARY LOAD

SUMMARY

, kWe Coal Handling and Conveying 440 Pulverizers 2,780 Sorbent Handling & Reagent Preparation 890 Ash Handling 530 Primary Air Fans 1,300 Forced Draft Fans 1,660 Induced Draft Fans 7,050 SCR 50 Baghouse 70 Wet FGD 2,970 2,3 Miscellaneous Balance of Plant 2,000 Steam Turbine Auxiliaries 400 Condensate Pumps 800 Circulating Water Pumps 4,730 Ground Water Pumps 480 Cooling Tower Fans 2,440 Transformer Losses 1,820 TOTAL AUXILIARIES, kWe 30,410 NET POWER, kWe 549,990 Net Plant Efficiency (HHV) 39.3%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,165 (8,687) 6 6 CONDENSER COOLING DUTY, 10 kJ/hr (10 Btu/hr) 2,298 (2,178)

CONSUMABLES As-Received Coal Feed, kg/hr (lb/hr) 185,759 (409,528)

Limestone Sorbent Feed, kg/hr (lb/hr) 18,437 (40,646) 1 Thermal Input, kWt 1,400,162 3

Raw Water Withdrawal, m /min (gpm) 20.1 (5,321) 3 Raw Water Consumption, m /min (gpm) 16.0 (4,227)

1. HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)

2. Boiler feed pumps are turbine driven

3. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads 386

Cost and Performance Baseline for Fossil Energy Plants Environmental Performance The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 2.4. A summary of the plant air emissions for Case 11 is presented in Exhibit 4-35.

Exhibit 4-35 Case 11 Air Emissions Tonne/year kg/GJ kg/MWh (ton/year)

(lb/106 Btu) (lb/MWh) 85% CF SO2 0.037 (0.086) 1,385 (1,526) 0.320 (.71)

NOx 0.030 (0.070) 1,130 (1,245) 0.261 (.576)

Particulates 0.006 (0.0130) 210 (231) 0.049 (.107)

Hg 4.91E-7 (1.14E-6) 0.018 (0.020) 4.27E-6 (9.41E-6) 3,284,245 CO2 87.5 (203.5) 760 (1,675)

(3,620,261)

CO21 802 (1,768) 1 CO2 emissions based on net power instead of gross power SO2 emissions are controlled using a wet limestone forced oxidation scrubber that achieves a removal efficiency of 98 percent. The byproduct calcium sulfate is dewatered and stored on site.

The wallboard grade material can potentially be marketed and sold, but since it is highly dependent on local market conditions, no byproduct credit was taken. The saturated FG exiting the scrubber is vented through the plant stack.

NOx emissions are controlled to about 0.5 lb/106 Btu through the use of LNBs and OFA. An SCR unit then further reduces the NOx concentration by 86 percent to 0.07 lb/106 Btu.

Particulate emissions are controlled using a pulse jet fabric filter, which operates at an efficiency of 99.8 percent.

Co-benefit capture results in a 90 percent reduction of mercury emissions.

CO2 emissions represent the uncontrolled discharge from the process.

The carbon balance for the plant is shown in Exhibit 4-36. The carbon input to the plant consists of carbon in the coal, carbon in the air, and carbon in the limestone reagent used in the FGD.

Carbon in the air is not neglected here since the Aspen model accounts for air components throughout. Carbon leaves the plant mostly as CO2 through the stack but also leaves as gypsum.

Exhibit 4-36 Case 11 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 118,411 (261,052) Stack Gas 120,377 (265,385)

Air (CO2) 257 (567) FGD Product 163 (358)

FGD Reagent 1,871 (4,124)

Total 120,539 (265,744) Total 120,539 (265,744) 387

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-37 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes sulfur emitted in the stack gas and the sulfur recovered from the FGD as gypsum.

Exhibit 4-37 Case 11 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 4,656 (10,264) Stack Gas 93 (205)

FGD Product 4,563 (10,059)

Total 4,656 (10,264) Total 4,656 (10,264)

Exhibit 4-38 shows the overall water balance for the plant. Water demand represents the total amount of water required for a particular process. Some water is recovered within the process and is re-used as internal recycle. The difference between demand and recycle is raw water withdrawal. Raw water withdrawal is defined as the water removed from the ground or diverted from a surface-water source for use in the plant and was assumed to be provided 50 percent by a POTW and 50 percent from groundwater. Raw water withdrawal can be represented by the water metered from a raw water source and used in the plant processes for any and all purposes, such as FDG makeup, BFW makeup, and cooling tower makeup. The difference between water withdrawal and process water discharge is defined as water consumption and can be represented by the portion of the raw water withdrawn that is evaporated, transpired, incorporated into products or otherwise not returned to the water source from which it was withdrawn. Water consumption represents the net impact of the plant process on the water source balance.

Exhibit 4-38 Case 11 Water Balance Process Water Internal Raw Water Water Raw Water Demand, Recycle, Withdrawal, Water Use Discharge, Consumption, m3/min m3/min m3/min m3/min m3/min (gpm)

(gpm) (gpm) (gpm)

(gpm)

FGD Makeup 3.6 (951) 0.0 (0) 3.6 (951) 0.0 (0) 3.6 (951)

BFW Makeup 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

Cooling Tower 18.4 (4,863) 1.9 (492) 16.5 (4,370) 4.1 (1,094) 12.4 (3,277)

Total 22.0 (5,813) 1.9 (492) 20.1 (5,321) 4.1 (1,094) 16.0 (4,227) 388

Cost and Performance Baseline for Fossil Energy Plants Heat and Mass Balance Diagrams A heat and mass balance diagram is shown for the Case 11 PC boiler, the FGD unit and steam cycle in Exhibit 4-39 and Exhibit 4-40. An overall plant energy balance is provided in tabular form in Exhibit 4-41. The power out is the steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 4-34) is calculated by multiplying the power out by a generator efficiency of 98.4 percent.

389

Cost and Performance Baseline for Fossil Energy Plants This page intentionally left blank 390

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-39 Case 11 Heat and Mass Balance, Supercritical PC Boiler without CO2 Capture MAKE-UP OXIDATION LEGEND WATER AIR 381,174 W 46,465 W Air 59.0 T 15 16 332.9 T 14.7 P 45.0 P Coal/Ash Slurry Nitrogen 13 Oxygen Baghouse 12 FGD 4,467,142 W ID FANS 357.4 T Sour Gas 337.0 T 15.3 P 14.2 P 138.0 H ASH 132.8 H Sour Water 11 31,769 W 134,744 W 70,244 W 14 17 59.0 T 135.0 T Steam 4,498,911 W 15.0 P 14.8 P 337.0 T 10 14.4 P 140.7 H Synthesis Gas LIMESTONE GYPSUM SLURRY 4,713,221 W Water Throttle Steam 19 135.0 T 18 To HP Turbine 14.8 P 3,669,421 W 128.0 H 1,100.0 T Lime/Ash 3,514.7 P 1,494.7 H Flue Gas 21 Single Reheat To IP Turbine P ABSOLUTE PRESSURE, PSIA 3,041,946 W F TEMPERATURE, °F 1,100.0 T W FLOWRATE, LBM/HR 655.8 P H ENTHALPY, BTU/LBM 1,570.2 H MWE POWER, MEGAWATTS ELECTRICAL AMMONIA SCR NOTES:

INFILTRATION 7 AIR 71,175 W 59.0 T 66.4 T 1. ENTHALPY REFERENCE POINT IS NATURAL STATE 14.7 P 15.3 P AT 32 °F AND 0.08865 PSIA 13.0 H 14.8 H Pulverized 20 3,041,946 W AIR 1 2

Coal 669.2 T 710.8 P 3,080,006 W 59.0 T FORCED 3 Boiler 1,325.4 H 14.7 P DRAFT FANS PLANT PERFORMANCE

SUMMARY

13.0 H Single Reheat Gross Plant Power: 580 MWe Extraction from Auxiliary Load: 30 MWe HP Turbine STACK Net Plant Power: 550 MWe 6 Net Plant Efficiency, HHV: 39.3%

Net Plant Heat Rate: 8,687 BTU/KWe 5

AIR 4 946,145 W 77.8 T 59.0 T PRIMARY 16.1 P 14.7 P AIR FANS 17.5 H DOE/NETL 13.0 H 9 From Feedwater SC PC PLANT 8 Heaters CASE 11 409,528 W 3,669,421 W COAL 556.6 T 4,185.0 P HEAT AND MATERIAL FLOW DIAGRAM ASH 552.5 H 7,942 W BITUMINOUS BASELINE STUDY CASE 11 SUPERCRITICAL PULVERIZED COAL BOILER AND GAS CLEANUP SYSTEMS DWG. NO. PAGES BB-HMB-CS-11-PG-1 1 OF 2 391

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-40 Case 11 Heat and Mass Balance, Supercritical Steam Cycle LEGEND Air Single Reheat Coal/Char/

Extraction Slurry/Slag From Boiler 21 Nitrogen 3,041,946 W 1,100.0 T 655.8 P 1,570.2 H Oxygen 19 223,857 W 3,669,421 W 2,762,263 W 687.5 T 2,538,406 W 687.5 T Sour Gas 1,100.0 T 687.5 T 134.9 P 3,514.7 P 134.9 P 134.9 P 1,370.8 H 1,494.7 H 1,370.8 H Sour Water Throttle Steam BOILER FEED HP IP LP TURBINE GENERATOR PUMP TURBINE Steam TURBINE TURBINE DRIVES Synthesis Gas 223,857 W 710.8 P 710.8 P 2,900.0 P 310.1 P 137.7 P 3.5 P 137.7 P 2,900.0 P 2,900.0 P 710.8 P 72.7 P 19.2 P 8.4 P 1,115.5 P 126.1 T 2.0 P Single Reheat 1,093.5 H Water 2,775,839 W Extraction to 20 101.1 T 22 Boiler 3,041,946 W 1.0 P 669.2 T 853.8 H 710.8 P 1,325.4 H CONDENSER STEAM SEAL REGULATOR 3,301 W 713.5 T P ABSOLUTE PRESSURE, PSIA 137.7 P HOT WELL F TEMPERATURE, °F 1,383.8 H W FLOWRATE, LBM/HR To Boiler 7,482 W 2,793 W H ENTHALPY, BTU/LBM 713.5 T 713.5 T 3,669,421 W 2,775,839 W MWE POWER, MEGAWATTS ELECTRICAL 137.7 P 137.7 P 556.6 T 101.1 T 1,383.8 H 1,383.8 H 4,185.0 P 1.0 P 552.5 H 69.1 H NOTES:

CONDENSATE 1. ENTHALPY REFERENCE POINT IS NATURAL STATE PUMPS AT 32 °F AND 0.08865 PSIA 101.4 T 92,383 W 250.0 P 146.4 T 70.0 H 200,638 W 3.4 P 269,128 W 327,489 W 169,635 W 98,904 W 88,519 W 545.6 T 1,077.8 H 772.0 T 663.9 T 888.4 T 127,330 W 293.8 T 211.3 T 1,085.0 P 689.5 P 300.8 P 696.6 T 69.0 P 18.2 P 8.1 P 1,304.2 H 1,367.5 H 3,669,421 W 1,323.6 H 3,669,421 W 1,467.0 H 133.6 P 1,375.5 H 1,188.3 H 1,152.2 H GLAND SEAL PLANT PERFORMANCE

SUMMARY

501.5 T 2,775,839 W 2,775,839 W 2,775,839 W 2,775,839 W 419.6 T CONDENSER 4,190.0 P 296.9 T 218.0 T 178.4 T 141.4 T 4,195.0 P P-1048 FWH 8 FWH 7 FWH 6 225.0 P 230.0 P 235.0 P 240.0 P P-1028 2,793 W 488.9 H 400.2 H FWH 4 FWH 3 FWH 2 FWH 1 Gross Plant Power: 580 MWe 266.5 H 186.4 H 146.7 H 109.8 H 212.0 T 23 14.7 P Auxiliary Load: 30 MWe 2,775,839 W 179.9 H Net Plant Power: 550 MWe 102.6 T Net Plant Efficiency, HHV: 39.3%

DEAERATOR 245.0 P 71.2 H Net Plant Heat Rate: 8,687 BTU/KWe 269,128 W 596,617 W 766,252 W 200,638 W 299,542 W 388,060 W 511.5 T 429.6 T 369.5 T 228.0 T 188.4 T 151.4 T 480,444 W 753.7 P 342.2 P 172.2 P 20.0 P 9.0 P 3.9 P 112.6 T 501.2 H 407.0 H 341.9 H 196.0 H 156.2 H 119.2 H 1.4 P 80.5 H DOE/NETL 3,669,421 W 359.5 T 349.4 T 133.6 P SC PC PLANT 4,200.0 P 320.7 H CASE 11 337.6 H BOILER FEED PUMPS HEAT AND MATERIAL FLOW DIAGRAM BITUMINOUS BASELINE STUDY CASE 11 SUPERCRITICAL PULVERIZED COAL POWER BLOCK SYSTEMS DWG. NO. PAGES BB-HMB-CS-11-PG-2 2 OF 2 392

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-41 Case 11 Overall Energy Balance (0°C [32°F] Reference)

Sensible +

HHV Power Total Latent Heat In GJ/hr (MMBtu/hr)

Coal 5,041 (4,778) 4.2 (4.0) 5,045 (4,782)

Air 56.2 (53.2) 56.2 (53.2)

Raw Water Makeup 76.8 (72.8) 76.8 (72.8)

Limestone 0.21 (0.20) 0.21 (0.20)

Auxiliary Power 110 (104) 110 (104)

Totals 5,041 (4,778) 137.4 (130.3) 110 (104) 5,288 (5,012)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.4 (0.4) 0.4 (0.4)

Fly Ash + FGD Ash 1.7 (1.7) 1.7 (1.7)

Flue Gas 636 (603) 636 (603)

Condenser 2,298 (2,178) 2,298 (2,178)

Cooling Tower 30.8 (29.2) 30.8 (29.2)

Blowdown Process Losses* 231 (219) 231 (219)

Power 2,089 (1,980) 2,089 (1,980)

Totals 0 (0) 3,198 (3,031) 2,089 (1,980) 5,288 (5,012)

Process losses are estimated to match the heat input to the plant. Process losses include losses from: turbines, gas cooling, etc.

393

Cost and Performance Baseline for Fossil Energy Plants 4.3.5 Case 11 - Major Equipment List Major equipment items for the SC PC plant with no CO2 capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section 4.3.6. In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 FUEL AND SORBENT HANDLING Equipment Operating Description Type Design Condition Spares No. Qty.

Bottom Trestle Dumper and 1 N/A 181 tonne (200 ton) 2 0 Receiving Hoppers 2 Feeder Belt 572 tonne/hr (630 tph) 2 0 3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0 4 Transfer Tower No. 1 Enclosed N/A 1 0 5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0 As-Received Coal Sampling 6 Two-stage N/A 1 0 System 7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0 8 Reclaim Hopper N/A 36 tonne (40 ton) 2 1 9 Feeder Vibratory 154 tonne/hr (170 tph) 2 1 10 Conveyor No. 3 Belt w/ tripper 308 tonne/hr (340 tph) 1 0 11 Crusher Tower N/A N/A 1 0 12 Coal Surge Bin w/ Vent Filter Dual outlet 154 tonne (170 ton) 2 0 Impactor 8 cm x 0 - 3 cm x 0 13 Crusher 2 0 reduction (3 in x 0 1/4 in x 0)

As-Fired Coal Sampling 14 Swing hammer N/A 1 1 System 15 Conveyor No. 4 Belt w/tripper 308 tonne/hr (340 tph) 1 0 16 Transfer Tower No. 2 Enclosed N/A 1 0 17 Conveyor No. 5 Belt w/ tripper 308 tonne/hr (340 tph) 1 0 Coal Silo w/ Vent Filter and 18 Field erected 726 tonne (800 ton) 3 0 Slide Gates Limestone Truck Unloading 19 N/A 36 tonne (40 ton) 1 0 Hopper 20 Limestone Feeder Belt 82 tonne/hr (90 tph) 1 0 21 Limestone Conveyor No. L1 Belt 82 tonne/hr (90 tph) 1 0 22 Limestone Reclaim Hopper N/A 18 tonne (20 ton) 1 0 23 Limestone Reclaim Feeder Belt 64 tonne/hr (70 tph) 1 0 24 Limestone Conveyor No. L2 Belt 64 tonne/hr (70 tph) 1 0 25 Limestone Day Bin w/ actuator 245 tonne (270 ton) 2 0 394

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED Equipment Operating Description Type Design Condition Spares No. Qty.

1 Coal Feeder Gravimetric 36 tonne/hr (40 tph) 6 0 Ball type or 2 Coal Pulverizer 36 tonne/hr (40 tph) 6 0 equivalent 3 Limestone Weigh Feeder Gravimetric 20 tonne/hr (22 tph) 1 1 4 Limestone Ball Mill Rotary 20 tonne/hr (22 tph) 1 1 Limestone Mill Slurry Tank 5 N/A 75,708 liters (20,000 gal) 1 1 with Agitator Limestone Mill Recycle Horizontal 1,287 lpm @ 12m H2O (340 gpm 6 1 1 Pumps centrifugal @ 40 ft H2O) 4 active 7 Hydroclone Classifier cyclones in a 5 341 lpm (90 gpm) per cyclone 1 1 cyclone bank 8 Distribution Box 2-way N/A 1 1 Limestone Slurry Storage 9 Field erected 439,108 liters (116,000 gal) 1 1 Tank with Agitator Limestone Slurry Feed Horizontal 908 lpm @ 9m H2O (240 gpm @

10 1 1 Pumps centrifugal 30 ft H2O) 395

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment Operating Description Type Design Condition Spares No. Qty.

Demineralized Water Vertical, cylindrical, 1 1,101,555 liters (291,000 gal) 2 0 Storage Tank outdoor 23,091 lpm @ 213 m H2O (6,100 2 Condensate Pumps Vertical canned 1 1 gpm @ 700 ft H2O)

Deaerator and Storage 1,830,699 kg/hr (4,036,000 lb/hr),

3 Horizontal spray type 1 0 Tank 5 min. tank Boiler Feed Barrel type, multi-stage, 30,662 lpm @ 3,444 m H2O 4 1 1 Pump/Turbine centrifugal (8,100 gpm @ 11,300 ft H2O)

Startup Boiler Feed Barrel type, multi-stage, 9,085 lpm @ 3,444 m H2O (2,400 5 Pump, Electric Motor 1 0 centrifugal gpm @ 11,300 ft H2O)

Driven LP Feedwater Heater 6 Horizontal U-tube 693,996 kg/hr (1,530,000 lb/hr) 2 0 1A/1B LP Feedwater Heater 7 Horizontal U-tube 693,996 kg/hr (1,530,000 lb/hr) 2 0 2A/2B LP Feedwater Heater 8 Horizontal U-tube 693,996 kg/hr (1,530,000 lb/hr) 2 0 3A/3B LP Feedwater Heater 9 Horizontal U-tube 693,996 kg/hr (1,530,000 lb/hr) 2 0 4A/4B 10 HP Feedwater Heater 6 Horizontal U-tube 1,832,513 kg/hr (4,040,000 lb/hr) 1 0 11 HP Feedwater Heater 7 Horizontal U-tube 1,832,513 kg/hr (4,040,000 lb/hr) 1 0 12 HP Feedwater heater 8 Horizontal U-tube 1,832,513 kg/hr (4,040,000 lb/hr) 1 0 Shop fabricated, water 18,144 kg/hr, 2.8 MPa, 343°C 13 Auxiliary Boiler 1 0 tube (40,000 lb/hr, 400 psig, 650°F)

No. 2 fuel oil for light 14 Fuel Oil System 1,135,624 liter (300,000 gal) 1 0 off Service Air 28 m3/min @ 0.7 MPa (1,000 15 Flooded Screw 2 1 Compressors scfm @ 100 psig) 16 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1 Closed Cycle Cooling 17 Shell and tube 53 GJ/hr (50 MMBtu/hr) each 2 0 Heat Exchangers Closed Cycle Cooling 20,820 lpm @ 30 m H2O (5,500 18 Horizontal centrifugal 2 1 Water Pumps gpm @ 100 ft H2O)

Engine-Driven Fire Vertical turbine, diesel 3,785 lpm @ 88 m H2O (1,000 19 1 1 Pump engine gpm @ 290 ft H2O)

Fire Service Booster Two-stage horizontal 2,650 lpm @ 64 m H2O (700 gpm 20 1 1 Pump centrifugal @ 210 ft H2O)

Stainless steel, single 5,943 lpm @ 18 m H2O (1,570 21 Raw Water Pumps 2 1 suction gpm @ 60 ft H2O)

Stainless steel, single 2,385 lpm @ 268 m H2O (630 22 Ground Water Pumps 5 1 suction gpm @ 880 ft H2O)

Stainless steel, single 1,893 lpm @ 49 m H2O (500 gpm 23 Filtered Water Pumps 2 1 suction @ 160 ft H2O) 24 Filtered Water Tank Vertical, cylindrical 1,816,998 liter (480,000 gal) 1 0 Multi-media filter, Makeup Water cartridge filter, RO 25 606 lpm (160 gpm) 1 1 Demineralizer membrane assembly, electrodeionization unit Liquid Waste Treatment 26 -- 10 years, 24-hour storm 1 0 System 396

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 4 BOILER AND ACCESSORIES Equipment Operating Description Type Design Condition Spares No. Qty.

1,832,513 kg/hr steam @ 25.5 Supercritical, drum, MPa/602°C/602°C (4,040,000 1 Boiler wall-fired, low NOx 1 0 lb/hr steam @ 3,700 burners, overfire air psig/1,115°F/1,115°F) 235,868 kg/hr, 3,220 m3/min @

2 Primary Air Fan Centrifugal 123 cm WG (520,000 lb/hr, 2 0 113,700 acfm @ 48 in. WG) 768,385 kg/hr, 10,486 m3/min @

3 Forced Draft Fan Centrifugal 47 cm WG (1,694,000 lb/hr, 2 0 370,300 acfm @ 19 in. WG) 1,114,476 kg/hr, 23,469 m3/min 4 Induced Draft Fan Centrifugal @ 91 cm WG (2,457,000 lb/hr, 2 0 828,800 acfm @ 36 in. WG)

Space for spare 5 SCR Reactor Vessel 2,227,139 kg/hr (4,910,000 lb/hr) 2 0 layer 6 SCR Catalyst -- -- 3 0 133 m3/min @ 108 cm WG 7 Dilution Air Blower Centrifugal 2 1 (4,700 acfm @ 42 in. WG) 8 Ammonia Storage Horizontal tank 147,631 liter (39,000 gal) 5 0 Ammonia Feed 28 lpm @ 91 m H2O (7 gpm @

9 Centrifugal 2 1 Pump 300 ft H2O) 397

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 5 FLUE GAS CLEANUP Equipment Operating Description Type Design Condition Spares No. Qty.

Single stage, high-ratio with pulse-jet 1,114,476 kg/hr (2,457,000 lb/hr) 1 Fabric Filter 2 0 online cleaning 99.8% efficiency system Counter-current 2 Absorber Module 44,769 m3/min (1,581,000 acfm) 1 0 open spray Horizontal 155,202 lpm @ 64 m H2O 3 Recirculation Pumps 5 1 centrifugal (41,000 gpm @ 210 ft H2O)

Horizontal 3,975 lpm (1,050 gpm) at 20 wt%

4 Bleed Pumps 2 1 centrifugal solids 78 m3/min @ 0.3 MPa (2,770 5 Oxidation Air Blowers Centrifugal 2 1 acfm @ 37 psia) 6 Agitators Side entering 50 hp 5 1 Radial assembly, 7 Dewatering Cyclones 984 lpm (260 gpm) per cyclone 2 0 5 units each 32 tonne/hr (35 tph) of 50 wt %

8 Vacuum Filter Belt Horizontal belt 2 1 slurry Filtrate Water Return Horizontal 606 lpm @ 12 m H2O (160 gpm 9 1 1 Pumps centrifugal @ 40 ft H2O)

Filtrate Water Return 10 Vertical, lined 378,541 lpm (100,000 gal) 1 0 Storage Tank Process Makeup Water Horizontal 3,180 lpm @ 21 m H2O (840 gpm 11 1 1 Pumps centrifugal @ 70 ft H2O)

ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES N/A 398

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 7 HRSG, DUCTING & STACK Equipment Operating Description Type Design Condition Spares No. Qty.

Reinforced concrete 152 m (500 ft) high x 1 Stack 1 0 with FRP liner 5.6 m (19 ft) diameter ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES Equipment Operating Description Type Design Condition Spares No. Qty.

611 MW Commercially 24.1 MPa/593°C/593°C 1 Steam Turbine available advanced 1 0 (3500 psig/

steam turbine 1100°F/1100°F)

Hydrogen cooled, 680 MVA @ 0.9 p.f., 24 2 Steam Turbine Generator 1 0 static excitation kV, 60 Hz, 3-phase 2,532 GJ/hr (2,400 Single pass, divided MMBtu/hr), Inlet water 3 Surface Condenser waterbox including temperature 16°C (60°F), 1 0 vacuum pumps Water temperature rise 11°C (20°F)

ACCOUNT 9 COOLING WATER SYSTEM Equipment Operating Description Type Design Condition Spares No. Qty.

Circulating Water 473,200 lpm @ 30 m 1 Vertical, wet pit 2 1 Pumps (125,000 gpm @ 100 ft) 11°C (51.5°F) wet bulb / 16°C Evaporative, (60°F) CWT / 27°C (80°F) HWT 2 Cooling Tower mechanical draft, multi- 1 0

/ 2648 GJ/hr (2510 MMBtu/hr) cell heat duty 399

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING Equipment Operating Description Type Design Condition Spares No. Qty.

Economizer Hopper (part of 1 -- -- 4 0 boiler scope of supply)

Bottom Ash Hopper (part of 2 -- -- 2 0 boiler scope of supply) 3 Clinker Grinder -- 3.6 tonne/hr (4 tph) 1 1 Pyrites Hopper (part of 4 pulverizer scope of supply -- -- 6 0 included with boiler) 5 Hydroejectors -- -- 12 Economizer /Pyrites Transfer 6 -- -- 1 0 Tank 151 lpm @ 17 m H2O (40 gpm 7 Ash Sluice Pumps Vertical, wet pit 1 1

@ 56 ft H2O) 7,571 lpm @ 9 m H2O (2000 8 Ash Seal Water Pumps Vertical, wet pit 1 1 gpm @ 28 ft H2O) 9 Hydrobins -- 151 lpm (40 gpm) 1 1 Baghouse Hopper (part of 10 -- -- 24 0 baghouse scope of supply)

Air Heater Hopper (part of 11 -- -- 10 0 boiler scope of supply) 14 m3/min @ 0.2 MPa (510 12 Air Blower -- 1 1 scfm @ 24 psi)

Reinforced 13 Fly Ash Silo 907 tonne (1,000 ton) 2 0 concrete 14 Slide Gate Valves -- -- 2 0 15 Unloader -- -- 1 0 16 Telescoping Unloading Chute -- 91 tonne/hr (100 tph) 1 0 400

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 11 ACCESSORY ELECTRIC PLANT Equipment Operating Description Type Design Condition Spares No. Qty.

24 kV/345 kV, 650 MVA, 3-1 STG Transformer Oil-filled 1 0 ph, 60 Hz Auxiliary 24 kV/4.16 kV, 32 MVA, 3-2 Oil-filled 1 1 Transformer ph, 60 Hz Low Voltage 4.16 kV/480 V, 5 MVA, 3-ph, 3 Dry ventilated 1 1 Transformer 60 Hz STG Isolated 4 Phase Bus Duct Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0 and Tap Bus Medium Voltage 5 Metal clad 4.16 kV, 3-ph, 60 Hz 1 1 Switchgear Low Voltage 6 Metal enclosed 480 V, 3-ph, 60 Hz 1 1 Switchgear Emergency Diesel Sized for emergency 7 750 kW, 480 V, 3-ph, 60 Hz 1 0 Generator shutdown ACCOUNT 12 INSTRUMENTATION AND CONTROL Equipment Operating Description Type Design Condition Spares No. Qty.

Monitor/keyboard; DCS - Main Operator printer (laser Operator stations/printers and 1 1 0 Control color); Engineering engineering stations/printers printer (laser B&W)

Microprocessor with 2 DCS - Processor N/A 1 0 redundant input/output DCS - Data 3 Fiber optic Fully redundant, 25% spare 1 0 Highway 401

Cost and Performance Baseline for Fossil Energy Plants 4.3.6 Case 11 - Costs Estimating Results The cost estimating methodology was described previously in Section 2.7. Exhibit 4-42 shows the total plant capital cost summary organized by cost account and Exhibit 4-43 shows a more detailed breakdown of the capital costs as well as owners costs, TOC, and TASC. Exhibit 4-44 shows the initial and annual O&M costs.

The estimated TOC of the SC PC boiler with no CO2 capture is $2,024/kW. No process contingency was included in this case because all elements of the technology are commercially proven. The project contingency is 8.7 percent of the TOC. The COE is 58.9 mills/kWh.

402

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-42 Case 11 Total Plant Cost Summary Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study TOTAL PLANT COST

SUMMARY

Case: Case 11 - 1x550 MWnet SuperCritical PC Plant Size: 550.0 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING $16,381 $4,414 $9,819 $0 $0 $30,614 $2,747 $0 $5,004 $38,365 $70 2 COAL & SORBENT PREP & FEED $11,008 $637 $2,793 $0 $0 $14,438 $1,265 $0 $2,356 $18,059 $33 3 FEEDWATER & MISC. BOP SYSTEMS $42,453 $0 $19,927 $0 $0 $62,380 $5,705 $0 $11,064 $79,149 $144 4 PC BOILER 4.1 PC Boiler & Accessories $157,253 $0 $88,235 $0 $0 $245,488 $23,891 $0 $26,938 $296,317 $539 4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4-4.9 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4 $157,253 $0 $88,235 $0 $0 $245,488 $23,891 $0 $26,938 $296,317 $539 5 FLUE GAS CLEANUP $79,643 $0 $27,049 $0 $0 $106,692 $10,211 $0 $11,690 $128,593 $234 5B CO2 REMOVAL & COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 6.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 6 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 7.2-7.9 HRSG Accessories, Ductwork and Stack $17,397 $1,000 $11,814 $0 $0 $30,211 $2,773 $0 $4,307 $37,291 $68 SUBTOTAL 7 $17,397 $1,000 $11,814 $0 $0 $30,211 $2,773 $0 $4,307 $37,291 $68 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $51,625 $0 $6,866 $0 $0 $58,491 $5,606 $0 $6,410 $70,507 $128 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $22,954 $1,089 $12,590 $0 $0 $36,633 $3,228 $0 $5,580 $45,441 $83 SUBTOTAL 8 $74,579 $1,089 $19,456 $0 $0 $95,124 $8,833 $0 $11,990 $115,948 $211 9 COOLING WATER SYSTEM $12,303 $6,296 $11,466 $0 $0 $30,066 $2,830 $0 $4,475 $37,370 $68 10 ASH/SPENT SORBENT HANDLING SYS $4,409 $140 $5,895 $0 $0 $10,444 $1,004 $0 $1,178 $12,627 $23 11 ACCESSORY ELECTRIC PLANT $17,541 $6,187 $18,041 $0 $0 $41,769 $3,682 $0 $5,617 $51,068 $93 12 INSTRUMENTATION & CONTROL $8,739 $0 $8,862 $0 $0 $17,601 $1,596 $0 $2,358 $21,555 $39 13 IMPROVEMENTS TO SITE $2,969 $1,707 $5,984 $0 $0 $10,660 $1,052 $0 $2,342 $14,054 $26 14 BUILDINGS & STRUCTURES $0 $22,720 $21,552 $0 $0 $44,272 $3,994 $0 $7,240 $55,506 $101 TOTAL COST $444,675 $44,192 $250,892 $0 $0 $739,759 $69,584 $0 $96,558 $905,901 $1,647 403

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-43 Case 11 Total Plant Cost Details Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $3,368 $0 $1,538 $0 $0 $4,906 $438 $0 $802 $6,146 $11 1.2 Coal Stackout & Reclaim $4,352 $0 $986 $0 $0 $5,338 $467 $0 $871 $6,676 $12 1.3 Coal Conveyors $4,046 $0 $976 $0 $0 $5,022 $440 $0 $819 $6,282 $11 1.4 Other Coal Handling $1,059 $0 $226 $0 $0 $1,284 $112 $0 $209 $1,606 $3 1.5 Sorbent Receive & Unload $135 $0 $41 $0 $0 $175 $15 $0 $29 $219 $0 1.6 Sorbent Stackout & Reclaim $2,176 $0 $399 $0 $0 $2,574 $224 $0 $420 $3,218 $6 1.7 Sorbent Conveyors $776 $168 $190 $0 $0 $1,135 $98 $0 $185 $1,418 $3 1.8 Other Sorbent Handling $469 $110 $246 $0 $0 $825 $73 $0 $135 $1,032 $2 1.9 Coal & Sorbent Hnd.Foundations $0 $4,136 $5,218 $0 $0 $9,354 $879 $0 $1,535 $11,767 $21 SUBTOTAL 1. $16,381 $4,414 $9,819 $0 $0 $30,614 $2,747 $0 $5,004 $38,365 $70 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $1,929 $0 $376 $0 $0 $2,305 $201 $0 $376 $2,881 $5 2.2 Coal Conveyor to Storage $4,939 $0 $1,078 $0 $0 $6,017 $526 $0 $981 $7,524 $14 2.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.5 Sorbent Prep Equipment $3,695 $159 $768 $0 $0 $4,622 $402 $0 $754 $5,778 $11 2.6 Sorbent Storage & Feed $445 $0 $171 $0 $0 $616 $55 $0 $101 $771 $1 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $478 $401 $0 $0 $879 $81 $0 $144 $1,105 $2 SUBTOTAL 2. $11,008 $637 $2,793 $0 $0 $14,438 $1,265 $0 $2,356 $18,059 $33 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 FeedwaterSystem $18,623 $0 $6,016 $0 $0 $24,638 $2,153 $0 $4,019 $30,810 $56 3.2 Water Makeup & Pretreating $4,460 $0 $1,436 $0 $0 $5,895 $557 $0 $1,291 $7,743 $14 3.3 Other Feedwater Subsystems $5,701 $0 $2,409 $0 $0 $8,111 $727 $0 $1,326 $10,163 $18 3.4 Service Water Systems $874 $0 $476 $0 $0 $1,350 $127 $0 $295 $1,772 $3 3.5 Other Boiler Plant Systems $6,807 $0 $6,721 $0 $0 $13,528 $1,285 $0 $2,222 $17,035 $31 3.6 FO Supply Sys & Nat Gas $255 $0 $319 $0 $0 $574 $54 $0 $94 $723 $1 3.7 Waste Treatment Equipment $3,024 $0 $1,724 $0 $0 $4,747 $462 $0 $1,042 $6,251 $11 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,709 $0 $828 $0 $0 $3,536 $340 $0 $775 $4,652 $8 SUBTOTAL 3. $42,453 $0 $19,927 $0 $0 $62,380 $5,705 $0 $11,064 $79,149 $144 4 PC BOILER 4.1 PC Boiler & Accessories $157,253 $0 $88,235 $0 $0 $245,488 $23,891 $0 $26,938 $296,317 $539 4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4. $157,253 $0 $88,235 $0 $0 $245,488 $23,891 $0 $26,938 $296,317 $539 404

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-43 Case 11 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 5 FLUE GAS CLEANUP 5.1 Absorber Vessels & Accessories $55,471 $0 $11,942 $0 $0 $67,413 $6,427 $0 $7,384 $81,224 $148 5.2 Other FGD $2,895 $0 $3,280 $0 $0 $6,175 $599 $0 $677 $7,452 $14 5.3 Bag House & Accessories $15,622 $0 $9,914 $0 $0 $25,536 $2,461 $0 $2,800 $30,797 $56 5.4 Other Particulate Removal Materials $1,057 $0 $1,131 $0 $0 $2,189 $212 $0 $240 $2,641 $5 5.5 Gypsum Dewatering System $4,598 $0 $781 $0 $0 $5,379 $512 $0 $589 $6,480 $12 5.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5.9 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5. $79,643 $0 $27,049 $0 $0 $106,692 $10,211 $0 $11,690 $128,593 $234 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $8,675 $0 $5,574 $0 $0 $14,249 $1,242 $0 $2,324 $17,816 $32 7.4 Stack $8,721 $0 $5,103 $0 $0 $13,824 $1,331 $0 $1,516 $16,671 $30 7.9 Duct & Stack Foundations $0 $1,000 $1,137 $0 $0 $2,137 $200 $0 $467 $2,804 $5 SUBTOTAL 7. $17,397 $1,000 $11,814 $0 $0 $30,211 $2,773 $0 $4,307 $37,291 $68 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $51,625 $0 $6,866 $0 $0 $58,491 $5,606 $0 $6,410 $70,507 $128 8.2 Turbine Plant Auxiliaries $347 $0 $744 $0 $0 $1,091 $107 $0 $120 $1,317 $2 8.3 Condenser & Auxiliaries $6,712 $0 $2,288 $0 $0 $9,000 $861 $0 $986 $10,848 $20 8.4 Steam Piping $15,895 $0 $7,837 $0 $0 $23,732 $1,994 $0 $3,859 $29,585 $54 8.9 TG Foundations $0 $1,089 $1,721 $0 $0 $2,810 $266 $0 $615 $3,691 $7 SUBTOTAL 8. $74,579 $1,089 $19,456 $0 $0 $95,124 $8,833 $0 $11,990 $115,948 $211 9 COOLING WATER SYSTEM 9.1 Cooling Towers $9,084 $0 $2,829 $0 $0 $11,913 $1,139 $0 $1,305 $14,358 $26 9.2 Circulating Water Pumps $1,887 $0 $116 $0 $0 $2,003 $169 $0 $217 $2,389 $4 9.3 Circ.Water System Auxiliaries $498 $0 $66 $0 $0 $565 $54 $0 $62 $680 $1 9.4 Circ.Water Piping $0 $3,950 $3,828 $0 $0 $7,779 $728 $0 $1,276 $9,783 $18 9.5 Make-up Water System $438 $0 $585 $0 $0 $1,024 $98 $0 $168 $1,290 $2 9.6 Component Cooling Water Sys $395 $0 $314 $0 $0 $709 $67 $0 $116 $892 $2 9.9 Circ.Water System Foundations& Structures $0 $2,346 $3,727 $0 $0 $6,073 $575 $0 $1,330 $7,977 $15 SUBTOTAL 9. $12,303 $6,296 $11,466 $0 $0 $30,066 $2,830 $0 $4,475 $37,370 $68 405

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-43 Case 11 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $590 $0 $1,818 $0 $0 $2,408 $236 $0 $264 $2,909 $5 10.7 Ash Transport & Feed Equipment $3,819 $0 $3,912 $0 $0 $7,731 $739 $0 $847 $9,317 $17 10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.9 Ash/Spent Sorbent Foundation $0 $140 $165 $0 $0 $305 $29 $0 $67 $401 $1 SUBTOTAL 10. $4,409 $140 $5,895 $0 $0 $10,444 $1,004 $0 $1,178 $12,627 $23 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $1,598 $0 $260 $0 $0 $1,858 $172 $0 $152 $2,182 $4 11.2 Station Service Equipment $2,824 $0 $928 $0 $0 $3,752 $351 $0 $308 $4,410 $8 11.3 Switchgear & Motor Control $3,247 $0 $552 $0 $0 $3,798 $352 $0 $415 $4,565 $8 11.4 Conduit & Cable Tray $0 $2,035 $7,038 $0 $0 $9,073 $878 $0 $1,493 $11,445 $21 11.5 Wire & Cable $0 $3,841 $7,414 $0 $0 $11,255 $948 $0 $1,830 $14,034 $26 11.6 Protective Equipment $260 $0 $885 $0 $0 $1,146 $112 $0 $126 $1,383 $3 11.7 Standby Equipment $1,277 $0 $29 $0 $0 $1,306 $120 $0 $143 $1,568 $3 11.8 Main Power Transformers $8,335 $0 $172 $0 $0 $8,507 $646 $0 $915 $10,068 $18 11.9 Electrical Foundations $0 $311 $763 $0 $0 $1,074 $103 $0 $235 $1,412 $3 SUBTOTAL 11. $17,541 $6,187 $18,041 $0 $0 $41,769 $3,682 $0 $5,617 $51,068 $93 12 INSTRUMENTATION & CONTROL 12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $450 $0 $270 $0 $0 $720 $68 $0 $118 $906 $2 12.7 Distributed Control System Equipment $4,543 $0 $794 $0 $0 $5,337 $495 $0 $583 $6,415 $12 12.8 Instrument Wiring & Tubing $2,463 $0 $4,885 $0 $0 $7,348 $626 $0 $1,196 $9,170 $17 12.9 Other I & C Equipment $1,284 $0 $2,913 $0 $0 $4,197 $407 $0 $460 $5,064 $9 SUBTOTAL 12. $8,739 $0 $8,862 $0 $0 $17,601 $1,596 $0 $2,358 $21,555 $39 406

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-43 Case 11 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $50 $998 $0 $0 $1,048 $104 $0 $230 $1,382 $3 13.2 Site Improvements $0 $1,657 $2,058 $0 $0 $3,715 $366 $0 $816 $4,897 $9 13.3 Site Facilities $2,969 $0 $2,928 $0 $0 $5,897 $581 $0 $1,296 $7,774 $14 SUBTOTAL 13. $2,969 $1,707 $5,984 $0 $0 $10,660 $1,052 $0 $2,342 $14,054 $26 14 BUILDINGS & STRUCTURES 14.1 Boiler Building $0 $8,281 $7,282 $0 $0 $15,564 $1,399 $0 $2,544 $19,507 $35 14.2 Turbine Building $0 $11,828 $11,024 $0 $0 $22,851 $2,060 $0 $3,737 $28,648 $52 14.3 Administration Building $0 $586 $620 $0 $0 $1,206 $109 $0 $197 $1,513 $3 14.4 Circulation Water Pumphouse $0 $168 $134 $0 $0 $301 $27 $0 $49 $378 $1 14.5 Water Treatment Buildings $0 $566 $516 $0 $0 $1,081 $97 $0 $177 $1,356 $2 14.6 Machine Shop $0 $392 $264 $0 $0 $656 $58 $0 $107 $821 $1 14.7 Warehouse $0 $266 $267 $0 $0 $532 $48 $0 $87 $668 $1 14.8 Other Buildings & Structures $0 $217 $185 $0 $0 $402 $36 $0 $66 $504 $1 14.9 Waste Treating Building & Str. $0 $416 $1,262 $0 $0 $1,678 $159 $0 $276 $2,112 $4 SUBTOTAL 14. $0 $22,720 $21,552 $0 $0 $44,272 $3,994 $0 $7,240 $55,506 $101 TOTAL COST $444,675 $44,192 $250,892 $0 $0 $739,759 $69,584 $0 $96,558 $905,901 $1,647 Owner's Costs Preproduction Costs 6 Months All Labor $7,258 $13 1 Month Maintenance Materials $895 $2 1 Month Non-fuel Consumables $892 $2 1 Month Waste Disposal $235 $0 25% of 1 Months Fuel Cost at 100% CF $1,427 $3 2% of TPC $18,118 $33 Total $28,826 $52 Inventory Capital 60 day supply of fuel and consumables at 100% CF $12,944 $24 0.5% of TPC (spare parts) $4,530 $8 Total $17,474 $32 Initial Cost for Catalyst and Chemicals $0 $0 Land $900 $2 Other Owner's Costs $135,885 $247 Financing Costs $24,459 $44 Total Overnight Costs (TOC) $1,113,445 $2,024 TASC Multiplier (IOU, low-risk, 35 year) 1.134 Total As-Spent Cost (TASC) $1,262,647 $2,296 407

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-44 Case 11 Initial and Annual Operating and Maintenance Costs INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 11 - 1x550 MWnet SuperCritical PC Heat Rate-net (Btu/kWh): 8,686 MWe-net: 550 Capacity Factor (%): 85 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. 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-O.J.'s 14.0 14.0 Annual Cost Annual Unit Cost

$ $/kW-net Annual Operating Labor Cost $5,524,319 $10.044 Maintenance Labor Cost $6,088,905 $11.070 Administrative & Support Labor $2,903,306 $5.279 Property Taxes and Insurance $18,118,017 $32.941 TOTAL FIXED OPERATING COSTS $32,634,546 $59.333 VARIABLE OPERATING COSTS

$/kWh-net Maintenance Material Cost $9,133,357 $0.00223 Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water (/1000 gallons) 0 3,884 1.08 $0 $1,303,324 $0.00032 Chemicals MU & WT Chem.(lbs) 0 18,799 0.17 $0 $1,009,427 $0.00025 Limestone (ton) 0 488 21.63 $0 $3,273,667 $0.00080 Carbon (Mercury Removal) (lb) 0 0 1.05 $0 $0 $0.00000 MEA Solvent (ton) 0 0 2,249.89 $0 $0 $0.00000 NaOH (tons) 0 0 433.68 $0 $0 $0.00000 H2SO4 (tons) 0 0 138.78 $0 $0 $0.00000 Corrosion Inhibitor 0 0 0.00 $0 $0 $0.00000 Activated Carbon (lb) 0 0 1.05 $0 $0 $0.00000 Ammonia (19% NH3) ton 0 74 129.80 $0 $2,960,869 $0.00072 Subtotal Chemicals $0 $7,243,963 $0.00177 Other Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 SCR Catalyst (m3) w/equip. 0.31 5,775.94 $0 $553,798 $0.00014 Emission Penalties 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $553,798 $0.00014 Waste Disposal Fly Ash (ton) 0 381 16.23 $0 $1,919,038 $0.00047 Bottom Ash (ton) 0 95 16.23 $0 $479,759 $0.00012 Subtotal-Waste Disposal $0 $2,398,797 $0.00059 By-products & Emissions Gypsum (tons) 0 759 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000 TOTAL VARIABLE OPERATING COSTS $0 $20,633,239 $0.00504 Fuel (ton) 0 4,914 38.18 $0 $58,217,892 $0.01422 408

Cost and Performance Baseline for Fossil Energy Plants 4.3.7 Case 12 - Supercritical PC with CO2 Capture The plant configuration for Case 12, SC PC, is the same as Case 11 with the exception that the Econamine CDR technology was added for CO2 capture. The nominal net output is maintained at 550 MW by increasing the boiler size and turbine/generator size to account for the greater auxiliary load imposed by the CDR facility. Unlike the IGCC cases where gross output was fixed by the available size of the CTs, the PC cases utilize boilers and steam turbines that can be procured at nearly any desired output making it possible to maintain a constant net output.

The process description for Case 12 is essentially the same as Case 11 with one notable exception, the addition of CO2 capture. A BFD and stream tables for Case 12 are shown in Exhibit 4-45 and Exhibit 4-46, respectively. Since the CDR facility process description was provided in Section 4.1.7, it is not repeated here.

4.3.8 Case 12 Performance Results The Case 12 modeling assumptions were presented previously in Section 4.3.2.

The plant produces a net output of 550 MW at a net plant efficiency of 28.4 percent (HHV basis). Overall plant performance is summarized in Exhibit 4-47, which includes auxiliary power requirements. The CDR facility, including CO2 compression, accounts for approximately 58 percent of the auxiliary plant load. The CWS (CWPs and cooling tower fan) accounts for over 13 percent of the auxiliary load, largely due to the high cooling water demand of the CDR facility 409

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-45 Case 12 Block Flow Diagram, Supercritical Unit with CO2 Capture 410

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-46 Case 12 Stream Table, Supercritical Unit with CO2 Capture 1 2 3 4 5 6 7 8 9 10 11 12 13 14 V-L Mole Fraction Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087 0.0000 CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450 0.0000 H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870 1.0000 N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324 0.0000 O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247 0.0000 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 V-L Flowrate (kgmol/hr) 66,876 66,876 1,990 20,544 20,544 2,818 1,546 0 0 94,107 0 94,107 94,107 3,385 V-L Flowrate (kg/hr) 1,929,852 1,929,852 57,422 592,830 592,830 81,325 44,605 0 0 2,799,052 0 2,799,052 2,799,052 60,975 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 256,652 4,977 19,910 19,910 0 0 25,966 Temperature (°C) 15 19 19 15 25 25 15 15 15 169 15 169 182 15 Pressure (MPa, abs) 0.10 0.11 0.11 0.10 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11 0.10 Enthalpy (kJ/kg)A 30.23 34.36 34.36 30.23 40.78 40.78 30.23 --- --- 327.40 --- 308.96 322.83 ---

Density (kg/m3) 1.2 1.2 1.2 1.2 1.3 1.3 1.2 --- --- 0.8 --- 0.8 0.8 ---

V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 28.857 28.857 --- --- 29.743 --- 29.743 29.743 ---

V-L Flowrate (lbmol/hr) 147,437 147,437 4,387 45,291 45,291 6,213 3,408 0 0 207,471 0 207,471 207,471 7,462 V-L Flowrate (lb/hr) 4,254,595 4,254,595 126,595 1,306,967 1,306,967 179,291 98,338 0 0 6,170,854 0 6,170,854 6,170,854 134,426 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 565,820 10,973 43,893 43,893 0 0 57,245 Temperature (°F) 59 66 66 59 78 78 59 59 59 337 59 337 360 59 Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.4 15.0 Enthalpy (Btu/lb)A 13.0 14.8 14.8 13.0 17.5 17.5 13.0 --- --- 140.8 --- 132.8 138.8 ---

Density (lb/ft 3) 0.076 0.078 0.078 0.076 0.081 0.081 0.076 --- --- 0.050 --- 0.049 0.052 ---

A - Reference conditions are 32.02 F & 0.089 PSIA 411

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-46 Case 12 Stream Table, Supercritical Unit with CO2 Capture (Continued) 15 16 17 18 19 20 21 22 23 24 25 26 27 28 V-L Mole Fraction Ar 0.0000 0.0128 0.0000 0.0081 0.0108 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO2 0.0000 0.0005 0.0004 0.1350 0.0179 0.9961 0.9985 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2O 1.0000 0.0062 0.9996 0.1537 0.0383 0.0039 0.0015 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 N2 0.0000 0.7506 0.0000 0.6793 0.9013 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O2 0.0000 0.2300 0.0000 0.0238 0.0316 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 V-L Flowrate (kgmol/hr) 13,485 975 250 102,548 77,286 12,511 12,481 44,922 44,922 126,511 103,236 103,236 49,304 49,304 V-L Flowrate (kg/hr) 242,941 28,289 4,498 2,956,531 2,177,293 549,344 548,802 809,288 809,288 2,279,133 1,859,826 1,859,826 888,227 888,227 Solids Flowrate (kg/hr) 0 0 40,138 0 0 0 0 0 0 0 0 0 0 0 Temperature (°C) 15 181 58 58 32 21 35 291 151 593 354 593 38 40 Pressure (MPa, abs) 0.10 0.31 0.10 0.10 0.10 0.16 15.27 0.51 0.92 24.23 4.90 4.52 0.01 1.69 Enthalpy (kJ/kg)A -46.80 191.58 --- 301.43 93.86 19.49 -211.71 3,045.10 636.31 3,476.62 3,081.81 3,652.22 2,115.77 166.72 Density (kg/m3) 1,003.1 2.4 --- 1.1 1.1 2.9 795.9 2.0 916.0 69.2 18.7 11.6 0.1 993.2 V-L Molecular Weight 18.015 29.029 --- 28.831 28.172 43.908 43.971 18.015 18.015 18.015 18.015 18.015 18.015 18.015 V-L Flowrate (lbmol/hr) 29,730 2,148 550 226,080 170,387 27,582 27,516 99,037 99,037 278,909 227,597 227,597 108,697 108,697 V-L Flowrate (lb/hr) 535,592 62,368 9,916 6,518,034 4,800,109 1,211,096 1,209,902 1,784,175 1,784,175 5,024,628 4,100,215 4,100,215 1,958,206 1,958,206 Solids Flowrate (lb/hr) 0 0 88,488 0 0 0 0 0 0 0 0 0 0 0 Temperature (°F) 59 357 136 136 89 69 95 556 304 1,100 668 1,100 101 103 Pressure (psia) 14.7 45.0 14.9 14.9 14.7 23.5 2,214.5 73.5 133.6 3,514.7 710.8 655.8 1.0 245.0 Enthalpy (Btu/lb)A -20.1 82.4 --- 129.6 40.4 8.4 -91.0 1,309.2 273.6 1,494.7 1,324.9 1,570.2 909.6 71.7 Density (lb/ft 3) 62.622 0.149 --- 0.067 0.070 0.184 49.684 0.123 57.184 4.319 1.166 0.722 0.004 62.002 412

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-47 Case 12 Plant Performance Summary POWER

SUMMARY

(Gross Power at Generator Terminals, kWe)

Steam Turbine Power 662,800 TOTAL (STEAM TURBINE) POWER, kWe 662,800 AUXILIARY LOAD

SUMMARY

, kWe Coal Handling and Conveying 510 Pulverizers 3,850 Sorbent Handling & Reagent Preparation 1,250 Ash Handling 740 Primary Air Fans 1,800 Forced Draft Fans 2,300 Induced Draft Fans 11,120 SCR 70 Baghouse 100 Wet FGD 4,110 Econamine FG Plus Auxiliaries 20,600 CO2 Compression 44,890 2,3 Miscellaneous Balance of Plant 2,000 Steam Turbine Auxiliaries 400 Condensate Pumps 560 Circulating Water Pumps 10,100 Ground Water Pumps 910 Cooling Tower Fans 5,230 Transformer Losses 2,290 TOTAL AUXILIARIES, kWe 112,830 NET POWER, kWe 549,970 Net Plant Efficiency (HHV) 28.4%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 12,663 (12,002)

CONDENSER COOLING DUTY, 106 kJ/hr (106 Btu/hr) 1,737 (1,646)

CONSUMABLES As-Received Coal Feed, kg/hr (lb/hr) 256,652 (565,820)

Limestone Sorbent Feed, kg/hr (lb/hr) 25,966 (57,245) 1 Thermal Input, kWt 1,934,519 3

Raw Water Withdrawal, m /min (gpm) 38.1 (10,071) 3 Raw Water Consumption, m /min (gpm) 29.3 (7,733)

1. HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)

2. Boiler feed pumps are turbine driven

3. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads 413

Cost and Performance Baseline for Fossil Energy Plants Environmental Performance The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 2.4. A summary of the plant air emissions for Case 12 is presented in Exhibit 4-48.

Exhibit 4-48 Case 12 Air Emissions Tonne/year kg/GJ kg/MWh (ton/year)

(lb/106 Btu) (lb/MWh) 85% CF SO2 0.001 (0.002) 36 (40) 0.007 (.02)

NOx 0.030 (0.070) 1,561 (1,720) 0.316 (.697)

Particulates 0.006 (0.0130) 290 (319) 0.059 (.129)

Hg 4.91E-7 (1.14E-6) 0.025 (0.028) 5.16E-6 (1.14E-5)

CO2 8.8 (20.4) 453,763 (500,188) 92 (203)

CO21 111 (244) 1 CO2 emissions based on net power instead of gross power SO2 emissions are controlled using a wet limestone forced oxidation scrubber that achieves a removal efficiency of 98 percent. The byproduct calcium sulfate is dewatered and stored on site.

The wallboard grade material can potentially be marketed and sold, but since it is highly dependent on local market conditions, no byproduct credit was taken. The SO2 emissions are further reduced to 10 ppmv using a NaOH based polishing scrubber in the CDR facility. The remaining low concentration of SO2 is essentially completely removed in the CDR absorber vessel resulting in very low SO2 emissions.

NOx emissions are controlled to about 0.5 lb/106 Btu through the use of LNBs and OFA. An SCR unit then further reduces the NOx concentration by 86 percent to 0.07 lb/106 Btu.

Particulate emissions are controlled using a pulse jet fabric filter, which operates at an efficiency of 99.8 percent.

Co-benefit capture results in a 90 percent reduction of mercury emissions.

Ninety percent of the CO2 in the FG is removed in CDR facility.

The carbon balance for the plant is shown in Exhibit 4-49. The carbon input to the plant consists of carbon in the coal in addition to carbon in the air and limestone for the FGD. Carbon in the air is not neglected here since the Aspen model accounts for air components throughout. Carbon leaves the plant as CO2 in the stack gas, carbon in the FGD product, and the captured CO2 product. The carbon capture efficiency is defined by the following fraction:

1-[(Stack Gas Carbon-Air Carbon)/(Total Carbon In-Air Carbon)] or

[1-(36,667-783)/(367,272-783)

100] or 90.2 percent 414

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-49 Case 12 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 163,602 (360,680) Stack Gas 16,632 (36,667)

Air (CO2) 355 (783) FGD Product 274 (605)

FGD Reagent 2,635 (5,809) CO2 Product 149,685 (329,999)

Total 166,592 (367,272) Total 166,592 (367,272)

Exhibit 4-50 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered from the FGD as gypsum, sulfur emitted in the stack gas, and sulfur removed in the polishing scrubber.

Exhibit 4-50 Case 12 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 6,433 (14,182) FGD Product 6,304 (13,898)

Stack Gas 2 (5)

Econamine Polishing 126 (278)

Scrubber/HSS Total 6,433 (14,182) Total 6,433 (14,182)

Exhibit 4-51 shows the overall water balance for the plant. The exhibit is presented in an identical manner as for Case 11.

Exhibit 4-51 Case 12 Water Balance Process Water Internal Raw Water Water Raw Water Demand, Recycle, Withdrawal, Water Use Discharge, Consumption, m3/min m3/min m3/min m3/min m3/min (gpm)

(gpm) (gpm) (gpm)

(gpm)

Econamine 0.1 (36) 0.0 (0) 0.1 (36) 0.00 (0) 0.1 (36)

FGD Makeup 5.1 (1,340) 0.0 (0) 5.1 (1,340) 0.00 (0) 5.1 (1,340)

BFW Makeup 0.0 (0) 0.0 (0) 0.0 (0) 0.00 (0) 0.0 (0)

Cooling Tower 39.4 (10,399) 6.5 (1,703) 32.9 (8,696) 8.9 (2,339) 24.1 (6,357)

Total 44.6 (11,774) 6.5 (1,703) 38.1 (10,071) 8.9 (2,339) 29.3 (7,733) 415

Cost and Performance Baseline for Fossil Energy Plants Heat and Mass Balance Diagrams A heat and mass balance diagram is shown for the Case 12 PC boiler, the FGD unit, CDR system, and steam cycle in Exhibit 4-52 and Exhibit 4-53. An overall plant energy balance is provided in tabular form in Exhibit 4-54. The power out is the steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 4-47) is calculated by multiplying the power out by a generator efficiency of 98.5 percent. The Econamine process heat out stream represents heat rejected to cooling water and ultimately to ambient via the cooling tower. The same is true of the condenser heat out stream. The CO2 compressor intercooler load is included in the Econamine process heat out stream.

416

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-52 Case 12 Heat and Mass Balance, Supercritical PC Boiler with CO2 Capture MAKE-UP OXIDATION LEGEND WATER AIR 62,368 W Air 535,592 W 15 16 357.4 T 59.0 T 14.7 P 45.0 P Coal/Ash 82.4 H Slurry Nitrogen Oxygen 10 Baghouse 12 13 FGD 6,214,747 W 360.4 T 337.0 T 6,170,854 W ID FANS Sour Gas 337.0 T 15.4 P 14.4 P 14.2 P 138.8 H 140.8 H 132.8 H Sour Water 11 191,671 W 98,404 W 14 17 59.0 T 135.8 T 6,518,034 W Steam 15.0 P 14.9 P 135.8 T 18 14.9 P ASH 129.6 H Synthesis Gas Throttle Steam 43,893 W To HP Turbine LIMESTONE GYPSUM SLURRY Water 24 5,024,628 W 1,100.0 T Lime/Ash 3,514.7 P Single Reheat 1,494.7 H To IP Turbine Flue Gas 26 P ABSOLUTE PRESSURE, PSIA 4,100,215 W F TEMPERATURE, °F 1,100.0 T W FLOWRATE, LBM/HR 655.8 P 4,800,109 W H ENTHALPY, BTU/LBM 1,570.6 H 88.8 T MWE POWER, MEGAWATTS ELECTRICAL AMMONIA SCR 14.7 P 40.4 H NOTES:

CO2 INFILTRATION 7 COMPRESSION 98,338 W AIR (INTERSTAGE 59.0 T 19 COOLING) 1. ENTHALPY REFERENCE POINT IS NATURAL STATE 14.7 P 66.4 T AT 32 °F AND 0.08865 PSIA 13.0 H 15.3 P Pulverized 14.8 H 25 4,100,215 W AIR 1 2

Coal 668.4 T 710.8 P 4,254,595 W 59.0 T FORCED 3 Boiler 1,324.9 H STACK 1,211,096 W 69.0 T 14.7 P DRAFT FANS 20 23.5 P 21 CO2 PLANT PERFORMANCE

SUMMARY

13.0 H 8.4 H PRODUCT 1,209,902 W Single Reheat Gross Plant Power: 663 MWe 95.0 T Extraction from Auxiliary Load: 113 MWe 2,214.5 P HP Turbine Net Plant Power: 550 MWe 6

FLUE GAS Acid Gas Net Plant Efficiency, HHV: 28.4%

Net Plant Heat Rate: 12,002 BTU/KWe 5

AIR 4 ABSORBER 1,306,967 W STRIPPER 77.8 T 59.0 T PRIMARY 16.1 P 1,784,175 W 14.7 P AIR FANS 17.5 H 306.3 T ECONAMINE 556.3 T 73.5 P DOE/NETL 13.0 H 9 73.5 P STEAM 1,181.0 H 1,309.6 H From Feedwater 22 SC PC PLANT Heaters CASE 12 COAL 8 5,024,628 W 565,820 W 545.5 T ECONAMINE FG+

4,185.0 P HEAT AND MATERIAL FLOW DIAGRAM ASH 539.3 H 10,973 W 252,068 W 1,784,175 W BITUMINOUS BASELINE STUDY 304.0 T 133.6 P CASE 12 273.6 H SUPERCRITICAL PULVERIZED COAL 23 BOILER AND GAS CLEANUP SYSTEMS ECONAMINE DWG. NO. PAGES CONDENSATE BB-HMB-CS-12-PG-1 1 OF 2 417

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-53 Case 12 Heat and Mass Balance, Supercritical Steam Cycle LEGEND ECONAMINE Air STEAM Single Reheat Coal/Char/

Extraction 1,784,175 W Slurry/Slag From Boiler 556.3 T 22 73.5 P 26 1,309.6 H Nitrogen 4,100,215 W 1,100.0 T 655.8 P 1,570.6 H Oxygen 24 3,731,302 W 375,024 W 5,024,628 W 1,100.0 T 556.3 T 1,572,104 W 556.3 T Sour Gas 73.5 P 556.3 T 73.5 P 3,514.7 P 1,309.2 H 73.5 P 1,309.2 H 1,494.7 H 1,309.2 H Sour Water Throttle Steam BOILER FEED HP IP LP TURBINE GENERATOR PUMP TURBINE Steam TURBINE TURBINE DRIVES Synthesis Gas 11.4 P 4.5 P 2,900.0 P 29.0 P 2.3 P 1,115.5 P 710.8 P 710.8 P 221.9 P 75.0 P 75.0 P 2,900.0 P 710.8 P 2,900.0 P 126.1 T 2.0 P Single Reheat 1,085.4 H Water Extraction to 25 1,337,035 W Boiler 101.1 T 1.0 P 1,009.5 H 4,100,215 W 668.4 T 710.8 P CONDENSER 1,324.9 H STEAM SEAL REGULATOR 3,301 W 674.7 T P ABSOLUTE PRESSURE, PSIA 75.0 P HOT WELL F TEMPERATURE, °F 1,367.7 H W FLOWRATE, LBM/HR To Boiler 4,985 W 2,793 W H ENTHALPY, BTU/LBM ECONAMINE 674.7 T 674.7 T 5,024,628 W CONDENSATE 75.0 P 75.0 P 1,958,206 W MWE POWER, MEGAWATTS ELECTRICAL 545.5 T 101.1 T 1,367.7 H 1,367.7 H 4,185.0 P 1.0 P 1,784,175 W 539.3 H 69.1 H NOTES:

304.0 T 133.6 P 273.6 H CONDENSATE 1. ENTHALPY REFERENCE POINT IS NATURAL STATE PUMPS AT 32 °F AND 0.08865 PSIA 23 101.4 T 37,063 W 250.0 P 128.8 T 70.0 H 83,560 W 2.2 P 281,028 W 612,527 W 285,001 W 71,629 W 47,801 W 370.1 T 1,054.1 H 763.9 T 665.2 T 803.0 T 103,690 W 216.1 T 156.0 T 990.5 P 700.8 P 211.9 P 595.3 T 25.0 P 10.4 P 4.3 P 1,223.5 H 1,367.5 H 5,024,628 W 1,323.6 H 5,024,628 W 1,426.1 H 70.0 P 1,328.7 H 1,153.6 H 1,123.0 H GLAND SEAL PLANT PERFORMANCE

SUMMARY

503.3 T 1,958,206 W 1,958,206 W 1,958,206 W 1,958,206 W 388.7 T CONDENSER 4,190.0 P 235.0 T 190.2 T 151.0 T 123.8 T 4,195.0 P P-1048 FWH 8 FWH 7 FWH 6 225.0 P 230.0 P 235.0 P 240.0 P P-1028 2,793 W 491.0 H 367.8 H FWH 4 FWH 3 FWH 2 FWH 1 Gross Plant Power: 663 MWe 203.5 H 158.5 H 119.3 H 92.2 H 212.0 T 28 14.7 P Auxiliary Load: 113 MWe 1,958,206 W 179.9 H Net Plant Power: 550 MWe 103.1 T Net Plant Efficiency, HHV: 28.4%

DEAERATOR 245.0 P 71.7 H Net Plant Heat Rate: 12,002 BTU/KWe 281,028 W 893,554 W 1,178,556 W 83,560 W 155,189 W 202,990 W 513.3 T 398.7 T 321.8 T 200.2 T 161.0 T 133.8 T 240,053 W 765.9 P 243.6 P 91.9 P 11.6 P 4.9 P 2.5 P 113.1 T 503.4 H 373.2 H 291.8 H 168.0 H 128.7 H 101.6 H 1.4 P 81.0 H DOE/NETL 5,024,628 W 311.8 T 302.9 T 70.0 P SC PC PLANT 4,200.0 P 272.3 H CASE 12 289.0 H BOILER FEED PUMPS HEAT AND MATERIAL FLOW DIAGRAM BITUMINOUS BASELINE STUDY CASE 12 SUPERCRITICAL PULVERIZED COAL POWER BLOCK SYSTEMS DWG. NO. PAGES BB-HMB-CS-12-PG-2 2 OF 2 418

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-54 Case 12 Overall Energy Balance (0°C [32°F] Reference)

Sensible +

HHV Power Total Latent Heat In GJ/hr (MMBtu/hr)

Coal 6,964 (6,601) 5.8 (5.5) 6,970 (6,606)

Air 77.6 (73.6) 77.6 (73.6)

Raw Water Makeup 144.9 (137.3) 144.9 (137.3)

Limestone 0.29 (0.28) 0.29 (0.28)

Auxiliary Power 406 (385) 406 (385)

Totals 6,964 (6,601) 228.6 (216.7) 406 (385) 7,599 (7,203)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.6 (0.6) 0.6 (0.6)

Fly Ash + FGD Ash 2.4 (2.3) 2.4 (2.3)

Flue Gas 204 (194) 204 (194)

Condenser 1,737 (1,646) 1,737 (1,646)

CO2 -116 (-110) -116 (-110)

Cooling Tower 65.8 (62.3) 65.8 (62.3)

Blowdown Econamine Losses 3,298 (3,126) 3,298 (3,126)

Process Losses* 21.3 (20.2) 21.3 (20.2)

Power 2,386 (2,262) 2,386 (2,262)

Totals 0 (0) 5,213 (4,941) 2,386 (2,262) 7,599 (7,203)

Process losses are estimated to match the heat input to the plant. Process losses include losses from:

turbines, HRSGs, combustion reactions, gas cooling, etc.

419

Cost and Performance Baseline for Fossil Energy Plants 4.3.9 Case 12 - Major Equipment List Major equipment items for the SC PC plant with CO2 capture are shown in the following tables.

The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section 4.3.10. In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 FUEL AND SORBENT HANDLING Equipment Operating Description Type Design Condition Spares No. Qty.

Bottom Trestle Dumper and 1 N/A 181 tonne (200 ton) 2 0 Receiving Hoppers 2 Feeder Belt 572 tonne/hr (630 tph) 2 0 3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0 4 Transfer Tower No. 1 Enclosed N/A 1 0 5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0 As-Received Coal Sampling 6 Two-stage N/A 1 0 System 7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0 8 Reclaim Hopper N/A 54 tonne (60 ton) 2 1 9 Feeder Vibratory 209 tonne/hr (230 tph) 2 1 10 Conveyor No. 3 Belt w/ tripper 426 tonne/hr (470 tph) 1 0 11 Crusher Tower N/A N/A 1 0 12 Coal Surge Bin w/ Vent Filter Dual outlet 209 tonne (230 ton) 2 0 Impactor 8 cm x 0 - 3 cm x 0 13 Crusher 2 0 reduction (3 in x 0 1/4 in x 0)

As-Fired Coal Sampling 14 Swing hammer N/A 1 1 System 15 Conveyor No. 4 Belt w/tripper 426 tonne/hr (470 tph) 1 0 16 Transfer Tower No. 2 Enclosed N/A 1 0 17 Conveyor No. 5 Belt w/ tripper 426 tonne/hr (470 tph) 1 0 Coal Silo w/ Vent Filter and 18 Field erected 907 tonne (1,000 ton) 3 0 Slide Gates Limestone Truck Unloading 19 N/A 36 tonne (40 ton) 1 0 Hopper 20 Limestone Feeder Belt 109 tonne/hr (120 tph) 1 0 21 Limestone Conveyor No. L1 Belt 109 tonne/hr (120 tph) 1 0 22 Limestone Reclaim Hopper N/A 18 tonne (20 ton) 1 0 23 Limestone Reclaim Feeder Belt 82 tonne/hr (90 tph) 1 0 24 Limestone Conveyor No. L2 Belt 82 tonne/hr (90 tph) 1 0 25 Limestone Day Bin w/ actuator 345 tonne (380 ton) 2 0 420

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED Equipment Operating Description Type Design Condition Spares No. Qty.

1 Coal Feeder Gravimetric 45 tonne/hr (50 tph) 6 0 Ball type or 2 Coal Pulverizer 45 tonne/hr (50 tph) 6 0 equivalent 3 Limestone Weigh Feeder Gravimetric 28 tonne/hr (31 tph) 1 1 4 Limestone Ball Mill Rotary 28 tonne/hr (31 tph) 1 1 Limestone Mill Slurry Tank 5 N/A 109,777 liters (29,000 gal) 1 1 with Agitator Limestone Mill Recycle Horizontal 1,855 lpm @ 12m H2O (490 gpm 6 1 1 Pumps centrifugal @ 40 ft H2O) 4 active 7 Hydroclone Classifier cyclones in a 5 454 lpm (120 gpm) per cyclone 1 1 cyclone bank 8 Distribution Box 2-way N/A 1 1 Limestone Slurry Storage 9 Field erected 617,022 liters (163,000 gal) 1 1 Tank with Agitator Limestone Slurry Feed Horizontal 1,287 lpm @ 9m H2O (340 gpm 10 1 1 Pumps centrifugal @ 30 ft H2O) 421

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment Operating Description Type Design Condition Spares No. Qty.

Demineralized Water Vertical, cylindrical, 1 1,506,594 liters (398,000 gal) 2 0 Storage Tank outdoor 16,277 lpm @ 213 m H2O (4,300 2 Condensate Pumps Vertical canned 1 1 gpm @ 700 ft H2O)

Deaerator and Storage 2,507,005 kg/hr (5,527,000 lb/hr),

3 Horizontal spray type 1 0 Tank 5 min. tank Boiler Feed Barrel type, multi-stage, 42,018 lpm @ 3,505 m H2O 4 1 1 Pump/Turbine centrifugal (11,100 gpm @ 11,500 ft H2O)

Startup Boiler Feed Barrel type, multi-stage, 12,492 lpm @ 3,505 m H2O 5 Pump, Electric Motor 1 0 centrifugal (3,300 gpm @ 11,500 ft H2O)

Driven LP Feedwater Heater 6 Horizontal U-tube 489,880 kg/hr (1,080,000 lb/hr) 2 0 1A/1B LP Feedwater Heater 7 Horizontal U-tube 489,880 kg/hr (1,080,000 lb/hr) 2 0 2A/2B LP Feedwater Heater 8 Horizontal U-tube 489,880 kg/hr (1,080,000 lb/hr) 2 0 3A/3B LP Feedwater Heater 9 Horizontal U-tube 489,880 kg/hr (1,080,000 lb/hr) 2 0 4A/4B 10 HP Feedwater Heater 6 Horizontal U-tube 2,508,366 kg/hr (5,530,000 lb/hr) 1 0 11 HP Feedwater Heater 7 Horizontal U-tube 2,508,366 kg/hr (5,530,000 lb/hr) 1 0 12 HP Feedwater heater 8 Horizontal U-tube 2,508,366 kg/hr (5,530,000 lb/hr) 1 0 Shop fabricated, water 18,144 kg/hr, 2.8 MPa, 343°C 13 Auxiliary Boiler 1 0 tube (40,000 lb/hr, 400 psig, 650°F)

No. 2 fuel oil for light 14 Fuel Oil System 1,135,624 liter (300,000 gal) 1 0 off Service Air 28 m3/min @ 0.7 MPa (1,000 15 Flooded Screw 2 1 Compressors scfm @ 100 psig) 16 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1 Closed Cycle Cooling 17 Shell and tube 53 GJ/hr (50 MMBtu/hr) each 2 0 Heat Exchangers Closed Cycle Cooling 20,820 lpm @ 30 m H2O (5,500 18 Horizontal centrifugal 2 1 Water Pumps gpm @ 100 ft H2O)

Engine-Driven Fire Vertical turbine, diesel 3,785 lpm @ 88 m H2O (1,000 19 1 1 Pump engine gpm @ 290 ft H2O)

Fire Service Booster Two-stage horizontal 2,650 lpm @ 64 m H2O (700 gpm 20 1 1 Pump centrifugal @ 210 ft H2O)

Stainless steel, single 11,016 lpm @ 18 m H2O (2,910 21 Raw Water Pumps 2 1 suction gpm @ 60 ft H2O)

Stainless steel, single 4,429 lpm @ 268 m H2O (1,170 22 Ground Water Pumps 5 1 suction gpm @ 880 ft H2O)

Stainless steel, single 2,725 lpm @ 49 m H2O (720 gpm 23 Filtered Water Pumps 2 1 suction @ 160 ft H2O) 24 Filtered Water Tank Vertical, cylindrical 2,619,505 liter (692,000 gal) 1 0 Multi-media filter, Makeup Water cartridge filter, RO 25 984 lpm (260 gpm) 1 1 Demineralizer membrane assembly, electrodeionization unit Liquid Waste Treatment 26 -- 10 years, 24-hour storm 1 0 System 422

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 4 BOILER AND ACCESSORIES Equipment Operating Description Type Design Condition Spares No. Qty.

2,508,366 kg/hr steam @ 25.5 Supercritical, drum, MPa/602°C/602°C (5,530,000 1 Boiler wall-fired, low NOx 1 0 lb/hr steam @ 3,700 burners, overfire air psig/1,115°F/1,115°F) 326,133 kg/hr, 4,449 m3/min @

2 Primary Air Fan Centrifugal 123 cm WG (719,000 lb/hr, 2 0 157,100 acfm @ 48 in. WG) 1,061,406 kg/hr, 14,484 m3/min 3 Forced Draft Fan Centrifugal @ 47 cm WG (2,340,000 lb/hr, 2 0 511,500 acfm @ 19 in. WG) 1,539,493 kg/hr, 32,491 m3/min 4 Induced Draft Fan Centrifugal @ 104 cm WG (3,394,000 lb/hr, 2 0 1,147,400 acfm @ 41 in. WG)

Space for spare 5 SCR Reactor Vessel 3,079,892 kg/hr (6,790,000 lb/hr) 2 0 layer 6 SCR Catalyst -- -- 3 0 184 m3/min @ 108 cm WG 7 Dilution Air Blower Centrifugal 2 1 (6,500 acfm @ 42 in. WG) 8 Ammonia Storage Horizontal tank 200,627 liter (53,000 gal) 5 0 Ammonia Feed 39 lpm @ 91 m H2O (10 gpm @

9 Centrifugal 2 1 Pump 300 ft H2O) 423

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 5 FLUE GAS CLEANUP Equipment Operating Description Type Design Condition Spares No. Qty.

Single stage, high-ratio with pulse-jet 1,539,493 kg/hr (3,394,000 lb/hr) 1 Fabric Filter 2 0 online cleaning 99.8% efficiency system Counter-current 2 Absorber Module 61,561 m3/min (2,174,000 acfm) 1 0 open spray Horizontal 215,768 lpm @ 64 m H2O 3 Recirculation Pumps 5 1 centrifugal (57,000 gpm @ 210 ft H2O)

Horizontal 5,565 lpm (1,470 gpm) at 20 wt%

4 Bleed Pumps 2 1 centrifugal solids 109 m3/min @ 0.3 MPa (3,840 5 Oxidation Air Blowers Centrifugal 2 1 acfm @ 37 psia) 6 Agitators Side entering 50 hp 5 1 Radial assembly, 7 Dewatering Cyclones 1,401 lpm (370 gpm) per cyclone 2 0 5 units each 44 tonne/hr (49 tph) of 50 wt %

8 Vacuum Filter Belt Horizontal belt 2 1 slurry Filtrate Water Return Horizontal 833 lpm @ 12 m H2O (220 gpm 9 1 1 Pumps centrifugal @ 40 ft H2O)

Filtrate Water Return 10 Vertical, lined 567,812 lpm (150,000 gal) 1 0 Storage Tank Process Makeup Water Horizontal 4,467 lpm @ 21 m H2O (1,180 11 1 1 Pumps centrifugal gpm @ 70 ft H2O) 424

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 5C CARBON DIOXIDE RECOVERY Equipment Operating Description Type Design Condition Spares No. Qty.

Econamine FG Amine-based CO2 1,626,129 kg/h (3,585,000 lb/h) 1 2 0 Plus capture technology 20.6 wt % CO2 concentration Econamine 16,959 lpm @ 52 m H2O (4,480 2 Condensate Centrifugal 1 1 gpm @ 170 ft H2O)

Pump CO2 Integrally geared, 301,656 kg/h @ 15.3 MPa 3 2 0 Compressor multi-stage centrifugal (665,037 lb/h @ 2,215 psia)

ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES N/A ACCOUNT 7 HRSG, DUCTING & STACK Equipment Operating Description Type Design Condition Spares No. Qty.

Reinforced concrete 152 m (500 ft) high x 1 Stack 1 0 with FRP liner 5.6 m (18 ft) diameter ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES Equipment Operating Description Type Design Condition Spares No. Qty.

698 MW Commercially 24.1 MPa/593°C/593°C 1 Steam Turbine available advanced 1 0 (3500 psig/

steam turbine 1100°F/1100°F)

Hydrogen cooled, 780 MVA @ 0.9 p.f., 24 2 Steam Turbine Generator 1 0 static excitation kV, 60 Hz, 3-phase 1,910 GJ/hr (1,810 Single pass, divided MMBtu/hr), Inlet water 3 Surface Condenser waterbox including temperature 16°C (60°F), 1 0 vacuum pumps Water temperature rise 11°C (20°F) 425

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 9 COOLING WATER SYSTEM Equipment Operating Description Type Design Condition Spares No. Qty.

Circulating Water 1,014,500 lpm @ 30 m 1 Vertical, wet pit 2 1 Pumps (268,000 gpm @ 100 ft) 11°C (51.5°F) wet bulb / 16°C Evaporative, (60°F) CWT / 27°C (80°F) HWT 2 Cooling Tower mechanical draft, multi- 1 0

/ 5655 GJ/hr (5360 MMBtu/hr) cell heat duty 426

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING Equipment Operating Description Type Design Condition Spares No. Qty.

Economizer Hopper (part of 1 -- -- 4 0 boiler scope of supply)

Bottom Ash Hopper (part of 2 -- -- 2 0 boiler scope of supply) 3 Clinker Grinder -- 5.4 tonne/hr (6 tph) 1 1 Pyrites Hopper (part of 4 pulverizer scope of supply -- -- 6 0 included with boiler) 5 Hydroejectors -- -- 12 Economizer /Pyrites Transfer 6 -- -- 1 0 Tank 227 lpm @ 17 m H2O (60 gpm 7 Ash Sluice Pumps Vertical, wet pit 1 1

@ 56 ft H2O) 7,571 lpm @ 9 m H2O (2000 8 Ash Seal Water Pumps Vertical, wet pit 1 1 gpm @ 28 ft H2O) 9 Hydrobins -- 227 lpm (60 gpm) 1 1 Baghouse Hopper (part of 10 -- -- 24 0 baghouse scope of supply)

Air Heater Hopper (part of 11 -- -- 10 0 boiler scope of supply) 20 m3/min @ 0.2 MPa (710 12 Air Blower -- 1 1 scfm @ 24 psi)

Reinforced 13 Fly Ash Silo 1,270 tonne (1,400 ton) 2 0 concrete 14 Slide Gate Valves -- -- 2 0 15 Unloader -- -- 1 0 16 Telescoping Unloading Chute -- 127 tonne/hr (140 tph) 1 0 427

Cost and Performance Baseline for Fossil Energy Plants ACCOUNT 11 ACCESSORY ELECTRIC PLANT Equipment Operating Description Type Design Condition Spares No. Qty.

24 kV/345 kV, 650 MVA, 3-1 STG Transformer Oil-filled 1 0 ph, 60 Hz Auxiliary 24 kV/4.16 kV, 123 MVA, 3-2 Oil-filled 1 1 Transformer ph, 60 Hz Low Voltage 4.16 kV/480 V, 18 MVA, 3-3 Dry ventilated 1 1 Transformer ph, 60 Hz STG Isolated 4 Phase Bus Duct Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0 and Tap Bus Medium Voltage 5 Metal clad 4.16 kV, 3-ph, 60 Hz 1 1 Switchgear Low Voltage 6 Metal enclosed 480 V, 3-ph, 60 Hz 1 1 Switchgear Emergency Diesel Sized for emergency 7 750 kW, 480 V, 3-ph, 60 Hz 1 0 Generator shutdown ACCOUNT 12 INSTRUMENTATION AND CONTROL Equipment Operating Description Type Design Condition Spares No. Qty.

Monitor/keyboard; DCS - Main Operator printer (laser Operator stations/printers and 1 1 0 Control color); Engineering engineering stations/printers printer (laser B&W)

Microprocessor with 2 DCS - Processor N/A 1 0 redundant input/output DCS - Data 3 Fiber optic Fully redundant, 25% spare 1 0 Highway 428

Cost and Performance Baseline for Fossil Energy Plants 4.3.10 Case 12 - Cost Estimating Basis The cost estimating methodology was described previously in Section 2.7. Exhibit 4-55 shows the total plant capital cost summary organized by cost account and Exhibit 4-56 shows a more detailed breakdown of the capital costs as well as owners costs, TOC, and TASC. Exhibit 4-57 shows the initial and annual O&M costs.

The estimated TOC of the SC PC boiler with CO2 capture is $3,570/kW. Process contingency represents 2.8 percent of the TOC and project contingency represents 10.2 percent. The COE, including CO2 TS&M costs of 5.7 mills/kWh, is 106.6 mills/kWh.

429

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-55 Case 12 Total Plant Cost Summary Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study TOTAL PLANT COST

SUMMARY

Case: Case 12 - 1x550 MWnet Super-Critical PC w/ CO2 Capture Plant Size: 550.0 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING $20,098 $5,400 $12,019 $0 $0 $37,517 $3,366 $0 $6,132 $47,015 $85 2 COAL & SORBENT PREP & FEED $13,673 $796 $3,473 $0 $0 $17,942 $1,572 $0 $2,927 $22,442 $41 3 FEEDWATER & MISC. BOP SYSTEMS $54,851 $0 $25,849 $0 $0 $80,700 $7,397 $0 $14,455 $102,552 $186 4 PC BOILER 4.1 PC Boiler & Accessories $195,902 $0 $109,921 $0 $0 $305,822 $29,763 $0 $33,559 $369,144 $671 4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4-4.9 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4 $195,902 $0 $109,921 $0 $0 $305,822 $29,763 $0 $33,559 $369,144 $671 5 FLUE GAS CLEANUP $101,027 $0 $34,490 $0 $0 $135,517 $12,971 $0 $14,849 $163,336 $297 5B CO2 REMOVAL & COMPRESSION $235,366 $0 $71,742 $0 $0 $307,108 $29,363 $54,181 $78,130 $468,782 $852 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 6.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 6 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 7.2-7.9 HRSG Accessories, Ductwork and Stack $17,541 $961 $11,881 $0 $0 $30,383 $2,783 $0 $4,359 $37,526 $68 SUBTOTAL 7 $17,541 $961 $11,881 $0 $0 $30,383 $2,783 $0 $4,359 $37,526 $68 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $56,794 $0 $7,537 $0 $0 $64,331 $6,165 $0 $7,050 $77,546 $141 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $27,360 $1,200 $15,331 $0 $0 $43,892 $3,826 $0 $6,848 $54,565 $99 SUBTOTAL 8 $84,154 $1,200 $22,868 $0 $0 $108,222 $9,991 $0 $13,898 $132,111 $240 9 COOLING WATER SYSTEM $20,722 $9,941 $18,443 $0 $0 $49,106 $4,622 $0 $7,236 $60,965 $111 10 ASH/SPENT SORBENT HANDLING SYS $5,276 $168 $7,053 $0 $0 $12,497 $1,202 $0 $1,410 $15,108 $27 11 ACCESSORY ELECTRIC PLANT $25,213 $10,656 $30,191 $0 $0 $66,060 $5,843 $0 $9,029 $80,931 $147 12 INSTRUMENTATION & CONTROL $10,017 $0 $10,157 $0 $0 $20,174 $1,829 $1,009 $2,826 $25,838 $47 13 IMPROVEMENTS TO SITE $3,321 $1,909 $6,692 $0 $0 $11,921 $1,176 $0 $2,620 $15,717 $29 14 BUILDINGS & STRUCTURES $0 $24,782 $23,519 $0 $0 $48,301 $4,357 $0 $7,899 $60,557 $110 TOTAL COST $787,159 $55,813 $388,298 $0 $0 $1,231,270 $116,235 $55,190 $199,329 $1,602,023 $2,913 430

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-56 Case 12 Total Plant Cost Details Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $4,115 $0 $1,880 $0 $0 $5,995 $536 $0 $980 $7,510 $14 1.2 Coal Stackout & Reclaim $5,318 $0 $1,205 $0 $0 $6,523 $571 $0 $1,064 $8,158 $15 1.3 Coal Conveyors $4,944 $0 $1,192 $0 $0 $6,137 $538 $0 $1,001 $7,676 $14 1.4 Other Coal Handling $1,294 $0 $276 $0 $0 $1,569 $137 $0 $256 $1,963 $4 1.5 Sorbent Receive & Unload $168 $0 $51 $0 $0 $218 $19 $0 $36 $273 $0 1.6 Sorbent Stackout & Reclaim $2,709 $0 $496 $0 $0 $3,205 $279 $0 $523 $4,007 $7 1.7 Sorbent Conveyors $967 $209 $237 $0 $0 $1,413 $122 $0 $230 $1,765 $3 1.8 Other Sorbent Handling $584 $137 $306 $0 $0 $1,027 $91 $0 $168 $1,285 $2 1.9 Coal & Sorbent Hnd.Foundations $0 $5,054 $6,376 $0 $0 $11,430 $1,074 $0 $1,876 $14,379 $26 SUBTOTAL 1. $20,098 $5,400 $12,019 $0 $0 $37,517 $3,366 $0 $6,132 $47,015 $85 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $2,388 $0 $465 $0 $0 $2,853 $249 $0 $465 $3,567 $6 2.2 Coal Conveyor to Storage $6,113 $0 $1,334 $0 $0 $7,447 $651 $0 $1,215 $9,313 $17 2.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.5 Sorbent Prep Equipment $4,617 $199 $959 $0 $0 $5,774 $503 $0 $942 $7,219 $13 2.6 Sorbent Storage & Feed $556 $0 $213 $0 $0 $769 $68 $0 $126 $963 $2 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $597 $501 $0 $0 $1,098 $102 $0 $180 $1,380 $3 SUBTOTAL 2. $13,673 $796 $3,473 $0 $0 $17,942 $1,572 $0 $2,927 $22,442 $41 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $22,860 $0 $7,384 $0 $0 $30,244 $2,643 $0 $4,933 $37,820 $69 3.2 Water Makeup & Pretreating $6,997 $0 $2,252 $0 $0 $9,249 $875 $0 $2,025 $12,149 $22 3.3 Other Feedwater Subsystems $6,998 $0 $2,958 $0 $0 $9,956 $892 $0 $1,627 $12,475 $23 3.4 Service Water Systems $1,372 $0 $746 $0 $0 $2,118 $199 $0 $463 $2,780 $5 3.5 Other Boiler Plant Systems $8,675 $0 $8,565 $0 $0 $17,240 $1,638 $0 $2,832 $21,709 $39 3.6 FO Supply Sys & Nat Gas $276 $0 $345 $0 $0 $621 $59 $0 $102 $781 $1 3.7 Waste Treatment Equipment $4,744 $0 $2,704 $0 $0 $7,448 $725 $0 $1,635 $9,808 $18 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,930 $0 $895 $0 $0 $3,825 $368 $0 $838 $5,031 $9 SUBTOTAL 3. $54,851 $0 $25,849 $0 $0 $80,700 $7,397 $0 $14,455 $102,552 $186 4 PC BOILER 4.1 PC Boiler & Accessories $195,902 $0 $109,921 $0 $0 $305,822 $29,763 $0 $33,559 $369,144 $671 4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4. $195,902 $0 $109,921 $0 $0 $305,822 $29,763 $0 $33,559 $369,144 $671 431

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-56 Case 12 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 5 FLUE GAS CLEANUP 5.1 Absorber Vessels & Accessories $70,185 $0 $15,109 $0 $0 $85,294 $8,132 $0 $9,343 $102,768 $187 5.2 Other FGD $3,663 $0 $4,150 $0 $0 $7,813 $758 $0 $857 $9,428 $17 5.3 Bag House & Accessories $20,190 $0 $12,813 $0 $0 $33,003 $3,180 $0 $3,618 $39,801 $72 5.4 Other Particulate Removal Materials $1,366 $0 $1,462 $0 $0 $2,828 $274 $0 $310 $3,413 $6 5.5 Gypsum Dewatering System $5,623 $0 $955 $0 $0 $6,579 $626 $0 $720 $7,925 $14 5.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5.9 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5. $101,027 $0 $34,490 $0 $0 $135,517 $12,971 $0 $14,849 $163,336 $297 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $207,807 $0 $63,097 $0 $0 $270,904 $25,901 $54,181 $70,197 $421,183 $766 5B.2 CO2 Compression & Drying $27,558 $0 $8,646 $0 $0 $36,204 $3,462 $0 $7,933 $47,599 $87 SUBTOTAL 5. $235,366 $0 $71,742 $0 $0 $307,108 $29,363 $54,181 $78,130 $468,782 $852 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $9,165 $0 $5,889 $0 $0 $15,054 $1,313 $0 $2,455 $18,822 $34 7.4 Stack $8,376 $0 $4,901 $0 $0 $13,277 $1,278 $0 $1,456 $16,011 $29 7.9 Duct & Stack Foundations $0 $961 $1,092 $0 $0 $2,052 $192 $0 $449 $2,693 $5 SUBTOTAL 7. $17,541 $961 $11,881 $0 $0 $30,383 $2,783 $0 $4,359 $37,526 $68 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $56,794 $0 $7,537 $0 $0 $64,331 $6,165 $0 $7,050 $77,546 $141 8.2 Turbine Plant Auxiliaries $382 $0 $819 $0 $0 $1,202 $118 $0 $132 $1,451 $3 8.3 Condenser & Auxiliaries $5,509 $0 $2,030 $0 $0 $7,540 $722 $0 $826 $9,088 $17 8.4 Steam Piping $21,469 $0 $10,585 $0 $0 $32,054 $2,693 $0 $5,212 $39,959 $73 8.9 TG Foundations $0 $1,200 $1,896 $0 $0 $3,096 $293 $0 $678 $4,067 $7 SUBTOTAL 8. $84,154 $1,200 $22,868 $0 $0 $108,222 $9,991 $0 $13,898 $132,111 $240 9 COOLING WATER SYSTEM 9.1 Cooling Towers $15,451 $0 $4,811 $0 $0 $20,262 $1,938 $0 $2,220 $24,419 $44 9.2 Circulating Water Pumps $3,219 $0 $248 $0 $0 $3,467 $293 $0 $376 $4,136 $8 9.3 Circ.Water System Auxiliaries $787 $0 $105 $0 $0 $892 $85 $0 $98 $1,075 $2 9.4 Circ.Water Piping $0 $6,243 $6,050 $0 $0 $12,293 $1,151 $0 $2,017 $15,460 $28 9.5 Make-up Water System $641 $0 $857 $0 $0 $1,498 $144 $0 $246 $1,888 $3 9.6 Component Cooling Water Sys $624 $0 $496 $0 $0 $1,120 $106 $0 $184 $1,410 $3 9.9 Circ.Water System Foundations & Structures $0 $3,698 $5,876 $0 $0 $9,575 $906 $0 $2,096 $12,577 $23 SUBTOTAL 9. $20,722 $9,941 $18,443 $0 $0 $49,106 $4,622 $0 $7,236 $60,965 $111 432

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-56 Case 12 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $706 $0 $2,175 $0 $0 $2,881 $283 $0 $316 $3,480 $6 10.7 Ash Transport & Feed Equipment $4,570 $0 $4,681 $0 $0 $9,250 $885 $0 $1,014 $11,149 $20 10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.9 Ash/Spent Sorbent Foundation $0 $168 $198 $0 $0 $365 $34 $0 $80 $479 $1 SUBTOTAL 10. $5,276 $168 $7,053 $0 $0 $12,497 $1,202 $0 $1,410 $15,108 $27 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $1,727 $0 $280 $0 $0 $2,008 $186 $0 $165 $2,358 $4 11.2 Station Service Equipment $4,957 $0 $1,629 $0 $0 $6,585 $616 $0 $540 $7,741 $14 11.3 Switchgear & Motor Control $5,699 $0 $969 $0 $0 $6,667 $618 $0 $729 $8,014 $15 11.4 Conduit & Cable Tray $0 $3,573 $12,354 $0 $0 $15,926 $1,542 $0 $2,620 $20,089 $37 11.5 Wire & Cable $0 $6,742 $13,014 $0 $0 $19,756 $1,664 $0 $3,213 $24,633 $45 11.6 Protective Equipment $261 $0 $888 $0 $0 $1,149 $112 $0 $126 $1,388 $3 11.7 Standby Equipment $1,360 $0 $31 $0 $0 $1,391 $128 $0 $152 $1,670 $3 11.8 Main Power Transformers $11,209 $0 $189 $0 $0 $11,398 $864 $0 $1,226 $13,488 $25 11.9 Electrical Foundations $0 $342 $837 $0 $0 $1,179 $113 $0 $258 $1,550 $3 SUBTOTAL 11. $25,213 $10,656 $30,191 $0 $0 $66,060 $5,843 $0 $9,029 $80,931 $147 12 INSTRUMENTATION & CONTROL 12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $516 $0 $309 $0 $0 $825 $78 $41 $142 $1,085 $2 12.7 Distributed Control System Equipment $5,207 $0 $910 $0 $0 $6,117 $567 $306 $699 $7,689 $14 12.8 Instrument Wiring & Tubing $2,823 $0 $5,599 $0 $0 $8,422 $718 $421 $1,434 $10,995 $20 12.9 Other I & C Equipment $1,471 $0 $3,339 $0 $0 $4,810 $466 $241 $552 $6,069 $11 SUBTOTAL 12. $10,017 $0 $10,157 $0 $0 $20,174 $1,829 $1,009 $2,826 $25,838 $47 433

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-56 Case 12 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $56 $1,116 $0 $0 $1,172 $116 $0 $258 $1,546 $3 13.2 Site Improvements $0 $1,853 $2,301 $0 $0 $4,154 $410 $0 $913 $5,477 $10 13.3 Site Facilities $3,321 $0 $3,275 $0 $0 $6,595 $650 $0 $1,449 $8,694 $16 SUBTOTAL 13. $3,321 $1,909 $6,692 $0 $0 $11,921 $1,176 $0 $2,620 $15,717 $29 14 BUILDINGS & STRUCTURES 14.1 Boiler Building $0 $8,851 $7,784 $0 $0 $16,635 $1,495 $0 $2,719 $20,849 $38 14.2 Turbine Building $0 $12,808 $11,937 $0 $0 $24,746 $2,230 $0 $4,046 $31,023 $56 14.3 Administration Building $0 $643 $680 $0 $0 $1,324 $120 $0 $217 $1,660 $3 14.4 Circulation Water Pumphouse $0 $176 $139 $0 $0 $315 $28 $0 $51 $395 $1 14.5 Water Treatment Buildings $0 $887 $809 $0 $0 $1,697 $153 $0 $277 $2,127 $4 14.6 Machine Shop $0 $430 $289 $0 $0 $719 $64 $0 $117 $901 $2 14.7 Warehouse $0 $292 $292 $0 $0 $584 $53 $0 $96 $732 $1 14.8 Other Buildings & Structures $0 $238 $203 $0 $0 $441 $40 $0 $72 $553 $1 14.9 Waste Treating Building & Str. $0 $456 $1,384 $0 $0 $1,840 $175 $0 $302 $2,317 $4 SUBTOTAL 14. $0 $24,782 $23,519 $0 $0 $48,301 $4,357 $0 $7,899 $60,557 $110 TOTAL COST $787,159 $55,813 $388,298 $0 $0 $1,231,270 $116,235 $55,190 $199,329 $1,602,023 $2,913 Owner's Costs Preproduction Costs 6 Months All Labor $10,579 $19 1 Month Maintenance Materials $1,541 $3 1 Month Non-fuel Consumables $1,637 $3 1 Month Waste Disposal $325 $1 25% of 1 Months Fuel Cost at 100% CF $1,971 $4 2% of TPC $32,040 $58 Total $48,094 $87 Inventory Capital 60 day supply of fuel and consumables at 100% CF $18,563 $34 0.5% of TPC (spare parts) $8,010 $15 Total $26,573 $48 Initial Cost for Catalyst and Chemicals $2,496 $5 Land $900 $2 Other Owner's Costs $240,304 $437 Financing Costs $43,255 $79 Total Overnight Costs (TOC) $1,963,644 $3,570 TASC Multiplier (IOU, high-risk, 35 year) 1.140 Total As-Spent Cost (TASC) $2,238,554 $4,070 434

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-57 Case 12 Initial and Annual Operating and Maintenance Costs INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 12 - 1x550 MWnet Super-Critical PC w/ CO2 Capture Heat Rate-net (Btu/kWh): 12,002 MWe-net: 550 Capacity Factor (%): 85 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant Skilled Operator 2.0 2.0 Operator 11.3 11.3 Foreman 1.0 1.0 Lab Tech's, etc. 2.0 2.0 TOTAL-O.J.'s 16.3 16.3 Annual Cost Annual Unit Cost

$ $/kW-net Annual Operating Labor Cost $6,444,907 $11.719 Maintenance Labor Cost $10,481,104 $19.058 Administrative & Support Labor $4,231,503 $7.694 Property Taxes and Insurance $32,040,467 $58.260 TOTAL FIXED OPERATING COSTS $53,197,981 $96.731 VARIABLE OPERATING COSTS

$/kWh-net Maintenance Material Cost $15,721,656 $0.00384 Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water(/1000 gallons) 0 7,324 1.08 $0 $2,457,806 $0.00060 Chemicals MU & WT Chem.(lbs) 0 35,452 0.17 $0 $1,903,577 $0.00046 Limestone (ton) 0 687 21.63 $0 $4,610,586 $0.00113 Carbon (Mercury Removal) lb 0 0 1.05 $0 $0 $0.00000 MEA Solvent (ton) 1,028 1.46 2,249.89 $2,312,307 $1,017,164 $0.00025 NaOH (tons) 73 7.26 433.68 $31,484 $976,789 $0.00024 H2SO4 (tons) 69 6.93 138.78 $9,615 $298,293 $0.00007 Corrosion Inhibitor 0 0 0.00 $142,156 $6,769 $0.00000 Activated Carbon (lb) 0 1,741 1.05 $0 $567,144 $0.00014 Ammonia (19% NH3) ton 0 102 129.80 $0 $4,090,854 $0.00100 Subtotal Chemicals $2,495,562 $13,471,176 $0.00329 Other Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 SCR Catalyst (m3) w/equip. 0.43 5,775.94 $0 $765,005 $0.00019 Emission Penalties 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $765,005 $0.00019 Waste Disposal Fly Ash (ton) 0 527 16.23 $0 $2,651,418 $0.00065 Bottom Ash (ton) 0 132 16.23 $0 $662,855 $0.00016 Subtotal-Waste Disposal $0 $3,314,273 $0.00081 By-products & Emissions Gypsum (tons) 0 1,062 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000 TOTAL VARIABLE OPERATING COSTS $2,495,562 $35,729,917 $0.00873 Fuel (ton) 0 6,790 38.18 $0 $80,434,598 $0.01964 435

Cost and Performance Baseline for Fossil Energy Plants 4.4 PC CASE

SUMMARY

The performance results of the four PC plant configurations are summarized in Exhibit 4-58.

Exhibit 4-58 Estimated Performance and Cost Results for Pulverized Coal Cases Pulverized Coal Boiler PC Subcritical PC Supercritical PERFORMANCE Case 9 Case 10 Case 11 Case 12 CO2 Capture 0% 90% 0% 90%

Gross Power Output (kWe) 582,600 672,700 580,400 662,800 Auxiliary Power Requirement (kWe) 32,580 122,740 30,410 112,830 Net Power Output (kWe) 550,020 549,960 549,990 549,970 Coal Flowrate (lb/hr) 437,378 614,994 409,528 565,820 Natural Gas Flowrate (lb/hr) N/A N/A N/A N/A HHV Thermal Input (kWth) 1,495,379 2,102,643 1,400,162 1,934,519 Net Plant HHV Efficiency (%) 36.8% 26.2% 39.3% 28.4%

Net Plant HHV Heat Rate (Btu/kWh) 9,277 13,046 8,687 12,002 Raw Water Withdrawal (gpm/MW net) 10.7 20.4 9.7 18.3 Process Water Discharge (gpm/MW net) 2.2 4.7 2.0 4.3 Raw Water Consumption (gpm/MW net) 8.5 15.7 7.7 14.1 CO2 Emissions (lb/MMBtu) 204 20 204 20 CO2 Emissions (lb/MWhgross) 1,783 217 1,675 203 CO2 Emissions (lb/MWhnet) 1,888 266 1,768 244 SO2 Emissions (lb/MMBtu) 0.0858 0.0017 0.0858 0.0016 SO2 Emissions (lb/MWhgross) 0.7515 0.0176 0.7063 0.0162 NOx Emissions (lb/MMBtu) 0.070 0.070 0.070 0.070 NOx Emissions (lb/MWhgross) 0.613 0.747 0.576 0.697 PM Emissions (lb/MMBtu) 0.0130 0.0130 0.0130 0.0130 PM Emissions (lb/MWhgross) 0.114 0.139 0.107 0.129 Hg Emissions (lb/TBtu) 1.143 1.143 1.143 1.143 Hg Emissions (lb/MWhgross) 1.00E-05 1.22E-05 9.41E-06 1.14E-05 COST Total Plant Cost (2007$/kW) 1,622 2,942 1,647 2,913 Total Overnight Cost (2007$/kW) 1,996 3,610 2,024 3,570 Bare Erected Cost 1,317 2,255 1,345 2,239 Home Office Expenses 124 213 127 211 Project Contingency 182 369 176 362 Process Contingency 0 105 0 100 Owner's Costs 374 667 377 657 Total Overnight Cost (2007$ x 1,000) 1,098,124 1,985,432 1,113,445 1,963,644 Total As Spent Capital (2007$/kW) 2,264 4,115 2,296 4,070 COE (mills/kWh, 2007$)1,2 59.4 109.6 58.9 106.5 CO2 TS&M Costs 0.0 5.8 0.0 5.6 Fuel Costs 15.2 21.3 14.2 19.6 Variable Costs 5.1 9.2 5.0 8.7 Fixed Costs 7.8 13.1 8.0 13.0 Capital Costs 31.2 60.2 31.7 59.6 LCOE (mills/kWh, 2007$)1,2 75.3 139.0 74.7 135.2 1

Capacity factor is 85% for all PC cases 2

COE and LCOE are defined in Section 2.7.

436

Cost and Performance Baseline for Fossil Energy Plants The components of TOC and overall TASC are shown for each PC case in Exhibit 4-59.

The following observations about TOC can be made:

The TOC of the non-capture SC PC case is only incrementally greater than non-capture subcritical PC (less than 2 percent). The TOC of subcritical PC with CO2 capture is approximately 1 percent greater than SC PC with CO2 capture.

The TOC penalty for adding CO2 capture in the subcritical case is 81 percent and is 76 percent in the SC case. The Econamine cost includes a process contingency of approximately $100/kW in both the subcritical and SC cases. Eliminating the process contingency results in a CO2 capture cost penalty of 76 and 71 percent for the subcritical and SC PC cases, respectively. In addition to the high cost of the Econamine process, there is a significant increase in the cost of the cooling towers and CWPs in the CO2 capture cases because of the larger cooling water demand discussed previously. In addition, the gross output of the two PC plants increases by 90 MW (subcritical) and 82 MW (SC) to maintain the net output at 550 MW. The increased gross output results in higher coal flow rate and consequent higher costs for all cost accounts in the estimate.

Exhibit 4-59 Plant Capital Cost for PC Cases 6,000 TASC Owner's Cost 5,000 Process Contingency 4,115 TOC or TASC, $/kW (2007$)

4,070 Project Contingency 4,000 3,610 3,570 Home Office Expense Bare Erected Cost 3,000 2,264 2,296 1,996 2,024 2,000 1,000 0

TOC TASC TOC TASC TOC TASC TOC TASC Subcritical PC Subcritical PC w/ CO2 Supercritical PC Supercritical PC w/ CO2 Capture Capture 437

Cost and Performance Baseline for Fossil Energy Plants The COE is shown for the four PC cases in Exhibit 4-60. The following observations can be made:

Capital costs represent the largest fraction of COE in all cases, but particularly so in the CO2 capture cases. Fuel cost is the second largest component of COE, and capital charges and fuel costs combined represent 74 to 78 percent of the total in all cases.

In the non-capture case the slight increase in capital cost in the SC case is more than offset by the efficiency gain so that the COE for SC PC is 1 percent less than subcritical despite having a nearly 2 percent higher TOC.

In the CO2 capture case, the cost differential between subcritical and SC PC is negligible (about 1 percent), but the SC PC has a 3 percent lower COE because of the higher efficiency.

Exhibit 4-60 COE for PC Cases 140 CO2 TS&M Costs Fuel Costs 120 Variable Costs Fixed Costs 5.9 Capital Costs 5.7 100 21.3 19.6 COE, mills/kWh (2007$)

80 9.2 8.7 13.1 13.0 60 15.2 14.2 40 5.1 5.0 7.8 8.0 60.2 59.6 20 31.2 31.7 0

Subcritical PC Subcritical PC w/ CO2 Capture Supercritical PC Supercritical PC w/ CO2 Capture 438

Cost and Performance Baseline for Fossil Energy Plants The sensitivity of COE to capacity factor is shown in Exhibit 4-61. Implicit in the curves is the assumption that a capacity factor of greater than 85 percent can be achieved without the expenditure of additional capital. The subcritical and SC cases with no CO2 capture are nearly identical making it difficult to distinguish between the two lines. The COE increases more rapidly at low CF because the relatively high capital component is spread over fewer kilowatt-hours of generation.

The sensitivity of COE to coal price is shown in Exhibit 4-62. As in the IGCC cases, the COE in the PC cases is relatively insensitive to coal price.

As presented in Section 2.4 the first year cost of CO2 avoided was calculated, and the results for the PC CO2 capture cases are shown in Exhibit 4-63.

The cost of CO2 avoided using the analogous non-capture technology as the reference is nearly identical for the subcritical and SC PC cases. Using SC PC as the non-capture reference case increases the avoided cost of subcritical PC with CO2 capture because subcritical PC has the higher COE of the two capture technologies.

Exhibit 4-61 Sensitivity of COE to Capacity Factor for PC Cases 300 Subcritical w/CO2 Capture Supercritical w/CO2 Capture 250 Subcritical No Capture Supercritical No Capture 200 COE, mills/kWh (2007$)

150 100 Coal price = $1.64/MMBtu 50 0

0 10 20 30 40 50 60 70 80 90 100 Capacity Factor, %

439

Cost and Performance Baseline for Fossil Energy Plants Exhibit 4-62 Sensitivity of COE to Coal Price for PC Cases 140 120 100 COE, mills/kWh (2007$)

80 60 Subcritical w/CO2 Capture 40 Supercritical w/CO2 Capture Capacity Factor = 85%

Subcritical No Capture 20 Supercritical No Capture 0

0 0.5 1 1.5 2 2.5 3 3.5 4 Fuel Price, $/MMBtu Exhibit 4-63 First Year Cost of CO2 Avoided in PC Cases 100 Avoided Cost (Analogous Technology w/o Capture Reference) 90 Avoided Cost (SC PC w/o Capture Reference) 80 75 68 69 69 70 60 CO2 Avoided Cost, $/tonne (2007$)

50 40 30 20 10 0

Subcritical PC Supercritical PC 440

Cost and Performance Baseline for Fossil Energy Plants The following observations can be made regarding plant performance with reference to Exhibit 4-58:

The efficiency of the non-capture, SC PC plant is 2.5 absolute percentage points higher than the equivalent subcritical PC plant (39.3 percent compared to 36.8 percent). The efficiencies are comparable to those reported in other studies once steam cycle conditions are considered. For example, in an EPA study [75] comparing PC and IGCC plant configurations the subcritical PC plant using bituminous coal had an efficiency of 35.9 percent with a steam cycle of 16.5 MPa/538°C/538°C (2,400 psig/1,000°F/1,000°F). The higher steam cycle temperature in this study 566°C/566°C (1,050°F/1,050°F) is one factor that results in a higher net efficiency. The same study reported a SC plant efficiency of 38.3 percent with a steam cycle of 24.1 MPa/566°C/566°C (3,500 psig/1,050°F/1,050°F). Again, the more aggressive steam conditions in this study, 593°C/593°C (1,100°F/1,100°F) are one factor resulting in a higher net efficiency.

Similar results from an EPRI study using Illinois No. 6 coal were reported as follows:[ 76]

o Subcritical PC efficiency of 35.7 percent with a steam cycle of 16.5 MPa/538°C/538°C (2,400 psig/1,000°F/1,000°F).

o SC PC efficiency of 38.3 percent with a steam cycle of 24.8 MPa/593°C/593°C (3,600 psig/1,100°F/1,100°F).

The addition of CO2 capture to the two PC cases results in a relative efficiency penalty of 28.9 percent in the subcritical PC case and 27.6 percent in the SC PC case. The efficiency is negatively impacted by the large auxiliary loads of the Econamine process and CO2 compression, as well as the large increase in cooling water requirement, which increases the CWP and cooling tower fan auxiliary loads. The auxiliary load increases by 90 MW in the subcritical PC case and by 82 MW in the SC PC case.

NOx, PM, and Hg emissions are the same for all four PC cases on a heat input basis because of the environmental target assumptions of fixed removal efficiencies for each case (86 percent SCR efficiency, 99.8 percent baghouse efficiency and 90 percent co-benefit capture). The emissions on a mass basis or normalized by gross output are higher for subcritical cases than SC cases and are higher for CO2 capture cases than non-capture cases because of the higher efficiencies of SC PC and non-capture PC cases.

SO2 emissions are likewise constant on a heat input basis for the non-capture cases, but the Econamine process polishing scrubber and absorber vessel result in negligible SO2 emissions in CO2 capture cases. The SO2 emissions for subcritical PC are higher than SC on a mass basis and when normalized by gross output because of the lower efficiency.

Uncontrolled CO2 emissions on a mass basis are greater for subcritical PC compared to SC because of the lower efficiency. The capture cases result in a 90 percent reduction of CO2 for both subcritical and SC PC.

Raw water consumption for all cases is dominated by cooling tower makeup requirements, which accounts for about 77 percent of raw water in non-capture cases and 81 percent of raw water in CO2 capture cases. The amount of raw water consumption in 441

Cost and Performance Baseline for Fossil Energy Plants the CO2 capture cases is greatly increased by the cooling water requirements of the Econamine process. Cooling water is required to:

o Reduce the FG temperature from 57°C (135°F) (FGD exit temperature) to 32°C (89°F) (Econamine absorber operating temperature), which also requires condensing water from the FG that comes saturated from the FGD unit.

o Remove the heat input by the stripping steam to cool the solvent o Remove the heat input from the auxiliary electric loads o Remove heat in the CO2 compressor intercoolers The normalized water withdrawal, process discharge and raw water consumption are shown in Exhibit 4-64 for each of the PC cases. In the CO2 capture cases, additional water is recovered from the FG as it is cooled to the absorber temperature of 32°C (89°F). The condensate is treated and also used as cooling tower makeup.

Exhibit 4-64 Raw Water Withdrawal and Consumption in PC Cases 25 Raw Water Withdrawal Process Discharge Raw Water Consumption 20.4 20 18.3 15.7 Water, gpm/MWnet 14.1 15 10.7 9.7 10 8.5 7.7 5

0 Subcritical Subcritical PC w/ CO2 Capture Supercritical PC Supercritical PC w/ CO2 PC Capture 442

Cost and Performance Baseline for Fossil Energy Plants

5. NATURAL GAS COMBINED CYCLE PLANTS Two NGCC power plant configurations were evaluated and are presented in this section. Each design is based on a market-ready technology that is assumed to be commercially available in time to support start up. Each design consists of two advanced F class CTGs, two HRSGs and one STG in a multi-shaft 2x2x1 configuration.

The NGCC cases are evaluated with and without CO2 capture on a common thermal input basis.

The NGCC designs that include CDR have a smaller plant net output resulting from the additional CDR facility auxiliary loads. Like in the IGCC cases, the sizes of the NGCC designs were determined by the output of the commercially available CT. Hence, evaluation of the NGCC designs on a common net output basis was not possible.

The Rankine cycle portion of both designs uses a single reheat 16.5 MPa/566°C/566°C (2400 psig/1050°F/1050°F) steam cycle. A more aggressive steam cycle was considered but not chosen because there are very few HRSGs in operation that would support such conditions [64].

5.1 NGCC COMMON PROCESS AREAS The two NGCC cases are nearly identical in configuration with the exception that Case 14 includes CO2 capture while Case 13 does not. The process areas that are common to the two plant configurations are presented in this section.

5.1.1 Natural Gas Supply System It was assumed that a natural gas main with adequate capacity is in close proximity (within 16 km [10 miles]) to the site fence line and that a suitable right of way is available to install a branch line to the site. For the purposes of this study it was also assumed that the gas will be delivered to the plant custody transfer point at 3.0 MPa (435 psig) and 38°C (100ºF), which matches the advanced F Class fuel system requirements. Hence, neither a pressure reducing station with gas preheating (to prevent moisture and hydrocarbon condensation), nor a fuel booster compressor are required.

A new gas metering station is assumed to be added on the site, adjacent to the new CT. The meter may be of the rate-of-flow type, with input to the plant computer for summing and recording, or may be of the positive displacement type. In either case, a complete time-line record of gas consumption rates and cumulative consumption is provided.

5.1.2 Combustion Turbine The combined cycle plant is based on two CTGs. The CTG is representative of the advanced F Class turbines with an ISO base rating of 184,400 kW when firing natural gas [ 77]. This machine is an axial flow, single spool, constant speed unit, with variable IGVs, and dry LNB combustion system.

Each CTG is provided with inlet air filtration systems; inlet silencers; lube and control oil systems including cooling; electric motor starting systems; acoustical enclosures including heating and ventilation; control systems including supervisory, fire protection, and fuel systems.

No back up fuel was envisioned for this project.

443

Cost and Performance Baseline for Fossil Energy Plants The CTG is typically supplied in several fully shop-fabricated modules, complete with all mechanical, electrical, and control systems required for CTG operation. Site CTG installation involves module interconnection and linking CTG modules to the plant systems. The CTG package scope of supply for combined cycle application, while project specific, does not vary much from project-to-project. A typical scope of supply is presented in Exhibit 5-1.

Exhibit 5-1 Combustion Turbine Typical Scope of Supply System System Scope ENGINE Coupling to Generator, Dry Chemical Exhaust Bearing Fire Protection System, ASSEMBLY Insulation Blankets, Platforms, Stairs and Ladders Engine Assembly Variable IGV System, Compressor, Bleed System, Purge Air System, Bearing Seal with Bedplate Air System, Combustors, Dual Fuel Nozzles, Turbine Rotor Cooler Walk-in acoustical HVAC, Lighting, and LP CO2 Fire Protection System enclosure MECHANICAL HVAC, Lighting, Air Compressor for Pneumatic System, LP CO2 Fire Protection PACKAGE System Lube Oil Reservoir, Accumulators, 2x100% AC Driven Oil Pumps, DC Emergency Lubricating Oil Oil Pump with Starter, 2x100% Oil Coolers, Duplex Oil Filter, Oil Temperature and System and Pressure Control Valves, Oil Vapor Exhaust Fans and Demister, Oil Heaters, Oil Control Oil System Interconnect Piping (SS and CS), Oil System Instrumentation, Oil for Flushing and First Filling HVAC, Lighting, AC and DC Motor Control Centers, Generator Voltage Regulating Cabinet, Generator Protective Relay Cabinet, DC Distribution Panel, Battery Charger, Digital Control System with Local Control Panel (all control and monitoring functions as well as data logger and sequence of events recorder),

ELECTRICAL Control System Valves and Instrumentation Communication link for interface with PACKAGE plant DCS Supervisory System, Bentley Nevada Vibration Monitoring System, LP CO2 Fire Protection System, Cable Tray and Conduit Provisions for Performance Testing including Test Ports, Thermowells, Instrumentation and DCS interface cards Inlet Duct Trash Screens, Inlet Duct and Silencers, Self Cleaning Filters, Hoist INLET AND System For Filter Maintenance, Evaporative Cooler System, Exhaust Duct EXHAUST Expansion Joint, Exhaust Silencers Inlet and Exhaust Flow, Pressure and SYSTEMS Temperature Ports and Instrumentation FUEL SYSTEMS Gas Valves Including Vent, Throttle and Trip Valves, Gas Filter/Separator, Gas N. Gas System Supply Instruments and Instrument Panel STARTING Enclosure, Starting Motor or Static Start System, Turning Gear and Clutch SYSTEM Assembly, Starting Clutch, Torque Converter Static or Rotating Exciter (Excitation transformer to be included for a static system), Line Termination Enclosure with CTs, VTs, Surge Arrestors, and Surge Capacitors, Neutral Cubicle with CT, Neutral Tie Bus, Grounding Transformer, and GENERATOR Secondary Resistor, Generator Gas Dryer, Seal Oil System (including Defoaming Tank, Reservoir, Seal Oil Pump, Emergency Seal Oil Pump, Vapor Extractor, and Oil Mist Eliminator), Generator Auxiliaries Control Enclosure, Generator Breaker, Iso-Phase bus connecting generator and breaker, Grounding System Connectors Totally Enclosed Water-to-Air-Cooled (TEWAC) System (including circulation system, interconnecting piping and controls), or Hydrogen Cooling System Generator Cooling (including H2 to Glycol and Glycol to Air heat exchangers, liquid level detector circulation system, interconnecting piping and controls)

Interconnecting Pipe, Wire, Tubing and Cable Instrument Air System Including Air MISCELLANEOUS Dryer On Line and Off Line Water Wash System LP CO2 Storage Tank Drain System Drain Tanks Coupling, Coupling Cover and Associated Hardware 444

Cost and Performance Baseline for Fossil Energy Plants The generators would typically be provided with the CT package. The generators are assumed to be 24 kV, 3-phase, 60 hertz, constructed to meet American National Standards Institute (ANSI) and National Electrical Manufacturers Association (NEMA) standards for turbine-driven synchronous generators. The generator is TEWAC, complete with excitation system, cooling, and protective relaying.

5.1.3 Heat Recovery Steam Generator The HRSG is configured with HP, IP, and LP steam drums, and superheater, reheater, and economizer sections. The HP drum is supplied with FW by the HP boiler feed pump to generate HP steam, which passes to the superheater section for heating to 566°C (1050°F). The IP drum is supplied with FW by the IP boiler feed pump. The IP steam from the drum is superheated to 566°C (1050°F) and mixed with hot reheat steam from the reheat section at 566°C (1050ºF).

The combined flows are admitted into the IP section of the steam turbine. The LP drum provides steam LP turbine.

The economizer sections heat condensate and FW (in separate tube bundles). The HRSG tubes are typically comprised of bare surface and/or finned tubing or pipe material. The high-temperature portions are type P91 or P22 ferritic alloy material; the low-temperature portions

(< 399°C [750°F]) are CS. Each HRSG exhausts directly to the stack, which is fabricated from CS plate materials and lined with Type 409 SS. The stack for the NGCC cases is assumed to be 46 m (150 ft) high, and the cost is included in the HRSG account.

5.1.4 NOx Control System This reference plant is designed to achieve 2.5 ppmvd NOx emissions (expressed as NO2 and referenced to 15 percent O2). Two measures are taken to reduce the NOx. The first is a DLN burner in the CTG. The DLN burners are a low NOx design and reduce the emissions to about 25 ppmvd (referenced to 15 percent O2) [ 78].

The second measure taken to reduce the NOx emissions was the installation of a SCR system.

SCR uses ammonia and a catalyst to reduce NOx to N2 and H2O. The SCR system consists of reactor, and ammonia supply and storage system. The SCR system is designed for 90 percent reduction while firing natural gas. This along with the dry LNB achieves the emission limit of 2.5 ppmvd (referenced to 15 percent O2).

Operation Description - The SCR reactor is located in the FG path inside the HRSG between the HP and IP sections. The SCR reactor is equipped with one catalyst layer consisting of catalyst modules stacked in line on a supporting structural frame. The SCR reactor has space for installation of an additional layer. Ammonia is injected into the gas immediately prior to entering the SCR reactor. The ammonia injection grid is arranged into several sections, and consists of multiple pipes with nozzles. Ammonia flow rate into each injection grid section is controlled taking into account imbalances in the FG flow distribution across the HRSG. The catalyst contained in the reactor enhances the reaction between the ammonia and the NOx in the gas. The catalyst consists of various active materials such as titanium dioxide, vanadium pentoxide, and tungsten trioxide. The optimum inlet FG temperature range for the catalyst is 260°C (500°F) to 343°C (650°F).

The ammonia storage and injection system consists of the unloading facilities, bulk storage tank, vaporizers, and dilution air skid.

445

Cost and Performance Baseline for Fossil Energy Plants 5.1.5 Carbon Dioxide Recovery Facility A CDR facility is used in Case 14 to remove 90 percent of the CO2 in the FG exiting the HRSG, purify it, and compress it to a SC condition. It is assumed that all of the carbon in the natural gas is converted to CO2. The CDR is comprised of FG supply, CO2 absorption, solvent stripping and reclaiming, and CO2 compression and drying.

The CO2 absorption/stripping/solvent reclaim process for Case 14 is based on the Fluor Econamine FG PlusSM technology as previously described in Section 4.1.7 with the exception that no SO2 polishing step is required in the NGCC case. If the pipeline natural gas used in this study contained the maximum amount of sulfur allowed per EPA specifications (0.6 gr S/100 scf), the FG would contain 0.4 ppmv of SO2, which is well below the limit where a polishing scrubber would be required (10 ppmv). A description of the basic process steps is repeated here for completeness with minor modifications to reflect application in an NGCC system as opposed to PC.

FG Cooling and Supply The function of the FG cooling and supply system is to transport FG from the HRSG to the CO2 absorption tower, and condition FG pressure, temperature and moisture content so it meets the requirements of the Econamine process. Temperature and hence moisture content of the FG exiting the HRSG is reduced in the Direct Contact FG Cooler, where FG is cooled using cooling water.

The water condensed from the FG is collected in the bottom of the Direct Contact FG Cooler section and re-circulated to the top of the Direct Contact FG Cooler section via the FG Circulation Water Cooler, which rejects heat to the plant CWS. Level in the Direct Contact FG Cooler is controlled by directing the excess water to the cooling water return line. In the Direct Contact FG Cooler, FG is cooled beyond the CO2 absorption process requirements to 33°C (91°F) to account for the subsequent FG temperature increase of 14°C (25°F) in the FG blower.

Downstream from the Direct Contact FG Cooler FG pressure is boosted in the FG blowers by approximately 0.01 MPa (2 psi) to overcome pressure drop in the CO2 absorber tower.

Circulating Water System Cooling water is provided from the NGCC plant CWS and returned to the NGCC plant cooling tower. The CDR facility requires a significant amount of cooling water for FG cooling, water wash cooling, absorber intercooling, reflux condenser duty, reclaimer cooling, the lean solvent cooler, and CO2 compression interstage cooling. The cooling water requirements for the CDR facility in the NGCC capture case is about 594,308 lpm (157,000 gpm), which greatly exceeds the NGCC plant cooling water requirement of about 200,626 lpm (53,000 gpm).

CO2 Absorption The cooled FG enters the bottom of the CO2 Absorber and flows up through the tower countercurrent to a stream of lean MEA-based solvent called Econamine. Approximately 90 percent of the CO2 in the feed gas is absorbed into the lean solvent, and the rest leaves the top of the absorber section and flows into the water wash section of the tower. The lean solvent enters the top of the absorber, absorbs the CO2 from the flue gas and leaves the bottom of the absorber with the absorbed CO2.

446

Cost and Performance Baseline for Fossil Energy Plants Water Wash Section The purpose of the Water Wash section is to minimize solvent losses due to mechanical entrainment and evaporation. The FG from the top of the CO2 Absorption section is contacted with a re-circulating stream of water for the removal of most of the lean solvent. The scrubbed gases, along with unrecovered solvent, exit the top of the wash section for discharge to the atmosphere via the vent stack. The water stream from the bottom of the wash section is collected on a chimney tray. A portion of the water collected on the chimney tray spills over to the absorber section as water makeup for the amine with the remainder pumped via the Wash Water Pump and cooled by the Wash Water Cooler, and recirculated to the top of the CO2 Absorber.

The wash water level is maintained by water makeup from the Wash Water Makeup Pump.

Rich/Lean Amine Heat Exchange System The rich solvent from the bottom of the CO2 Absorber is preheated by the lean solvent from the Solvent Stripper in the Rich Lean Solvent Exchanger. The heated rich solvent is routed to the Solvent Stripper for removal of the absorbed CO2. The stripped solvent from the bottom of the Solvent Stripper is pumped via the Hot Lean Solvent Pumps through the Rich Lean Exchanger to the Solvent Surge Tank. Prior to entering the Solvent Surge Tank, a slipstream of the lean solvent is pumped via the Solvent Filter Feed Pump through the Solvent Filter Package to prevent buildup of contaminants in the solution. From the Solvent Surge Tank the lean solvent is pumped via the Warm Lean Solvent Pumps to the Lean Solvent Cooler for further cooling, after which the cooled lean solvent is returned to the CO2 Absorber, completing the circulating solvent circuit.

Solvent Stripper The purpose of the Solvent Stripper is to separate the CO2 from the rich solvent feed exiting the bottom of the CO2 Absorber. The rich solvent is collected on a chimney tray below the bottom packed section of the Solvent Stripper and routed to the Solvent Stripper Reboilers where the rich solvent is heated by steam, stripping the CO2 from the solution. Steam is provided from the crossover pipe between the IP and LP sections of the steam turbine at about 0.51 MPa (73.5 psia) and 152°C (306°F). The hot wet vapor from the top of the stripper containing CO2, steam, and solvent vapor, is partially condensed in the Solvent Stripper Condenser by cross exchanging the hot wet vapor with cooling water. The partially condensed stream then flows to the Solvent Stripper Reflux Drum where the vapor and liquid are separated. The uncondensed CO2-rich gas is then delivered to the CO2 product compressor. The condensed liquid from the Solvent Stripper Reflux Drum is pumped via the Solvent Stripper Reflux Pumps where a portion of condensed overhead liquid is used as make-up water for the Water Wash section of the CO2 Absorber. The rest of the pumped liquid is routed back to the Solvent Stripper as reflux, which aids in limiting the amount of solvent vapors entering the stripper overhead system.

Solvent Stripper Reclaimer A small slipstream of the lean solvent from the Solvent Stripper bottoms is fed to the Solvent Stripper Reclaimer for the removal of high-boiling nonvolatile impurities (HSS), volatile acids, and iron products from the circulating solvent solution. The solvent bound in the HSS is recovered by reaction with caustic and heating with steam. The solvent reclaimer system reduces corrosion, foaming and fouling in the solvent system. The reclaimed solvent is returned 447

Cost and Performance Baseline for Fossil Energy Plants to the Solvent Stripper and the spent solvent is pumped via the Solvent Reclaimer Drain Pump to the Solvent Reclaimer Drain Tank.

Steam Condensate Steam condensate from the Solvent Stripper Reclaimer accumulates in the Solvent Reclaimer Condensate Drum and level controlled to the Solvent Reboiler Condensate Drum. Steam condensate from the Solvent Stripper Reboilers is also collected in the Solvent Reboiler Condensate Drum and returned to the steam cycle just downstream of the deaerator via the Solvent Reboiler Condensate Pumps.

Corrosion Inhibitor System A proprietary corrosion inhibitor is continuously injected into the CO2 Absorber rich solvent bottoms outlet line, the Solvent Stripper bottoms outlet line and the Solvent Stripper top tray.

This constant injection is to help control the rate of corrosion throughout the CO2 recovery plant system.

Gas Compression and Drying System In the compression section, the CO2 is compressed to 15.3 MPa (2,215 psia) by a six-stage centrifugal compressor. The discharge pressures of the stages were balanced to give reasonable power distribution and discharge temperatures across the various stages as shown in Exhibit 5-2.

Power consumption for this large compressor was estimated assuming a polytropic efficiency of 86 percent and a mechanical efficiency of 98 percent for all stages. During compression to 15.3 MPa (2,215 psia) in the multiple-stage, intercooled compressor, the CO2 stream is dehydrated to a dewpoint of -40ºC (-40°F) with triethylene glycol. The virtually moisture-free SC CO2 stream is delivered to the plant battery limit as sequestration ready. CO2 TS&M costs were estimated and included in LCOE and COE using the methodology described in Section 2.7.

5.1.6 Steam Turbine The steam turbine consists of an HP section, an IP section, and one double-flow LP section, all connected to the generator by a common shaft. The HP and IP sections are contained in a single span, opposed-flow casing, with the double-flow LP section in a separate casing.

Main steam from the boiler passes through the stop valves and control valves and enters the turbine at 16.5 MPa/566°C (2400 psig/1050°F). The steam initially enters the turbine near the middle of the HP span, flows through the turbine, and returns to the HRSG for reheating. The reheat steam flows through the reheat stop valves and intercept valves and enters the IP section at 2.5 MPa/566°C (360 psia/1050°F). After passing through the IP section, the steam enters a cross-over pipe, which transports the steam to the LP section. A branch line equipped with combined stop/intercept valves conveys LP steam from the HRSG LP drum to a tie-in at the cross-over line. The steam divides into two paths and flows through the LP sections exhausting downward into the condenser.

448

Cost and Performance Baseline for Fossil Energy Plants Exhibit 5-2 CO2 Compressor Interstage Pressures Outlet Pressure, Stage MPa (psia) 1 0.36 (52) 2 0.78 (113) 3 1.71 (248) 4 3.76 (545) 5 8.27 (1,200) 6 15.3 (2,215)

Turbine bearings are lubricated by a CL, water-cooled pressurized oil system. Turbine shafts are sealed against air in-leakage or steam blowout using a modern positive pressure variable clearance shaft sealing design arrangement connected to a LP steam seal system. The generator is a hydrogen-cooled synchronous type, generating power at 24 kV. A static, transformer type exciter is provided. The generator is cooled with a hydrogen gas recirculation system using fans mounted on the generator rotor shaft. The STG is controlled by a triple-redundant microprocessor-based electro-hydraulic control system. The system provides digital control of the unit in accordance with programmed control algorithms, color monitor/operator interfacing, and datalink interfaces to the balance-of-plant DCS, and incorporates on-line repair capability.

5.1.7 Water and Steam Systems Condensate The function of the condensate system is to pump condensate from the condenser hotwell to the deaerator, through the gland steam condenser; and the low-temperature economizer section in the HRSG.

The system consists of one main condenser; two 50 percent capacity, motor-driven vertical multistage condensate pumps (total of two pumps for the plant); one gland steam condenser; condenser air removal vacuum pumps, condensate polisher, and a low-temperature tube bundle in the HRSG.

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.

Feedwater The function of the FW system is to pump the various FW streams from the deaerator storage tank in the HRSG to the respective steam drums. One 100 percent capacity motor-driven feed pump is provided per each HRSG (total of two pumps for the plant). The FW pumps are equipped with an interstage takeoff to provide IP and LP FW. Each pump is provided with inlet and outlet isolation valves, outlet check valves, and individual minimum flow recirculation lines 449

Cost and Performance Baseline for Fossil Energy Plants discharging back to the deaerator storage tank. The recirculation flow is controlled by pneumatic flow control valves. 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.

Steam System The steam system is comprised of main, reheat, intermediate, and LP steam systems. The function of the main steam system is to convey main steam from the HRSG superheater outlet to the HP turbine stop valves. The function of the reheat system is to convey steam from the HP turbine exhaust to the HRSG reheater and from the HRSG reheater outlet to the turbine reheat stop valves.

Main steam exits the HRSG superheater through a motor-operated stop/check valve and a motor-operated gate valve, and is routed to the HP turbine.

Cold reheat steam exits the HP turbine, and flows through a motor-operated isolation gate valve to the HRSG reheater. Hot reheat steam exits at the HRSG reheater through a motor-operated gate valve and is routed to the IP turbines.

Circulating Water System The function of the CWS is to supply cooling water to condense the main turbine exhaust steam, for the auxiliary cooling system and for the CDR facility in Case 14. The system consists of two 50 percent capacity vertical CWPs (total of two pumps for the plant), a mechanical draft evaporative cooling tower, and 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 the condenser can be removed from service for cleaning or plugging tubes. This can be done during normal operation at reduced load.

The auxiliary cooling system is a CL system. Plate and frame heat exchangers with circulating water as the cooling medium are provided. The system provides cooling water to the following systems:

1. CTG lube oil coolers

2. CTG air coolers

3. STG lube oil coolers

4. STG hydrogen coolers

5. Boiler feed water pumps

6. Air compressors

7. Generator seal oil coolers (as applicable)

8. Sample room chillers

9. Blowdown coolers

10. Condensate extraction pump-motor coolers The CDR system in Case 14 requires a substantial amount of cooling water that is provided by the NGCC plant CWS. The additional cooling load imposed by the CDR is reflected in the significantly larger CWPs and cooling tower in that case.

450

Cost and Performance Baseline for Fossil Energy Plants Buildings and Structures Structures assumed for NGCC cases can be summarized as follows:

1. Generation Building housing the STG

2. CWP House

3. Administration / Office / Control Room / Maintenance Building

4. Water Treatment Building

5. Fire Water Pump House 5.1.8 Accessory Electric Plant The accessory electric plant consists of all switchgear and control equipment, generator equipment, station service equipment, conduit and cable trays, wire, and cable. It also includes the main transformer, required foundations, and standby equipment.

5.1.9 Instrumentation and Control An integrated plant-wide DCS is provided. The DCS is a redundant microprocessor-based, functionally distributed system. The control room houses an array of video monitors and keyboard units. The monitor/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 procedures with operator selection of modular automation routines available.

451

Cost and Performance Baseline for Fossil Energy Plants 5.2 NGCC CASES This section contains an evaluation of plant designs for Cases 13 and 14. These two cases are similar in design and are based on an NGCC plant with a constant thermal input. Both plants use a single reheat 16.5 MPa/566°C/566°C (2400 psig/1050°F/1050°F) cycle. The only difference between the two plants is that Case 14 includes CO2 capture while Case 13 does not.

The balance of Section 5.2 is organized as follows:

Process and System Description provides an overview of the technology operation as applied to Case 13. The systems that are common to all NGCC cases were covered in Section 5.1 and only features that are unique to Case 13 are discussed further in this section.

Key Assumptions is a summary of study and modeling assumptions relevant to Cases 13 and 14.

Sparing Philosophy is provided for both Cases 13 and 14.

Performance Results provides the main modeling results from Case 13, including the performance summary, environmental performance, carbon balance, water balance, mass and energy balance diagrams, and energy balance table.

Equipment List provides an itemized list of major equipment for Case 13 with account codes that correspond to the cost accounts in the Cost Estimates section.

Cost Estimates provides a summary of capital and operating costs for Case 13.

Process and System Description, Performance Results, Equipment List and Cost Estimates are reported for Case 14.

5.2.1 Process Description In this section the NGCC process without CO2 capture is described. The system description follows the BFD in Exhibit 5-3 and stream numbers reference the same exhibit. The tables in Exhibit 5-4 provide process data for the numbered streams in the BFD. The BFD shows only one of the two CT/HRSG combinations, but the flow rates in the stream table are the total for two systems.

Ambient air (stream 1) and natural gas (stream 2) are combined in the dry LNB, which is operated to control the rotor inlet temperature at 1371°C (2500°F). The FG exits the turbine at 629°C (1163°F) (stream 3) and passes into the HRSG. The HRSG generates both the main steam and reheat steam for the steam turbine. FG exits the HRSG at 106°C (222°F) and passes to the plant stack 452

Cost and Performance Baseline for Fossil Energy Plants Exhibit 5-3 Case 13 Block Flow Diagram, NGCC without CO2 Capture 453

Cost and Performance Baseline for Fossil Energy Plants Exhibit 5-4 Case 13 Stream Table, NGCC without CO2 Capture 1 2 3 4 5 6 V-L Mole Fraction Ar 0.0092 0.0000 0.0089 0.0089 0.0000 0.0000 CH4 0.0000 0.9310 0.0000 0.0000 0.0000 0.0000 C2H6 0.0000 0.0320 0.0000 0.0000 0.0000 0.0000 C3H8 0.0000 0.0070 0.0000 0.0000 0.0000 0.0000 C4H10 0.0000 0.0040 0.0000 0.0000 0.0000 0.0000 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO2 0.0003 0.0100 0.0404 0.0404 0.0000 0.0000 H2O 0.0099 0.0000 0.0867 0.0867 1.0000 1.0000 N2 0.7732 0.0160 0.7432 0.7432 0.0000 0.0000 O2 0.2074 0.0000 0.1209 0.1209 0.0000 0.0000 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 V-L Flowrate (kgmol/hr) 109,323 4,380 113,831 113,831 21,589 28,545 V-L Flowrate (kg/hr) 3,154,735 75,901 3,230,636 3,230,636 388,927 514,240 Solids Flowrate (kg/hr) 0 0 0 0 0 0 Temperature (°C) 15 38 629 106 566 38 Pressure (MPa, abs) 0.10 3.10 0.11 0.10 16.65 0.01 Enthalpy (kJ/kg)A 30.23 46.30 835.81 248.81 3,472.36 160.61 Density (kg/m3) 1.2 22.2 0.4 0.9 47.7 992.9 V-L Molecular Weight 28.857 17.328 28.381 28.381 18.015 18.015 V-L Flowrate (lbmol/hr) 241,016 9,657 250,954 250,954 47,595 62,930 V-L Flowrate (lb/hr) 6,955,000 167,333 7,122,333 7,122,333 857,437 1,133,706 Solids Flowrate (lb/hr) 0 0 0 0 0 0 Temperature (°F) 59 100 1,163 222 1,050 101 Pressure (psia) 14.7 450.0 15.2 14.7 2,414.7 1.0 Enthalpy (Btu/lb)A 13.0 19.9 359.3 107.0 1,492.8 69.1 Density (lb/ft 3) 0.076 1.384 0.025 0.057 2.977 61.982 A - Reference conditions are 32.02 F & 0.089 PSIA 454

Cost and Performance Baseline for Fossil Energy Plants 5.2.2 Key System Assumptions System assumptions for Cases 13 and 14, NGCC with and without CO2 capture, are compiled in Exhibit 5-5.

Exhibit 5-5 NGCC Plant Study Configuration Matrix Case 13 Case 14 w/o CO2 Capture w/CO2 Capture 16.5/566/566 16.5/566/566 Steam Cycle, MPa/°C/°C (psig/°F/°F)

(2400/1050/1050) (2400/1050/1050)

Fuel Natural Gas Natural Gas Fuel Pressure at Plant Battery Limit MPa 3.1 (450) 3.1 (450)

(psia)

Condenser Pressure, mm Hg (in Hg) 50.8 (2) 50.8 (2)

Cooling Water to Condenser, °C (ºF) 16 (60) 16 (60)

Cooling Water from Condenser, °C (ºF) 27 (80) 27 (80)

Stack Temperature, °C (°F) 106 (222) 29 (85)

SO2 Control Low Sulfur Fuel Low Sulfur Fuel NOx Control LNB and SCR LNB and SCR SCR Efficiency, % (A) 90 90 Ammonia Slip (End of Catalyst Life),

10 10 ppmv Particulate Control N/A N/A Mercury Control N/A N/A CO2 Control N/A Econamine Overall CO2 Capture (A) N/A 90.7%

Off-site Saline CO2 Sequestration N/A

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