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Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity Revision 2
	ML12170A423
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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
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Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity Revision 2 , November 20 10 DOE/NETL-20 10/1397

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/20 10/1397 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 Earth's 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 today's 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 (CO 2) capture and sequestratio n 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 (CO 2) 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 view s 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 , owner's 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 today's technology are capable of producing electricity at relatively high efficiencies of about 39 percent , higher heating value

([HHV], without CO 2 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 , 01 0/kW (average); IGCC, $

2,50 5/kW (average). With CO 2 capture, capital costs are: NGCC, $1, 497/kW; PC, $3,5 90/kW (average); IGCC, $

3,5 68/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 NG CC, 59 mills/kWh for P C (average), and 77 mills/kWh (average) for IGCC.

When today's technology for CO 2 capture and sequestration (CCS) is integrated into these new power plants, the resultant COE

, including the cost of CO 2 TS&M , is: 86 mills/kWh for NGCC; 1 08 mills/kWh (average) for PC; and 1 12 mills/kWh (average) for IGCC. The cost of transporting CO 2 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 CO 2 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 equal s that of NGCC with CO 2 capture at a gas price of $9.8 0/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 today's 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 VII 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 U SE................................

................................

7 COST RESULTS ................................

................................

..............................

9 TOTAL OVERNIGHT COST ................................

................................

............

9 COST OF ELECTRICITY

................................

..............

11 CO 2 EMISSION PRICE IMPACT ................................

................................

..16 COST O F CO 2 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 CO 2 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 Cost and Performance Baseline for Fossil Energy Plants VIII 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 CO 2 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 CONOCO PHILLIPS E-G AS TM 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-G ASŽ IGCC POWER PLANT WITH CO 2 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 CO 2 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 NO X CONTROL SYSTEM ................................

................................

...............................

309 4.1.4 PARTICULATE CONTROL ................................

................................

.............................

310 4.1.5 MERCURY REMOVAL ................................

................................

..310 Cost and Performance Baseline for Fossil Energy Plants IX 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 CO 2 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 CO 2 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

................................

......4 36 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 NO X 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 Cost and Performance Baseline for Fossil Energy Plants X 5.2.6 CASE 13 - COST ESTIMATING ................................

................................

.....................

469 5.2.7 CASE 14 - NGCC WITH CO 2 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 M IX ................................

................................

.......524 6.6.3 PJM MARKETS ................................

................................

...........

524 6.6.4 PJM ENERGY MARKETS ................................

................................

.............................

525 6.6.5 D AY-AHEAD MARKET ................................

................................

.525 6.6.6 PRICES AND DEMAND ................................

................................

.527

6.7 DESCRIPTION

OF THE PJM REGIONAL MODELING ................................

........................

529 6.8 WPLAN ET 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 CO 2 CAPTURE ........545 8.1 CASE 2A - GEE IGCC IN QUENCH ONLY MODE WITH CO 2 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 Cost and Performance Baseline for Fossil Energy Plants XI List of Exhibits Exhibit ES-1 Case Descriptions

................................

..... 2Exhibit ES-2 Cost and Performance Summary and Environmental Profile for All Cases

............

5Exhibit ES-3 Net Plant Efficiency (HHV Basis)

................................

...........

6Exhibit ES-4 Raw Water Withdrawal and Consumption

................................

..............................

8Exhibit ES-5 Plant Capital Costs

................................

. 10Exhibit ES-6 Economic Parameters Used to Calculate COE

................................

......................

12Exhibit ES-7 COE by Cost Component

................................

.......................

13Exhibit ES-8 COE Sensitivity to Fuel Costs in Non

-Capture Cases

................................

...........

14Exhibit ES-9 COE Sensitivity to Fuel Costs in CO 2 Capture Cases

................................

............

15Exhibit ES-10 COE Sensitivity to Capacity Factor

................................

..... 16Exhibit ES-11 Impact of Carbon Emissions Price on Study Technologies

................................

. 17Exhibit ES

-12 Lowest Cost Power Generation Options Comparing NGCC and Coal

................

18Exhibit ES-13 First Year CO 2 Avoided Costs

................................

.............

20Exhibit ES-14 Study Environmental Targets

................................

...............

21Exhibit ES-15 SO 2, NOx, and Particulate Emission Rates

................................

..........................

23Exhibit ES-16 Mercury Emission Rates

................................

......................

24Exhibit ES-17 CO 2 Emissions Normalized By Net Output

................................

.........................

26Exhibit 1-1 Case Descriptions

................................

..... 29Exhibit 2-1 Site Ambient Conditions

................................

...........................

31Exhibit 2-2 Site Characteristics

................................

... 31Exhibit 2-3 Design Coal

................................

...............

33Exhibit 2-4 Natural Gas Composition

................................

..........................

34Exhibit 2-5 Standards of Performance for Electric Utility Steam Generating Units

...................

35Exhibit 2-6 NSPS Mercury Emission Limits

................................

...............

36Exhibit 2-7 Probability Distribution of Mercury Concentration in the Illinois No. 6 Coal

......... 36Exhibit 2-8 Environmental Targets for IGCC Cases

................................

... 37Exhibit 2-9 Environmental Targets for PC Cases

................................

........ 38Exhibit 2-10 Environmental Targets for NGCC Cases

................................

39Exhibit 2-11 Capital Cost Levels and their Elements

................................

.. 43Exhibit 2-12 Features of an AACE Class 4 Cost Estimate

................................

..........................

44Exhibit 2-13 AACE Guidelines for Process Contingency

................................

...........................

48Exhibit 2-14 TASC/TOC Factors

................................

. 49Exhibit 2-15 Owner's Costs Included in TOC

................................

.............

50Exhibit 2-16 CO 2 Pipeline Specification

................................

.....................

53Exhibit 2-17 Deep, Saline Aquifer Specification

................................

........ 54Exhibit 2-18 Global Economic Assumptions

................................

..............

57Exhibit 2-19 Financial Structure for Investor Owned Utility High and Low Risk Projects

........ 58Exhibit 2-20 Illustration of COE Solutions using DCF Analysis

................................

................

60Exhibit 2-21 PC with CCS in Current 2007 Dollars

................................

.... 61Exhibit 2-22 Capital Charge Factors for COE Equation

................................

.............................

62Exhibit 2-23 COE and LCOE Summary

................................

......................

63Exhibit 3-1 Air Extracted from the Combustion Turbine and Supplied to the ASU in Non

-Carbon Capture Cases

................................

...........

70Exhibit 3-2 Typical ASU Process Schematic

................................

..............

71 Cost and Performance Baseline for Fossil Energy Plants XII Exhibit 3-3 Flow Diagram for a Conventional AGR Unit

................................

...........................

75Exhibit 3-4 Common Chemical Reagents Used in AGR Processes

................................

............

76Exhibit 3-5 Physical Solvent AGR Process Simplified Flow Diagram

................................

....... 77Exhibit 3-6 Common Physical Solvents Used in AGR Processes

................................

...............

78Exhibit 3-7 Common Mixed Solvents Used in AGR Processes

................................

..................

79Exhibit 3-8 Equilibrium Solubility Data on H 2S and CO 2 in Various Solvents

..........................

79Exhibit 3-9 Typical Three

-Stage Claus Sulfur Plant

................................

... 82Exhibit 3-10 Advanced F Class Combustion Turbine Performance Characteristics Using Natural Gas ................................

................................

........ 85Exhibit 3-11 Typical Fuel Specification for F

-Class Machines

................................

...................

86Exhibit 3-12 Allowable Gas Fuel Contaminant Level for F

-Class Machines

.............................

87Exhibit 3-13 Case 1 Block Flow Diagram, GEE IGCC without CO 2 Capture ............................

98Exhibit 3-14 Case 1 Stream Table, GEE IGCC without CO 2 Capture ................................

........ 99Exhibit 3-15 GEE IGCC Plant Study Configuration Matrix

................................

.....................

103Exhibit 3-16 Balance of Plant Assumptions

................................

..............

104Exhibit 3-17 Case 1 Plant Performance Summary

................................

.... 106Exhibit 3-18 Case 1 Emissions

................................

.. 107Exhibit 3-19 Case 1 Carbon Balance

................................

.........................

108Exhibit 3-20 Case 1 Sulfur Balance

................................

...........................

108Exhibit 3-21 Case 1 Water Balance

................................

...........................

109Exhibit 3-22 Case 1 Coal Gasification and Air Separation Units Heat and Mass Balance Schematic ................................

................................

............................

111Exhibit 3-23 Case 1 Syngas Cleanup Heat and Mass Balance Schematic

................................

112Exhibit 3-24 Case 1 Combined

-Cycle Power Generation Heat and Mass Balance Schematic

. 113Exhibit 3-25 Case 1 Overall Energy Balance (0°C [32°F] Reference)

................................

...... 115Exhibi t 3-26 Case 1 Total Plant Cost Summary

................................

........ 125Exhibit 3-27 Case 1 Total Plant Cost Details

................................

............

126Exhibit 3-28 Case 1 Initial and Annual O&M Costs

................................

. 130Exhibit 3-29 Case 2 Block Flow Diagram, GEE IGCC with CO 2 Capture ...............................

132Exhibit 3-30 Case 2 Stream Table, GEE IGCC with CO 2 Capture ................................

...........

133Exhibit 3-31 Case 2 Plant Performance Summary

................................

.... 136Exhibit 3-32 Case 2 Air Emissions

................................

............................

137Exhibit 3-33 Case 2 Carbon Balance

................................

.........................

138Exhibit 3-34 Case 2 Sulfur Balance

................................

...........................

138Exhibit 3-35 Case 2 Water Balance

................................

...........................

139Exhibit 3-36 Case 2 Coal Gasification and Air Separation Units Heat and Mass Balance Schematic ................................

................................

............................

141Exhibit 3-37 Case 2 Syngas Cleanup Heat and Mass Balance Schematic

................................

142Exhibit 3-38 Case 2 Combined

-Cycle Power Generation Heat and Mass Balance Schematic

. 143Exhibit 3-39 Case 2 Overall Energy Balance (0°C [32°F] Reference)

................................

...... 145Exhibit 3-40 Case 2 Total Plant Cost Summary

................................

........ 156Exhibit 3-41 Case 2 Total Plant Cost Details

................................

............

157Exhibit 3-42 Case 2 Initial and Annual Operating and Maintenance Costs

..............................

161Exhibit 3-43 Case 3 Block Flow Diagram , E-GasŽ IGCC without CO 2 Capture ....................

165Exhibit 3-44 Case 3 Stream Table , E-GasŽ IGCC without CO 2 Capture ................................

166Exhibit 3-45 CoP IGCC Plant Study Configuration Matrix

................................

......................

171 Cost and Performance Baseline for Fossil Energy Plants XIII Exhibit 3-46 Case 3 Plant Performance Summary

................................

.... 173Exhibit 3-47 Case 3 Air Emissions

................................

............................

174Exhibi t 3-48 Case 3 Carbon Balance

................................

.........................

175Exhibit 3-49 Case 3 Sulfur Balance

................................

...........................

175Exhibit 3-50 Case 3 Water Balance

................................

...........................

176Exhibit 3-51 Case 3 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic ................................

................................

............................

177Exhibit 3-52 Case 3 Syngas Cleanup Heat and Mass Balance Schematic

................................

178Exhibit 3-53 Case 3 Combined Cycle Power Generation Heat and Mass Balance Schematic

. 179Exhibit 3-54 Case 3 Overall Energy Balance (0°C [32°F] Reference)

................................

...... 181Exhibit 3-55 Case 3 Total Plant Cost Summary

................................

........ 192Exhibit 3-56 Case 3 Total Plant Cost Details

................................

............

193Exhibit 3-57 Case 3 Initial and Annual Operating and Maintenance Costs ..............................

197Exhibit 3-58 Case 4 Block Flow Diagram , E-GasŽ IGCC with CO 2 Capture .........................

199Exhibit 3-59 Case 4 Stream Table , E-GasŽ IGCC with CO 2 Capture ................................

..... 200Exhibit 3-60 Case 4 Plant Performance Summary

................................

.... 204Exhibit 3-61 Case 4 Air Emissions

................................

............................

205Exhibit 3-62 Case 4 Carbon Balance

................................

.........................

206Exhibit 3-63 Case 4 Sulfur Balance

................................

...........................

206Exhibit 3-64 Case 4 Water Balance

................................

...........................

207Exhibit 3-65 Case 4 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic ................................

................................

............................

209Exhibit 3-66 Case 4 Syngas Cleanup Heat and Mass Balance Schematic

................................

210Exhibit 3-67 Case 4 Combined Cycle Power Generation Heat and Mass Balance Schematic

. 211Exhibit 3-68 Case 4 Overall Energy Balance (0°C [32°F] Reference)

................................

...... 213Exhibit 3-69 Case 4 Total Plant Cost Summary

................................

........ 223Exhibit 3-70 Case 4 Total Plant Cost Details

................................

............

224Exhibit 3-71 Case 4 Initial and Annual Operating and Maintenance Costs

..............................

228Exhibit 3-72 Case 5 Block Flow Diagram, Shell IGCC without CO 2 Capture .........................

232Exhibit 3-73 Case 5 Stream Table, Shell IGCC without CO 2 Capture ................................

...... 233Exhibit 3-74 Shell IGCC Plant Study Configuration Matrix

................................

.....................

238Exhibit 3-75 Case 5 Plant Performance Summary

................................

.... 240Exhibit 3-76 Case 5 Air Emissions

................................

............................

241Exhibit 3-77 Case 5 Carbon Balance

................................

.........................

242Exhibit 3-78 Case 5 Sulfur Balance

................................

...........................

242Exhibit 3-79 Case 5 Water Balance

................................

...........................

243Exhibit 3-80 Case 5 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic ................................

................................

............................

245Exhibit 3-81 Case 5 Syngas Cleanup Heat and Mass Balance Schematic

................................

246Exhibit 3-82 Case 5 Combined Cycle Power Generation Heat and Mass Balance Schematic

. 247Exhibit 3-83 Case 5 Overall Energy Balance (0°C [32°F] Reference)

................................

...... 249Exhibi t 3-84 Case 5 Total Plant Cost Summary

................................

........ 259Exhibit 3-85 Case 5 Total Plant Cost Details

................................

............

260Exhibit 3-86 Case 5 Initial and Annual Operating and Maintenance Costs

..............................

264Exhibit 3-87 Case 6 Block Flow Diagram, Shell IGCC with CO 2 Capture ..............................

268Exhibit 3-88 Case 6 Stream Table, Shell IGCC with CO 2 Capture ................................

...........

269 Cost and Performance Baseline for Fossil Energy Plants XIV Exhibit 3-89 Case 6 Plant Performance Summary

................................

.... 272Exhibit 3-90 Case 6 Air Emissions

................................

............................

273Exhibit 3-91 Case 6 Carbon Balance

................................

.........................

274Exhibit 3-92 Case 6 Sulfur Balanc e ................................

................................

...........................

274Exhibit 3-93 Case 6 Water Balance

................................

...........................

275Exhibit 3-94 Case 6 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic ................................

................................

............................

277Exhibit 3-95 Case 6 Syngas Cleanup Heat and Mass Balance Schematic

................................

27 8Exhibit 3-96 Case 6 Combined Cycle Power Generation Heat and Mass Balance Schematic

. 279Exhibi t 3-97 Case 6 Overall Energy Balance (0°C [32°F] Reference)

................................

...... 281Exhibit 3-98 Case 6 Total Plant Cost Summary

................................

........ 291Exhibit 3-99 Case 6 Total Plant Cost Details

................................

............

292Exhibit 3-100 Case 6 Initial and Annual Operating and Maintenance Costs

............................

296Exhibit 3-101 Estimated Performance and Cost Results for IGCC Cases

................................

. 297Exhibit 3-102 Plant Capital Cost for IGCC Cases

................................

..... 298Exhibit 3-103 COE for IGCC Cases

................................

..........................

299Exhibit 3-104 Capacity Factor Sensitivity of IGCC Cases

................................

........................

300Exhibit 3-105 Coal Price Sensitivity of IGCC Cases

................................

301Exhibit 3-106 Cost of CO 2 Avoided in IGCC Cases

................................

. 301Exhibit 3-107 Carbon Conversion Efficiency and Slag Carbon Content ................................

.. 302Exhibit 3-108 Raw Water Withdrawal and Consumption in IGCC Cases

................................

304Exhibit 4-1 Fluor Econamine FG Plus SM Typical Flow Diagram

................................

.............

314Exhibit 4-2 CO 2 Compressor Interstage Pressures

................................

.... 317Exhibit 4-3 Case 9 Block Flow Diagram, Subcritical Unit without CO 2 Capture .....................

324Exhibit 4-4 Case 9 Stream Table, Subcritical Unit without CO 2 Capture ................................

. 325Exhibit 4-5 Subcritical PC Plant Study Configuration Matrix

................................

..................

327Exhibit 4-6 Balance of Plant Assumptions

................................

................

328Exhibit 4-7 Case 9 Plant Performance Summary

................................

...... 330Exhibit 4-8 Case 9 Air Emissions

................................

..............................

331Exhibit 4-9 Case 9 Carbon Balance

................................

...........................

332Exhibit 4-10 Case 9 Sulfur Balance

................................

...........................

332Exhibit 4-11 Case 9 Water Balance

................................

...........................

333Exhibit 4-12 Case 9 Heat and Mass Balance, Subcritical PC Boiler without CO 2 Capture ...... 335Exhibit 4-13 Case 9 Heat and Mass Balance, Subcritical Steam Cycle

................................

.... 336Exhibit 4-14 Case 9 Overall Energy Balance (0°C [32°F] Reference)

................................

...... 337Exhibit 4-15 Case 9 Total Plant Cost Summary

................................

........ 347Exhibit 4-16 Case 9 Total Plant Cost Details

................................

............

348Exhibit 4-17 Case 9 Initial and Annual Operating and Maintenance Costs

..............................

352Exhibit 4-18 Case 10 Block Flow Diagram, Subcritical Unit with CO 2 Capture ......................

354Exhibit 4-19 Case 10 Stream Table, Subcritical Unit with CO 2 Capture ................................

... 355Exhibit 4-20 Case 10 Plant Performance Summary

................................

... 357Exhibit 4-21 Case 10 Air Emissions

................................

..........................

358Exhibit 4-22 Case 10 Carbon Balance

................................

.......................

359Exhibit 4-23 Case 10 Sulfur Balance

................................

.........................

359Exhibit 4-24 Case 10 Water Balance

................................

.........................

359Exhibit 4-25 Case 10 Heat and Mass Balance, Subcritical PC Boiler with CO 2 Capture ......... 361 Cost and Performance Baseline for Fossil Energy Plants XV Exhibit 4-26 Case 10 Heat and Mass Balance, Subcritical Steam Cycle

................................

.. 362Exhibit 4-27 Case 10 Overall Energy Balance (0°C [32°F] Reference)

................................

.... 363Exhibit 4-28 Case 10 Total Plant Cost Summary

................................

...... 374Exhibit 4-29 Case 10 Total Plant Cost Details

................................

..........

375Exhibit 4-30 Case 10 Initial and Annual Operating and Maintenance Costs

............................

379Exhibit 4-31 Case 11 Block Flow Diagram, Supercritical Unit without CO 2 Capture ..............

381Exhibit 4-32 Case 11 Stream Table, Supercritical Unit without CO 2 Capture ..........................

382 Exhibit 4-33 Supercritical PC Plant Study Configuration Matrix

................................

.............

384Exhibit 4-34 Case 11 Plant Performance Summary

................................

.. 386Exhibit 4-35 Case 11 Air Emissions

................................

..........................

387Exhibit 4-36 Case 11 Carbon Balance

................................

.......................

387Exhibit 4-37 Case 11 Sulfur Balance

................................

.........................

388Exhibit 4-38 Case 11 Water Balance

................................

.........................

388Exhibit 4-39 Case 11 Heat and Mass Balance, Supercritical PC Boiler without CO 2 Capture . 391Exhibit 4-40 Case 11 Heat and Mass Balance, Supercritical Steam Cycle

...............................

392Exhibit 4-41 Case 11 Overall Energy Balance (0°C [32°F] Reference

) ................................

.... 393Exhibit 4-42 Case 11 Total Plant Cost Summary

................................

...... 403Exhibit 4-43 Case 11 Total Plant Cost Details

................................

..........

404Exhibit 4-44 Case 11 Initial and Annual Operating and Maintenance Costs

............................

408Exhibit 4-45 Case 12 Block Flow Diagram, Supercritical Unit with CO 2 Capture ...................

410Exhibit 4-46 Case 12 Stream Table, Supercritical Unit with CO 2 Capture ...............................

411Exhibit 4-47 Case 12 Plant Performance Summary

................................

.. 413Exhibit 4-48 Case 12 Air Emissions

................................

..........................

414Exhibit 4-49 Case 12 Carbon Balance

................................

.......................

415Exhibit 4-50 Case 12 Sulfur Balance

................................

.........................

415Exhibit 4-51 Case 12 Water Balance

................................

.........................

415Exhibit 4-52 Case 12 Heat and Mass Balance, Supercritical PC Boiler with CO 2 Capture ...... 417Exhibit 4-53 Case 12 Heat and Mass Balance, Supercritical Steam Cycle

...............................

418Exhibit 4-54 Case 12 Overall Energy Balance (0°C [32°F] Reference)

................................

.... 419Exhibit 4-55 Case 12 Total Plant Cost Summary

................................

...... 430Exhibit 4-56 Case 12 Total Plant Cost Details

................................

..........

431Exhibit 4-57 Case 12 Initial and Annual Operating and Maintenance Costs

............................

435Exhibit 4-58 Estimated Performance and Cost Results for Pulverized Coal Cases

..................

436Exhibi t 4-59 Plant Capital Cost for PC Cases

................................

...........

437Exhibit 4-60 COE for PC Cases

................................

. 438Exhibit 4-61 Sensitivity of COE to Capacity Factor for PC Cases

................................

...........

439Exhibit 4-62 Sensitivity of COE to Coal Price for PC Cases

................................

....................

440Exhibit 4-63 First Year Cost of CO 2 Avoided in PC Cases

................................

.......................

440Exhibit 4-64 Raw Water Withdrawal and Consumption in PC Cases

................................

....... 442Exhibit 5-1 Combustion Turbine Typical Scope of Supply

................................

.......................

444Exhibit 5-2 CO 2 Compressor Interstage Pressures

................................

.... 449Exhibit 5-3 Case 13 Block Flow Diagram, NGCC without CO 2 Capture ................................

. 453Exhibit 5-4 Case 13 Stream Table, NGCC without CO 2 Capture ................................

.............

454Exhibit 5-5 NGCC Plant Study Configuration Matrix

................................

..............................

455Exhibit 5-6 NGCC Balance of Plant Assumptions

................................

.... 456Exhibit 5-7 Case 13 Plant Performance Summary

................................

.... 457 Cost and Performance Baseline for Fossil Energy Plants XVI Exhibit 5-8 Case 13 Air Emissions

................................

............................

458Exhibit 5-9 Case 13 Carbon Balance

................................

.........................

458Exhibit 5-10 Case 13 Water Balance

................................

.........................

459Exhibit 5-11 Case 13 Heat and Mass Balance, NGCC without CO 2 Capture ...........................

461Exhibit 5-12 Case 13 Overall Energy Balance (0°C [32°F] Reference)

................................

.... 463Exhibit 5-13 Case 13 Total Plant Cost Summary

................................

...... 470Exhibit 5-14 Case 13 Total Plant Cost Details

................................

..........

471Exhibit 5-15 Case 13 Initial and Annual Operating and Maintenance Cost Summary

.............

475Exhibit 5-16 Case 14 Block Flow Diagram, NGCC with CO 2 Capture ................................

.... 477Exhibit 5-17 Case 14 Stream Table, NGCC with CO 2 Capture ................................

................

478Exhibit 5-18 Case 14 Plant Performance Summary

................................

.. 479Exhibit 5-19 Case 14 Air Emissions

................................

..........................

480Exhibit 5-20 Case 14 Carbon Balance

................................

.......................

480Exhibi t 5-21 Case 14 Water Balance

................................

.........................

481Exhibit 5-22 Case 14 Heat and Mass Balance, NGCC with CO 2 Capture ................................

483Exhibit 5-23 Case 14 Overall Energy Balance (0°C [32°F] Reference)

................................

.... 485Exhibit 5-24 Case 14 Total Plant Cost Summary

................................

...... 493Exhibit 5-25 Case 14 Total Plant Cost Details ................................

................................

..........

494Exhibit 5-26 Case 14 Initial and Annual Operating and Maintenance Cost Summary

.............

498Exhibit 5-27 Estimated Performance and Cost Results for NGCC Cases

................................

. 499Exhibit 5-28 Plant Capital Cost for NGCC Cases

................................

..... 500Exhibit 5-29 COE of NGCC Cases

................................

............................

501Exhibit 5-30 Sensitivity of COE to Capacity Factor in NGCC Cases

................................

....... 502Exhibit 5-31 Sensitivity of COE to Fuel Price in NGCC Cases

................................

................

502Exhibit 5-32 Raw Water Withdrawal and Consumption in NGCC Cases

................................

. 504Exhibit 6-1 COE By Cost Component

................................

.......................

508Exhibit 6-2 First Year CO 2 Avoided Costs

................................

................

509Exhibit 6-3 COE Sensitivity to Fuel Costs in Non

-Capture Cases

................................

............

510Exhibit 6-4 COE Sensitivity to Fuel Costs in CO 2 Capture Cases

................................

............

511Exhibit 6-5 COE Sensitivity to Capacity Factor in Non

-Capture Cases

................................

... 512Exhibit 6-6 COE Sensitivity to Capacity Factor in Capture Cases

................................

............

513Exhibit 6-7 Dispatch Based Capacity Factors for Cases without CO 2 Capture .........................

514Exhibit 6-8 Estimated Stacking Order in PJM for Year 2010 Based on First Year Production Costs ................................

................................

.... 517Exhibit 6-9 Capacity Factors of Replacement Units Dispatched into PJM

...............................

518Exhibit 6-10 Dispatch Based Capacity Factors Assuming No CO 2 Capture .............................

518Exhibit 6-11 Summary of Prospective Facility Parameters for Modeling

................................

. 519Exhibit 6-12 Comparison of COE as a Function of Capacity Factor

................................

........ 520Exhibit 6-13 Impact of Dispatched Based Capacity Factors on the Cost of Electricity ............

521Exhibit 6-14 The PJM Operating Territory

................................

...............

523Exhibit 6-15 PJM Installed Capacity by Fuel Type

................................

... 524Exhibit 6-16 PJM East Day

-Ahead LMP for 2006

................................

.... 526Exhibit 6-17 PJM Load and Day

-Ahead LMP for 2006

................................

............................

527Exhibit 6-18 PJM Day

-Ahead LMP vs. Demand for 2006

................................

........................

528Exhibit 6-19 PJM Price/Load Distribution for 2006

................................

.. 528Exhibit 6-20 Data Sources for Electricity Generation in the PJM Region in Year 2006

..........

530 Cost and Performance Baseline for Fossil Energy Plants XVII Exhibit 6-21 Assumptions for Projecting PJM Year 2006 into 2010

................................

........ 531Exhibit 6-22 Breakdown of Additional Generation in the PJM ISO by Fuel Type

...................

531Exhibit 6-23 Summary of Prospective Facility Parameters

................................

.......................

532Exhibit 7-1 Cost Accounts Affected by Change in Cooling System

................................

......... 534Exhibit 7-2 Normalized Raw Water Withdrawal for Baseline, Parallel and Dry Cooling Case s ................................

................................

.............

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

................................

.............

537Exhibit 7-4 Net Output Reduction Relative to the Baseline (Wet Cooling) Case

.....................

538Exhibit 7-5 Total Overnight Cost for Baseline, Parallel and Dry Cooling Cases

......................

540 Exhibit 7-6 COE for Baseline, Parallel and Dry Cooling Systems

................................

............

541Exhibit 7-7 Design Ambient Conditions for SC PC Sensitivity Case

................................

........ 542Exhibit 8-1 Case 2A Block Flow Diagram, GEE Quench Only IGCC with CO 2 Capture ........ 547Exhibit 8-2 Case 2A Stream Table, GEE Quench Only IGCC with CO 2 Capture ....................

548Exhibit 8-3 GEE IGCC Plant Study Configuration Matrix

................................

.......................

551Exhibit 8-4 Case 2A Plant Performance Summary

................................

.... 553Exhibit 8-5 Case 2A Air Emissions

................................

...........................

554Exhibit 8-6 Case 2A Carbon Balance

................................

........................

555Exhibit 8-7 Case 2A Sulfur Balance

................................

..........................

555Exhibit 8-8 Case 2A Water Balance

................................

..........................

556Exhibit 8-9 Case 2A Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic ................................

................................

............................

557Exhibit 8-10 Case 2A Syngas Cleanup Heat and Mass Balance Schematic

..............................

558Exhibit 8-11 Case 2A Combined Cycle Power Generation Heat and Mass Balance Schematic

................................

.............

559Exhibit 8-12 Case 2A Overall Energy Balance

................................

......... 561Exhibit 8-13 Case 2A Total Plant Cost Summary

................................

..... 571Exhibit 8-14 Case 2A Total Plant Cost Details

................................

......... 572Exhibit 8-15 Case 2A Initial and Annual Operating and Maintenance Costs

...........................

576Exhibit 9-1 Case 12A Block Flow Diagram, Supercritical Unit with CO 2 Capture (MEA Sensitivity)

................................

..........................

579Exhibit 9-2 Case 12A Stream Table, Supercritical Unit with CO 2 Capture ..............................

580Exhibit 9-3 Case 12A Plant Performance Summary

................................

.. 582Exhibit 9-4 Case 12A Total Plant Cost Summary

................................

..... 584Exhibit 9-5 Case 12A Total Plant Cost Details

................................

......... 585Exhibit 9-6 Case 12A Initial and Annual Operating and Maintenance Costs

...........................

589Exhibit 10-1 Record of Revisions

................................

..............................

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

Cost and Performance Baseline for Fossil Energy Plants XIX PREPARED BYResearch and Development Solutions, LLC (RDS)

UPDATED BYEnergy 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 Cost and Performance Baseline for Fossil Energy Plants XX Acknowledgments This report was initially prepared by Research and Development Solutions, LLC (RDS) for the United States Department of Energy's (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.

Cost and Performance Baseline for Fossil Energy Plants XXI AACE Association for the Advancement of Cost Engineering LIST OF ACRONYMS AND ABBREVIATIONS 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 Bt u British thermal unit Btu/h r 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 m 3/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 CO 2 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 Diis opropanolamine DLN Dry low NOx DOE Department of Energy

Cost and Performance Baseline for Fossil Energy Plants XXII EAF Equivalent availability factor E-Gas TM 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 g pd Gallons per day gpm Gallons per minute gr/100 scf grains per one hundred standard cubic feet GSU Generator step-u p transformers GT Gas turbine GWh Gigawatt-hour h Hour H 2 Hydrogen H 2 S Hydrogen sulfide H 2 SO 4 Sulfuric acid Hg Mercury HDPE High-density polyethylene HHV Higher heating value hp Horsepower HP High-pressure HRSG Heat recovery steam generator

Cost and Performance Baseline for Fossil Energy Plants XXIII 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. H 2 O 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/h r Kilogram per hour kJ Kilojoules kJ/h r 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/h r Pounds per hour lb/ft 2 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 Cost and Performance Baseline for Fossil Energy Plants XXIV lpm Liters per minute LSE Load-serving entities m Meters m/min Meters per minute m 3/min Cubic meter per minute MAC Main Air Compressor MAF Moisture/Ash-Free MCR Maximum continuous rating m d Millidarcy MDEA Methyldiethanolamine MEA Monoethanolamine MHz Megahertz Mills/kWh Tenths of a cent per kilowat t hour MJ/Nm 3 Megajoule per normal cubic meter MMBtu Million British thermal units (also shown as 10 6 Btu) MMBtu/h r Million British thermal units (also shown as 10 6 Btu) per hour MMkJ Million kilojoules (also shown as 10 6 kJ) MMkJ/h r Million kilojoules (also shown as 10 6 kJ) per hour MNQC Multi Nozzle Quiet Combustor mol% Mole percent MPa Megapascals MVA Mega volt-amps MW Megaw a tt MWe Megawatts electric MWh Megawatt-hour N 2 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 N H 3 Ammonia Nm 3 Normal cubic meter Nm 3/h r 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 O 2 Oxygen O&M Operation and maintenance

Cost and Performance Baseline for Fossil Energy Plants XXV OC Fn 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/valve s 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 p si 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 s cf 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

Cost and Performance Baseline for Fossil Energy Plants XXVI Shell Shell Global Solutions SNCR Selective non

-catalytic reduction SNG Synthetic natural gas SO 2 Sulfur dioxide SOx Oxides of sulfur SRU Sulfur recovery unit SS Stainless steel SS Amine SS Specialty Amine STG Steam turbine generator Syngas Synthe tic 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

Cost and Performance Baseline for Fossil Energy Plants 1 The objective of this report i s 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:

EXECUTIVE

SUMMARY

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 o f 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 Energy's (DOE) Clean Coal Programs Twelve power plant configurations were analyzed as listed in Exhibit ES-1. The list includes s ix IGCC cases utilizing General Electric Energy (GEE), ConocoPhillips (CoP), and Shell Global Solutions (Shell) gasifiers each with and without carbon dioxide (CO 2) capture; four PC cases, two subcritical and two supercritical (SC), each with and without C O 2 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 Cost and Performance Baseline for Fossil Energy Plants 2 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 Administration's (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 Case Unit Cycle Steam Cycle, psig/F/ F Combustion Turbine Gasifier/Boiler Technology Oxidant H 2 S Separation/

Removal Sulfur Removal/ Recovery CO 2 Separa-tion 1 IGCC 1800/1050/1050 2 x Advanced F Class GEE Radiant Only 95 mol% O 2 Selexol Claus Plant 2 IGCC 1800/1000/1000 2 x Advanced F Class GEE Radiant Only 95 mol% O 2 Selexol Claus Plant Selexol 2 nd stage 3 IGCC 1800/1050/1050 2 x Advanced F Class CoP E-GasŽ 95 mol% O 2 Refrigerated MDEA Claus Plant 4 IGCC 1800/1000/1000 2 x Advanced F Class CoP E-GasŽ 95 mol% O 2 Selexol Claus Plant Selexol 2 nd stage 5 IGCC 1800/1050/1050 2 x Advanced F Class Shell 95 mol% O 2 Sulfinol-M Claus Plant 6 IGCC 1800/1000/1000 2 x Advanced F Class Shell 95 mol% O 2 Selexol Claus Plant Selexol 2 nd stage -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- 9 PC 2400/1050/1050 Subcritical PC Air Wet Flue gas desulfuri-zation (FGD)/ Gypsum 10 PC 2400/1050/1050 Subcritical PC Air Wet FGD/ Gypsum Amine Absorber 11 PC 3500/1100/1100 Supercritical PC Air Wet FGD/ Gypsum 12 PC 3500/1100/1100 Supercritical PC Air Wet FGD/ Gypsum Amine Absorber 13 NGCC 2400/1050/10 50 2 x Advanced F Class HRSG Air 14 NGCC 2400/1050/10 50 2 x Advanced F Class HRSG Air Amine 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 Cost and Performance Baseline for Fossil Energy Plants 3 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 (CT s) 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 6 29 MW (Case 5). The range in IGCC net output is caused by the much higher auxiliary load imposed in the CO 2 capture cases, primarily due to CO 2 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 5 55 and 4 74 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 The net plant efficiency (H H V basis) for all twelve cases is shown in Energy Efficiency Exhibit ES-3. The primary conclusions that can be drawn are:

The NGCC with no CO 2 capture has the highest net efficiency of the technologies modeled in this study with an efficiency of 50.2 percent.

The NGCC case with CO 2 capture results in the highest efficiency (4 2.8 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 CO 2 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 (4 2.1 percent), the slurry

-fed, two-stage CoP gasifier (39.

7 percent) and the slurry-fed, single

-stage GEE gasifier (3 9.0 percent).

Cost and Performance Baseline for Fossil Energy Plants 4 When CO 2 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 3 1.2 percent. The relative efficiency penalty for adding CO 2 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 1 4.7 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 CO 2 capture to the PC cases via the Flu o r Econamine FG Plus SM (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.

Cost and Performance Baseline for Fossil Energy Plants 5 Exhibit ES-2 Cost and Performance Summary and Environmental Profile for All Cases 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. PERFORMANCECase 1Case 2Case 3Case 4Case 5Case 6 Case 9Case 10Case 11Case 12Case 13Case 14CO2 Capture 0%90%0%90%0%90%0%90%0%90%0%90%Gross Power Output (kWe)747,800734,000738,200703,700737,000673,400582,600672,700580,400662,800564,700511,000Auxiliary Power Requirement (kWe)125,750190,750113,140190,090108,020176,54032,580122,74030,410112,8309,62037,430Net Power Output (kWe)622,050543,250625,060513,610628,980496,860550,020549,960549,990549,970555,080473,570Coal Flowrate (lb/hr)466,901487,011459,958484,212436,646465,264437,378614,994409,528565,820N/AN/ANatural Gas Flowrate (lb/hr)N/AN/AN/AN/AN/AN/AN/AN/AN/AN/A167,333167,333HHV Thermal Input (kWth)1,596,3201,665,0741,572,5821,655,5031,492,8781,590,7221,495,3792,102,6431,400,1621,934,5191,105,8121,105,812Net 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)8,75610,4588,58510,9988,09910,9249,27713,0468,68712,0026,7987,968Raw Water Withdrawal (gpm/MWnet)7.610.77.011.16.611.310.720.49.718.34.38.4Process Water Discharge (gpm/MWnet)1.62.01.42.11.22.02.24.72.04.31.02.1Raw Water Consumption (gpm/MWnet)6.08.75.59.05.39.38.515.77.714.13.36.3 CO 2 Emissions (lb/MMBtu) 197 20 199 20 197 20 204 20 204 20 118 12 CO 2 Emissions (lb/MWhgross)1,434 1521,448 1581,361 1611,783 2171,675 203 790 87 CO 2 Emissions (lb/MWhnet)1,723 2061,710 2171,595 2181,888 2661,768 244 804 94 SO 2 Emissions (lb/MMBtu)0.00120.00220.01170.00220.00420.00210.08580.00170.08580.0016NegligibleNegligible SO 2 Emissions (lb/MWhgross)0.00900.01660.08520.01730.02900.01710.75150.01760.70630.0162NegligibleNegligibleNOx Emissions (lb/MMBtu)0.0590.0490.0600.0490.0590.0490.0700.0700.0700.0700.0090.008NOx Emissions (lb/MWhgross)0.4300.3760.4340.3960.4090.3960.6130.7470.5760.6970.0600.061PM Emissions (lb/MMBtu)0.00710.00710.00710.00710.00710.00710.01300.01300.01300.0130NegligibleNegligiblePM Emissions (lb/MWhgross)0.0520.0550.0520.0570.0490.0570.1140.1390.1070.129NegligibleNegligibleHg Emissions (lb/TBtu)0.5710.5710.5710.5710.5710.5711.1431.1431.1431.143NegligibleNegligibleHg Emissions (lb/MWhgross)4.16E-064.42E-064.15E-064.59E-063.95E-064.61E-061.00E-051.22E-059.41E-061.14E-05NegligibleNegligibleCOSTTotal Plant Cost (2007$/kW)1,9872,7111,9132,8172,2173,1811,6222,9421,6472,913 5841,226Total Overnight Cost (2007$/kW)2,4473,3342,3513,4662,7163,9041,9963,6102,0243,570 7181,497 Bare Erected Cost1,5282,0321,4702,1131,6952,3851,3172,2551,3452,239 482 926 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 271Total Overnight Cost (2007$ x 1,000)1,521,8801,811,4111,469,5771,780,2901,708,5241,939,8781,098,1241,985,4321,113,4451,963,644398,290709,039Total As Spent Capital (2007$/kW)2,7893,8012,6803,9523,0974,4512,2644,1152,2964,070 7711,614COE (mills/kWh, 2007$)1,276.3105.674.0110.381.3119.459.4109.658.9106.558.985.9 CO2 TS&M Costs0.05.20.05.50.05.60.05.80.05.60.03.2 Fuel Costs14.317.114.018.013.317.915.221.314.219.644.552.2 Variable Costs7.39.37.29.87.89.95.19.25.08.71.32.6 Fixed Costs11.314.811.115.512.116.77.813.18.013.03.05.7 Capital Costs43.459.141.761.548.269.231.260.231.759.610.122.3LCOE (mills/kWh, 2007$)1,296.7133.993.8139.9103.1151.475.3139.074.7135.274.7108.9Integrated Gasification Combined CyclePulverized Coal BoilerNGCCGEE R+QCoP E-Gas FSQShellPC SubcriticalPC Supercritical Advanced F Class Cost and Performance Baseline for Fossil Energy Plants 6 Exhibit ES-3 Net Plant Efficiency (HHV Basis) 39.0%32.6%39.7%31.0%42.1%31.2%36.8%26.2%39.3%28.4%50.2%42.8%0.0%10.0%20.0%30.0%40.0%50.0%60.0%GEEGEE w/CO2 CaptureCoPCoP w/ CO2 CaptureShellShell w/ CO2 CaptureSubcritical PCSubcritical PC w/ CO2 CaptureSupercritical PCSupercritical PC w/ CO2 CaptureNGCCNGCC w/ CO2 CaptureEfficiency, % (HHV Basis)

Cost and Performance Baseline for Fossil Energy Plants 7 Three water values are presented for each technology in Water Use Exhib it 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 CO 2 capture cases is 2.

4:1.4:1.0 (PC: IGCC: NGCC). The NGCC CO 2 capture case still has the lowest water consumption.

CO 2 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 CO 2 capture, PC normalized raw water consumption increases by 83 percent and NGCC by 9 1 percent. The large cooling water demand of the Econamine process drives this substantial increase for PC and NGCC

.

Cost and Performance Baseline for Fossil Energy Plants 8 Exhibit ES-4 Raw Water Withdrawal and Consumption 7.610.77.011.16.611.310.720.49.718.34.38.46.08.75.59.05.39.38.515.77.714.13.36.30.05.010.015.020.025.0GEEGEE w/CO2 CaptureCoPCoP w/ CO2 CaptureShellShell w/ CO2 CaptureSubcritical PCSubcritical PC w/ CO2 CaptureSupercritical PCSupercritical PC w/ CO2 CaptureNGCCNGCC w/ CO2 CaptureWater, gpm/MWnetRaw Water WithdrawalProcess DischargeRaw Water Consumption Cost and Performance Baseline for Fossil Energy Plants 9 COST RESULTS The Total Overnight Cost (TOC) for each plant was calculated by adding owner's 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).

Total Overnight Cost The cost estimates carry an accuracy of -15%/+30%, consistent with a "feasibility study" level o f 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 psi a 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.

CO 2 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 TO C 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.

Cost and Performance Baseline for Fossil Energy Plants 10 Exhibit ES-5 Plant Capital Cost s Note: TOC expressed in 2007 dollars

. TASC expressed in m ixed-year 2007 to 2011 year dollars for coal plants and 2007 to 2009 mixed-year dollars for NGCC

.2,4473,3342,3513,4662,7163,9041,9963,6102,0243,5707181,4972,7893,8012,6803,9523,0974,4512,2644,1152,2964,0707711,614 01,0002,0003,0004,0005,0006,000TOCTASCTOCTASCTOCTASCTOCTASCTOCTASCTOCTASCTOCTASCTOCTASCTOCTASCTOCTASCTOCTASCTOCTASCGEEGEE w/ CO2 CaptureCoPCoP w/ CO2 CaptureShellShell w/ CO2 CaptureSubcritical PCSubcritical PC w/ CO2 CaptureSupercritical PCSupercritical PC w/ CO2 CaptureNGCCNGCC w/ CO2 CaptureTOC or TASC, $/kWTASCOwner's CostProcess ContingencyProject ContingencyHome Office ExpenseBare Erected Cost Cost and Performance Baseline for Fossil Energy Plants 11 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 P C cases have the highest TOC at an average of $3,590/kW.

The average TOC for IGCC CO 2 capture cases is $

3,5 68/kW, which is less than one percent lower than the average of the P C cases. The process contingency for the IGCC capture cases ranges from $1 19-131/kW, for the PC cases from $100-105/kW and $60/kW for the NGCC case.

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 plant's 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) [Cost of Electricity 2] was used to determine a "base

-year" (2007) COE that, when escalated at an assumed nominal annual general inflation rate of 3

percent 1Exhibit ES-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 first year capital charge factor (CCF) shown in , 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 CO 2 capture) and the PC and NGCC cases with CO 2 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 Labor's 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.

Cost and Performance Baseline for Fossil Energy Plants 12 Exhibit ES-6 Economic Parameters Used to Calculate COE High Risk (5 year capital expenditure period) Low Risk (5 year capital expenditure period) High Risk (3 year capital expenditure period) Low Risk (3 year capital expenditure period) First Year Capital Charge Factor 0.1 243 0.11 65 0.1 111 0.1 048 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 CO 2 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 d efinitively 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 CO 2 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 CO 2 capture case.

The fuel component of COE ranges from 15

-19 percent for the IGCC cases and the PC CO 2 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 CO 2 capture case.

CO 2 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.

Cost and Performance Baseline for Fossil Energy Plants 13 Exhibit ES-7 COE by Cost Component 43.459.141.761.548.269.231.260.231.759.610.122.311.314.811.115.512.116.77.813.18.013.03.05.77.39.37.29.87.89.95.19.25.08.71.32.614.317.114.018.013.317.915.221.314.219.644.552.25.35.65.75.95.73.276.28105.6674.02110.3981.31119.4659.40109.6958.91106.6358.9085.93 020406080100120140160GEEGEE w/CO2 CaptureCoPCoP w/ CO2 CaptureShellShell w/ CO2 CaptureSubcritical PCSubcritical PC w/ CO2 CaptureSupercritical PCSupercritical PC w/ CO2 CaptureNGCCNGCC w/ CO2 CaptureCOE, mills/kWh (2007$)CO2 TS&M CostsFuel CostsVariable CostsFixed CostsCapital Costs Cost and Performance Baseline for Fossil Energy Plants 14 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 CO 2 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 $9.8 0/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 IGC C. Exhibit ES-8 COE Sensitivity to Fuel Costs in Non

-Capture Cases 40 50 60 70 80 90 100 3 4 5 6 7 8 9 10 11 12 13COE, mills/kWh (2007$)Natural Gas Price, $/MMBtuNGCCPC w/ coal at $1.23/MMBtuPC w/ coal at $1.64/MMBtuPC w/ coal at $2.05/MMBtuIGCC w/ coal at $1.23/MMBtuIGCC w/ coal at $1.64/MMBtuIGCC w/ coal at $2.05/MMBtu Cost and Performance Baseline for Fossil Energy Plants 15 Exhibit ES-9 COE Sensitivity to Fuel Costs in CO 2 Capture Cases The sensitivity of COE to CF is shown for all technologies in Exhibit ES-10. The subcritical and SC PC cases with no CO 2 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 CO 2 capture) show a greater increase in COE with decreased CF. Conversely, NGCC with no CO 2 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 CO 2 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.

40 50 60 70 80 90 100 110 120 130 140 3 4 5 6 7 8 9 10 11 12 13COE, mills/kWh (2007$)Natural Gas Price, $/MMBtuNGCCPC w/ coal at $1.23/MMBtuPC w/ coal at $1.64/MMBtuPC w/ coal at $2.05/MMBtuIGCC w/ coal at $1.23/MMBtuIGCC w/ coal at $1.64/MMBtuIGCC w/ coal at $2.05/MMBtu Cost and Performance Baseline for Fossil Energy Plants 16 Exhibit ES-10 COE Sensitivity to Capacity Factor 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 co al-based technologies will be impacted more than natural gas

-based technologies.

The most economically favored option for each technology is shown in C O 2 Emission Price Impact 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. 0 50 100 150 200 250 300 0 10 20 30 40 50 60 70 80 90 100COE, mills/kWh (2007$)Capacity Factor, %Shell w/CO2 captureSub PC w/CO2 captureSC PC w/CO2 captureCoP w/CO2 captureGEE w/CO2 captureShell no captureGEE no captureCoP no captureSub PC no captureNGCC w/CO2 captureSC PC no captureNGCC no captureCoal = $1.64/MMBtuNatural Gas = $6.55/MMBtu Cost and Performance Baseline for Fossil Energy Plants 17 Exhibit ES-11 Impact of Carbon Emissions Price on Study Technologies The intersection of the capture and non

-capture curves for a given technology gives the cost of CO 2 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 CO 2 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 emission s pric e 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 CO 2 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 CO 2 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 high er natural gas price of $9.50/MMBtu.

The SC PC and IGCC non-capture curves are nearly parallel indicating that the CO 2 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 (3 9.3 versus 3 9.7 percent net efficiency)

. The SC PC and GEE IGCC cases with CO 2 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 0 20 40 60 80 100 120 140 160 0 10 20 30 40 50 60 70 80 90 100COE, mills/kWh (2007$)First Year CO 2Emission Price, $/tonneNGCC w/Cap ($9.50/MMBtu)NGCC ($9.50/MMBtu)IGCC (GEE) w/CaptureIGCC (CoP)SCPC w/CaptureSCPCNGCC w/Capture ($6.55/MMBtu)NGCC ($6.55/MMBtu)

Cost and Performance Baseline for Fossil Energy Plants 18 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 $6 7/tonne ($6 1/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 CO 2 emission price of $3 0/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 CO 2 emissions price exceeds $

46/tonne ($42/ton). The relationship between technologies and CO 2 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 The plot demonstrates the following points:

Non-capture plants are the low cost option below a first year CO 2 price of $60/tonne ($54/ton).

0 2 4 6 8 10 12 14 16 18 20 0 10 20 30 40 50 60 70 80 90 100 110Natural Gas Price, $/MMBtuFirst Year CO 2Emission Price, $/tonneCOE parity between NGCC with CCSand IGCC with CCSCOE parity between Supercritical PC without CCS and IGCC with CCSSupercritical PC without CCShas lowest COENGCCwith CCShas lowest COEIGCCwith CCShas lowest COENGCCwithout CCShas lowest COE Cost and Performance Baseline for Fossil Energy Plants 19 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.

The first year cost of CO 2 avoided was calculated as illustrated in Equation ES

-1: Cost of CO2 Avoided MWhtonsEmissions COEmissions CO MWhCOECOECostAvoidedremovalwithreferencereferenceremovalwith/}{/$}{2 2 (ES-1) The COE with CO 2 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 CO 2 capture as the reference. The following conclusions can be drawn:

The total first year cost of CO 2 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.

C O 2 avoided costs for IGCC plants using analogous non

-capture plants as reference are substantially less than for PC and NGCC because the IGCC CO 2 removal is accomplished prior to combustion and at elevated pressure using physical absorption.

CO 2 avoided costs for IGCC plants using analogous non

-capture as reference are less than NGCC plants because the baseline CO 2 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 CO

2. CO 2 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.

CO 2 avoided cost s for NGCC using SC PC as the reference are 5 3 percent lower than IGCC and 5 0 percent lower than PC because of the relatively low COE of the NGCC capture plant compared to IGCC and PC.

Cost and Performance Baseline for Fossil Energy Plants 20 Exhibit ES-13 First Year CO 2 Avoided Costs 43 54 61 68 69 84 66 73 86 75 69 36 0 10 20 30 40 50 60 70 80 90 100GEECoPShellSubcritical PCSupercritical PCNGCCFirst Year CO 2Avoided Cost, $/tonne (2007$)Avoided Cost (Analogous Technology w/o Capture Reference)Avoided Cost (SC PC w/o Capture Reference)

Cost and Performance Baseline for Fossil Energy Plants 21 ENVIRONMENTAL PERFORM ANCE The environmental targets for each technology are summarized i n Exhibit ES-14. Emission rates of sulfur dioxide (SO 2), nitrogen oxide (NOx), and particulate matter (PM) are shown graphically i n 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 SO 2 0.0128 lb/MMBtu 0.085 lb/MMBtu Negligible NOx 15 ppmv (dry) @ 15% O 2 0.070 lb/MMBtu 2.5 ppmv (dry) @ 15% O 2 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 SO 2, 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), SO 2 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 O 2 and , coupled with a selective catalytic reduction (SCR) unit that achieve s 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 CO 2 capture cases, to achieve 9 5 percent CO 2 capture from the sy ngas, the sulfur Cost and Performance Baseline for Fossil Energy Plants 22 removal is greater than in the non

-capture cases resulting in emissions of approximately 0.00 09 kg/GJ (0.00 22 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 (N 2) dilution could limit IGCC NOx emissions to the environmental target of 15 ppmvd at 15 percent O

2. 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 SO 2, resulting in the environmental target of 0.037 kg/GJ (0.085 lb/MMBtu). In the CO 2 capture cases, the Econamine system employs a polishing scrubber to reduce emissions to

10 ppm v entering the CO 2 absorber. Nearly all of the remaining SO 2 is absorbed by the Econamine solvent resulting in negligible emissions of SO 2 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).

CO 2 emissions are not currently regulated. However, since there is increasing momentum for establishing carbon limits, it was a n objective of this study to examine the relative amounts of CO 2 capture achievable among the six technologies. CO 2 emissions are presented in Exhibit ES-17 for each case, normalized by net output. In the body of the report CO 2 emissions are presented on both a net and gross MWh basis. New Source Performance Standards (NSPS) contain emission limits for SO 2 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

CO 2 emissions are presented in both ways. The following conclusions can be drawn:

Cost and Performance Baseline for Fossil Energy Plants 23 Exhibit ES-15 SO 2, NOx , and Particulate Emission Rates 0.000.020.040.060.080.100.12GEEGEE w/CO2 CaptureCoPCoP w/ CO2 CaptureShellShell w/ CO2 CaptureSubcritical PCSubcritical PC w/ CO2 CaptureSupercritical PCSupercritical PC w/ CO2 CaptureNGCCNGCC w/ CO2 CaptureEmissions, lb/MMBtuSO2NOxParticulate Matter Cost and Performance Baseline for Fossil Energy Plants 24 Exhibit ES-16 Mercury Emission Rates 0.00.20.40.60.81.01.21.4GEEGEE w/CO2 CaptureCoPCoP w/ CO2 CaptureShellShell w/ CO2 CaptureSubcritical PCSubcritical PC w/ CO2 CaptureSupercritical PCSupercritical PC w/ CO2 CaptureNGCCNGCC w/ CO2 CaptureHg Emissions, lb/TBtu Cost and Performance Baseline for Fossil Energy Plants 25 In cases with no CO 2 capture , NGCC emits 5 6 percent less CO 2 than PC and 52 percent less CO 2 than IGCC per unit of net output. The lower NGCC CO 2 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 CO 2 reduction goal in this study was a nominal 90 percent in all cases. The result is that the controlled CO 2 emissions follow the same trend as the uncontrolled, i.e., the NGCC case emits less CO 2 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 CO 2. 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 CO 2 capture case resulted in 90.3 percent reduction of CO 2 in the syngas. The Shell capture case resulted in 90.1 percent reduction of CO 2 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 0.0 6 vol% in the Shell gasifier).

The CoP capture case resulted in 90.4 percent reduction of CO 2 in the syngas.

Among the three non-capture IGCC cases th e 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 CO 2 in the FG and that 90 percent is subsequently removed in the Econamine process, which was also supported by a vendor quote.

Cost and Performance Baseline for Fossil Energy Plants 26 Exhibit ES-17 C O 2 Emissions Normalized By Net Output 1,7232061,7102171,5952181,8882661,76824480494 0 5001,0001,5002,0002,500GEEGEE w/CO2 CaptureCoPCoP w/ CO2 CaptureShellShell w/ CO2 CaptureSubcritical PCSubcritical PC w/ CO2 CaptureSupercritical PCSupercritical PC w/ CO2 CaptureNGCCNGCC w/ CO2 Capture CO 2Emissions, lb/net

-MWh Cost and Performance Baseline for Fossil Energy Plants 27 1. The objective of this report i s 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: INTRODUCTION 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 o f 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 DOE's Clean Coal Program s Twelve different power plant design configurations were analyzed. The configurations are listed in Exhibit 1-1. The list includes s ix 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.

Cost and Performance Baseline for Fossil Energy Plants 28 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 CO 2 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 6 73 to 7 48 MW, which results in a range of net output from 49 7 (case 6) to 6 29 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/h r (4 37,000 to 487,000 lb/h r). Similar to the IGCC cases, the NGCC cases do not have a common net power output. Th e

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

CO 2 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 industry's 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 CO 2 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 des cribes 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 CO 2 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.

Cost and Performance Baseline for Fossil Energy Plants 29 Exhibit 1-1 Case Descriptions Case Unit Cycle Steam Cycle, psig/F/ F Combustion Turbine Gasifier/Boiler Technology Oxidant H 2S Separation/

Removal Sulfur Removal/ Recovery PM Control NOx Control CO 2 Separa-tion CO 2 Capture CO 2 Sequestra-tion 1 IGCC 1800/1050/1050 2 x Advanced F Class GEE Radiant Only 95 mol% O 2 Single-Stage Selexol Claus Plant Quench, scrubber and AGR adsorber N 2 dilution 2 IGCC 1800/1000/1000 2 x Advanced F Class GEE Radiant Only 95 mol% O 2 Two-Stage Selexol Claus Plant Quench, scrubber and AGR adsorber N 2 dilution Selexol 2 nd stage 90%1 Off-Site 3 IGCC 1800/1050/1050 2 x Advanced F Class CoP E-GasŽ 95 mol% O 2 Refrigerated MDEA Claus Plant Cyclone, barrier filter and scrubber N 2 dilution 4 IGCC 1800/1000/1000 2 x Advanced F Class CoP E-GasŽ 95 mol% O 2 Selexol Claus Plant Cyclone, barrier filter and scrubber N 2 dilution Selexol 2 nd stage 90%1 Off-Site 5 IGCC 1800/1050/1050 2 x Advanced F Class Shell 95 mol% O 2 Sulfinol-M Claus Plant Cyclone, barrier filter and scrubber N 2 dilution 6 IGCC 1800/1000/1000 2 x Advanced F Class Shell 95 mol% O 2 Selexol Claus Plant Cyclone, barrier filter and scrubber N 2 dilution Selexol 2 nd stage 90%1 Off-Site 9 PC 2400/1050/1050 Subcritical PC Air Wet FGD/ Gypsum Baghouse LNB w/OFA and SCR 10 PC 2400/1050/1050 Subcritical PC Air Wet FGD/ Gypsum Baghouse LNB w/OFA and SCR Amine Absorber 90% Off-Site 11 PC 3500/1100/1100 Supercritical PC Air Wet FGD/ Gypsum Baghouse LNB w/OFA and SCR 12 PC 3500/1100/1100 Supercritical PC Air Wet FGD/ Gypsum Baghouse LNB w/OFA and SCR Amine Absorber 90% Off-Site 13 NGCC 2400/1050/1050 2 x Advanced F Class HRSG Air LNB and SCR 14 NGCC 2400/1050/1050 2 x Advanced F Class HRSG Air LNB and SCR Amine Absorber 90% Off-Site 1 Defined as the percentage of carbon in the syngas that is captured; differences are explained in Chapter

3.

Cost and Performance Baseline for Fossil Energy Plants 30 This page intentionally left blank

Cost and Performance Baseline for Fossil Energy Plants 31 2. 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/buil d 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. GENERAL EVALUATION BASIS 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 chapter

s. 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 CO 2 Storage Compressed to 15.3 MPa (2,2 15 psi a), transported 80 kilometers (50 miles) and sequestered in a saline formation at a depth of 1,239 m (4,055 ft)

Cost and Performance Baseline for Fossil Energy Plants 32 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 NETL's Coal Quality Guidelines

[1The Power Systems Financial Model (PSFM) was used to derive the capital charge factors (CCF) and levelization factors (LF) for this study

[]. 2The 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 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 2007 minemouth cost of Illinois No. 6 in 2006 dollars, $32.66/tonne ($29.63/ton), was obtained from Supplemental Table 112 of the EIA's 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.)

Cost and Performance Baseline for Fossil Energy Plants 33 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 Cost and Performance Baseline for Fossil Energy Plants 34 2.3 NATURAL GAS CHARACTERISTICS Natural gas is utilized as the main fuel in Cases 13 and 14 (NGCC with and without CO 2 capture), and its composition is presented in Exhibit 2-4 [5Exhibit 2-4 Natural Gas Composition

]. Component Volume Percentage Methane CH 4 93.1 Ethane C 2 H 6 3.2 Propane C 3 H 8 0.7 n-Butane C 4 H10 0.4 Carbon Dioxide CO 2 1.0 Nitrogen N 2 1.6 Total 100.0 LHV HHV kJ/kg 47, 454 5 2 , 581 MJ/scm 3 4.71 38.46 Btu/lb 20, 410 22, 600 Btu/scf 9 32 1,0 3 2 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) (20 07 cost of natural gas in 2007 dollars). The cost was determined using the following information from the EIA's 2008 AEO: The 20 07 East North Central region delivered cost of natural gas to electric utilities in 2006 dollars, $

231.47/1000 m 3 ($6.5 5/1000 ft 3), was obtained from the AEO 2008 reference case Table 108 and converted to an energy basis, $6.02/MMkJ ($6.35/MMBtu).

The 20 07 cost was escalated to 2007 dollars using the GDP chain

-type price index from AEO 200 8, resulting in a delivered 20 07 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 TARGET S 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 Cost and Performance Baseline for Fossil Energy Plants 35 minimum level of control that would be required for a new fossil energy plant

[6Exhibit 2-5 Standards of Performance for Electric Utility Steam Generating Units

]. Stationary CT emission limits are further defined in 40 CFR Part 60, Subpart KKKK.

Built, Reconstructed, or Modified After February 28, 2005 New Units Reconstructed Units Modified Units Emission Limit % Reduction Emission Limit (lb/MMBtu)

% Reduction Emission Limit (lb/MMBtu)

% Reduction PM 0.015 lb/MMBtu 99.9 0.015 99.9 0.015 99.8 SO 2 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

[7In 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 200 9, 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 , t he 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.

Cost and Performance Baseline for Fossil Energy Plants 36 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 [9Exhibit 2-7]. Hence, as illustrated in , 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 0%10%20%30%40%50%

60%

70%

80%90%100%0.00 ppm Hg0.05 ppm Hg0.10 ppm Hg0.15 ppm Hg0.20 ppm Hg0.25 ppm Hg0.30 ppm HgMercury Concentraion in Coal, ppm dbProbability Illinois #6 Sample Will Be At or Below ValueP:\X_GEMSET\0_GEMSET Fuels Price Database\Rev.0 Fuels\[IllinoisNo6 Mercury.xls] Rev. 00 11/21/05 10:Arithmetic Mean = 0.09 ppm dbStandard Deviation = 0.06 ppm db Cost and Performance Baseline for Fossil Energy Plants 37 2.4.1 The IGCC environmental targets were chosen to match the EPRI

's design basis for their CoalFleet for Tomorrow Initiative and are shown in IGCC Exhibit 2-8 [10Exhibit 2-8 Environmental Targets for IGCC Cases

]. EPRI notes that these are design targets and are not to be used for permitting values.

Pollutant Environmental Target NSPS Limit 1 Control Technology NOx 15 ppmv (dry)

@ 15% O 2 1.0 lb/MWh (0.091 lb/MMBtu)

Low NOx burners and syngas nitrogen dilution SO 2 0.0128 lb/MMBtu 1.4 lb/MWh (0.127 lb/MMBtu)

Selexol, MDEA or Sulfinol (depending on gasifier technology)

Particulate Matter (Filterable) 0.0071 lb/MMBtu 0.015 lb/MMBtu Quench, water scrubber, and/or cyclones and candle filters (depending on gasifier technology)

Mercury > 90% capture 20 x 10-6 lb/MWh (1.8 lb/TBtu)

Carbon bed 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 CO 2 capture. Based on published vendor literature, it was assumed that LNB s and nitrogen dilution can achieve 15 ppmv d at 15 percen t O 2, and that value was used for all IGCC cases

[11 , 12To achieve an environmental target of 0.0128 lb/MMBtu of SO 2 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 CO 2 capture cases, the two

-stage Selexol process was designed for 95 percent CO 2 removal , which results in a sulfur capture of greater than 99.7 percent, hence the lower sulfur emissions in the CO 2 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 Cost and Performance Baseline for Fossil Energy Plants 38 reached. Eastman has yet to experience any mercury contamination in its product

[13 2.4.2 ]. 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.

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 PC 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 SO 2 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 Pollutant Environmental Target NSPS Limit Average of Recent Permits Control Technology NOx 0.07 lb/MMBtu 1.0 lb/MWh (0.111 lb/MMBtu) 0.08 lb/MMBtu Low NOx burners, overfire air and SCR SO 2 0.085 lb/MMBtu 1.4 lb/MWh (0.156 lb/MMBtu) 0.16 lb/MMBtu Wet limestone scrubber Particulate Matter (Filterable) 0.013 lb/MMBtu 0.015 lb/MMBtu 0.017 lb/MMBtu Fabric filter Mercury 1.14 lb/TBtu 20 x 10-6 lb/MWh (2.2 lb/TBtu) 2.49 lb/TBtu Co-benefit capture Cost and Performance Baseline for Fossil Energy Plants 39 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]. EPA's 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 EPA's Information Collection Request (ICR) data on U.S. coal

-fired boilers using bituminous coal, fabric filters , and wet FGD is 98 percent

[16Since co-benefit capture alone exceeds the requirements of NSPS and recent permit averages, no activated carbon injection is included in this study.

]. 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.

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

N/A N/A N/A 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 O 2 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.

Cost and Performance Baseline for Fossil Energy Plants 40 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/Nm 3 (950 and 1,100 Btu/scf) and having a total sulfur content of less than 13.7 mg/Nm 3 (0.6 gr/100 scf)

[19The pipeline natural gas was assumed to contain no particulate matter (PM) and no mercury resulting in no emissions of either.

]. Assuming a sulfur content equal to the EPA limit for pipeline natural gas, resulting SO 2 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, SO 2 emissions were considered negligible.

2.4.4 CO 2 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 CO 2 emissions. Because the form of emission limits, should they be imposed, is not known, CO 2 emissions are reported on both a lb/(gross) MWh and lb/(net) MWh basis in each capture case emissions table.

Carbon Dioxide For the IGCC cases that have CO 2 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 CO 2, and a tw o-stage Selexol process with a second stage CO2 removal efficiency of 92 percent, a number that was supported by vendor quotes. The GEE CO 2 capture case resulted in 90.3 percent reduction of CO 2 in the syngas. The Shell capture case resulted in 90.1 percent reduction of CO 2 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 CO 2 in the syngas.

For PC and NGCC cases that have CO 2 capture, it is assumed that all of the fuel carbon is converted to CO 2 in the FG. CO 2 is also generated from limestone in the FGD system, and 90 percent of the CO 2 exiting the FGD absorber is subsequently captured using the Econamine technology.

The cost of CO 2 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 CO 2 capture cases includes TS&M as well as capture and compression.

MWhtonsEmissions COEmissions CO MWhCOECOECostAvoidedremovalwithreferencereferenceremovalwith/}{/$}{2 2 Cost and Performance Baseline for Fossil Energy Plants 41 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) [20NERC 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 study's definition of CF. ]. 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.

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 [21There are four operating IGCC's 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

[]. 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), o r 81.2 percent. 22The addition of CO 2 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 CO 2 capture cases.

]. 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.

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 CO 2 capture cases) was applied to offset the water demand. The difference between demand and recycle is raw Cost and Performance Baseline for Fossil Energy Plants 42 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 CO 2 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 As illustrated in Capital Costs 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 Cost and Performance Baseline for Fossil Energy Plants 43 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

The BECThe 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.

TPCThe 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.

TOCThe comprises the TPC plus owner's 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.

TASCprocess equipmentsupporting facilitiesdirect and indirect laborBEC TPCTOCTASCEPC contractor servicesprocess contingencyproject contingencypreproduction costsinventory capitalfinancing costsother owner's costsescalation during capital expenditure periodinterest on debt during capital expenditure periodBare Erected CostTotal Plant CostTotal Overnight CostTotal As-Spent CostBEC, TPC and TOC are all "overnight" costs expressed in base-year dollars.TASC is expressed in mixed

-year current dollars, spread over the capital expenditure period. 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.

Cost and Performance Baseline for Fossil Energy Plants 44 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

[24Most 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 stud y have an expected accuracy range of -15%/+30%. Exhibit 2-12 Features of an AACE Class 4 Cost Estimate Project Definition Typical Engineering Completed Expected Accuracy 1 to 15% plant capacity, block schematics, indicated layout, process flow diagrams for main process systems, and preliminary engineered process and utility equipment lists

-15% to -30% on the low side, and +20% to +50% on the high side 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-CO 2 Capture Plant Maturity The case estimates provided include technologies at different commercial maturity levels. The estimates for the non

-CO 2-capture PC and NGCC cases represent well

-developed commercial technology or "n th 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

-CO 2-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 n th-of-a-kind (NOAK) cost. Thus, each of these cases reflect s the expected cost for the next commercial sale of each of these respective technologies.

CO 2 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.

Cost and Performance Baseline for Fossil Energy Plants 45 The pre-combustion CO2 removal technology for the IGCC capture cases has a stronger commercial experience base. Pre

-combustion CO 2 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 CO 2 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 today's 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 company's 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 company's 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

.

Cost and Performance Baseline for Fossil Energy Plants 46 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 a t 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 Cost and Performance Baseline for Fossil Energy Plants 47 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 GE E IGCC cases include s a syngas expander

, which is not required for the Co P or Shell cases.

The C Ts 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 CO 2-capture and non-CO 2-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.

Cost and Performance Baseline for Fossil Energy Plants 48 As shown in Exhibit 2-13, AACE International Recommended Practice 16R

-90 provides guidelines for estimating process contingency based on EPRI philosophy

[25Process 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 psi a 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 CO 2 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 Technology Status Process Contingency

(% 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.

Cost and Performance Baseline for Fossil Energy Plants 49 Owner's Costs Exhibit 2-15 explains the estimation method for owner's 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 Institute's "Technical Assessment Guide (TAG)

- Power Generation and Storage Technology Options" also has guidelines for estimating owner's 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 owner's 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 Cost and Performance Baseline for Fossil Energy Plants 50 Exhibit 2-15 Owner's Costs Included in TOC Owner's Cost Estimate Basis Prepaid Royalties Any technology royalties are assumed to be included in the associated equipment cost, and thus are not included as an owner's cost.

Preproduction (Start-Up) Costs 6 months operating labor 1 month maintenance materials at full capacity 1 month non

-fuel consumables at full capacity 1 month waste disposal 25% of one month's fuel cost at full capacity 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 Capital Although inventory capital (see below) is accounted for, no additional costs are included for working capital.

Inventory Capital 0.5% of TPC for spare parts 60 day supply (at full capacity) of fuel. Not applicable for natural gas.

60 day supply (at full capacity) of non

-fuel consumables (e.g., chemicals and catalysts) that are stored on site. Does 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)

Financing Cost 2.7% of TPC This financing cost (not included by AACE 16R

-90) covers the cost of securing financing, including fees and closing costs 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.

Cost and Performance Baseline for Fossil Energy Plants 51 Owner's Cost Estimate Basis Other Owner's Costs 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

- Owner's 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) - Owner's contingency (Sometimes called "management reserve", these are funds to cover costs relating to delayed startup, fluctuations in equipment costs, unplanned labor incentives in excess of a five

-day/ten-hour-per-day work week. Owner's 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 tax es. - 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.

Cost and Performance Baseline for Fossil Energy Plants 52 2.7.2 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:

Operations and Maintenance Costs Operating labor Maintenance

- material and labor Administrative and support labor Consumables Fuel Waste disposal Co-p roduct or b y-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 $3 4.65/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.

Cost and Performance Baseline for Fossil Energy Plants 53 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 ($8 40/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 For those cases that feature carbon sequestration, the capital and operating costs for CO 2 TS&M were independently estimated by NETL. Those costs were converted to a TS&M COE increment that was added to the plant COE.

CO 2 Transport, Storage and Monitoring CO 2 TS&M was modeled based on the following assumptions:

CO 2 is supplied to the pipeline at the plant fence line at a pressure of 15.3 MPa (2,215 psia). The CO 2 product gas composition varies in the cases presented, but is expected to meet the specification described in Exhibit 2-16 [26Exhibit 2-16 CO 2 Pipeline Specification

]. A glycol dryer located near the mid-point of the compression train is used to meet the moisture 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) N 2 Concentration ppmv < 300 O 2 Concentration ppmv < 40 Ar Concentration ppmv < 10 H 2O Concentration ppmv < 150 Cost and Performance Baseline for Fossil Energy Plants 54 The CO 2 is transported 80 km (50 miles) via pipeline to a geologic sequestration field for injection into a saline formation.

The CO 2 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, CO 2 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 The saline formation is at a depth of 1,23 6 m (4,055 ft) and has a permeability of 22 millidarcy (md) 2) and formation pressure of 8.4 MPa (1,220 psig)

[]. (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.

29 29]. This is considered an average storage site and requires roughly one injection well for each 9,360 tonnes (10,320 short tons) of CO 2 injected per day

[]. 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 M d 22 Pipeline Distance km (miles) 80 (50) Injection Rate per Well tonne (ton) CO 2/day 9,360 (10,320)

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

Cost and Performance Baseline for Fossil Energy Plants 55 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 CO 2 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 Journal's (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 CO 2 pipeline, as noted in various studies

[27 , 29 , 30 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

[]. 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 CO 2 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 CO 2 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 CO 2 Storage and Sink Enhancement Options

[27]. These costs include all of the costs associated with determining, developing, and maintaining a CO 2 storage location, including site evaluation, well drilling, and the capital equipment required for distributing and injecting CO

2. Pore Volume Acquisition costs are the costs associated with acquiring rights to use the sub

-surface volume where the CO 2 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 CO 2 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 Cost and Performance Baseline for Fossil Energy Plants 56 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 CO 2, the injecting party may bear financial liability. Several types of liability protection schem es have been suggested for CO 2 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 , 35Liability 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.

]. 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 CO 2 monitoring and, in the event of an at

-fault incident, damage payments.

Monitoring Costs Monitoring costs were evaluated based on the methodology set forth in the International Energy Agency (IEA) Greenhouse Gas (GHG) R&D Programme's Overview of Monitoring Projects for Geologic Storage Projects report

[36 2.7.4 ]. In this scenario, operational monitoring of the CO 2 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.

The global economic assumptions are listed in Finance Structure, Discounted Cash Flow Analysis, and COE 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 CO 2 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 Cost and Performance Baseline for Fossil Energy Plants 57 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 Contracting Strategy Engineering Procurement Construction Management (owner assumes project risks for performance, schedule and cost)

Type of Debt Financing Non-Recourse (collateral that secures debt is 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 Capital Expenditure Period Natural Gas Plants: 3 Years Coal Plants: 5 Years Operational Period 30 years Economic Analysis Period (used for IRROE) 33 or 35 Years (capital expenditure period plus operational period)

TREATMENT OF CAPITAL COSTS Capital Cost Escalation During Capital Expenditure Period (nominal annual rate) 3.6%2Distribution of Total Overnight Capital over the Capital Expenditure Period (before escalation) 3-Year Period: 10%, 60%, 30%

5-Year Period: 10%, 30%, 25%, 20%, 15%

Working Capital zero for all parameters

% of Total Overnight Capital that is Depreciated 100% (this assumption introduces a very small error even if a substantial amount of TOC is actually non

-depreciable)

ESCALATION OF OPERATING REVENUES AND COSTS Escalation of CO E (revenue), O&M Costs, and Fuel Costs (nominal annual rate) 3.0%3 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.)

Cost and Performance Baseline for Fossil Energy Plants 58 Exhibit 2-19 Financial Structure for Investor Owned Utility High and Low Risk Projects Type of Security % of Total Current (Nominal) Dollar Cost Weighted Current (Nominal) Cost After Tax Weighted Cost of 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 5Exhibit 2-20 in two ways: a COE and a levelized COE (LCOE).

To illustrate how the two are related, COE solutions are shown in 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 plant's 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 6Exhibit 2-20, 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 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 plant's 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 customer's 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 Labor's 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.

Cost and Performance Baseline for Fossil Energy Plants 59 The LEVELIZED COE is the revenue received by the generator per net megawatt

-hour during the power plant's 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 7Exhibit 2-20. "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 bas e-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 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.

Cost and Performance Baseline for Fossil Energy Plants 60 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.

Cost and Performance Baseline for Fossil Energy Plants 61 Exhibit 2-21 PC with CCS in Current 2007 Dollars For scenarios that adhere to the global economic assumptions listed in Estimating COE with Capital Charge Factors 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 8Exhibit 2-22, 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 . 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).

Cost and Performance Baseline for Fossil Energy Plants 62 Exhibit 2-22 Capital Charge Factors for COE Equation Finance Structure High Risk IOU Low Risk IOU 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

-yea r costs when expressed in base

-year (2007) dollars.

where: COE = revenue received by the generator ($/MWh, equivalent to mills/kWh) during the power plant's 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 Cost and Performance Baseline for Fossil Energy Plants 63 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 Case COE LCOE Base-Year First Operational Year Base-Year First Operational Year 2007$ (all cases) 2010$ (NGCC cases) 2012$ (coal cases) 2007$ (all cases) 2010$ (NGCC cases) 2012$ (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 7 4.65 8 1.58 N/A 14 85.93 93.89 N/A 10 8.9 3 119.03 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

- CO 2 capture cases and $

3,334/kW to $3,904/kW for capture cases. Plant size ranges from 62 2 - 6 29 MW (net) for non

-capture cases and 497 - 5 43 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 Energy's 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

-CO 2 capture gasification plants range from $2,483/kW to $3,122/kW in June 2007 dollars.

Corresponding plant sizes range form 770 - 600 Cost and Performance Baseline for Fossil Energy Plants 64 MW , respectively.

Published estimates from similar CO 2 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 Project Scope Differences in Cost Estimates 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

Cost and Performance Baseline for Fossil Energy Plants 65 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 o f the equipment is sized to accommodate a future conversion to CO 2 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.

Cost and Performance Baseline for Fossil Energy Plants 66 This page intentionally left blank

Cost and Performance Baseline for Fossil Energy Plants 67 3. 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.

IGCC POWER PLANTS The six cases are based on the GEE gasifier, the CoP E

-GasŽ gasifier and the Shell gasifier, each with and without CO 2 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 CO 2 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/5 59°C/5 59°C (1800 psig/1038°F/10 38°F) to 12.4 MPa/562°C/562°C (1800 psig/1043°F/1043°F) for all of the non

-CO 2 capture cases and 12.4 MPa/53 4°C/53 4°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 CO 2 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 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. Coal Receiving and Storage 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.

Cost and Performance Baseline for Fossil Energy Plants 68 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 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)

[Air Separation Unit (ASU) Choice and Integration 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 GT's air compressor.

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.

Residual Nitrogen Injection 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/Nm 3 (119-12 5 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.

Integration between the ASU and the CT can be practiced by extracting some, or all, of the ASU's 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 Air Integration

Cost and Performance Baseline for Fossil Energy Plants 69 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.

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. Elevated Pressure ASU Experience in Gasification 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]. For this study, air integration is used for the non

-carbon capture cases only. In the CO 2 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.

ASU Basis 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/Nm 3 (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].

Cost and Performance Baseline for Fossil Energy Plants 70 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

[46The air separation plant is designed to produce 95 mole percent (mol%) O 2 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-CO 2 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, CO 2, and C 4+ 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 of f-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.

Cost and Performance Baseline for Fossil Energy Plants 71 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 AirAir FilterMain AirCompressorCWSCWRSteam Cond.1st StageDCA2nd StageDCAPrepurifiersBooster AirCompressorTurbine Air BoosterRegen HeaterSteam Cond.RegenerationNitrogenRegen. N2 BlowerLiq. Oxygen PumpTurbineCryogenic AirSeparation UnitSingle TrainGT NitrogenHP OxygenOxygenCompressorGT NitrogenCompressorChillerAir from Gas TurbineCWSCWR Cost and Performance Baseline for Fossil Energy Plants 72 3.1.3 Selection of Technology

- In the cases with CO 2 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 (H 2) and CO 2 by reacting the CO with water over a bed of catalyst. The H 2O: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 CO 2 separation and capture, CO shift convertors are not required.

Water Gas Shift Reactors Water Gas Shift:

CO + H 2 O CO 2 + H 2 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 CO 2 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 CH 4 present in the syngas. With the third reactor added, CO 2 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 CO 2 capture cases the heat exchanger after the first SGS reactor is used to vaporize water that is then used to adjust the syngas H 2O: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 9 7 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 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

[Mercury Removal 13].

Cost and Performance Baseline for Fossil Energy Plants 73 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

-CO 2 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 13]. Eastman Chemical also operates their beds ahead of their SRU at a temperature of 30°C (86°F)

[]. 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 Chemical's 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/ft 3 was based on the Calgon Carbon Corporation HGR

-P sulfur-impregnated pelletized activated carbon

[48Carbon Replacement Time

- Eastman Chemicals replaces its bed every 18 to 24 months []. 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.

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 b e as high as 20 wt% [49 3.1.5 ]. The mercury laden carbon is considered to be a hazardous waste, and the disposal cost estimate reflects this categorization.

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 SO 2/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 H 2S, thereby resulting in stack gas emissions of less than 4 ppmv SO 2. Acid Gas Removal (AGR) Process Selection 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 COS Hydrolysis

Cost and Performance Baseline for Fossil Energy Plants 74 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 CO 2 capture, the SGS reactors reduce COS to H 2S 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 + H 2 O CO 2 + H 2 S 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 H 2S 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 H 2S and CO to form COS and H

2. 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.

H 2 S 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. Sulfur Removal Exhibit 3-3 is a simplified diagram of the AGR process

[50There 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.

Cost and Performance Baseline for Fossil Energy Plants 7 5 Exhibit 3-3 Flow Diagram for a Conventional AGR Unit 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.

Chemical Solvents 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 H 2S in the presence of CO 2, 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 H 2S 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.

Treated GasCooler Lean SolventL/R ExchangerRich SolventAbsorberLean SolventPumpReboilerStripperAcid GasCondenser Feed GasTreated GasCooler Lean SolventL/R ExchangerRich SolventAbsorberLean SolventPumpReboilerStripperAcid GasCondenser Feed Gas Cost and Performance Baseline for Fossil Energy Plants 76 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 Methyldiethanolamine MDEA BASF, Dow, Elf, Snamprogetti, Shell, Union Carbide, Coastal Chemical Hindered amine Exxon Potassium carbonate "hot pot" Eickmeyer, Exxon, Lurgi, 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 H 2S partial pressures.

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 (Henry's 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.

Physical Solvents 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 H 2S than CO 2, they can be designed for selective H 2S or total AGR. In applications where CO 2 capture is desired the CO 2 is flashed off at various pressures, which reduces the compression work and parasitic power load associated with sequestration.

Cost and Performance Baseline for Fossil Energy Plants 77 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 CO 2 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 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.

Hybrid Solvents 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 H 2 S. Treated GasCooler Lean SolventL/R ExchangerRich Solvent Feed GasAbsorberLean SolventPumpReboilerStripperAcid GasCondenserFlash GasTreated GasCooler Lean SolventL/R ExchangerRich Solvent Feed GasAbsorberLean SolventPumpReboilerStripperAcid GasCondenserFlash Gas Cost and Performance Baseline for Fossil Energy Plants 78 Exhibit 3-6 Common Physical Solvents Used in AGR Processes Solvent Solvent/Process Trade Name Process Licensors Dimethyl ether of poly

-ethylene glycol Selexol UOP Methanol Rectisol Linde AG and Lurgi Methanol and toluene Rectisol II Linde AG N-methyl pyrrolidone Purisol Lurgi Polyethylene glycol and dialkyl ethers Sepasolv MPE BASF 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 CO 2 and 4 ppmv of H 2S, 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 H 2S and, in some cases, COS to meet very stringent purified gas specifications.

Exhibit 3-8 shows reported equilibrium solubility data for H 2S and CO 2 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 CO 2 and H 2S in different solvents and the effects of temperature. More importantly, it shows an order of magnitude higher solubility of H 2S over CO 2 at a given temperature, which gives rise to the selective absorption of H 2S in physical solvents. It also illustrates that the acid gas solubility in physical solvents increases with lower solvent temperature

s.

Cost and Performance Baseline for Fossil Energy Plants 79 Exhibit 3-7 Common Mixed Solvents Used in AGR Processes Solvent/Chemical Reagent Solvent/Process Trade Name Process Licensors Methanol/MDEA or diethylamine Amisol Lurgi Sulfolane/MDEA or DIPA Sulfinol Shell Methanol and toluene Selefining Snamprogetti (Unspecified) /MDEA FLEXSORB PS Exxon Exhibit 3-8 Equilibrium Solubility Data on H 2S and CO 2 in Various Solvents

Cost and Performance Baseline for Fossil Energy Plants 80 The ability of a process to selectively absorb H 2S may be further enhanced by the relative absorption rates of H 2S and CO 2. 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 CO 2 and H 2S absorption rates are very different.

A two-stage Selexol process is used for all IGCC CO 2 capture cases in this study. A brief process description follows. AGR used in CO 2 Capture Cases Untreated syngas enters the first of two absorbers where H 2S is preferentially removed using loaded solvent from the CO 2 absorber. The gas exiting the H 2S absorber passes through the second absorber where CO 2 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 CO 2 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 CO 2 loaded solvent exits the CO 2 absorber , and a portion is sent to the H 2S absorber, a portion is sent to a reabsorber and the remainder is sent to a series of flash drums for regeneration. The CO 2 product stream is obtained from the three flash drums, and after flash regeneration the solvent is chilled and returned to the CO 2 absorber. The rich solvent exiting the H 2S 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 H 2S concentrator and partially flashes. The remaining liquid contacts nitrogen from the ASU and a portion of the CO 2 along with lesser amounts of H 2S and COS are stripped from the rich solvent. The stripped gases from the H 2S concentrator are sent to the reabsorber where the H 2S and COS that were co

-stripped in the concentrator are transferred to a stream of loaded solvent from the CO 2 absorber. The clean gas from the reabsorber is combined with the clean gas from the H 2S absorber and sent to the CT. The solvent exiting the H 2S 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 CO 2 absorber. 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 GE E gasifiers in various applications. Both existing E

-Gas gasifiers use MDEA, but could in theory use any of the existing AGR technologies

[AGR/Gasifier Pairings 50]. The following selections were made for the AGR process in non

-CO 2 capture cases:

Cost and Performance Baseline for Fossil Energy Plants 81 GE E 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 websit e [51 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.

]. 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.

The two-stage Selexol process is used in all three cases that require CO 2 capture. According to the previously referenced SFA Pacific report, "For future IGCC with CO 2 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 Currently, most of the world's 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 H 2S 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. Sulfur Recovery/Tail Gas Cleanup Process Selection 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 converts H 2S to elemental sulfur via the following reactions:

The Claus Process H 2S + 3/2 O 2 H 2O + SO 2 2H 2S + SO 2 2H 2O + 3S The second reaction, the Claus reaction, is equilibrium limited. The overall reaction is:

3H 2S + 3/2 O 2 3H 2O + 3S The sulfur in the vapor phase exists as S 2 , S 6, and S8 molecular species, with the S 2 predominant at higher temperatures, and S 8 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 H 2S is burned in the furnace with oxygen from the air to give sufficient SO 2 to react with the remaining H 2S. 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, Cost and Performance Baseline for Fossil Energy Plants 82 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. 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.

Claus Plant Sulfur Recovery Efficiency Exhibit 3-9 Typical Three

-Stage Claus Sulfur Plant Claus plant sulfur recovery efficiency depends on many factors:

H 2S 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 H 2S, 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 SO

2. This results in a more stable temperature in the furnace.

Large diluent streams in the feed to the Claus plant, such as N 2 from combustion air, or a high CO 2 content in the feed gas, lead to higher cost Claus processes and any add

-on or tail gas units. Oxygen-Blown Claus

Cost and Performance Baseline for Fossil Energy Plants 83 One way to reduce diluent flows through the Claus plant and to obtain stable temperatures in the furnace for dilute H 2S 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 H 2S 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 H 2 S 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% O 2 in the oxidant feed stream. Although oxygen enrichment has many benefits, its primary benefit for lean H 2S 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.

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, C S 2 , H 2S, SO 2, and elemental sulfur vapors. In addition, there may be H 2, CO, and CO 2 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 H 2S. Then, the resulting H 2S 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.

Tail Gas Treating 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.

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.

Flare Stack

Cost and Performance Baseline for Fossil Energy Plants 84 3.1.7 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 a nd 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.

Slag Handling 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 roa d 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 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 CO 2 capture. High H 2 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 Combustion Turbine Exhibit 3-10.

Cost and Performance Baseline for Fossil Energy Plants 85 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 (Btu/kWh) 6,256 (5,934)

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.

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.

Combustion Turbine Package Scope of Supply 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

[CT Firing Temperature Control Issue for Low Calorific Value Fuel 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. IGV s 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.

Cost and Performance Baseline for Fossil Energy Plants 86 In this study the firing temperature (defined as inlet rotor temperature) using natural gas in NGCC applications is 13 71°C (25 00°F) while the firing temperature in the n on-capture IGCC cases is 13 3 3-1343°C (2432-2449°F) and in the CO 2 capture cases is 131 7-132 2°C (2402-2412°F). The further reduction in firing temperature in the CO 2 capture cases is done to maintain parts life as the H 2O content of the combustion products increases from 6-9 vol% in the non-capture cases to 1 2-1 4 vol% in the capture cases. The decrease in temperature also results in the lower temperature steam cycle in the CO 2 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 CO 2 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

-

CO 2 capture cases

. Typical fuel specifications and contaminant levels for successful CT operation are provided in reference [Combustion Turbine Syngas Fuel Requirements 54Exhibit 3-11] and presented for F Class machines in 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/m 3 (Btu/scf) None 3.0 (100) Gas Fuel Pressure, MPa (psia) 3.1 (450) Gas Fuel Temperature, °C ( F) (1) Varies with gas pressure (2)

Flammability Limit Ratio, Rich

-to-Lean, Volume Basis (3) 2:2.1 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.

Cost and Performance Baseline for Fossil Energy Plants 87 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 CO 2 capture cases as well; however, in this study integration was considered only for non

-carbon capture cases.

Normal Operation Exhibit 3-12 Allowable Gas Fuel Contaminant Level for F

-Class Machines Turbine Inlet Limit, ppbw Fuel Limit, ppmw Turbine Inlet Flow/Fuel Flow 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 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/Nm 3 (119-125 Btu/scf). The advantages of using nitrogen as the primary diluent include:

Cost and Performance Baseline for Fossil Energy Plants 88 Nitrogen from the ASU is already partially compressed and using it for dilution eliminates wasting the compression energ

y. Limiting the water content reduces the need to de

-rate firing temperature, particularly in the high-hydrogen (CO 2 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 fo r 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 (1 090°F) for non

-CO 2 capture cases and 56 2°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 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.

Heat Recovery Steam Generator 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.

Cost and Performance Baseline for Fossil Energy Plants 89 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.

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). Steam Turbine Generator and Auxiliaries 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 Cost and Performance Baseline for Fossil Energy Plants 90 algorithms, color cathode ray tube (CRT) operator interfacing, and datalink interfaces to the balance-of-plant DCS, and incorporates on

-line repair capability.

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.

Condensate 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.

Feedwater System 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.

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 and Reheat Steam Systems Main steam at approximately 12.4 MPa/559°C to 562°C (1800 psig/1038°F to 1043°F)

(non- CO 2 capture cases) or 12.4 MPa/534°C (1800 psig/993°F to 994

°F) (CO 2 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 CO 2 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.

Cost and Performance Baseline for Fossil Energy Plants 91 Safety valves are installed to comply with appropriate codes and to ensure the safety of personnel and equipment.

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.

Circulating Water System 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 singl e-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.

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.

Raw Water, Fire Protection, and Cycle Makeup Water Systems 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 CO 2 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.

Cost and Performance Baseline for Fossil Energy Plants 92 3.1.10 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.

Accessory Electric Plant 3.1.11 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. Instrumentation and Control 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.

Cost and Performance Baseline for Fossil Energy Plants 93 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 2 89°C (5 50°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 (1 250°F), then through a water quench where the syngas is further cooled to about 2 32°C (4 50°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 Electric's 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.

Cost and Performance Baseline for Fossil Energy Plants 94 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 Development and Current Status

[Gasifier Background 57The 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.

] - Initial development of the GEE gasification technology (formerly licensed by Texaco and then ChevronTexaco) was conducted in the 1940s at Texaco's 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 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 H 2, and have no SGC s. 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 (MW e). 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 H 2S. After additional cooling, the syngas is sent to a conventional AGR unit, where H 2S is absorbed by reaction with an amine solvent. H 2S is removed from the amine by steam stripping and sent to a sulfuric acid (H 2 SO 4) plant. The cleaned gas is sent to a General Electric MS 7001FA CT.

Cost and Performance Baseline for Fossil Energy Plants 95 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 Motiva's Delaware City Plant and produce a nominal 238,136 kg/h r (525,000 lb/h r) of 8.6 MPa (125 0 psig) steam, and 120,656 kg/h r (266,000 lb/h r) 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 NO x and SO 2 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 Nm 3/h r (6.7 million scfh) with an energy content of about 1,897 million kJ/h r (HHV) (1,800 million Btu/h r). 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 H 2/CO ratio and CO 2 content of GEE gasification fuel gas helps achieve low NO x and CO emissions in even the higher

-temperature advanced CT s. 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.

Cost and Performance Baseline for Fossil Energy Plants 96 3.2.2 In this section the overall GEE gasification process is described. The system description follows the block flow diagram (BFD) in Process Description Exhibit 3-1 3 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 receiving and handling is common to all cases and was covered in Section Coal Grinding and Slurry Preparation 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

[58The 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).

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.

Gasification 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.

Cost and Performance Baseline for Fossil Energy Plants 97 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 (2,400F) 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.

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/h r (908,5 00 lb/h r) 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.

Raw Gas Cooling/Particulate Removal 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 exiting the water quench passes to a syngas scrubber where a water wash is used to remove remaining chlorides, NH 3, SO 2 , 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

. Syngas Scrubber/Sour Water Stripper The sour water stripper removes NH 3, SO 2, 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.

Cost and Performance Baseline for Fossil Energy Plants 98 Exhibit 3-13 Case 1 Block Flow Diagram, GEE IGCC without CO 2 Capture Cost and Performance Baseline for Fossil Energy Plants 99 Exhibit 3-14 Case 1 Stream Table, GEE IGCC without CO 2 Capture 1 2 3 4 5 6 7 8 9 10 11 12V-L Mole Fraction Ar0.00920.02330.03180.00230.03180.00000.00000.00000.00860.00680.00680.0099 CH 40.00000.00000.00000.00000.00000.00000.00000.00000.00120.00090.00090.0013 CO0.00000.00000.00000.00000.00000.00000.00000.00000.35790.28250.28250.4151 CO 20.00030.00810.00000.00000.00000.00000.00000.00000.13660.10780.10790.1586COS0.00000.00000.00000.00000.00000.00000.00000.00000.00020.00010.00000.0000 H 20.00000.00000.00000.00000.00000.00000.00000.00000.34160.26960.26960.3961 H 2 O0.00990.20810.00000.00030.00000.00000.99940.00000.13580.31810.31800.0012 HCl0.00000.00000.00000.00000.00000.00000.00000.00000.00080.00020.00020.0000 H 2 S0.00000.00000.00000.00000.00000.00000.00000.00000.00730.00570.00590.0085 N 20.77320.56210.01780.99190.01780.00000.00000.00000.00800.00630.00630.0092 NH 30.00000.00000.00000.00000.00000.00000.00060.00000.00210.00200.00200.0000 O 20.20740.19850.95040.00540.95040.00000.00000.00000.00000.00000.00000.0000 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000Total1.00001.00001.00001.00001.00000.00001.00000.00001.00001.00001.00001.0000V-L Flowrate (kgmol/hr)21,8721,067 10219,3805,298 04,829 022,21228,14228,14219,153V-L Flowrate (kg/hr)631,16428,9413,290543,810170,485 087,000 0446,032552,597552,597390,595Solids Flowrate (kg/hr) 0 0 0 0 0211,783 023,236 0 0 0 0Temperature (°C) 15 20 32 93 32 15 1461,316 677 223 223 35Pressure (MPa, abs)0.100.110.862.650.860.105.795.625.555.485.415.24Enthalpy (kJ/kg)

A30.2336.8026.6792.5226.67---558.58---1,424.131,066.741,066.6340.35Density (kg/m 3)1.21.611.024.411.0---866.9---13.926.726.341.9V-L Molecular Weight28.85727.13232.18128.06032.181---18.015---20.08119.63619.63620.393V-L Flowrate (lbmol/hr)48,2202,352 22542,72611,680 010,647 048,96962,04362,04342,226V-L Flowrate (lb/hr)1,391,47963,8037,2531,198,895375,855 0191,803 0983,3331,218,2671,218,267861,115Solids Flowrate (lb/hr) 0 0 0 0 0466,901 051,227 0 0 0 0Temperature (°F) 59 68 90 199 90 59 2952,4001,250 433 433 95Pressure (psia)14.716.4125.0384.0125.014.7840.0815.0805.0795.0785.0760.0Enthalpy (Btu/lb)

A13.015.811.539.811.5---240.1---612.3458.6458.617.3Density (lb/ft 3)0.0760.0980.6871.5210.687---54.120---0.8701.6651.6432.617A - Reference conditions are 32.02 F & 0.089 PSIA Cost and Performance Baseline for Fossil Energy Plants 100 Exhibit 3-14 Case 1 Stream Table, GEE IGCC without CO 2 Captu re (Continued) 13 14 15 16 17 18 19 20 21 22 23 24V-L Mole Fraction Ar0.00970.00000.00000.00400.01000.01000.01000.00920.00920.00890.00890.0000 CH 40.00130.00000.00000.00000.00130.00130.00130.00000.00000.00000.00000.0000 CO0.39770.00020.00000.00210.40890.40890.40890.00000.00000.00000.00000.0000 CO 20.18110.61240.00000.69470.15620.15620.15620.00030.00030.08070.08070.0000COS0.00000.00000.00000.00010.00000.00000.00000.00000.00000.00000.00000.0000 H 20.38120.00000.00000.04150.39200.39200.39200.00000.00000.00000.00000.0000 H 2 O0.00120.01280.00000.00180.00060.00060.00060.00990.00990.06380.06381.0000 HCl0.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 H 2 S0.00860.18170.00000.01110.00000.00000.00000.00000.00000.00000.00000.0000 N 20.01910.19050.00000.24480.03090.03090.03090.77320.77320.74270.74270.0000 NH 30.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 O 20.00000.00230.00000.00000.00000.00000.00000.20740.20740.10390.10390.0000 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000Total1.00001.00000.00001.00001.00001.00001.00001.00001.00001.00001.00001.0000V-L Flowrate (kgmol/hr)19,992 951 0 83919,44519,44519,445110,2534,410136,882136,88235,596V-L Flowrate (kg/hr)422,59236,883 031,997397,047397,047397,0473,181,557127,2623,995,1523,995,152641,276Solids Flowrate (kg/hr) 0 05,307 0 0 0 0 0 0 0 0 0Temperature (°C) 35 45 174 38 45 241 196 15 432 589 132 561Pressure (MPa, abs)5.215.20.4095.5125.1715.1363.1720.1011.6190.1050.10512.512Enthalpy (kJ/kg)

A36.92-1.2----5.03954.553365.190296.11430.227463.785741.466235.1323,502.816Density (kg/m 3)43.495.05,288.297.740.024.116.41.27.90.40.935.1V-L Molecular Weight21.138 39---38.14520.41920.41920.41928.85728.85729.18729.18718.015V-L Flowrate (lbmol/hr)44,0752,096 01,84942,87042,87042,870243,0669,723301,773301,77378,476V-L Flowrate (lb/hr)931,65581,313 070,540875,339875,339875,3397,014,133280,5658,807,8038,807,8031,413,772Solids Flowrate (lb/hr) 0 011,699 0 0 0 0 0 0 0 0 0Temperature (°F) 94 112 345 100 112 465 386 59 8101,093 2701,043Pressure (psia)755.0750.059.3799.5750.0745.0460.014.7234.915.215.21,814.7Enthalpy (Btu/lb)

A15.9-0.5----2.223.5157.0127.313.0199.4318.8101.11,505.9Density (lb/ft 3)2.712 6330.1296.0982.4991.5081.0260.0760.4950.0270.0572.191 Cost and Performance Baseline for Fossil Energy Plants 101 Syngas exiting the scrubber (stream

10) passes through a COS hydrolysis reactor where about 99.5 percent of the COS is converted to CO 2 and H 2S (Section COS Hydrolysis, Mercury Removal and Acid Gas Removal 3.1.5). The gas exiting the COS reactor (stream 1

1) passes through a series of heat exchangers and knockou t (KO) drums to lower the syngas temperature to 3 5°C (95°F) and to separate entrained water. The cooled syngas (stream 1 2) then passes through a carbon bed to remove 95 percent of the Hg (Section 3.1.4). Cool, particulate

-free syngas (stream 1

3) enters the Selexol absorber unit at approximately 5.2 MPa (755 psia) and 34°C (94°F). In this absorber, H 2S is preferentially removed from the fuel gas stream along with smaller amounts of CO 2, 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 H 2S concentrator. A portion of the non

-sulfur bearing absorbed gases is driven from the solvent in the H 2S concentrator using N 2 from the ASU as the stripping medium. The temperature of the H 2S concentrator overhead stream is reduced prior to entering the reabsorber where a second stage of H 2S 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 H 2S and 61 percent CO 2 (with the balance mostly N 2), is then sent to the 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 H 2S in the acid gas to elemental sulfur. About 5, 307 kg/h r (11,699 lb/h r) of elemental sulfur (stream 1

5) are recovered from the fuel gas stream. This value represents an overall sulfur recovery efficiency of 99.6 percent. Claus Unit 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, H 2S 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 NH 3 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 H 2S 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/h r (27,408 lb/h r) 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 MP a (415 psig) for IP steam

. Clean syngas exiting the Selexol absorber is re

-heated (stream 1

8) 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 1 7 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 Power Block

Cost and Performance Baseline for Fossil Energy Plants 102 power an advanced, commercially available steam turbine using a 12.4 MPa/

562°C/562°C (1800 psig/1043°F/1043°F) steam cycle.

The elevated pressure ASU was described in Section Air Separation Unit 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% O 2 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 1 7 percent of the ASU air requirements (stream 21).

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

Cost and Performance Baseline for Fossil Energy Plants 103 3.2.3 System assumptions for Cases 1 and 2, GEE IGCC with and without CO 2 capture, are presented in Key System Assumptions 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) O 2:Coal Ratio, kg O 2/kg dry coal 0.9 1 0.9 1 Carbon Conversion, %

98 98 Syngas HHV at Gasifier Outlet, kJ/Nm 3 (Btu/scf) 8, 6 63 (233) 8, 6 44 (2 32) Steam Cycle, MPa/°C/°C (psig/ F/ F) 12.4/56 2/56 2 (1800/10 43/10 43) 12.4/53 4/53 4 (1800/994/994) Condenser Pressure, mm Hg (in Hg) 51 (2.0) 51 (2.0) Combustion Turbine 2x Advanced F Class (232 MW output each) 2x Advanced F Class (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 H 2S Separation Selexol Selexol 1 st Stage Sulfur Removal, %

99.7 99.9 Sulfur Recovery Claus Plant with Tail Gas Recycle to Selexol/ Elemental Sulfur Claus Plant with Tail Gas Recycle to Selexol/ Elemental Sulfur Particulate Control Water Quench, Scrubber, and AGR Absorber Water Quench, Scrubber, and AGR Absorber Mercury Control Carbon Bed Carbon Bed NOx Control Multi Nozzle Quiet Combustor (MNQC) (LNB) and N 2 Dilution MNQC (LNB) and N 2 Dilution CO 2 Separation N/A Selexol 2nd Stage Overall CO2 Capture N/A 90.3% CO 2 Sequestration N/A Off-site Saline Formation

Cost and Performance Baseline for Fossil Energy Plants 104 The balance of plant assumptions are common to all cases and are presented in Balance of Plant

- Cases 1 and 2 Exhibit 3-16. Exhibit 3-16 Balance of Plant Assumptions Recirculating Wet Cooling Tower Cooling system 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 250 hp 480 volt Motors between 250 hp and 5,000 hp 4,160 volt Motors above 5,000 hp 13,800 volt Steam and Gas Turbine 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 de

-ionized (DI) water is drawn from municipal sources Process Wastewater Water associated with gasification activity and 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 was 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 is treated for chloride and metals, and discharged.

Cost and Performance Baseline for Fossil Energy Plants 105 3.2.4 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.

Sparing Philosophy 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 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 effi ciency 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

[Case 1 Performance Results 59 , 60Overall performance for the plant is summarized in

]. Typically the higher efficiencies result from fuel blends that include petroleum coke.

Exhibit 3-17 , which includes auxiliary power requirements. The ASU accounts for approximately 7 8 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.

Cost and Performance Baseline for Fossil Energy Plants 106 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 Miscellaneous Balance of Plant 2 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 10 6 kJ/h r (10 6 Btu/h r) 1,540 (1,460)

CONSUMABLES As-Received Coal Feed, kg/h r (lb/h r) 211,783 (466,901)

Thermal Input 1, kWt 1,596,320 Raw Water Withdrawal, m 3/min (gpm) 17.9 (4,735)

Raw Water Consumption , m 3/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

Cost and Performance Baseline for Fossil Energy Plants 107 The environmental targets for emissions of Hg, NOx, SO 2 , and PM were presented in Section 2.4. A summary of the plant air emissions for Case 1 is presented in Environmental Performance Exhibit 3-18. Exhibit 3-18 Case 1 Emissions kg/GJ (lb/10 6 Btu) Tonne/year (ton/year) @

80% capacity factor kg/MWh (lb/MWh) SO 2 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)

Hg 2.46E-7 (5.71E-7) 0.010 (0.011) 1.89E-6 (4.16E-6) CO 2 84.6 (196.8) 3,407,901 (3,756,568) 650 (1,434)

CO 2 1 782 (1,723) 1 CO 2 emissions based on net power instead of gross power The low level of SO 2 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 H 2 S-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 H 2 S and then recycled back to the Selexol process, thereby eliminating the need for a tail gas treatment unit.

NO x emissions are limited by nitrogen dilution of the syngas to 15 ppmvd (as NO 2 @15 percent O 2). 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 NO x 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.

CO 2 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 CO 2 in the stack gas and ASU vent gas.

Cost and Performance Baseline for Fossil Energy Plants 108 Exhibit 3-19 Case 1 Carbon Balance Carbon In, kg/hr (lb/hr)

Carbon Out, kg/h r (lb/hr) Coal 135,000 (297,625)

Slag 2,700 (5,952)

Air (CO 2) 519 (1,143)

Stack Gas 132,716 (292,588) ASU Vent 103 (227) CO 2 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/h r (lb/hr) Coal 5,308 (11,702)

Elemental Sulfur 5,307 (11,699)

Stack Gas 2 (3) CO 2 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.

Cost and Performance Baseline for Fossil Energy Plants 109 Exhibit 3-21 Case 1 Water Balance Water Use Water Demand, m 3/min (gpm) Internal Recycle, m 3/min (gpm) Raw Water Withdrawal, m 3/min (gpm) Process Water Discharge, m 3/min (gpm) Raw Water Consumption, m 3/min (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 Gasifier Steam Shift Steam GT Steam Dilution BFW Makeup 0.2 (54) 0.20 (54) 0.0 (0) 0.2 (54) 0.20 (54) 0.0 (0) 0.2 (54)

Cooling Tower BFW Blowdown SWS Blowdown SWS Excess Water Humidifier Tower Blowdown 16.4 (4,321)

0.49 (129) 0.20 (54) 0.29 (75) 15.9 (4,192)

-0.20 (-54) -0.29 (-75) 3.7 (972) 12.2 (3,220)

Total 21.3 (5,618) 3.34 (883) 17.9 (4,735) 3.7 (979) 14.2 (3,755)

Heat and mass balance diagrams are shown for the following subsystems in Heat and Mass Balance Diagrams 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.

Cost and Performance Baseline for Fossil Energy Plants 110 This page intentionally left blank

Cost and Performance Baseline for Fossil Energy Plants 111 Exhibit 3-22 Case 1 Coal Gasification and Air Separation Units Heat and Mass Balance Schematic N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA DOE/NETL D UAL T RAIN IGCC P LANT C ASE 1 H EAT AND M ATERIAL F LOW D IAGRAM B ITUMINOUS BASELINE S TUDY C ASE 1 GEE G ASIFIER ASU AND G ASIFICATION DWG. NO.BB-HMB-CS-1-PG-1 P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas P AGES 1 OF 3 Ambient Air Four Stage Air Compressor Elevated Pressure ASU Four Stage N 2 Compressor Four Stage O 2 Compressor ASU Vent Water Steam Gross Plant Power

748 MWe Auxiliary Load

126 MWe Net Plant Power

622 MWe Net Plant Efficiency , HHV: 39.0%Net Plant Heat Rate

8 , 756 BTU/KWe N 2 to GT Combustor 1 , 391 , 479 W 59.0 T 14.7 P 13.0 H 375 , 855 W 90.0 T 125.0 P 11.5 H 375 , 855 W 241.2 T 940.0 P 40.8 H To Claus Plant 7 , 253 W 90.0 T 125.0 P 11.5 H 63 , 803 W 68.2 T 16.4 P 15.8 H 1 , 073 , 296 W 90.0 T 56.4 P 14.2 H 150 , 595 W 50.0 T 182.0 P 2.9 H 5 1 3 2 Slurry Mix Tank Milled Coal Slag 466 , 901 W 59.0 T 14.7 P 191 , 803 W 295.0 T 840.0 P 240.1 H 51 , 227 W 2 , 400.0 T 815.0 P 1 , 198 , 895 W 389.0 T 384.0 P 88.2 H 658 , 704 W 159.7 T 840.0 P 2 , 933.2 H 100.0 T 189.5 P 18.0 H 6 Air From GT Compressor 280 , 565 W 220.0 T 224.9 P 50.9 H 280 , 565 W 809.8 T 234.9 P 199.4 H 1 , 198 , 895 W 199.0 T 384.0 P 39.8 H 21 HP BFW N 2 to AGR N 2 Boost Compressor 24 , 996 W 199.0 T 384.0 P 39.8 H 24 , 996 W 376.3 T 785.0 P 84.2 H Saturated Steam To HRSG HP Superheater GE Energy Gasifier Radiant Syngas Cooler Black Water Flash Tank Knockout Drum Vent To Claus Unit Raw Fuel Gas CWS CWR Fines Process Water From Sour Water Stripper Syngas Scrubber Slag Quench Section Drag Conveyor 4 983 , 333 W 1 , 250.0 T 805.0 P 612.3 H 1 , 218 , 267 W 402.9 T 800.0 P 445.7 H Syngas Quench 1 , 346 , 417 W 450.0 T 805.0 P 535.7 H 8 9 Sour Water 7

Cost and Performance Baseline for Fossil Energy Plants 112 Exhibit 3-23 Case 1 Syngas Cleanup Heat and Mass Balance Schematic Mercury Removal Knock Out Drum Syngas Preheater Sour Drum Process Condensate to Syngas Scrubber Makeup Water Claus Plant Tail Gas Furnace Catalytic Reactor Beds Sulfur Knock Out From ASU Syngas Coolers Sour Stripper 1 , 218 , 267 W 402.9 T 800.0 P 457.9 H 931 , 655 W 94.2 T 755.0 P 15.9 H 81 , 313 W 112.2 T 750.0 P 875 , 339 W 385.6 T 460.0 P 127.3 H 11 , 699 W 79 , 721 W 450.0 T 58.9 P 249.7 H 2 , 855 W 234.5 T 65.0 P 405.2 H 7 , 253 W 90.0 T 125.0 P 11.5 H N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA DOE/NETL D UAL T RAIN IGCC P LANT C ASE 1 H EAT AND M ATERIAL F LOW D IAGRAM B ITUMINOUS BASELINE S TUDY C ASE 1 GEE G ASIFIER G AS CLEANUP SYSTEM DWG. NO.BB-HMB-CS-1-PG-2 P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas P AGES 2 OF 3 Sour Gas Sour Water Water Steam Gross Plant Power

748 MWe Auxiliary Load

126 MWe Net Plant Power

622 MWe Net Plant Efficiency , HHV: 39.0%Net Plant Heat Rate

8 , 756 BTU/KWe 15 12 16 CO 2 Tailgas 71 , 392 W 120.0 T 56.8 P 32.0 H 861 , 115 W 95.3 T 760.0 P 17.3 H 9 , 181 W 118.2 T 56.8 P 44.4 H 3 70 , 540 W 100.0 T 799.5 P Raw Syngas 17 875 , 339 W 112.2 T 750.0 P 23.5 H Claus Oxygen Preheater 7 , 253 W 450.0 T 124.5 P 91.9 H COS Hydrolysis 1 , 218 , 267 W 432.7 T 785.0 P 458.6 H COS Hydrolysis Preheater 1 , 218 , 267 W 432.9 T 795.0 P 458.6 H 10 11 Clean Gas Acid Gas 13 AGR- Selexol 14 Fuel Gas Expander Fuel Gas To GT 19 875 , 339 W 465.0 T 745.0 P 157.0 H 18 N 2 to AGR 24 , 996 W 376.3 T 785.0 P 84.2 H Hydrogenation and Tail Gas Cooling Tail Gas Recycle Compressor Cost and Performance Baseline for Fossil Energy Plants 113 Exhibit 3-24 Case 1 Combined-Cycle Power Generation Heat and Mass Balance Schematic HRSG HP Turbine IP Turbine Nitrogen Diluent Intake Ambient Air Steam Seal Regulator Ip Extraction Steam To 250 PSIA Header LP Process Header Blowdown Flash To WWT Gland Steam Condenser Condensate to Gasification Island HP BFW to Radiant Syngas Cooler HP Saturated Steam to HRSG Superheater LP Turbine Stack Expander Compressor Fuel Gas Deaerator IP BFW Generator Generator Condensate Pump HP Pump Steam Turbine LP Pump Advanced F

-Class Gas Turbine MP Flash Bottoms LP Flash Tops 1 , 198 , 895 W 385.0 T 389.0 P 87.2 H 7 , 014 , 133 W 59.0 T 14.7 P 13.0 H 1 , 581 , 185 W 101.1 T 1.0 P 69.1 H 8 , 807 , 803 W 269.7 T 15.2 P 101.1 H 875 , 339 W 385.6 T 460.0 P 127.3 H 8 , 807 , 803 W 1 , 092.7 T 15.2 P 318.8 H From Gasifier Island Preheating To Claus LP BFW 1 , 413 , 772 W 1 , 042.7 T 1 , 814.7 P 1 , 505.9 H 9 , 644 W 298.0 T 65.0 P 1 , 179.0 H 1 , 440 , 764 W 278.8 T 2 , 250.7 P 252.3 H 26 , 992 W 585.0 T 2 , 000.7 P 593.3 H 1 , 542 , 260 W 512.1 T 65.0 P 1 , 288.0 H 1 , 581 , 185 W 103.2 T 120.0 P 71.4 H 1 , 581 , 185 W 235.0 T 105.0 P 203.7 H 1 , 400 W 661.9 T 65.0 P 1 , 361.9 H 1 , 400 W 212.0 T 14.7 P 179.9 H IP Pump N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA DOE/NETL D UAL T RAIN IGCC P LANT C ASE 1 H EAT AND M ATERIAL F LOW D IAGRAM B ITUMINOUS BASELINE S TUDY C ASE 1 GEE G ASIFIER P OWER B LOCK S YSTEM DWG. NO.BB-HMB-CS-1-PG-3 P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas P AGES 3 OF 3 Sour Gas Sour Water Water Steam Gross Plant Power

748 MWe Auxiliary Load

126 MWe Net Plant Power

622 MWe Net Plant Efficiency , HHV: 39.0%Net Plant Heat Rate

8 , 756 BTU/KWe 20 22 24 19 23 Flue Gas HOT WELL CONDENSER Make-up 27 , 011 W 59.0 T 14.7 P 27.1 H 8 , 822 W 701.7 T 501.4 P 1 , 358.0 H 9 , 515 W 661.9 T 65.0 P 1 , 361.9 H 35 , 544 W 897.8 T 280.0 P 1 , 472.7 H 780 W 1 , 042.7 T 1 , 814.7 P 1 , 505.9 H 1 , 312 W 540.7 T 65.0 P 1 , 302.1 H Air Extraction 280 , 565 W 809.8 T 234.9 P 199.4 H 21 Cost and Performance Baseline for Fossil Energy Plants 114 This page intentionally left blank

Cost and Performance Baseline for Fossil Energy Plants 115 Exhibit 3-25 Case 1 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total 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) CO 2 Cooling Tower Blowdown 27.3 (25.9) 27 (26) HRSG Flue Gas 939 (890) 939 (890) Condenser 1,536 (1,456) 1,536 (1,456)

Non-Condenser Cooling Tower Loads* 422 (400) 422 (400) 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, CO 2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection) and extraction air cooler.

- Calculated by difference to close the energy balance.

Cost and Performance Baseline for Fossil Energy Plants 116 3.2.6 Major equipment items for the GEE gasifier with no CO 2 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 Case 1 - Major Equipment List 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 No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Bottom Trestle Dumper and Receiving HoppersN/A181 tonne (200 ton) 2 0 2FeederBelt572 tonne/hr (630 tph) 2 0 3Conveyor No. 1Belt1,134 tonne/hr (1,250 tph) 1 0 4Transfer Tower No. 1EnclosedN/A 1 0 5Conveyor No. 2Belt1,134 tonne/hr (1,250 tph) 1 0 6As-Received Coal Sampling SystemTwo-stageN/A 1 0 7Stacker/ReclaimerTraveling, linear1,134 tonne/hr (1,250 tph) 1 0 8Reclaim HopperN/A45 tonne (50 ton) 2 1 9FeederVibratory172 tonne/hr (190 tph) 2 1 10Conveyor No. 3Belt w/ tripper354 tonne/hr (390 tph) 1 0 11Crusher TowerN/AN/A 1 0 12Coal Surge Bin w/ Vent FilterDual outlet172 tonne (190 ton) 2 0 13CrusherImpactor reduction8 cm x 0 - 3 cm x 0(3" x 0 1/4" x 0) 2 0 14As-Fired Coal Sampling SystemSwing hammerN/A 1 1 15Conveyor No. 4Belt w/tripper354 tonne/hr (390 tph) 1 0 16Transfer Tower No. 2EnclosedN/A 1 0 17Conveyor No. 5Belt w/ tripper354 tonne/hr (390 tph) 1 0 18Coal Silo w/ Vent Filter and Slide GatesField erected816 tonne (900 ton) 3 0 Cost and Performance Baseline for Fossil Energy Plants 117 ACCOUNT 2 COAL PREPARATION AND FEED Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1FeederVibratory82 tonne/h (90 tph) 3 0 2Conveyor No. 6Belt w/tripper236 tonne/h (260 tph) 1 0 3Rod Mill Feed HopperDual Outlet463 tonne (510 ton) 1 0 4Weigh FeederBelt118 tonne/h (130 tph) 2 0 5Rod MillRotary118 tonne/h (130 tph) 2 0 6Slurry Water Storage Tank with AgitatorField erected287,504 liters (75,950 gal) 2 0 7Slurry Water PumpsCentrifugal795 lpm (210 gpm) 2 1 8Trommel ScreenCoarse163 tonne/h (180 tph) 2 0 9Rod Mill Discharge Tank with AgitatorField erected376,122 liters (99,360 gal) 2 0 10Rod Mill Product PumpsCentrifugal3,028 lpm (800 gpm) 2 2 11Slurry Storage Tank with AgitatorField erected1,128,440 liters (298,100 gal) 2 0 12Slurry Recycle PumpsCentrifugal6,435 lpm (1,700 gpm) 2 2 13Slurry Product PumpsPositive displacement3,028 lpm (800 gpm) 2 2 Cost and Performance Baseline for Fossil Energy Plants 118 ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Demineralized Water Storage TankVertical, cylindrical, outdoor1,082,628 liters (286,000 gal) 2 0 2Condensate PumpsVertical canned6,624 lpm @ 91 m H2O(1,750 gpm @ 300 ft H2O) 2 1 3Deaerator (integral w/ HRSG)Horizontal spray type493,508 kg/hr (1,088,000 lb/hr) 2 0 4Intermediate Pressure Feedwater PumpHorizontal centrifugal, single stage8,366 lpm @ 27 m H2O(2,210 gpm @ 90 ft H2O) 2 1 5High Pressure Feedwater Pump No. 1Barrel type, multi-stage, centrifugalHP water: 6,246 lpm @ 1,859 m H2O (1,650 gpm @ 6,100 ft H2O)2 1 6High Pressure Feedwater Pump No. 2Barrel type, multi-stage, centrifugalIP water: 1,060 lpm @ 223 m H2O (280 gpm @ 730 ft H2O) 2 1 7Auxiliary BoilerShop fabricated, water tube18,144 kg/hr, 2.8 MPa, 343°C(40,000 lb/hr, 400 psig, 650°F) 1 0 8Service Air CompressorsFlooded Screw28 m3/min @ 0.7 MPa(1,000 scfm @ 100 psig) 2 1 9Instrument Air DryersDuplex, regenerative28 m3/min (1,000 scfm) 2 1 10Closed Cylce Cooling Heat ExchangersPlate and frame247 GJ/hr (234 MMBtu/hr) each 2 0 11Closed Cycle Cooling Water PumpsHorizontal centrifugal88,579 lpm @ 21 m H2O(23,400 gpm @ 70 ft H2O) 2 1 12Engine-Driven Fire PumpVertical turbine, diesel engine3,785 lpm @ 107 m H2O(1,000 gpm @ 350 ft H2O) 1 1 13Fire Service Booster PumpTwo-stage horizontal centrifugal2,650 lpm @ 76 m H2O(700 gpm @ 250 ft H2O) 1 1 14Raw Water PumpsStainless steel, single suction4,618 lpm @ 18 m H2O(1,220 gpm @ 60 ft H2O) 2 1 15Ground Water PumpsStainless steel, single suction3,066 lpm @ 268 m H2O (810 gpm @ 880 ft H2O) 3 1 16Filtered Water PumpsStainless steel, single suction2,082 lpm @ 49 m H2O(550 gpm @ 160 ft H2O) 2 1 17Filtered Water TankVertical, cylindrical1,003,134 liter (265,000 gal) 2 0 18Makeup Water DemineralizerAnion, cation, and mixed bed303 lpm (80 gpm) 2 0 19Liquid Waste Treatment System10 years, 24-hour storm 1 0 Cost and Performance Baseline for Fossil Energy Plants 119 ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1GasifierPressurized slurry-feed, entrained bed2,812 tonne/day, 5.6 MPa(3,100 tpd, 815 psia) 2 0 2Synthesis Gas CoolerVertical downflow radiant heat exchanger with outlet quench chamber245,393 kg/hr (541,000 lb/hr) 2 0 3Syngas Scrubber Including Sour Water StripperVertical upflow336,112 kg/hr (741,000 lb/hr) 2 0 4Raw Gas CoolersShell and tube with condensate drain215,910 kg/hr (476,000 lb/hr) 8 0 5Raw Gas Knockout DrumVertical with mist eliminator215,456 kg/hr, 35°C, 5.3 MPa(475,000 lb/hr, 95°F, 765 psia) 2 0 6Flare StackSelf-supporting, carbon steel, stainless steel top, pilot ignition336,112 kg/hr (741,000 lb/hr) syngas 2 0 7ASU Main Air CompressorCentrifugal, multi-stage4,757 m3/min @ 1.3 MPa(168,000 scfm @ 190 psia) 2 0 8Cold BoxVendor design2,268 tonne/day (2,500 tpd) of 95% purity oxygen 2 0 9Oxygen CompressorCentrifugal, multi-stage1,161 m3/min (41,000 scfm)Suction - 0.9 MPa (130 psia)Discharge - 6.5 MPa (940 psia) 2 0 10Primary Nitrogen CompressorCentrifugal, multi-stage3,766 m3/min (133,000 scfm)Suction - 0.4 MPa (60 psia)Discharge - 2.7 MPa (390 psia) 2 0 11Secondary Nitrogen CompressorCentrifugal, single-stage538 m3/min (19,000 scfm)Suction - 1.2 MPa (180 psia)Discharge - 2.7 MPa (390 psia) 2 0 12Syngas Dilution Nitrogen Boost CompressorCentrifugal, single-stage0 m3/min (0 scfm)Suction - 2.6 MPa (380 psia)Discharge - 3.2 MPa (470 psia) 2 0 13AGR Nitrogen Boost CompressorCentrifugal, single-stage85 m3/min (3,000 scfm)Suction - 2.6 MPa (380 psia)Discharge - 5.4 MPa (790 psia) 2 0 14Extraction Air Heat ExchangerGas-to-gas, vendor design69,853 kg/hr, 432°C, 1.6 MPa(154,000 lb/hr, 810°F, 235 psia) 2 0 Cost and Performance Baseline for Fossil Energy Plants 120 ACCOUNT 5A SYNGAS CLEANUP ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES ACCOUNT 7 HRSG, DUCTING, AND STACK Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Mercury AdsorberSulfated carbon bed215,003 kg/hr (474,000 lb/hr) 35°C (95°F) 5.2 MPa (760 psia) 2 0 2Sulfur PlantClaus type140 tonne/day (154 tpd) 1 0 3COS Hydrolysis ReactorFixed bed, catalytic303,907 kg/hr (670,000 lb/hr)221°C (430°F)5.4 MPa (790 psia) 2 0 4Acid Gas Removal PlantSelexol232,239 kg/hr (512,000 lb/hr)35°C (94°F)5.2 MPa (755 psia) 2 0 5Hydrogenation ReactorFixed bed, catalytic36,161 kg/hr (79,721 lb/hr)232°C (450°F)0.4 MPa (58.9 psia) 1 0 6Tail Gas Recycle CompressorCentrifugal31,997 kg/hr (70,540 lb/hr) each 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Gas TurbineAdvanced F class230 MW 2 0 2Gas Turbine GeneratorTEWAC260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0 3Syngas Expansion Turbine/GeneratorTurbo Expander218,359 kg/h (481,400 lb/h)5.1 MPa (745 psia) Inlet3.2 MPa (460 psia) Outlet 2 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1StackCS plate, type 409SS liner76 m (250 ft) high x8.4 m (27 ft) diameter 1 0 2Heat Recovery Steam GeneratorDrum, multi-pressure with economizer section and integral deaeratorMain steam - 352,702 kg/hr, 12.4 MPa/561°C (777 , 575 lb/hr , 1 , 800 psig/1 , 043°F) Reheat steam - 345,710 kg/hr, 3.1 MPa/561°C (762 , 160 lb/hr , 452 psig/1 , 043°F)2 0 Cost and Performance Baseline for Fossil Energy Plants 121 ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES ACCOUNT 9 COOLING WATER SYSTEM Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Steam TurbineCommercially available advanced steam turbine291 MW 12.4 MPa/561°C/561°C (1 , 800 psig/ 1043°F/1043°F)1 0 2Steam Turbine GeneratorHydrogen cooled, static excitiation320 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0 3Steam BypassOne per HRSG50% steam flow @ design steam conditions 2 0 4Surface CondenserSingle pass, divided waterbox including vacuum pumps1,688 GJ/hr (1,600 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F)1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Circulating Water PumpsVertical, wet pit420,181 lpm @ 30 m(111,000 gpm @ 100 ft) 2 1 2Cooling TowerEvaporative, mechanical draft, multi-cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,353 GJ/hr (2,230 MMBtu/hr) heat duty 1 0 Cost and Performance Baseline for Fossil Energy Plants 122 ACCOUNT 10 SLAG RECOVERY AND HANDLING Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Slag Quench TankWater bath242,266 liters (64,000 gal) 2 0 2Slag CrusherRoll13 tonne/hr (14 tph) 2 0 3Slag DepressurizerLock Hopper13 tonne/hr (14 tph) 2 0 4Slag Receiving TankHorizontal, weir147,631 liters (39,000 gal) 2 0 5Black Water Overflow TankShop fabricated64,352 liters (17,000 gal) 2 6Slag ConveyorDrag chain13 tonne/hr (14 tph) 2 0 7Slag Separation ScreenVibrating13 tonne/hr (14 tph) 2 0 8Coarse Slag ConveyorBelt/bucket13 tonne/hr (14 tph) 2 0 9Fine Ash Settling TankVertical, gravity208,198 liters (55,000 gal) 2 0 10Fine Ash Recycle PumpsHorizontal centrifugal38 lpm @ 14 m H2O(10 gpm @ 46 ft H2O) 2 2 11Grey Water Storage TankField erected68,137 liters (18,000 gal) 2 0 12Grey Water PumpsCentrifugal227 lpm @ 564 m H2O(60 gpm @ 1,850 ft H2O) 2 2 13Slag Storage BinVertical, field erected907 tonne (1,000 tons) 2 0 14Unloading EquipmentTelescoping chute109 tonne/hr (120 tph) 1 0 Cost and Performance Baseline for Fossil Energy Plants 123 ACCOUNT 11 ACCESSORY ELECTRIC PLANT ACCOUNT 12 INSTRUMENTATION AND CONTROLS Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1CTG Step-up TransformerOil-filled24 kV/345 kV, 260 MVA, 3-ph, 60 Hz 2 0 2STG Step-up TransformerOil-filled24 kV/345 kV, 320 MVA, 3-ph, 60 Hz 1 0 3High Voltage Auxiliary TransformerOil-filled345 kV/13.8 kV, 54 MVA, 3-ph, 60 Hz 2 0 4Medium Voltage Auxiliary TransformerOil-filled24 kV/4.16 kV, 29 MVA, 3-ph, 60 Hz 1 1 5Low Voltage TransformerDry ventilated4.16 kV/480 V, 4 MVA, 3-ph, 60 Hz 1 1 6CTG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled24 kV, 3-ph, 60 Hz 2 0 7STG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled24 kV, 3-ph, 60 Hz 1 0 8Medium Voltage SwitchgearMetal clad4.16 kV, 3-ph, 60 Hz 1 1 9Low Voltage SwitchgearMetal enclosed480 V, 3-ph, 60 Hz 1 1 10Emergency Diesel GeneratorSized for emergency shutdown750 kW, 480 V, 3-ph, 60 Hz 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1DCS - Main ControlMonitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W)Operator stations/printers and engineering stations/printers 1 0 2DCS - ProcessorMicroprocessor with redundant input/outputN/A 1 0 3DCS - Data HighwayFiber opticFully redundant, 25% spare 1 0 Cost and Performance Baseline for Fossil Energy Plants 124 3.2.7 The cost estimating methodology was described previously in Section 2.6. Case 1 - Cost Estimating 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 owner's costs, TOC, and TASC. Exhibit 3-28 shows the initial and annual O&M costs.

The estimated TOC of the GEE gasifier with no CO 2 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.

Cost and Performance Baseline for Fossil Energy Plants 125 Exhibit 3-26 Case 1 Total Plant Cost Summary Client: USDOE/NETLReport Date:2009-Oct-08Project: Bituminous Baseline StudyCase: Case 1 - GEE Radiant 640MW IGCC w/o CO2Plant Size: 622.1MW,netEstimate Type: ConceptualCost Base (Jun) 2007($x1000)AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING$13,912$2,585$10,788$0$0$27,285$2,477$0$5,952$35,714$57 2COAL & SORBENT PREP & FEED$23,713$4,326$14,245$0$0$42,284$3,844$1,535$9,533$57,195$92 3FEEDWATER & MISC. BOP SYSTEMS$9,622$7,783$9,458$0$0$26,863$2,531$0$6,737$36,131$58 4GASIFIER & ACCESSORIES4.1Syngas Cooler Gasifier System$111,116$0$60,871$0$0$171,987$15,755$23,878$32,445$244,065$3924.2Syngas Cooler (w/ Gasifier - $)w/4.1$0w/4.1$0$0$0$0$0$0$0$04.3ASU/Oxidant Compression$160,703$0w/equip.$0$0$160,703$15,577$0$17,628$193,908$3124.4-4.9Other Gasification Equipment$7,664$11,266$12,070$0$0$31,001$3,020$0$7,624$41,645$67SUBTOTAL 4$279,483$11,266$72,942$0$0$363,691$34,352$23,878$57,697$479,618$771 5AGAS CLEANUP & PIPING$57,957$3,800$55,494$0$0$117,251$11,380$93$25,944$154,668$249 5BCO2 REMOVAL & COMPRESSION

$0$0$0$0$0$0$0$0$0$0$0 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine Generator$85,752$0$6,269$0$0$92,021$8,724$4,601$10,535$115,881$1866.2-6.9Combustion Turbine Other$5,928$887$1,801$0$0$8,615$816$0$1,721$11,152$18SUBTOTAL 6$91,679$887$8,070$0$0$100,636$9,540$4,601$12,256$127,033$204 7HRSG, DUCTING & STACK7.1Heat Recovery Steam Generator$35,357$0$5,027$0$0$40,384$3,840$0$4,422$48,646$787.2-7.9SCR System, Ductwork and Stack$3,329$2,373$3,108$0$0$8,810$817$0$1,566$11,193$18SUBTOTAL 7$38,685$2,373$8,136$0$0$49,194$4,657$0$5,989$59,839$96 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$29,111$0$4,994$0$0$34,104$3,272$0$3,738$41,114$668.2-8.9Turbine Plant Auxiliaries and Steam Piping$10,373$1,001$7,239$0$0$18,613$1,694$0$4,041$24,348$39SUBTOTAL 8$39,483$1,001$12,233$0$0$52,718$4,967$0$7,778$65,462$105 9COOLING WATER SYSTEM$9,649$9,237$7,877$0$0$26,763$2,486$0$5,971$35,220$57 10ASH/SPENT SORBENT HANDLING SYS$14,359$8,029$14,555$0$0$36,943$3,559$0$4,363$44,864$72 11ACCESSORY ELECTRIC PLANT$28,222$10,643$21,238$0$0$60,103$5,165$0$12,277$77,546$125 12INSTRUMENTATION & CONTROL$10,249$1,885$6,603$0$0$18,737$1,698$937$3,561$24,933$40 13IMPROVEMENTS TO SITE$3,349$1,974$8,263$0$0$13,586$1,341$0$4,478$19,405$31 14BUILDINGS & 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$1,987TOTAL PLANT COST

SUMMARY

Cost and Performance Baseline for Fossil Energy Plants 126 Exhibit 3-27 Case 1 Total Plant Cost Details AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING1.1Coal Receive & Unload$3,653$0$1,785$0$0$5,439$487$0$1,185$7,111$111.2Coal Stackout & Reclaim$4,721$0$1,144$0$0$5,865$514$0$1,276$7,655$121.3Coal Conveyors & Yd Crush$4,389$0$1,132$0$0$5,522$485$0$1,201$7,207$121.4Other Coal Handling$1,148$0$262$0$0$1,410$123$0$307$1,840$31.5Sorbent Receive & Unload

$0$0$0$0$0$0$0$0$0$0$01.6Sorbent Stackout & Reclaim

$0$0$0$0$0$0$0$0$0$0$01.7Sorbent Conveyors

$0$0$0$0$0$0$0$0$0$0$01.8Other Sorbent Handling

$0$0$0$0$0$0$0$0$0$0$01.9Coal & Sorbent Hnd.Foundations

$0$2,585$6,464$0$0$9,049$867$0$1,983$11,900$19SUBTOTAL 1.$13,912$2,585$10,788$0$0$27,285$2,477$0$5,952$35,714$57 2COAL & SORBENT PREP & FEED2.1Coal Crushing & Dryingw/ 2.3$0w/ 2.3$0$0$0$0$0$0$0$02.2Prepared Coal Storage & Feed$1,558$373$244$0$0$2,175$186$0$472$2,833$52.3Slurry Prep & Feed$21,299$0$9,398$0$0$30,697$2,789$1,535$7,004$42,025$682.4Misc.Coal Prep & Feed

$857$623$1,869$0$0$3,349$308$0$731$4,388$72.5Sorbent Prep Equipment

$0$0$0$0$0$0$0$0$0$0$02.6Sorbent Storage & Feed

$0$0$0$0$0$0$0$0$0$0$02.7Sorbent Injection System

$0$0$0$0$0$0$0$0$0$0$02.8Booster Air Supply System

$0$0$0$0$0$0$0$0$0$0$02.9Coal & Sorbent Feed Foundation

$0$3,330$2,734$0$0$6,063$562$0$1,325$7,950$13SUBTOTAL 2.$23,713$4,326$14,245$0$0$42,284$3,844$1,535$9,533$57,195$92 3FEEDWATER & MISC. BOP SYSTEMS3.1Feedwater System$2,896$4,974$2,626$0$0$10,496$972$0$2,294$13,762$223.2Water Makeup & Pretreating

$620$65$347$0$0$1,031$98$0$339$1,469$23.3Other Feedwater Subsystems$1,585$536$482$0$0$2,602$234$0$567$3,403$53.4Service Water Systems

$355$731$2,536$0$0$3,621$353$0$1,192$5,167$83.5Other Boiler Plant Systems$1,904$738$1,829$0$0$4,471$424$0$979$5,874$93.6FO Supply Sys & Nat Gas

$315$596$556$0$0$1,467$141$0$322$1,930$33.7Waste Treatment Equipment

$867$0$529$0$0$1,395$136$0$459$1,991$33.8Misc. Power Plant Equipment$1,080$145$554$0$0$1,779$172$0$585$2,536$4SUBTOTAL 3.$9,622$7,783$9,458$0$0$26,863$2,531$0$6,737$36,131$58 4GASIFIER & ACCESSORIES4.1Syngas Cooler Gasifier System$111,116$0$60,871$0$0$171,987$15,755$23,878$32,445$244,065$3924.2Syngas Cooler (w/ Gasifier - $)w/4.1$0w/4.1$0$0$0$0$0$0$0$04.3ASU/Oxidant Compression$160,703$0w/equip.$0$0$160,703$15,577$0$17,628$193,908$3124.4Scrubber & Low Temperature Cooling$5,873$4,781$4,975$0$0$15,629$1,501$0$3,426$20,556$334.5Black Water & Sour Gas Sectionw/4.1$0w/4.1$0$0$0$0$0$0$0$04.6Other Gasification Equipment$1,791$0$1,681$0$0$3,472$417$0$948$4,837$84.8Major Component Riggingw/4.1&4.2$0w/4.1&4.2$0$0$0$0$0$0$0$04.9Gasification Foundations

$0$6,486$5,414$0$0$11,900$1,103$0$3,251$16,253$26SUBTOTAL 4.$279,483$11,266$72,942$0$0$363,691$34,352$23,878$57,697$479,618$771 Cost and Performance Baseline for Fossil Energy Plants 127 Exhibit 3-27 Case 1 Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 5AGAS CLEANUP & PIPING5A.1Single Stage Selexol$41,961$0$35,605$0$0$77,565$7,501$0$17,013$102,080$1645A.2Elemental Sulfur Plant$10,055$2,004$12,972$0$0$25,031$2,431$0$5,493$32,955$535A.3Mercury Removal$1,057$0$804$0$0$1,862$180$93$427$2,561$45A.4COS Hydrolysis$3,575$0$4,668$0$0$8,243$801$0$1,809$10,853$175A.5Particulate Removal

$0$0$0$0$0$0$0$0$0$0$05A.6Blowback Gas Systems$1,310$0$248$0$0$1,558$190$0$350$2,098$35A.7Fuel Gas Piping

$0$688$482$0$0$1,170$108$0$256$1,534$25A.9HGCU Foundations

$0$1,108$714$0$0$1,822$167$0$597$2,586$4SUBTOTAL 5A.$57,957$3,800$55,494$0$0$117,251$11,380$93$25,944$154,668$249 5BCO2 REMOVAL & COMPRESSION5B.1CO2 Removal System

$0$0$0$0$0$0$0$0$0$0$05B.2CO2 Compression & Drying

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 5B.

$0$0$0$0$0$0$0$0$0$0$0 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine Generator$85,752$0$6,269$0$0$92,021$8,724$4,601$10,535$115,881$1866.2Syngas Expander$5,928$0$819$0$0$6,747$641$0$1,108$8,496$146.3Compressed Air Piping

$0$0$0$0$0$0$0$0$0$0$06.9Combustion Turbine Foundations

$0$887$982$0$0$1,868$175$0$613$2,656$4SUBTOTAL 6.$91,679$887$8,070$0$0$100,636$9,540$4,601$12,256$127,033$204 7HRSG, DUCTING & STACK7.1Heat Recovery Steam Generator$35,357$0$5,027$0$0$40,384$3,840$0$4,422$48,646$787.2Open$0$0$0$0$0$0$0$0$0$0$07.3Ductwork$0$1,706$1,217$0$0$2,923$256$0$636$3,816$67.4Stack$3,329$0$1,250$0$0$4,579$439$0$502$5,519$97.9HRSG,Duct & Stack Foundations

$0$667$640$0$0$1,307$122$0$429$1,858$3SUBTOTAL 7.$38,685$2,373$8,136$0$0$49,194$4,657$0$5,989$59,839$96 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$29,111$0$4,994$0$0$34,104$3,272$0$3,738$41,114$668.2Turbine Plant Auxiliaries

$202$0$463$0$0$665$65$0$73$803$18.3Condenser & Auxiliaries$5,053$0$1,484$0$0$6,537$625$0$716$7,878$138.4Steam Piping$5,117$0$3,600$0$0$8,717$749$0$2,367$11,833$198.9TG Foundations

$0$1,001$1,693$0$0$2,694$255$0$885$3,835$6SUBTOTAL 8.$39,483$1,001$12,233$0$0$52,718$4,967$0$7,778$65,462$105 Cost and Performance Baseline for Fossil Energy Plants 128 Exhibit 3-27 Case 1 Total Plant Cost Details (Continued) AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 9COOLING WATER SYSTEM9.1Cooling Towers$6,699$0$1,219$0$0$7,918$754$0$1,301$9,973$169.2Circulating Water Pumps$1,737$0$122$0$0$1,859$157$0$302$2,318$49.3Circ.Water System Auxiliaries

$147$0$21$0$0$168$16$0$28$211$09.4Circ.Water Piping

$0$6,124$1,588$0$0$7,712$697$0$1,682$10,090$169.5Make-up Water System

$343$0$490$0$0$833$80$0$183$1,096$29.6Component Cooling Water Sys

$723$865$615$0$0$2,203$206$0$482$2,891$59.9Circ.Water System Foundations

$0$2,248$3,822$0$0$6,071$576$0$1,994$8,640$14SUBTOTAL 9.$9,649$9,237$7,877$0$0$26,763$2,486$0$5,971$35,220$57 10ASH/SPENT SORBENT HANDLING SYS10.1Slag Dewatering & Cooling$11,822$6,519$13,243$0$0$31,584$3,048$0$3,463$38,095$6110.2Gasifier Ash Depressurizationw/10.1w/10.1w/10.1$0$0$0$0$0$0$0$010.3Cleanup Ash Depressurizationw/10.1w/10.1w/10.1$0$0$0$0$0$0$0$010.4High Temperature Ash Piping

$0$0$0$0$0$0$0$0$0$0$010.5Other Ash Recovery Equipment

$0$0$0$0$0$0$0$0$0$0$010.6Ash Storage Silos

$575$0$626$0$0$1,201$116$0$198$1,515$210.7Ash Transport & Feed Equipment

$771$0$186$0$0$957$89$0$157$1,204$210.8Misc. Ash Handling Equipment$1,191$1,460$436$0$0$3,087$294$0$507$3,888$610.9Ash/Spent Sorbent Foundation

$0$51$64$0$0$115$11$0$38$163$0SUBTOTAL 10.$14,359$8,029$14,555$0$0$36,943$3,559$0$4,363$44,864$72 11ACCESSORY ELECTRIC PLANT11.1Generator Equipment

$958$0$947$0$0$1,905$182$0$209$2,296$411.2Station Service Equipment$3,920$0$353$0$0$4,273$394$0$467$5,134$811.3Switchgear & Motor Control $7,247$0$1,318$0$0$8,565$794$0$1,404$10,763$1711.4Conduit & Cable Tray

$0$3,366$11,106$0$0$14,472$1,400$0$3,968$19,840$3211.5Wire & Cable

$0$6,432$4,226$0$0$10,658$774$0$2,858$14,291$2311.6Protective Equipment

$0$686$2,496$0$0$3,182$311$0$524$4,017$611.7Standby Equipment

$236$0$230$0$0$466$44$0$77$587$111.8Main Power Transformers$15,862$0$146$0$0$16,008$1,211$0$2,583$19,801$3211.9Electrical Foundations

$0$158$416$0$0$574$55$0$189$818$1SUBTOTAL 11.$28,222$10,643$21,238$0$0$60,103$5,165$0$12,277$77,546$125 12INSTRUMENTATION & CONTROL12.1IGCC Control Equipmentw/4.1$0w/4.1$0$0$0$0$0$0$0$012.2Combustion Turbine Controlw/6.1$0w/6.1$0$0$0$0$0$0$0$012.3Steam Turbine Controlw/8.1$0w/8.1$0$0$0$0$0$0$0$012.4Other Major Component Control$1,012$0$676$0$0$1,687$160$84$290$2,221$412.5Signal Processing Equipmentw/12.7$0w/12.7$0$0$0$0$0$0$0$012.6Control Boards,Panels & Racks

$233$0$149$0$0$382$36$19$87$524$112.7Computer & Accessories$5,397$0$173$0$0$5,570$511$278$636$6,995$1112.8Instrument Wiring & Tubing

$0$1,885$3,854$0$0$5,739$487$287$1,628$8,141$1312.9Other I & C Equipment$3,608$0$1,752$0$0$5,359$504$268$920$7,051$11SUBTOTAL 12.$10,249$1,885$6,603$0$0$18,737$1,698$937$3,561$24,933$40 Cost and Performance Baseline for Fossil Energy Plants 129 Exhibit 3-27 Case 1 Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 13IMPROVEMENTS TO SITE13.1Site Preparation

$0$105$2,246$0$0$2,351$233$0$775$3,360$513.2Site Improvements

$0$1,869$2,483$0$0$4,352$429$0$1,435$6,216$1013.3Site Facilities$3,349$0$3,534$0$0$6,883$679$0$2,268$9,830$16SUBTOTAL 13.$3,349$1,974$8,263$0$0$13,586$1,341$0$4,478$19,405$31 14BUILDINGS & STRUCTURES14.1Combustion Turbine Area

$0$265$150$0$0$414$36$0$90$541$114.2Steam Turbine Building

$0$2,446$3,484$0$0$5,930$546$0$971$7,447$1214.3Administration Building

$0$845$613$0$0$1,459$130$0$238$1,827$314.4Circulation Water Pumphouse

$0$167$88$0$0$255$22$0$42$319$114.5Water Treatment Buildings

$0$518$506$0$0$1,024$93$0$167$1,284$214.6Machine Shop

$0$433$296$0$0$729$65$0$119$912$114.7Warehouse

$0$699$451$0$0$1,149$102$0$188$1,439$214.8Other Buildings & Structures

$0$418$326$0$0$744$66$0$162$973$214.9Waste Treating Building & Str.

$0$935$1,787$0$0$2,723$254$0$595$3,572$6SUBTOTAL 14.

$0$6,725$7,701$0$0$14,427$1,314$0$2,573$18,313$29TOTAL COST$620,363$72,516$257,603$0$0$950,481$89,310$31,044$165,109$1,235,944$1,987Owner's CostsPreproduction Costs6 Months All Labor$12,214$201 Month Maintenance Materials$2,742$41 Month Non-fuel Consumables

$269$01 Month Waste Disposal

$304$025% of 1 Months Fuel Cost at 100% CF$1,627$32% of TPC$24,719$40Total$41,874$67Inventory Capital60 day supply of fuel and consumables at 100% CF$13,328$210.5% of TPC (spare parts)$6,180$10Total$19,507$31Initial Cost for Catalyst and Chemicals$4,892$8Land$900$1Other Owner's Costs$185,392$298Financing Costs$33,370$54Total Overnight Costs (TOC)$1,521,880$2,447TASC Multiplier(IOU, high-risk, 35 year)1.140Total As-Spent Cost (TASC)$1,734,944$2,789 Cost and Performance Baseline for Fossil Energy Plants 130 Exhibit 3-28 Case 1 Initial and Annual O&M Costs INITIAL & ANNUAL O&M EXPENSESCost Base (Jun):

2007Case 1 - GEE Radiant 640MW IGCC w/o CO2Heat Rate-net (Btu/kWh):8,756 MWe-net: 622 Capacity Factor (%):

80OPERATING & MAINTENANCE LABOROperating Labor Operating Labor Rate(base):34.65$/hour Operating Labor Burden:30.00% of base Labor O-H Charge Rate:25.00% of laborTotal Operating Labor Requirements(O.J.)per Shift:1 unit/mod. Plant Skilled Operator2.02.0 Operator9.09.0 Foreman1.01.0 Lab Tech's, etc.3.03.0 TOTAL-O.J.'s15.015.0Annual CostAnnual Unit Cost

$$/kW-netAnnual Operating Labor Cost$5,918,913$9.515Maintenance Labor Cost$13,622,877$21.900Administrative & Support Labor$4,885,447$7.854Property Taxes and Insurance$24,718,883$39.738TOTAL FIXED OPERATING COSTS$49,146,120$79.007VARIABLE OPERATING COSTS$/kWh-netMaintenance Material Cost$26,322,759$0.00604ConsumablesConsumptionUnit Initial Fill Initial Fill /Day Cost CostWater (/1000 gallons) 03,4091.08$0$1,076,793$0.00025ChemicalsMU & WT Chem. (lbs) 020,3110.17$0$1,026,436$0.00024Carbon (Mercury Removal) (lb)54,833 751.05$57,584$23,034$0.00001COS Catalyst (m3) 4220.292,397.36$1,011,578$202,316$0.00005Water Gas Shift Catalyst (ft3) 0 0498.83$0$0$0.00000Selexol Solution (gal)285,358 4513.40$3,823,295$175,961$0.00004SCR Catalyst (m3) 0 00.00$0$0$0.00000Ammonia (19% NH3) (ton) 0 00.00$0$0$0.00000Claus Catalyst (ft3)w/equip.1.94131.27$0$74,422$0.00002Subtotal Chemicals$4,892,457$1,502,168$0.00034OtherSupplemental Fuel (MBtu) 0 00.00$0$0$0.00000Gases, N2 etc. (/100scf) 0 00.00$0$0$0.00000L.P. Steam (/1000 pounds) 0 00.00$0$0$0.00000Subtotal Other

$0$0$0.00000Waste DisposalSpent Mercury Catalyst (lb.)

0 750.42$0$9,148$0.00000Flyash (ton) 0 00.00$0$0$0.00000Slag (ton) 0 61516.23$0$2,912,403$0.00067 Subtotal-Waste Disposal

$0$2,921,551$0.00067By-products & EmissionsSulfur (tons) 0 1400.00$0$0$0.00000Subtotal By-Products

$0$0$0.00000TOTAL VARIABLE OPERATING COSTS$4,892,457$31,823,271$0.00730Fuel (ton) 05,60338.18$0$62,470,676$0.01433 Cost and Performance Baseline for Fossil Energy Plants 131 3.2.8 Case 2 is configured to produce electric power with CO 2 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 CO 2 capture process increases the auxiliary load on the plant, the net output is significantly reduced relative to Case 1.

Case 2 - GEE IGCC with CO 2 Capture The process description for Case 2 is similar to Case 1 with several notable exceptions to accommodate CO 2 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.

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).

Gasification Raw gas cooling and particulate removal are the same as Case 1 with the exception that approximately 443,118 kg/h r (976,891 lb/h r) of saturated steam at 13.8 MPa (2,000 psia) is generated in the radiant SGCs.

Raw Gas Cooling/Particulate Removal No differences from Case 1.

Syngas Scrubber/Sour Water Stripper The SGS process was described in Section SGS 3.1.3. In Case 2 steam (stream 1

1) is added to the syngas exiting the scrubber to adjust the H 2O: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

1 1. A second stage of SGS results in 9 7 percent overall conversion of the CO to CO

2. The warm syngas from the second stage of SGS (stream 1

2) is cooled to 236°C (45 6°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 is the same as in Case 1.

Mercury Removal and AGR The AGR process in Case 2 is a two stage Selexol process where H 2S is removed in the first stage and CO 2 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 CO 2-rich stream and an acid gas feed to the Claus plant. The acid gas (stream 1 8) contains 35 percent H 2S and 52 percent CO 2 with the balance primarily N

2. The CO 2-rich stream is discussed further in the CO 2 compression section.

Cost and Performance Baseline for Fossil Energy Plants 132 Exhibit 3-29 Case 2 Block Flow Diagram, GEE IGCC with CO 2 Capture Cost and Performance Baseline for Fossil Energy Plants 133 Exhibit 3-30 Case 2 Stream Table, GEE IGCC with CO 2 Capture 1 2 3 4 5 6 7 8 9 10 11 12V-L Mole Fraction Ar0.00920.01660.03180.00230.03180.00000.00000.00000.00860.00680.00000.0054 CH 40.00000.00000.00000.00000.00000.00000.00000.00000.00110.00090.00000.0007 CO0.00000.00000.00000.00000.00000.00000.00000.00000.35760.28230.00000.0060 CO 20.00030.00540.00000.00000.00000.00000.00000.00000.13800.10890.00000.3082COS0.00000.00000.00000.00000.00000.00000.00000.00000.00020.00010.00000.0000 H 20.00000.00000.00000.00000.00000.00000.00000.00000.34060.26890.00000.4366 H 2 O0.00990.13630.00000.00030.00000.00000.99950.00000.13690.31901.00000.2325 HCl0.00000.00000.00000.00000.00000.00000.00000.00000.00080.00020.00000.0001 H 2 S0.00000.00000.00000.00000.00000.00000.00000.00000.00730.00570.00000.0047 N 20.77320.70610.01780.99200.01780.00000.00000.00000.00700.00550.00000.0044 NH 30.00000.00000.00000.00000.00000.00000.00050.00000.00190.00160.00000.0013 O 20.20740.13560.95040.00540.95040.00000.00000.00000.00000.00000.00000.0000 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000Total1.00001.00001.00001.00001.00000.00001.00000.00001.00001.00001.00001.0000V-L Flowrate (kgmol/hr)27,3611,650 9620,0515,526 05,037 023,12229,2847,19336,478V-L Flowrate (kg/hr)789,56045,3323,080562,615177,828 090,748 0465,243575,983129,587705,570Solids Flowrate (kg/hr) 0 0 0 0 0220,904 024,237 0 0 0 0Temperature (°C) 15 18 32 93 32 15 1421,316 677 206 288 240Pressure (MPa, abs)0.100.110.862.650.860.105.795.625.555.525.525.41Enthalpy (kJ/kg)

A30.2335.6426.6792.5026.67---537.77---1,424.651,065.712,918.18942.21Density (kg/m 3)1.21.511.024.411.0---872.0---14.027.225.624.8V-L Molecular Weight28.85727.47632.18128.06032.181---18.015---20.12119.66918.01519.343V-L Flowrate (lbmol/hr)60,3213,637 21144,20412,183 011,106 050,97664,56115,85880,419V-L Flowrate (lb/hr)1,740,68399,9406,7911,240,354392,044 0200,064 01,025,6851,269,825285,6911,555,516Solids Flowrate (lb/hr) 0 0 0 0 0487,011 053,433 0 0 0 0Temperature (°F) 59 65 90 199 90 59 2872,4001,250 403 550 463Pressure (psia)14.716.4125.0384.0125.014.7840.0815.0805.0800.0800.0785.0Enthalpy (Btu/lb)

A13.015.311.539.811.5---231.2---612.5458.21,254.6405.1Density (lb/ft 3)0.0760.0910.6871.5210.687---54.440---0.8711.6991.5971.550A - Reference conditions are 32.02 F & 0.089 PSIA Cost and Performance Baseline for Fossil Energy Plants 134 Exhibit 3-30 Case 2 Stream Table, GEE IGCC with CO 2 Capture (Continued) 13 14 15 16 17 18 19 20 21 22 23 24V-L Mole Fraction Ar0.00710.00710.01150.01150.00020.00180.00000.01030.00920.00910.00910.0000 CH 40.00090.00090.00150.00150.00000.00040.00000.00000.00000.00000.00000.0000 CO0.00780.00770.01240.01240.00020.00220.00000.00640.00000.00000.00000.0000 CO 20.40190.40550.05020.05020.99480.52140.00000.66640.00030.00830.00830.0000COS0.00000.00000.00000.00000.00000.00020.00000.00000.00000.00000.00000.0000 H 20.56920.56490.91390.91390.00480.10280.00000.25610.00000.00000.00000.0000 H 2 O0.00120.00130.00010.00010.00000.02260.00000.00170.00990.12220.12221.0000 HCl0.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 H 2 S0.00610.00610.00000.00000.00000.34770.00000.00500.00000.00000.00000.0000 N 20.00580.00640.01050.01050.00000.00080.00000.05420.77320.75410.75410.0000 NH 30.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 O 20.00000.00000.00000.00000.00000.00000.00000.00000.20740.10640.10640.0000 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000Total1.00001.00001.00001.00001.00001.00000.00001.00001.00001.00001.00001.0000V-L Flowrate (kgmol/hr)27,97828,36817,42317,42310,425 497 0 390110,253139,657139,65734,500V-L Flowrate (kg/hr)552,391564,92090,17990,179456,65017,684 012,5293,181,5573,834,3523,834,352621,521Solids Flowrate (kg/hr) 0 0 0 0 0 05,524 0 0 0 0 0Temperature (°C) 35 35 35 196 51 48 178 38 15 562 132 534Pressure (MPa, abs)5.145.15.1023.17215.2700.1630.1195.5120.1010.1050.10512.512Enthalpy (kJ/kg)

A37.1136.4195.5321,124.237-162.30674.865---5.29530.227834.762343.8193,432.885Density (kg/m 3)40.740.910.14.2641.82.25,280.577.91.20.40.936.7V-L Molecular Weight19.744 205.1765.17643.80535.588---32.15328.85727.45527.45518.015V-L Flowrate (lbmol/hr)61,68162,54038,41238,41222,9831,095 0 859243,066307,891307,89176,059V-L Flowrate (lb/hr)1,217,8131,245,436198,810198,8101,006,74038,986 027,6227,014,1338,453,2998,453,2991,370,220Solids Flowrate (lb/hr) 0 0 0 0 0 012,178 0 0 0 0 0Temperature (°F) 95 95 95 384 124 119 352 100 591,044 270 994Pressure (psia)745.0740.0740.0460.02,214.723.717.3799.514.715.215.21,814.7Enthalpy (Btu/lb)

A16.015.784.1483.3-69.832.2---2.313.0358.9147.81,475.9Density (lb/ft 3)2.544 30.6300.26040.0680.137329.6494.8640.0760.0260.0532.293 Cost and Performance Baseline for Fossil Energy Plants 135 CO 2 from the AGR process is flashed at three pressure levels to separate CO 2 and decrease H 2 losses to the CO 2 product pipeline. The HP CO 2 stream is flashed at 2.0 MPa (289.7 psia), compressed, and recycled back to the CO 2 absorber. The M P CO 2 stream is flashed at 1.0 MPa (149.7 psia). The L P CO 2 stream is flashed at 0.1 MPa (16.7 psia), compressed to 1.0 MPa (149.5 psia)

, and combined with the MP CO 2 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 CO 2 stream is dehydrated to a dewpoint of

-40ºC (-40°F) with triethylene glycol. The raw CO 2 stream from the Selexol process contains over 9 9 percent CO

2. The CO 2 (stream 1 7) is transported to the plant fence line and is sequestration ready. CO 2 TS&M costs were estimated using the methodology described in Section 2.7.

CO 2 Compression and Dehydration The Claus plant is the same as Case 1 with the following exceptions:

Claus Unit 5, 528 kg/h r (12, 178 lb/h r) of sulfur (stream 1

9) are produced The waste heat boiler generates 13,555 kg/hr (29,884 lb/h r) of 4.0 MPa (575 psia) steam of which 12,679 kg/h r (27 , 953 lb/h r) is available to the medium pressure steam header.

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 1

6) 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 2

2) 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 2

3) 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.

Power Block 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. Air Separation Unit (ASU) 3.2.9 The Case 2 modeling assumptions were presented previously in Section Case 2 Performance Results 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 CO 2 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.

Cost and Performance Baseline for Fossil Energy Plants 136 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 CO 2 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 Plant 2 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 10 6 kJ/h r (10 6 Btu/h r) 1,509 (1,430)

CONSUMABLES As-Received Coal Feed, kg/h r (lb/h r) 220,904 (487,011)

Thermal Input 1, kWt 1,665,074 Raw Water Withdrawal, m 3/min (gpm) 22.0 (5,815)

Raw Water Consumption , m 3/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

Cost and Performance Baseline for Fossil Energy Plants 137 The environmental targets for emissions of Hg, NOx, SO 2, and PM were presented in Section 2.4. A summary of the plant air emissions for Case 2 is presented in Environmental Performance Exhibit 3-32. Exhibit 3-32 Case 2 Air Emissions kg/GJ (lb/10 6 Btu) Tonne/year (tons/year) @

80% capacity factor kg/MWh (lb/MWh) SO 2 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) CO 2 8.5 (19.7) 355,438 (391,804) 69 (152) CO 2 1 93 (206) 1 CO 2 emissions based on net power instead of gross power The low level of SO 2 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 CO 2 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 H 2 S-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 H 2S and then recycled back to the Selexol process, thereby eliminating the need for a tail gas treatment unit.

NO x emissions are limited by nitrogen dilution to 15 ppmvd (as NO 2 @15 percent O 2). Ammonia in the syngas is removed with process condensate prior to the low

-temperature AGR process. This helps lower NO x 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-tw o percent of the CO 2 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 CO 2 in the stack gas, ASU vent gas, and the captured CO 2 product. The carbon capture efficiency is defined as the amount of carbon in the CO 2 product stream relative to the amount of carbon in the coal less carbon contained in the slag, represented by the following fraction:

Cost and Performance Baseline for Fossil Energy Plants 138 (Carbon in CO 2 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/h r (lb/hr) Coal 140,815 (310,444)

Slag 2,816 (6,209)

Air (CO 2) 540 (1,191)

Stack Gas 13,842 (30,516)

ASU Vent 107 (237) CO 2 Product 124,589 (274,672)

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/h r (lb/hr) Coal 5,537 (12,207)

Elemental Sulfur 5,524 (12,178)

Stack Gas 3 (6) CO 2 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.

Cost and Performance Baseline for Fossil Energy Plants 139 Exhibit 3-35 Case 2 Water Balance Water Use Water Demand, m 3/min (gpm) Internal Recycle, m 3/min (gpm) Raw Water Withdrawal, m 3/min (gpm) Process Water Discharge, m 3/min (gpm) Raw Water Consumption, m 3/min (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 Gasifier Steam Shift Steam GT Steam Dilution BFW Makeup 2.4 (627) 2.2 (571) 0.21 (56) 0.0 (0) 2.4 (627) 2.2 (571) 0.21 (56) 0.0 (0) 2.4 (627)

Cooling Tower BFW Blowdown SWS Blowdown SWS Excess Water Humidifier Tower Blowdown 18.0 (4,750)

0.49 (129) 0.21 (56) 0.28 (73) 17.5 (4,622)

-0.21 (-56) -0.28 (-73) 4.0 (1,068) 13.5 (3,553)

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 are shown for the following subsystems in Heat and Mass Balance Diagrams 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.

Cost and Performance Baseline for Fossil Energy Plants 140 This page intentionally left blank

Cost and Performance Baseline for Fossil Energy Plants 141 Exhibit 3-36 Case 2 Coal Gasification and Air Separation Units Heat and Mass Balance Schematic N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA DOE/NETL D UAL T RAIN IGCC P LANT C ASE 2 H EAT AND M ATERIAL F LOW D IAGRAM B ITUMINOUS BASELINE S TUDY C ASE 2 GEE G ASIFIER ASU AND G ASIFICATION DWG. NO.BB-HMB-CS-2-PG-1 P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas P AGES 1 OF 3 Ambient Air Four Stage Air Compressor Elevated Pressure ASU Four Stage N 2 Compressor Four Stage O 2 Compressor ASU Vent Water Steam Gross Plant Power

734 MWe Auxiliary Load

191 MWe Net Plant Power

543 MWe Net Plant Efficiency , HHV: 32.6%Net Plant Heat Rate

10 , 458 BTU/KWe N 2 to GT Combustor 1 , 740 , 683 W 59.0 T 14.7 P 13.0 H 392 , 044 W 90.0 T 125.0 P 11.5 H 392 , 044 W 241.2 T 940.0 P 40.8 H To Claus Plant 6 , 791 W 90.0 T 125.0 P 11.5 H 99 , 940 W 64.8 T 16.4 P 15.3 H 1 , 083 , 577 W 90.0 T 56.4 P 14.2 H 156 , 777 W 50.0 T 182.0 P 2.9 H 5 1 3 2 Slurry Mix Tank Milled Coal Slag 487 , 011 W 59.0 T 14.7 P 200 , 064 W 287.0 T 840.0 P 231.2 H 53 , 433 W 2 , 400.0 T 815.0 P 676 , 491 W 385.0 T 384.0 P 87.2 H 687 , 075 W 156.4 T 840.0 P 2 , 950.2 H 100.0 T 189.5 P 18.0 H 6 676 , 491 W 199.0 T 384.0 P 39.8 H HP BFW N 2 to GT Combustor N 2 Boost Compressor 563 , 864 W 199.0 T 384.0 P 39.8 H 563 , 864 W 385.0 T 469.0 P 87.0 H Saturated Steam To HRSG HP Superheater GE Energy Gasifier Radiant Syngas Cooler Black Water Flash Tank Knockout Drum Vent To Claus Unit Raw Fuel Gas CWS CWR Fines Process Water From Sour Water Stripper Syngas Scrubber Slag Quench Section Drag Conveyor 4 1 , 025 , 685 W 1 , 250.0 T 805.0 P 612.5 H 1 , 269 , 825 W 403.1 T 800.0 P 458.2 H Syngas Quench 1 , 403 , 986 W 450.0 T 805.0 P 536.1 H 8 9 10 Sour Water 7

Cost and Performance Baseline for Fossil Energy Plants 142 Exhibit 3-37 Case 2 Syngas Cleanup Heat and Mass Balance Schematic Mercury Removal Knock Out Drum Syngas Preheater Sour Drum Process Condensate to Syngas Scrubber Makeup Water Claus Plant Tail Gas Furnace Catalytic Reactor Beds Sulfur Knock Out From ASU Syngas Coolers Sour Stripper 1 , 269 , 825 W 403.1 T 800.0 P 458.2 H 1 , 245 , 436 W 94.6 T 740.0 P 15.7 H 38 , 986 W 119.0 T 23.7 P 198 , 810 W 384.3 T 460.0 P 483.3 H 12 , 178 W 36 , 094 W 450.0 T 12.3 P 457.8 H 2 , 495 W 239.1 T 65.0 P 441.9 H 6 , 791 W 90.0 T 125.0 P 11.5 H N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA DOE/NETL D UAL T RAIN IGCC P LANT C ASE 2 H EAT AND M ATERIAL F LOW D IAGRAM B ITUMINOUS BASELINE S TUDY C ASE 2 GEE G ASIFIER G AS CLEANUP SYSTEM DWG. NO.BB-HMB-CS-2-PG-2 P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas P AGES 2 OF 3 Sour Gas Sour Water Water Steam Gross Plant Power

734 MWe Auxiliary Load

191 MWe Net Plant Power

543 MWe Net Plant Efficiency , HHV: 32.6%Net Plant Heat Rate

10 , 458 BTU/KWe 19 13 20 CO 2 Tailgas 30 , 072 W 120.0 T 10.6 P 112.1 H 1 , 217 , 813 W 94.9 T 745.0 P 16.0 H 8 , 472 W 114.3 T 10.6 P 40.0 H 3 27 , 622 W 100.0 T 799.5 P Raw Syngas 15 198 , 810 W 94.6 T 740.0 P 84.1 H Claus Oxygen Preheater 6 , 791 W 450.0 T 124.5 P 91.9 H 18 Fuel Gas Expander Fuel Gas To GT 16 198 , 810 W 465.0 T 735.0 P 597.2 H High Temperature Shift #1 Low Temperature Shift #2 Shift Steam 12 11 COS Hydrolysis Preheater 1 , 269 , 825 W 413.1 T 795.0 P 450.3 H 285 , 691 W 550.0 T 800.0 P 1 , 254.1 H 1 , 555 , 516 W 436.4 T 795.0 P 598.0 H 776.2 T 795.0 P 582.1 H 400.0 T 795.0 P 408.0 H 1 , 555 , 516 W 463.4 T 785.0 P 405.1 H 1 , 555 , 516 W 455.6 T 780.0 P 401.5 H Two-Stage Selexol Clean Gas CO 2 Acid Gas Multistage Intercooled CO 2 Compressor Interstage Knockout CO 2 Product 17 10 14 1 , 006 , 740 W 123.8 T 2 , 214.7 P Tail Gas Recycle Compressor Hydrogenation and Tail Gas Cooling Cost and Performance Baseline for Fossil Energy Plants 143 Exhibit 3-38 Case 2 Combined-Cycle Power Generation Heat and Mass Balance Schematic HRSG HP Turbine IP Turbine Nitrogen Diluent Intake Ambient Air Steam Seal Regulator Ip Extraction Steam To 250 PSIA Header LP Process Header Blowdown Flash To WWT Gland Steam Condenser Condensate to Gasification Island HP BFW to Radiant Syngas Cooler HP Saturated Steam to HRSG Superheater LP Turbine Stack Expander Compressor Fuel Gas Deaerator IP BFW Generator Generator Condensate Pump HP Pump Steam Turbine LP Pump Advanced F

-Class Gas Turbine MP Flash Bottoms LP Flash Tops 7 , 014 , 133 W 59.0 T 14.7 P 13.0 H 1 , 875 , 803 W 101.1 T 1.0 P 69.1 H 8 , 453 , 299 W 269.9 T 15.2 P 147.8 H 198 , 810 W 384.3 T 460.0 P 483.3 H 8 , 453 , 299 W 1 , 043.8 T 15.2 P 358.9 H From Gasifier Island Preheating To Claus LP BFW 1 , 370 , 220 W 993.8 T 1 , 814.7 P 1 , 475.9 H 10 , 303 W 298.0 T 65.0 P 1 , 179.0 H 1 , 399 , 040 W 278.8 T 2 , 250.7 P 252.3 H 28 , 836 W 585.0 T 2 , 000.7 P 593.3 H 1 , 550 , 132 W 474.9 T 65.0 P 1 , 269.6 H 1 , 875 , 803 W 102.9 T 120.0 P 71.1 H 1 , 875 , 803 W 235.0 T 105.0 P 203.7 H 1 , 400 W 614.9 T 65.0 P 1 , 338.7 H 1 , 400 W 212.0 T 14.7 P 179.9 H IP Pump N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA DOE/NETL D UAL T RAIN IGCC P LANT C ASE 2 H EAT AND M ATERIAL F LOW D IAGRAM B ITUMINOUS BASELINE S TUDY C ASE 2 GEE G ASIFIER P OWER B LOCK S YSTEM DWG. NO.BB-HMB-CS-2-PG-3 P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas P AGES 3 OF 3 Sour Gas Sour Water Water Steam Gross Plant Power

734 MWe Auxiliary Load

191 MWe Net Plant Power

543 MWe Net Plant Efficiency , HHV: 32.6%Net Plant Heat Rate

10 , 458 BTU/KWe 21 22 24 16 23 Flue Gas HOT WELL CONDENSER Make-up 313 , 510 W 59.0 T 14.7 P 27.1 H 9 , 026 W 660.5 T 501.4 P 1 , 334.5 H 9 , 761 W 614.9 T 65.0 P 1 , 338.7 H 34 , 034 W 852.1 T 280.0 P 1 , 448.8 H 798 W 993.8 T 1 , 814.7 P 1 , 475.9 H 1 , 337 W 505.0 T 65.0 P 1 , 284.5 H Cost and Performance Baseline for Fossil Energy Plants 144 This page intentionally left blank

Cost and Performance Baseline for Fossil Energy Plants 145 Exhibit 3-39 Case 2 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total 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) CO 2 -74 (-70) -74 (-70) Cooling Tower Blowdown 30 (28) 30 (28) HRSG Flue Gas 1,318 (1,250) 1,318 (1,250)

Condenser 1,513 (1,434) 1,513 (1,434)

Non-Condenser Cooling Tower Loads* 632 (599) 632 (599) 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, CO 2 compressor intercoolers, sour water stripper condenser, and syngas cooler (low level heat rejection).

- Calculated by difference to close the energy balance

.

Cost and Performance Baseline for Fossil Energy Plants 146 3.2.10 Major equipment items for the GEE gasifier with CO 2 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 Case 2 - Major Equipment List 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 No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Bottom Trestle Dumper and Receiving HoppersN/A181 tonne (200 ton) 2 0 2FeederBelt572 tonne/hr (630 tph) 2 0 3Conveyor No. 1Belt1,134 tonne/hr (1,250 tph) 1 0 4Transfer Tower No. 1EnclosedN/A 1 0 5Conveyor No. 2Belt1,134 tonne/hr (1,250 tph) 1 0 6As-Received Coal Sampling SystemTwo-stageN/A 1 0 7Stacker/ReclaimerTraveling, linear1,134 tonne/hr (1,250 tph) 1 0 8Reclaim HopperN/A45 tonne (50 ton) 2 1 9FeederVibratory181 tonne/hr (200 tph) 2 1 10Conveyor No. 3Belt w/ tripper363 tonne/hr (400 tph) 1 0 11Crusher TowerN/AN/A 1 0 12Coal Surge Bin w/ Vent FilterDual outlet181 tonne (200 ton) 2 0 13CrusherImpactor reduction8 cm x 0 - 3 cm x 0(3" x 0 1/4" x 0) 2 0 14As-Fired Coal Sampling SystemSwing hammerN/A 1 1 15Conveyor No. 4Belt w/tripper363 tonne/hr (400 tph) 1 0 16Transfer Tower No. 2EnclosedN/A 1 0 17Conveyor No. 5Belt w/ tripper363 tonne/hr (400 tph) 1 0 18Coal Silo w/ Vent Filter and Slide GatesField erected816 tonne (900 ton) 3 0 Cost and Performance Baseline for Fossil Energy Plants 147 ACCOUNT 2 COAL PREPARATION AND FEED Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1FeederVibratory82 tonne/h (90 tph) 3 0 2Conveyor No. 6Belt w/tripper245 tonne/h (270 tph) 1 0 3Rod Mill Feed HopperDual Outlet490 tonne (540 ton) 1 0 4Weigh FeederBelt118 tonne/h (130 tph) 2 0 5Rod MillRotary118 tonne/h (130 tph) 2 0 6Slurry Water Storage Tank with AgitatorField erected299,921 liters (79,230 gal) 2 0 7Slurry Water PumpsCentrifugal833 lpm (220 gpm) 2 1 8Trommel ScreenCoarse172 tonne/h (190 tph) 2 0 9Rod Mill Discharge Tank with AgitatorField erected392,323 liters (103,640 gal) 2 0 10Rod Mill Product PumpsCentrifugal3,407 lpm (900 gpm) 2 2 11Slurry Storage Tank with AgitatorField erected1,176,894 liters (310,900 gal) 2 0 12Slurry Recycle PumpsCentrifugal6,435 lpm (1,700 gpm) 2 2 13Slurry Product PumpsPositive displacement3,407 lpm (900 gpm) 2 2 Cost and Performance Baseline for Fossil Energy Plants 148 ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Demineralized Water Storage TankVertical, cylindrical, outdoor1,093,984 liters (289,000 gal) 2 0 2Condensate PumpsVertical canned7,836 lpm @ 91 m H2O(2,070 gpm @ 300 ft H2O) 2 1 3Deaerator (integral w/ HRSG)Horizontal spray type546,579 kg/hr (1,205,000 lb/hr) 2 0 4Intermediate Pressure Feedwater PumpHorizontal centrifugal, single stage8,025 lpm @ 27 m H2O(2,120 gpm @ 90 ft H2O) 2 1 5High Pressure Feedwater Pump No. 1Barrel type, multi-stage, centrifugalHP water: 6,057 lpm @ 1,859 m H2O (1,600 gpm @ 6,100 ft H2O)2 1 6High Pressure Feedwater Pump No. 2Barrel type, multi-stage, centrifugalIP water: 1,703 lpm @ 223 m H2O (450 gpm @ 730 ft H2O) 2 1 7Auxiliary BoilerShop fabricated, water tube18,144 kg/hr, 2.8 MPa, 343°C(40,000 lb/hr, 400 psig, 650°F) 1 0 8Service Air CompressorsFlooded Screw28 m3/min @ 0.7 MPa(1,000 scfm @ 100 psig) 2 1 9Instrument Air DryersDuplex, regenerative28 m3/min (1,000 scfm) 2 1 10Closed Cylce Cooling Heat ExchangersPlate and frame362 GJ/hr (343 MMBtu/hr) each 2 0 11Closed Cycle Cooling Water PumpsHorizontal centrifugal129,840 lpm @ 21 m H2O(34,300 gpm @ 70 ft H2O) 2 1 12Engine-Driven Fire PumpVertical turbine, diesel engine3,785 lpm @ 107 m H2O(1,000 gpm @ 350 ft H2O) 1 1 13Fire Service Booster PumpTwo-stage horizontal centrifugal2,650 lpm @ 76 m H2O(700 gpm @ 250 ft H2O) 1 1 14Raw Water PumpsStainless steel, single suction5,716 lpm @ 18 m H2O(1,510 gpm @ 60 ft H2O) 2 1 15Ground Water PumpsStainless steel, single suction2,839 lpm @ 268 m H2O (750 gpm @ 880 ft H2O) 4 1 16Filtered Water PumpsStainless steel, single suction3,369 lpm @ 49 m H2O(890 gpm @ 160 ft H2O) 2 1 17Filtered Water TankVertical, cylindrical1,608,800 liter (425,000 gal) 2 0 18Makeup Water DemineralizerAnion, cation, and mixed bed1,476 lpm (390 gpm) 2 0 19Liquid Waste Treatment System10 years, 24-hour storm 1 0 Cost and Performance Baseline for Fossil Energy Plants 149 ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1GasifierPressurized slurry-feed, entrained bed2,903 tonne/day, 5.6 MPa(3,200 tpd, 814.96 psia) 2 0 2Synthesis Gas CoolerVertical downflow radiant heat exchanger with outlet quench chamber255,826 kg/hr (564,000 lb/hr) 2 0 3Syngas Scrubber Including Sour Water StripperVertical upflow350,173 kg/hr (772,000 lb/hr) 2 0 4Raw Gas CoolersShell and tube with condensate drain388,275 kg/hr (856,000 lb/hr) 8 0 5Raw Gas Knockout DrumVertical with mist eliminator304,360 kg/hr, 35°C, 5.2 MPa(671,000 lb/hr, 95°F, 750 psia) 2 0 6Flare StackSelf-supporting, carbon steel, stainless steel top, pilot ignition350,173 kg/hr (772,000 lb/hr) syngas 2 0 7ASU Main Air CompressorCentrifugal, multi-stage5,947 m3/min @ 1.3 MPa(210,000 scfm @ 190 psia) 2 0 8Cold BoxVendor design2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2 0 9Oxygen CompressorCentrifugal, multi-stage1,189 m3/min (42,000 scfm)Suction - 0.9 MPa (130 psia)Discharge - 6.5 MPa (940 psia) 2 0 10Primary Nitrogen CompressorCentrifugal, multi-stage3,794 m3/min (134,000 scfm)Suction - 0.4 MPa (60 psia)Discharge - 2.7 MPa (390 psia) 2 0 11Secondary Nitrogen CompressorCentrifugal, single-stage538 m3/min (19,000 scfm)Suction - 1.2 MPa (180 psia)Discharge - 2.7 MPa (390 psia) 2 0 12Syngas Dilution Nitrogen Boost CompressorCentrifugal, single-stage1,982 m3/min (70,000 scfm)Suction - 2.6 MPa (380 psia)Discharge - 3.2 MPa (470 psia) 2 0 Cost and Performance Baseline for Fossil Energy Plants 150 ACCOUNT 5A SOUR GAS SHIFT AND SYNGAS CLEANUP ACCOUNT 5B CO 2 COMPRESSION

Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Mercury AdsorberSulfated carbon bed303,907 kg/hr (670,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 2 0 2Sulfur PlantClaus type146 tonne/day (161 tpd) 1 0 3Water Gas Shift ReactorsFixed bed, catalytic388,275 kg/hr (856,000 lb/hr) 227°C (440°F) 5.4 MPa (790 psia) 4 0 4Shift Reactor Heat Recovery ExchangersShell and TubeExchanger 1: 157 GJ/hr (149 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) 4 0 5Acid Gas Removal PlantTwo-stage Selexol310,711 kg/hr (685,000 lb/hr) 35°C (95°F) 5.1 MPa (740 psia) 2 0 6Hydrogenation ReactorFixed bed, catalytic18,009 kg/hr (39,704 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 1 0 7Tail Gas Recycle CompressorCentrifugal13,782 kg/hr (30,385 lb/hr) 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1CO2 CompressorIntegrally geared, multi-stage centrifugal1,133 m3/min @ 15.3 MPa (40,000 scfm @ 2,215 psia) 4 0 Cost and Performance Baseline for Fossil Energy Plants 151 ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES ACCOUNT 7 HRSG, DUCTING, AND STACK Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Gas TurbineAdvanced F class232 MW 2 0 2Gas Turbine GeneratorTEWAC260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0 3Syngas Expansion Turbine/GeneratorTurbo Expander49,578 kg/h (109,300 lb/h)5.1 MPa (735 psia) Inlet3.2 MPa (460 psia) Outlet 2 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1StackCS plate, type 409SS liner76 m (250 ft) high x8.5 m (28 ft) diameter 1 0 2Heat Recovery Steam GeneratorDrum, multi-pressure with economizer section and integral deaeratorMain steam - 341,837 kg/hr, 12.4 MPa/534°C (753 , 621 lb/hr , 1 , 800 psig/994°F) Reheat steam - 336,628 kg/hr, 3.1 MPa/534°C (742 , 137 lb/hr , 452 psig/994°F)2 0 Cost and Performance Baseline for Fossil Energy Plants 152 ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES ACCOUNT 9 COOLING WATER SYSTEM Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Steam TurbineCommercially available advanced steam turbine277 MW 12.4 MPa/534°C/534°C (1 , 800 psig/ 994°F/994°F)1 0 2Steam Turbine GeneratorHydrogen cooled, static excitiation310 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0 3Steam BypassOne per HRSG50% steam flow @ design steam conditions 2 0 4Surface CondenserSingle pass, divided waterbox including vacuum pumps1,667 GJ/hr (1,580 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F)1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Circulating Water PumpsVertical, wet pit461,820 lpm @ 30 m(122,000 gpm @ 100 ft) 2 1 2Cooling TowerEvaporative, mechanical draft, multi-cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,585 GJ/hr (2,450 MMBtu/hr) heat duty 1 0 Cost and Performance Baseline for Fossil Energy Plants 153 ACCOUNT 10 SLAG RECOVERY AND HANDLING Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Slag Quench TankWater bath253,623 liters (67,000 gal) 2 0 2Slag CrusherRoll14 tonne/hr (15 tph) 2 0 3Slag DepressurizerLock Hopper14 tonne/hr (15 tph) 2 0 4Slag Receiving TankHorizontal, weir151,416 liters (40,000 gal) 2 0 5Black Water Overflow TankShop fabricated68,137 liters (18,000 gal) 2 6Slag ConveyorDrag chain14 tonne/hr (15 tph) 2 0 7Slag Separation ScreenVibrating14 tonne/hr (15 tph) 2 0 8Coarse Slag ConveyorBelt/bucket14 tonne/hr (15 tph) 2 0 9Fine Ash Settling TankVertical, gravity215,768 liters (57,000 gal) 2 0 10Fine Ash Recycle PumpsHorizontal centrifugal38 lpm @ 14 m H2O(10 gpm @ 46 ft H2O) 2 2 11Grey Water Storage TankField erected68,137 liters (18,000 gal) 2 0 12Grey Water PumpsCentrifugal227 lpm @ 564 m H2O(60 gpm @ 1,850 ft H2O) 2 2 13Slag Storage BinVertical, field erected998 tonne (1,100 tons) 2 0 14Unloading EquipmentTelescoping chute109 tonne/hr (120 tph) 1 0 Cost and Performance Baseline for Fossil Energy Plants 154 ACCOUNT 11 ACCESSORY ELECTRIC PLANT ACCOUNT 12 INSTRUMENTATION AND CONTROL Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1CTG Step-up TransformerOil-filled24 kV/345 kV, 260 MVA, 3-ph, 60 Hz 2 0 2STG Step-up TransformerOil-filled24 kV/345 kV, 310 MVA, 3-ph, 60 Hz 1 0 3High Voltage Auxiliary TransformerOil-filled345 kV/13.8 kV, 80 MVA, 3-ph, 60 Hz 2 0 4Medium Voltage Auxiliary TransformerOil-filled24 kV/4.16 kV, 48 MVA, 3-ph, 60 Hz 1 1 5Low Voltage TransformerDry ventilated4.16 kV/480 V, 7 MVA, 3-ph, 60 Hz 1 1 6CTG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled24 kV, 3-ph, 60 Hz 2 0 7STG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled24 kV, 3-ph, 60 Hz 1 0 8Medium Voltage SwitchgearMetal clad4.16 kV, 3-ph, 60 Hz 1 1 9Low Voltage SwitchgearMetal enclosed480 V, 3-ph, 60 Hz 1 1 10Emergency Diesel GeneratorSized for emergency shutdown750 kW, 480 V, 3-ph, 60 Hz 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1DCS - Main ControlMonitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W)Operator stations/printers and engineering stations/printers 1 0 2DCS - ProcessorMicroprocessor with redundant input/outputN/A 1 0 3DCS - Data HighwayFiber opticFully redundant, 25% spare 1 0 Cost and Performance Baseline for Fossil Energy Plants 155 3.2.11 The cost estimating methodology was described previously in Section Case 2 - Cost Estimating 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 owner's costs, TOC, and TASC. Exhibit 3-42 shows the initial and annual O&M costs.

The estimated TOC of the GEE gasifier with CO 2 capture is $3,334/kW. Process contingency represents 3.6 percent of the TPC and project contingency represents 11.1 percent. The COE, including CO 2 TS&M costs of 5.3 mills/kWh is 1 05.7 mills/kWh.

Cost and Performance Baseline for Fossil Energy Plants 156 Exhibit 3-40 Case 2 Total Plant Cost Summary Client: USDOE/NETLReport Date:2010-Jan-14Project: Bituminous Baseline StudyCase: Case 2 - GEE Radiant 550MW IGCC w/ CO2Plant Size: 543.3MW,netEstimate Type: ConceptualCost Base (Jun) 2007($x1000)AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING$14,280$2,654$11,074$0$0$28,008$2,542$0$6,110$36,660$67 2COAL & SORBENT PREP & FEED$24,391$4,448$14,651$0$0$43,489$3,954$1,579$9,804$58,826$108 3FEEDWATER & MISC. BOP SYSTEMS$10,158$7,914$10,237$0$0$28,309$2,671$0$7,166$38,146$70 4GASIFIER & ACCESSORIES4.1Syngas Cooler Gasifier System$113,863$0$62,389$0$0$176,251$16,146$24,460$33,252$250,109$4604.2Syngas Cooler (w/ Gasifier - $)w/4.1$0w/ 4.1$0$0$0$0$0$0$0$04.3ASU/Oxidant Compression$193,046$0w/equip.$0$0$193,046$18,712$0$21,176$232,934$4294.4-4.9Other Gasification Equipment$7,894$12,285$12,270$0$0$32,449$3,078$0$7,755$43,282$80SUBTOTAL 4$314,803$12,285$74,659$0$0$401,747$37,935$24,460$62,183$526,325$969 5AGAS CLEANUP & PIPING$96,775$3,334$82,247$0$0$182,357$17,666$27,526$45,625$273,174$503 5BCO2 COMPRESSION$18,256$0$11,190$0$0$29,446$2,836$0$6,456$38,739$71 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine Generator$92,026$0$6,583$0$0$98,609$9,348$9,861$11,782$129,600$2396.2-6.9Combustion Turbine Other$5,550$887$1,748$0$0$8,185$775$0$1,650$10,610$20SUBTOTAL 6$97,576$887$8,331$0$0$106,794$10,123$9,861$13,432$140,210$258 7HRSG, DUCTING & STACK7.1Heat Recovery Steam Generator$33,620$0$4,780$0$0$38,401$3,651$0$4,205$46,257$857.2-7.9SCR System, Ductwork and Stack$3,376$2,407$3,153$0$0$8,936$828$0$1,589$11,353$21SUBTOTAL 7$36,996$2,407$7,933$0$0$47,336$4,480$0$5,794$57,610$106 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$28,123$0$4,808$0$0$32,931$3,160$0$3,609$39,699$738.2-8.9Turbine Plant Auxiliaries and Steam Piping$10,211$967$7,075$0$0$18,253$1,662$0$3,950$23,865$44SUBTOTAL 8$38,333$967$11,883$0$0$51,183$4,821$0$7,559$63,564$117 9COOLING WATER SYSTEM$10,319$9,775$8,388$0$0$28,483$2,646$0$6,348$37,477$69 10ASH/SPENT SORBENT HANDLING SYS$14,734$8,239$14,938$0$0$37,910$3,652$0$4,476$46,038$85 11ACCESSORY ELECTRIC PLANT$32,062$12,584$24,591$0$0$69,237$5,953$0$14,261$89,451$165 12INSTRUMENTATION & CONTROL$11,404$2,098$7,347$0$0$20,849$1,889$1,042$3,962$27,743$51 13IMPROVEMENTS TO SITE$3,485$2,054$8,600$0$0$14,140$1,396$0$4,661$20,196$37 14BUILDINGS & 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$2,711TOTAL PLANT COST

SUMMARY

Cost and Performance Baseline for Fossil Energy Plants 157 Exhibit 3-41 Case 2 Total Plant Cost Details AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING1.1Coal Receive & Unload$3,750$0$1,833$0$0$5,583$500$0$1,217$7,299$131.2Coal Stackout & Reclaim$4,846$0$1,175$0$0$6,021$528$0$1,310$7,858$141.3Coal Conveyors & Yd Crush$4,505$0$1,162$0$0$5,668$498$0$1,233$7,398$141.4Other Coal Handling$1,179$0$269$0$0$1,448$127$0$315$1,889$31.5Sorbent Receive & Unload

$0$0$0$0$0$0$0$0$0$0$01.6Sorbent Stackout & Reclaim

$0$0$0$0$0$0$0$0$0$0$01.7Sorbent Conveyors

$0$0$0$0$0$0$0$0$0$0$01.8Other Sorbent Handling

$0$0$0$0$0$0$0$0$0$0$01.9Coal & Sorbent Hnd.Foundations

$0$2,654$6,635$0$0$9,289$890$0$2,036$12,215$22SUBTOTAL 1.$14,280$2,654$11,074$0$0$28,008$2,542$0$6,110$36,660$67 2COAL & SORBENT PREP & FEED2.1Coal Crushing & Dryingw/2.3$0w/2.3$0$0$0$0$0$0$0$02.2Prepared Coal Storage & Feed$1,602$383$251$0$0$2,236$191$0$485$2,913$52.3Slurry Prep & Feed$21,908$0$9,667$0$0$31,575$2,869$1,579$7,205$43,227$802.4Misc.Coal Prep & Feed

$881$641$1,922$0$0$3,443$316$0$752$4,512$82.5Sorbent Prep Equipment

$0$0$0$0$0$0$0$0$0$0$02.6Sorbent Storage & Feed

$0$0$0$0$0$0$0$0$0$0$02.7Sorbent Injection System

$0$0$0$0$0$0$0$0$0$0$02.8Booster Air Supply System

$0$0$0$0$0$0$0$0$0$0$02.9Coal & Sorbent Feed Foundation

$0$3,424$2,811$0$0$6,234$577$0$1,362$8,174$15SUBTOTAL 2.$24,391$4,448$14,651$0$0$43,489$3,954$1,579$9,804$58,826$108 3FEEDWATER & MISC. BOP SYSTEMS3.1Feedwater System$2,836$4,870$2,571$0$0$10,276$952$0$2,246$13,474$253.2Water Makeup & Pretreating

$717$75$401$0$0$1,193$114$0$392$1,699$33.3Other Feedwater Subsystems$1,552$524$472$0$0$2,548$229$0$555$3,332$63.4Service Water Systems

$411$845$2,934$0$0$4,190$409$0$1,380$5,979$113.5Other Boiler Plant Systems$2,203$854$2,116$0$0$5,173$491$0$1,133$6,796$133.6FO Supply Sys & Nat Gas

$315$596$556$0$0$1,467$141$0$322$1,930$43.7Waste Treatment Equipment$1,003$0$612$0$0$1,615$157$0$532$2,303$43.8Misc. Power Plant Equipment$1,121$150$576$0$0$1,847$178$0$608$2,634$5SUBTOTAL 3.$10,158$7,914$10,237$0$0$28,309$2,671$0$7,166$38,146$70 4GASIFIER & ACCESSORIES4.1Syngas Cooler Gasifier System$113,863$0$62,389$0$0$176,251$16,146$24,460$33,252$250,109$4604.2Syngas Cooler (w/ Gasifier - $)w/4.1$0w/ 4.1$0$0$0$0$0$0$0$04.3ASU/Oxidant Compression$193,046$0w/equip.$0$0$193,046$18,712$0$21,176$232,934$4294.4Scrubber & Low Temperature Cooling$6,049$4,924$5,125$0$0$16,097$1,546$0$3,529$21,172$394.5Black Water & Sour Gas Sectionw/4.1$0w/4.1$0$0$0$0$0$0$0$04.6Soot Recovery & SARU$1,845$876$1,731$0$0$4,452$429$0$976$5,857$114.8Major Component Riggingw/4.1$0w/4.1$0$0$0$0$0$0$0$04.9Gasification Foundations

$0$6,486$5,414$0$0$11,900$1,103$0$3,251$16,253$30SUBTOTAL 4.$314,803$12,285$74,659$0$0$401,747$37,935$24,460$62,183$526,325$969 Cost and Performance Baseline for Fossil Energy Plants 158 Exhibit 3-41 Case 2 Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 5AGAS CLEANUP & PIPING5A.1Double Stage Selexol$74,127$0$62,899$0$0$137,025$13,252$27,405$35,536$213,219$3925A.2Elemental Sulfur Plant$10,329$2,059$13,326$0$0$25,713$2,498$0$5,642$33,853$625A.3Mercury Removal$1,376$0$1,047$0$0$2,423$234$121$556$3,334$65A.4Shift Reactors$9,594$0$3,862$0$0$13,456$1,290$0$2,949$17,696$335A.5Particulate Removal

$0$0$0$0$0$0$0$0$0$0$05A.6Blowback Gas Systems$1,349$0$256$0$0$1,605$196$0$360$2,161$45A.7Fuel Gas Piping

$0$634$444$0$0$1,078$100$0$236$1,413$35A.9HGCU Foundations

$0$642$414$0$0$1,056$97$0$346$1,498$3SUBTOTAL 5A.$96,775$3,334$82,247$0$0$182,357$17,666$27,526$45,625$273,174$503 5BCO2 COMPRESSION5B.1CO2 Removal System

$0$0$0$0$0$0$0$0$0$0$05B.2CO2 Compression & Drying$18,256$0$11,190$0$0$29,446$2,836$0$6,456$38,739$71SUBTOTAL 5B.$18,256$0$11,190$0$0$29,446$2,836$0$6,456$38,739$71 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine Generator$92,026$0$6,583$0$0$98,609$9,348$9,861$11,782$129,600$2396.2Syngas Expander$5,550$0$767$0$0$6,316$600$0$1,038$7,954$156.3Compressed Air Piping

$0$0$0$0$0$0$0$0$0$0$06.9Combustion Turbine Foundations

$0$887$982$0$0$1,868$175$0$613$2,656$5SUBTOTAL 6.$97,576$887$8,331$0$0$106,794$10,123$9,861$13,432$140,210$258 7HRSG, DUCTING & STACK7.1Heat Recovery Steam Generator$33,620$0$4,780$0$0$38,401$3,651$0$4,205$46,257$857.2Open$0$0$0$0$0$0$0$0$0$0$07.3Ductwork$0$1,731$1,235$0$0$2,965$260$0$645$3,870$77.4Stack$3,376$0$1,268$0$0$4,644$445$0$509$5,598$107.9HRSG, Duct & Stack Foundations

$0$676$650$0$0$1,326$123$0$435$1,884$3SUBTOTAL 7.$36,996$2,407$7,933$0$0$47,336$4,480$0$5,794$57,610$106 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$28,123$0$4,808$0$0$32,931$3,160$0$3,609$39,699$738.2Turbine Plant Auxiliaries

$195$0$447$0$0$642$63$0$70$775$18.3Condenser & Auxiliaries$5,009$0$1,471$0$0$6,480$619$0$710$7,809$148.4Steam Piping$5,006$0$3,522$0$0$8,528$733$0$2,315$11,576$218.9TG Foundations

$0$967$1,635$0$0$2,603$247$0$855$3,704$7SUBTOTAL 8.$38,333$967$11,883$0$0$51,183$4,821$0$7,559$63,564$117 Cost and Performance Baseline for Fossil Energy Plants 159 Exhibit 3-41 Case 2 Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 9COOLING WATER SYSTEM9.1Cooling Towers$7,155$0$1,302$0$0$8,457$805$0$1,389$10,652$209.2Circulating Water Pumps$1,856$0$134$0$0$1,990$168$0$324$2,481$59.3Circ.Water System Auxiliaries

$155$0$22$0$0$177$17$0$29$224$09.4Circ.Water Piping

$0$6,481$1,680$0$0$8,161$738$0$1,780$10,679$209.5Make-up Water System

$388$0$555$0$0$943$90$0$207$1,240$29.6Component Cooling Water Sys

$765$915$651$0$0$2,331$218$0$510$3,060$69.9Circ.Water System Foundations

$0$2,379$4,044$0$0$6,423$609$0$2,110$9,142$17SUBTOTAL 9.$10,319$9,775$8,388$0$0$28,483$2,646$0$6,348$37,477$69 10ASH/SPENT SORBENT HANDLING SYS10.1Slag Dewatering & Cooling$12,136$6,692$13,595$0$0$32,424$3,129$0$3,555$39,109$7210.2Gasifier Ash Depressurizationw/10.1w/10.1w/10.1$0$0$0$0$0$0$0$010.3Cleanup Ash Depressurizationw/10.1w/10.1w/10.1$0$0$0$0$0$0$0$010.4High Temperature Ash Piping

$0$0$0$0$0$0$0$0$0$0$010.5Other Ash Recovery Equipment

$0$0$0$0$0$0$0$0$0$0$010.6Ash Storage Silos

$589$0$641$0$0$1,229$119$0$202$1,551$310.7Ash Transport & Feed Equipment

$790$0$190$0$0$980$91$0$161$1,232$210.8Misc. Ash Handling Equipment$1,219$1,494$446$0$0$3,160$301$0$519$3,980$710.9Ash/Spent Sorbent Foundation

$0$52$65$0$0$117$11$0$39$167$0SUBTOTAL 10.$14,734$8,239$14,938$0$0$37,910$3,652$0$4,476$46,038$85 11ACCESSORY ELECTRIC PLANT11.1Generator Equipment

$947$0$937$0$0$1,885$180$0$206$2,271$411.2Station Service Equipment$4,697$0$423$0$0$5,121$472$0$559$6,152$1111.3Switchgear & Motor Control $8,684$0$1,579$0$0$10,264$952$0$1,682$12,898$2411.4Conduit & Cable Tray

$0$4,034$13,308$0$0$17,342$1,677$0$4,755$23,775$4411.5Wire & Cable

$0$7,708$5,064$0$0$12,772$928$0$3,425$17,125$3211.6Protective Equipment

$0$686$2,496$0$0$3,182$311$0$524$4,016$711.7Standby Equipment

$234$0$228$0$0$462$44$0$76$581$111.8Main Power Transformers$17,500$0$144$0$0$17,644$1,334$0$2,847$21,825$4011.9Electrical Foundations

$0$156$410$0$0$567$54$0$186$807$1SUBTOTAL 11.$32,062$12,584$24,591$0$0$69,237$5,953$0$14,261$89,451$165 12INSTRUMENTATION & CONTROL12.1IGCC Control Equipmentw/4.1$0w/4.1$0$0$0$0$0$0$0$012.2Combustion Turbine Controlw/6.1$0w/6.1$0$0$0$0$0$0$0$012.3Steam Turbine Controlw/8.1$0w/8.1$0$0$0$0$0$0$0$012.4Other Major Component Control$1,126$0$752$0$0$1,877$178$94$322$2,471$512.5Signal Processing Equipmentw/12.7$0 w/12.7$0$0$0$0$0$0$0$012.6Control Boards,Panels & Racks

$259$0$166$0$0$425$40$21$97$583$112.7Computer & Accessories$6,005$0$192$0$0$6,197$569$310$708$7,784$1412.8Instrument Wiring & Tubing

$0$2,098$4,288$0$0$6,386$542$319$1,812$9,059$1712.9Other I & C Equipment$4,014$0$1,949$0$0$5,963$561$298$1,023$7,846$14SUBTOTAL 12.$11,404$2,098$7,347$0$0$20,849$1,889$1,042$3,962$27,743$51 Cost and Performance Baseline for Fossil Energy Plants 160 Exhibit 3-41 Case 2 Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 13IMPROVEMENTS TO SITE13.1Site Preparation

$0$109$2,337$0$0$2,447$243$0$807$3,496$613.2Site Improvements

$0$1,945$2,585$0$0$4,530$447$0$1,493$6,470$1213.3Site Facilities$3,485$0$3,678$0$0$7,163$706$0$2,361$10,230$19SUBTOTAL 13.$3,485$2,054$8,600$0$0$14,140$1,396$0$4,661$20,196$37 14BUILDINGS & STRUCTURES14.1Combustion Turbine Area

$0$265$150$0$0$414$36$0$90$541$114.2Steam Turbine Building

$0$2,377$3,387$0$0$5,764$530$0$944$7,238$1314.3Administration Building

$0$882$640$0$0$1,522$136$0$249$1,906$414.4Circulation Water Pumphouse

$0$166$88$0$0$253$22$0$41$317$114.5Water Treatment Buildings

$0$600$585$0$0$1,185$107$0$194$1,486$314.6Machine Shop

$0$452$309$0$0$761$68$0$124$952$214.7Warehouse

$0$729$471$0$0$1,200$106$0$196$1,502$314.8Other Buildings & Structures

$0$437$340$0$0$777$69$0$169$1,015$214.9Waste Treating Building & Str.

$0$976$1,865$0$0$2,841$265$0$621$3,728$7SUBTOTAL 14.

$0$6,882$7,834$0$0$14,716$1,340$0$2,628$18,684$34TOTAL COST$723,574$76,529$303,902$0$0$1,104,005$103,905$64,468$200,468$1,472,845$2,711Owner's CostsPreproduction Costs6 Months All Labor$13,488$251 Month Maintenance Materials$2,998$61 Month Non-fuel Consumables

$384$11 Month Waste Disposal

$318$125% of 1 Months Fuel Cost at 100% CF$1,697$32% of TPC$29,457$54Total$48,341$89Inventory Capital60 day supply of fuel and consumables at 100% CF$14,068$260.5% of TPC (spare parts)$7,364$14Total$21,432$39Initial Cost for Catalyst and Chemicals$7,199$13Land$900$2Other Owner's Costs$220,927$407Financing Costs$39,767$73Total Overnight Costs (TOC)$1,811,411$3,334TASC Multiplier(IOU, high-risk, 35 year)1.140Total As-Spent Cost (TASC)$2,065,009$3,801 Cost and Performance Baseline for Fossil Energy Plants 161 Exhibit 3-42 Case 2 Initial and Annual Operating and Maintenance Costs INITIAL & ANNUAL O&M EXPENSESCost Base (Jun):

2007Case 2 - GEE Radiant 550MW IGCC w/ CO2Heat Rate-net (Btu/kWh):10,458 MWe-net: 543 Capacity Factor (%):

80OPERATING & MAINTENANCE LABOROperating Labor Operating Labor Rate(base):34.65$/hour Operating Labor Burden:30.00% of base Labor O-H Charge Rate:25.00% of laborTotal Operating Labor Requirements(O.J.)per Shift:1 unit/mod. Plant Skilled Operator2.02.0 Operator10.010.0 Foreman1.01.0 Lab Tech's, etc.3.03.0 TOTAL-O.J.'s16.016.0Annual CostAnnual Unit Cost

$$/kW-netAnnual Operating Labor Cost$6,313,507$11.622Maintenance Labor Cost$15,266,708$28.103Administrative & Support Labor$5,395,054$9.931Property Taxes and Insurance$29,456,896$54.223TOTAL FIXED OPERATING COSTS$56,432,165$103.879VARIABLE OPERATING COSTS$/kWh-netMaintenance Material Cost$28,779,845$0.00756ConsumablesConsumptionUnit Initial Fill Initial Fill /Day Cost CostWater (/1000 gallons) 04,1871.08$0$1,322,398$0.00035ChemicalsMU & WT Chem. (lbs) 024,9440.17$0$1,260,554$0.00033Carbon (Mercury Removal) (lb)79,786 1091.05$83,789$33,516$0.00001COS Catalyst (m3) 0 02,397.36$0$0$0.00000Water Gas Shift Catalyst (ft3)6,2464.28498.83$3,115,855$623,171$0.00016Selexol Solution (gal)298,502 9513.40$3,999,401$371,618$0.00010SCR Catalyst (m3) 0 00.00$0$0$0.00000Ammonia (19% NH3) (ton) 0 00.00$0$0$0.00000Claus Catalyst (ft3)w/equip2.01131.27$0$77,209$0.00002Subtotal-Chemicals$7,199,046$2,366,068$0.00062OtherSupplemental Fuel (MBtu) 0 00.00$0$0$0.00000Gases, N2 etc. (/100scf) 0 00.00$0$0$0.00000L.P. Steam (/1000 pounds) 0 00.00$0$0$0.00000Subtotal-Other

$0$0$0.00000Waste DisposalSpent Mercury Catalyst (lb.)

0 1090.42$0$13,311$0.00000Flyash (ton) 0 00.00$0$0$0.00000Slag (ton) 0 64116.23$0$3,037,841$0.00080Subtotal Waste Disposal

$0$3,051,152$0.00080By-products & Emissions 0 00.00$0$0.00000Sulfur (ton) 0 1460.00$0$0$0.00000Subtotal By-products

$0$0$0.00000TOTAL VARIABLE OPERATING COSTS$7,199,046$35,519,462$0.00933Fuel (ton) 05,84438.18$0$65,161,317$0.01712 Cost and Performance Baseline for Fossil Energy Plants 162 3.3 CONOCOPHILLIPS E

-GAS TM IGCC CASES This section contains an evaluation of plant designs for Cases 3 and 4, which are based on the CoP E-GasŽ gasifier. Cases 3 and 4 are very similar in terms of process, equipment, scope and arrangement, except that Case 4 includes SGS reactors, CO 2 absorption/regeneration and compression/transport systems. There are no provisions for CO 2 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 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/h r [4 lb/h r]) 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 Dow's 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.

Gasifier Background 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 PSI's Wabash River station in West Terre Haute, Indiana to produce 265 MW of net power from local high

-sulfur bituminous coal. The design of Cost and Performance Baseline for Fossil Energy Plants 163 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

-GasŽ 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 Nm 3/h r (5 million scf/h r) with an energy content of about 1,370 MMkJ/h r (1,300 MMBtu/h r) (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 Nm 3/hr (6.7 million scf/h r) with an energy content of about 1,950 MMkJ/h r (1,850 MMBtu/h r) (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 CH 4 content than other gasifiers. This becomes a disadvantage in CO 2 capture cases since the CH 4 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

-GasŽ 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.

Cost and Performance Baseline for Fossil Energy Plants 164 3.3.2 In this section the overall CoP gasification process is described. The system description follows the BFD in Process Description 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 receiving and handling is common to all cases and was covered in Section Coal Grinding and Slurry Preparation 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.

This plant utilizes two gasification trains to process a total of 5,0 07 tonnes/day (5, 519 TPD) of Illinois No. 6 coal. Each of the 2 x 50 percent gasifiers operate at maximum capacity. The E

-GasŽ 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 MP a (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 2,600F). 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, 900F). Total slurry to both stages is shown as stream 7 in Gasification Exhibit 3-43.

Cost and Performance Baseline for Fossil Energy Plants 165 Exhibit 3-43 Case 3 Block Flow Diagram , E-GasŽ IGCC without CO 2 Capture Cost and Performance Baseline for Fossil Energy Plants 166 Exhibit 3-44 Case 3 Stream Table , E-GasŽ IGCC without CO 2 Capture 1 2 3 4 5 6 7 8 9 10 11 12V-L Mole Fraction Ar0.00920.02410.03180.00230.03180.00000.00000.00000.00000.00780.00780.0096 CH 40.00000.00000.00000.00000.00000.00000.00000.00000.00000.04650.04650.0575 CO0.00000.00000.00000.00000.00000.00000.00000.00000.00000.30110.30110.3727 CO 20.00030.00830.00000.00000.00000.00000.00000.00000.00000.15560.15590.1929COS0.00000.00000.00000.00000.00000.00000.00000.00000.00000.00030.00000.0000 H 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.27240.27240.3372 H 2 O0.00990.21630.00000.00030.00001.00000.00000.99680.00000.18890.18850.0015 HCl0.00000.00000.00000.00000.00000.00000.00000.00000.00000.00020.00020.0000 H 2 S0.00000.00000.00000.00000.00000.00000.00000.00000.00000.00720.00750.0092 N 20.77320.54600.01780.99190.01780.00000.00000.00000.00000.01570.01570.0194 NH 30.00000.00000.00000.00000.00000.00000.00000.00320.00000.00450.00450.0000 O 20.20740.20540.95040.00540.95040.00000.00000.00000.00000.00000.00000.0000 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000Total1.00001.00001.00001.00001.00001.00000.00001.00000.00001.00001.00001.0000V-L Flowrate (kgmol/hr)18,976 916 11117,4274,6943,766 04,758 021,81721,81717,626V-L Flowrate (kg/hr)547,57624,8203,567489,004151,05667,848 085,707 0459,732459,732384,240Solids Flowrate (kg/hr) 0 0 0 0 0 0208,634 021,295 0 0 0Temperature (°C) 15 20 32 93 32 343 15 1491,038 186 186 35Pressure (MPa, abs)0.100.110.862.650.865.100.105.794.244.074.003.83Enthalpy (kJ/kg)

A30.2336.9226.6792.5226.670.00---567.36---673.10672.8839.55Density (kg/m 3)1.21.611.024.411.020.1---862.4---22.722.333.0V-L Molecular Weight28.85727.09032.18128.06032.18118.015---18.012---21.07321.07321.799V-L Flowrate (lbmol/hr)41,8342,020 24438,42010,3488,303 010,490 048,09848,09838,859V-L Flowrate (lb/hr)1,207,19954,7197,8641,078,070333,021149,578 0188,951 01,013,5361,013,536847,104Solids Flowrate (lb/hr) 0 0 0 0 0 0459,958 046,947 0 0 0Temperature (°F) 59 69 90 199 90 650 59 3001,900 367 367 95Pressure (psia)14.716.4125.0384.0125.0740.014.7840.0615.0590.0580.0555.0Enthalpy (Btu/lb)

A13.015.911.539.811.5---243.9---289.4289.317.0Density (lb/ft 3)0.0760.0980.6871.5210.6871.257---53.837---1.4161.3912.061A - Reference conditions are 32.02 F & 0.089 PSIA Cost and Performance Baseline for Fossil Energy Plants 167 Exhibit 3-44 Case 3 Stream Table (Continued) 13 14 15 16 17 18 19 20 21 22 23 24 25V-L Mole Fraction Ar0.00950.00980.00850.00850.00000.00000.00410.00550.00920.00920.00870.00870.0000 CH 40.05550.05760.05000.05000.00020.00000.00010.00000.00000.00000.00000.00000.0000 CO0.35970.37340.32410.32410.00100.00000.08480.00610.00000.00000.00000.00000.0000 CO 20.21370.19310.16760.16760.75370.00000.49830.77900.00030.00030.08030.08030.0000COS0.00000.00000.00000.00000.00010.00000.00030.00000.00000.00000.00000.00000.0000 H 20.32990.34250.29730.29730.00090.00000.02090.13110.00000.00000.00000.00000.0000 H 2 O0.00150.00150.13330.13330.00000.00000.33500.00180.00990.00990.08600.08601.0000 HCl0.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 H 2 S0.00900.00000.00000.00000.24430.00000.00140.00430.00000.00000.00000.00000.0000 N 20.02130.02210.01920.01920.00000.00000.05370.07230.77320.77320.72500.72500.0000 NH 30.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 O 20.00000.00000.00000.00000.00000.00000.00000.00000.20740.20740.10000.10000.0000 SO 20.00000.00000.00000.00000.00000.00000.00130.00000.00000.00000.00000.00000.0000Total1.00001.00001.00001.00001.00000.00001.00001.00001.00001.00001.00001.00001.0000V-L Flowrate (kgmol/hr)18,27517,60120,27620,276 674 0 873 649110,2534,410137,246137,24640,181V-L Flowrate (kg/hr)408,330380,350428,548428,54827,980 028,10824,0903,181,557127,2623,971,8483,971,848723,874Solids Flowrate (kg/hr) 0 0 0 0 05,215 0 0 0 0 0 0 0Temperature (°C) 34 45 143 193 45 175 232 38 15 432 588 132 561Pressure (MPa, abs)3.793.763.213.23.7570.4090.4065.5120.1011.6190.1050.10512.512Enthalpy (kJ/kg)

A36.8255.08489.40569.9-0.670---731.470-6.62530.227463.785783.868272.2943,500.624Density (kg/m 3)33.731.019.717.373.55,285.43.196.31.27.90.40.935.2V-L Molecular Weight22.34421.61021.135 2141.529---32.20937.14128.85728.85728.94028.94018.015V-L Flowrate (lbmol/hr)40,28938,80444,70244,7021,485 01,9241,430243,0669,723302,576302,57688,584V-L Flowrate (lb/hr)900,213838,528944,788944,78861,685 061,96753,1107,014,133280,5658,756,4278,756,4271,595,870Solids Flowrate (lb/hr) 0 0 0 0 011,497 0 0 0 0 0 0 0Temperature (°F) 94 112 290 380 112 347 450 100 59 8101,091 2701,041Pressure (psia)550.0545.0465.0460.0545.059.358.9799.514.7234.915.215.21,814.7Enthalpy (Btu/lb)

A15.823.7210.4245.0-0.3---314.5-2.813.0199.4337.0117.11,505.0Density (lb/ft 3)2.1051.9381.230 14.586329.9540.1956.0120.0760.4950.0260.0562.194 Cost and Performance Baseline for Fossil Energy Plants 168 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 CH 4 to remain. The syngas CH 4 concentration exiting the gasifier in Case 3 is 4.3 vol% (compared to 0.10 vol% in Case 1 [GEE] and 0.0 01 vol% in Case 5 [Shell]). The relatively high CH 4 concentration impacts CO 2 capture efficiency as discussed further in Section 3.3.8. 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.

Raw Gas Cooling/Particulate Removal 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 exiting the second of the two low temperature heat exchangers passes to a syngas scrubber where a water wash is used to remove chlorides, SO 2, NH 3 , and particulate. The syngas exits the scrubber saturated at 169°C (337°F). Syngas Scrubber/Sour Water Stripper The sour water stripper removes NH 3, SO 2, 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.

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 CO 2 and H 2O (Section COS Hydrolysis, Mercury Removal and Acid Gas Removal 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).

Cost and Performance Baseline for Fossil Energy Plants 169 Cool, particula te-free syngas (stream 13) enters the absorber unit at approximately 3.

8 MPa (550 psia) and 34°C (94°F). In the absorber, H 2S 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 H 2 S concentration of less than 30 ppmv in the sweet syngas. The stripper acid gas stream (stream 1 7), consisting of 2 4 percent H 2S and 7 5 percent CO 2, 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.

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, H 2S 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 NH 3 present in the sour gas stream.

Claus Unit Following the thermal stage and condensation of sulfur, two reheaters and two sulfur converters are used to obtain a per

-pass H 2S 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/h r (30,568 lb/h r) 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/h r (11, 497 lb/h r) of elemental sulfur (stream

18) is recovered from the fuel gas stream. This value represents an overall sulfur recovery efficiency of 99.

7 percent. 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 5 88°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.

Power Block The elevated pressure ASU was described in Section Air Separation Unit 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% O 2 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 2 2).

Cost and Performance Baseline for Fossil Energy Plants 170 Balance of plant items were covered in Sections Balance of Plant 3.1.9 , 3.1.10 , and 3.1.11. 3.3.3 System assumptions for Cases 3 and 4, CoP IGCC with and without CO 2 capture, are compiled in Key System Assumptions Exhibit 3-45. The balance of plant assumptions are common to all cases and were presented previously in Balance of Plant - Cases 3 and 4 Exhibit 3-16. 3.3.4 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.

Sparing Philosophy 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%).

Cost and Performance Baseline for Fossil Energy Plants 171 Exhibit 3-45 CoP IGCC Plant Study Configuration Matrix Case 3 4 Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615) O 2:Coal Ratio, kg O 2/kg dry coal 0.8 1 0.8 8 Carbon Conversion, %

99.2 99.2 Syngas HHV at Gasifier Outlet, kJ/Nm 3 (Btu/scf) 8,3 19 (223) 7,02 1 (189) Steam Cycle, MPa/°C/°C (psig/ F/ F) 12.4/56 1/56 1 (1800/10 41/10 41) 12.4/53 4/53 4 (1800/994/994) Condenser Pressure, mm Hg (in Hg) 51 (2.0) 51 (2.0) CT 2x Advanced F Class (232 MW output each) 2x Advanced F Class (232 MW output each)

Gasifier Technology CoP E-GasŽ CoP E-GasŽ 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 H 2S Separation Refrigerated MDEA Selexol 1 st Stage Sulfur Removal, %

99.7 99.9 Sulfur Recovery Claus Plant with Tail Gas Recycle to Gasifier/ Elemental Sulfur Claus Plant with Tail Gas Recycle to Gasifier/ Elemental Sulfur Particulate Control Cyclone, Candle Filter, Scrubber, and AGR Absorber Cyclone, Candle Filter, Scrubber, and AGR Absorber Mercury Control Carbon Bed Carbon Bed NOx Control MNQC (LNB), N 2 Dilution and Humidification MNQC (LNB), N 2 Dilution and Humidification CO 2 Separation N/A Selexol 2nd Stage Overall CO2 Capture N/A 90.4% CO 2 Sequestration N/A Off-site Saline Formation

Cost and Performance Baseline for Fossil Energy Plants 172 3.3.5 The plant produces a net output of 625 MWe at a net plant efficiency of 39.

7 percent (HHV basis). Case 3 Performance Results 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.

Cost and Performance Baseline for Fossil Energy Plants 173 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 Plant 2 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 10 6 kJ/h r (10 6 Btu/h r) 1,414 (1,340)

CONSUMABLES As-Received Coal Feed, kg/h r (lb/h r) 208,634 (459,958)

Thermal Input 1, kWt 1,572,582 Raw Water Withdrawal , m 3/min (gpm) 16.5 (4,367)

Raw Water Consumption , m 3/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

Cost and Performance Baseline for Fossil Energy Plants 174 The environmental targets for emissions of Hg, NOx, SO 2 , and PM were presented in Section 2.4. A summary of the plant air emissions for Case 3 is presented in Environmental Performance Exhibit 3-47. Exhibit 3-47 Case 3 Air Emissions kg/GJ (lb/10 6 Btu) Tonne/year (ton/year) 80% capacity factor kg/MWh (lb/MWh) SO 2 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) CO 2 85.7 (199.2) 3,398,362 (3,746,053) 657 (1,448)

CO 2 1 776 (1,710) 1 CO 2 emissions based on net power instead of gross power The low level of SO 2 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 H 2 S-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 H 2S and then recycled back to the gasifier, thereby eliminating the need for a tail gas treatment unit.

NO x emissions are limited by the use of nitrogen dilution (primarily) and humidification (to a lesser extent) to 15 ppmvd (as NO 2 @ 15 percent O 2). 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 NO x 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.

CO 2 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 CO 2 in the stack gas and ASU vent gas.

Cost and Performance Baseline for Fossil Energy Plants 175 Exhibit 3-48 Case 3 Carbon Balance Carbon In, kg/hr (lb/hr)

Carbon Out, kg/h r (lb/hr) Coal 132,993 (293,199)

Slag 1,064 (2,346)

Air (CO 2) 507 (1,118)

Stack Gas 132,344 (291,769)

ASU Vent 92 (202) CO 2 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/h r (lb/hr) Coal 5,229 (11,528)

Elemental Sulfur 5,215 (11,497)

Stack Gas 14 (31) CO 2 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 sour ce from which it was withdrawn.

Water consumption represents the net impact of the plant process on the water source balance.

Cost and Performance Baseline for Fossil Energy Plants 176 Exhibit 3-50 Case 3 Water Balance Water Use Water Demand, m 3/min (gpm) Internal Recycle, m 3/min (gpm) Raw Water Withdrawal, m 3/min (gpm) Process Water Discharge, m 3/min (gpm) Raw Water Consumption, m 3/min (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 Gasifier Steam Shift Steam GT Steam Dilution BFW Makeup 1.3 (354) 1.1 (299) 0.21 (55) 0.0 (0) 1.3 (354) 1.1 (299) 0.21 (55) 0.0 (0) 1.3 (354)

Cooling Tower BFW Blowdown SWS Blowdown SWS Excess Water Humidifier Tower Blowdown 15.1 (3,991)

0.35 (93) 0.21 (55) 0.15 (38) 14.8 (3,898)

-0.21 (-55) -0.15 (-38) 3.4 (897) 11.4 (3,000)

Total 19.2 (5,067) 2.65 (700) 16.5 (4,367) 3.4 (901) 13.1 (3,465)

Heat and mass balance diagrams are shown for the following subsystems in Heat and Mass Balance Diagrams 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.

Cost and Performance Baseline for Fossil Energy Plants 177 Exhibit 3-51 Case 3 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA DOE/NETL D UAL T RAIN IGCC P LANT C ASE 3 H EAT AND M ATERIAL F LOW D IAGRAM B ITUMINOUS BASELINE S TUDY C ASE 3 C O P G ASIFIER ASU AND G ASIFICATION DWG. NO.BB-HMB-CS-3-PG-1 P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas P AGES 1 OF 3 Ambient Air Four Stage Air Compressor Elevated Pressure ASU Four Stage N 2 Compressor Four Stage O 2 Compressor ASU Vent Water Steam Gross Plant Power

738 MWe Auxiliary Load

113 MWe Net Plant Power

625 MWe Net Plant Efficiency , HHV: 39.7%Net Plant Heat Rate

8 , 585 BTU/KWe N 2 to GT Combustor 1 , 207 , 199 W 59.0 T 14.7 P 13.0 H 333 , 021 W 90.0 T 125.0 P 11.5 H 333 , 021 W 223.0 T 740.0 P 37.5 H To Claus Plant 7 , 864 W 90.0 T 125.0 P 11.5 H 54 , 719 W 68.5 T 16.4 P 15.9 H 957 , 085 W 90.0 T 56.4 P 14.2 H 133 , 998 W 50.0 T 182.0 P 2.9 H 5 1 3 2 Candle Filter Slurry Mix Tank E-Gas TM Gasifier Milled Coal Water Slag Cyclones Saturated Steam to HRSG BFW from HRSG Blowdown to Flash Tank Fire Tube Boiler Steam Drum 459 , 958 W 59.0 T 14.7 P 188 , 951 W 300.0 T 840.0 P 243.9 H 46 , 947 W 1 , 900.0 T 615.0 P 1 , 241 , 593 W 600.0 T 605.0 P 422.3 H 1 , 078 , 070 W 389.0 T 384.0 P 88.2 H Fuel Gas 9 648 , 909 W 161.6 T 840.0 P 3 , 007.7 H 1 , 241 , 593 W 600.0 T 605.0 P 422.3 H 1 , 241 , 593 W 1 , 833.8 T 615.0 P 968.9 H 144 , 019 W 158.8 T 800.0 P 36.9 H N 2 Diluent Preheater 1 , 241 , 593 W 450.0 T 600.0 P 361.4 H 100.0 T 189.5 P 18.0 H 7 8 Steam 149 , 578 W 650.0 T 740.0 P 1 , 316.8 H Syngas Recycle Compressor 144 , 019 W 105.0 T 600.0 P 18.8 H 4 Air From GT Compressor 280 , 565 W 220.0 T 224.9 P 50.9 H 280 , 565 W 809.8 T 234.9 P 199.4 H IP BFW Raw Syngas to Scrubber 1 , 061 , 562 W 450.0 T 600.0 P 361.4 H 1 , 078 , 070 W 199.0 T 384.0 P 39.8 H 22 6 Cost and Performance Baseline for Fossil Energy Plants 178 Exhibit 3-52 Case 3 Syngas Cleanup Heat and Mass Balance Schematic Mercury Removal Knock Out Drum Raw Syngas Syngas Preheater Fuel Gas to GT Sour Drum To Water Treatment Makeup Water Claus Plant Tail Gas Furnace Catalytic Reactor Beds Sulfur Knock Out From ASU Syngas Coolers Sour Stripper Syngas Scrubber Condensate to Deaerator Condensate 1 , 061 , 562 W 450.0 T 600.0 P 361.4 H 1 , 013 , 536 W 336.7 T 595.0 P 284.4 H 900 , 213 W 93.7 T 550.0 P 15.8 H 944 , 788 W 290.3 T 465.0 P 210.4 H 61 , 685 W 112.2 T 545.0 P 944 , 788 W 380.0 T 460.0 P 245.0 H 11 , 497 W 61 , 967 W 450.0 T 58.9 P 314.5 H 3 , 916 W 191.1 T 65.0 P 190.1 H 7 , 864 W 90.0 T 125.0 P 11.5 H N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA DOE/NETL D UAL T RAIN IGCC P LANT C ASE 3 H EAT AND M ATERIAL F LOW D IAGRAM B ITUMINOUS BASELINE S TUDY C ASE 3 C O P G ASIFIER G AS CLEANUP SYSTEM DWG. NO.BB-HMB-CS-3-PG-2 P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas P AGES 2 OF 3 Sour Gas Sour Water Water Steam Gross Plant Power

738 MWe Auxiliary Load

113 MWe Net Plant Power

625 MWe Net Plant Efficiency , HHV: 39.7%Net Plant Heat Rate

8 , 585 BTU/KWe 14 18 12 16 20 CO 2 Tailgas 53 , 768 W 120.0 T 56.8 P 33.1 H 847 , 104 W 95.2 T 555.0 P 17.0 H 8 , 858 W 118.5 T 56.8 P 44.8 H 3 53 , 110 W 100.0 T 799.5 P Humidification 15 838 , 528 W 112.2 T 545.0 P 23.7 H Claus Oxygen Preheater 7 , 864 W 450.0 T 124.5 P 91.9 H COS Hydrolysis 1 , 013 , 536 W 367.0 T 580.0 P 289.3 H COS Hydrolysis Preheater 1 , 013 , 536 W 366.7 T 590.0 P 289.4 H 10 11 19 Clean Gas Acid Gas 13 AGR- MDEA 17 Tail Gas Compressor Hydrogenation And Tail Gas Cooling Cost and Performance Baseline for Fossil Energy Plants 179 Exhibit 3-53 Case 3 Combined Cycle Power Generation Heat and Mass Balance Schematic HRSG HP Turbine IP Turbine Nitrogen Diluent Intake Ambient Air Steam Seal Regulator Gasifier Steam Ip Extraction Steam To 250 PSIA Header Blowdown Flash To WWT Gland Steam Condenser Condensate to Gasification Island HP BFW to Syngas Cooler HP Saturated Steam to HRSG Superheater LP Turbine Stack Expander Compressor Fuel Gas Deaerator IP BFW Generator Generator Condensate Pump HP Pump Steam Turbine LP Pump Advanced F

-Class Gas Turbine MP Flash Bottoms LP Flash Tops 1 , 078 , 070 W 199.0 T 384.0 P 39.8 H 7 , 014 , 133 W 59.0 T 14.7 P 13.0 H 1 , 603 , 037 W 101.1 T 1.0 P 69.1 H 8 , 756 , 427 W 269.9 T 15.2 P 117.1 H 944 , 788 W 380.0 T 460.0 P 245.0 H 8 , 756 , 427 W 1 , 091.1 T 15.2 P 337.0 H LP Process Header From Gasifier Island Preheating To Claus LP BFW 1 , 595 , 870 W 1 , 041.1 T 1 , 814.7 P 1 , 505.0 H 9 , 989 W 298.0 T 65.0 P 1 , 179.0 H 1 , 623 , 826 W 278.8 T 2 , 250.7 P 252.3 H 27 , 956 W 585.0 T 2 , 000.7 P 593.3 H 1 , 414 , 204 W 539.6 T 65.0 P 1 , 301.6 H 1 , 603 , 037 W 103.2 T 120.0 P 71.4 H 1 , 603 , 037 W 235.0 T 105.0 P 203.7 H 1 , 400 W 660.4 T 65.0 P 1 , 361.1 H 1 , 400 W 212.0 T 14.7 P 179.9 H IP Pump N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA DOE/NETL D UAL T RAIN IGCC P LANT C ASE 3 H EAT AND M ATERIAL F LOW D IAGRAM B ITUMINOUS BASELINE S TUDY C ASE 3 C O P G ASIFIER P OWER B LOCK S YSTEM DWG. NO.BB-HMB-CS-3-PG-3 P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas P AGES 3 OF 3 Sour Gas Sour Water Water Steam Gross Plant Power

738 MWe Auxiliary Load

113 MWe Net Plant Power

625 MWe Net Plant Efficiency , HHV: 39.7%Net Plant Heat Rate

8 , 585 BTU/KWe 21 23 25 16 24 Flue Gas HOT WELL CONDENSER Make-up 176 , 912 W 59.0 T 14.7 P 27.1 H 8 , 828 W 700.3 T 501.4 P 1 , 357.3 H 9 , 522 W 660.4 T 65.0 P 1 , 361.1 H 25 , 722 W 896.4 T 280.0 P 1 , 472.0 H 781 W 1 , 041.1 T 1 , 814.7 P 1 , 505.0 H 1 , 313 W 539.6 T 65.0 P 1 , 301.6 H Air Extraction 280 , 565 W 809.8 T 234.9 P 199.4 H 22 Cost and Performance Baseline for Fossil Energy Plants 180 This page intentionally left blank Cost and Performance Baseline for Fossil Energy Plants 181 Exhibit 3-54 Case 3 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total 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) CO 2 Cooling Tower Blowdown 25.2 (23.9) 25 (24) HRSG Flue Gas 1,082 (1,025) 1,082 (1,025)

Condenser 1,415 (1,342) 1,415 (1,342)

Non-Condenser Cooling Tower Loads*

411 (389) 411 (389) 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, CO 2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection) and extraction air cooler.

- Calculated by difference to close the energy balance.

Cost and Performance Baseline for Fossil Energy Plants 182 3.3.6 Major equipment items for the CoP gasifier with no CO 2 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 Case 3 - Major Equipment List 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 No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Bottom Trestle Dumper and Receiving HoppersN/A181 tonne (200 ton) 2 0 2FeederBelt572 tonne/hr (630 tph) 2 0 3Conveyor No. 1Belt1,134 tonne/hr (1,250 tph) 1 0 4Transfer Tower No. 1EnclosedN/A 1 0 5Conveyor No. 2Belt1,134 tonne/hr (1,250 tph) 1 0 6As-Received Coal Sampling SystemTwo-stageN/A 1 0 7Stacker/ReclaimerTraveling, linear1,134 tonne/hr (1,250 tph) 1 0 8Reclaim HopperN/A45 tonne (50 ton) 2 1 9FeederVibratory172 tonne/hr (190 tph) 2 1 10Conveyor No. 3Belt w/ tripper345 tonne/hr (380 tph) 1 0 11Crusher TowerN/AN/A 1 0 12Coal Surge Bin w/ Vent FilterDual outlet172 tonne (190 ton) 2 0 13CrusherImpactor reduction8 cm x 0 - 3 cm x 0(3" x 0 1/4" x 0) 2 0 14As-Fired Coal Sampling SystemSwing hammerN/A 1 1 15Conveyor No. 4Belt w/tripper345 tonne/hr (380 tph) 1 0 16Transfer Tower No. 2EnclosedN/A 1 0 17Conveyor No. 5Belt w/ tripper345 tonne/hr (380 tph) 1 0 18Coal Silo w/ Vent Filter and Slide GatesField erected726 tonne (800 ton) 3 0 Cost and Performance Baseline for Fossil Energy Plants 183 ACCOUNT 2 COAL PREPARATION AND FEED Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1FeederVibratory73 tonne/h (80 tph) 3 0 2Conveyor No. 6Belt w/tripper227 tonne/h (250 tph) 1 0 3Rod Mill Feed HopperDual Outlet463 tonne (510 ton) 1 0 4Weigh FeederBelt118 tonne/h (130 tph) 2 0 5Rod MillRotary118 tonne/h (130 tph) 2 0 6Slurry Water Storage Tank with AgitatorField erected283,227 liters (74,820 gal) 2 0 7Slurry Water PumpsCentrifugal795 lpm (210 gpm) 2 1 8Trommel ScreenCoarse163 tonne/h (180 tph) 2 0 9Rod Mill Discharge Tank with AgitatorField erected370,519 liters (97,880 gal) 2 0 10Rod Mill Product PumpsCentrifugal3,028 lpm (800 gpm) 2 2 11Slurry Storage Tank with AgitatorField erected1,111,406 liters (293,600 gal) 2 0 12Slurry Recycle PumpsCentrifugal6,057 lpm (1,600 gpm) 2 2 13Slurry Product PumpsPositive displacement3,028 lpm (800 gpm) 2 2 Cost and Performance Baseline for Fossil Energy Plants 184 ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Demineralized Water Storage TankVertical, cylindrical, outdoor1,082,628 liters (286,000 gal) 2 0 2Condensate PumpsVertical canned6,700 lpm @ 91 m H2O(1,770 gpm @ 300 ft H2O) 2 1 3Deaerator (integral w/ HRSG)Horizontal spray type478,994 kg/hr (1,056,000 lb/hr) 2 0 4Intermediate Pressure Feedwater PumpHorizontal centrifugal, single stage8,101 lpm @ 27 m H2O(2,140 gpm @ 90 ft H2O) 2 1 5High Pressure Feedwater Pump No. 1Barrel type, multi-stage, centrifugalHP water: 7,041 lpm @ 1,859 m H2O (1,860 gpm @ 6,100 ft H2O)2 1 6High Pressure Feedwater Pump No. 2Barrel type, multi-stage, centrifugalIP water: 492 lpm @ 223 m H2O (130 gpm @ 730 ft H2O) 2 1 7Auxiliary BoilerShop fabricated, water tube18,144 kg/hr, 2.8 MPa, 343°C(40,000 lb/hr, 400 psig, 650°F) 1 0 8Service Air CompressorsFlooded Screw28 m3/min @ 0.7 MPa(1,000 scfm @ 100 psig) 2 1 9Instrument Air DryersDuplex, regenerative28 m3/min (1,000 scfm) 2 1 10Closed Cylce Cooling Heat ExchangersPlate and frame240 GJ/hr (228 MMBtu/hr) each 2 0 11Closed Cycle Cooling Water PumpsHorizontal centrifugal86,307 lpm @ 21 m H2O(22,800 gpm @ 70 ft H2O) 2 1 12Engine-Driven Fire PumpVertical turbine, diesel engine3,785 lpm @ 107 m H2O(1,000 gpm @ 350 ft H2O) 1 1 13Fire Service Booster PumpTwo-stage horizontal centrifugal2,650 lpm @ 76 m H2O(700 gpm @ 250 ft H2O) 1 1 14Raw Water PumpsStainless steel, single suction4,240 lpm @ 18 m H2O(1,120 gpm @ 60 ft H2O) 2 1 15Ground Water PumpsStainless steel, single suction2,801 lpm @ 268 m H2O (740 gpm @ 880 ft H2O) 3 1 16Filtered Water PumpsStainless steel, single suction1,628 lpm @ 49 m H2O(430 gpm @ 160 ft H2O) 2 1 17Filtered Water TankVertical, cylindrical787,366 liter (208,000 gal) 2 0 18Makeup Water DemineralizerAnion, cation, and mixed bed303 lpm (80 gpm) 2 0 19Liquid Waste Treatment System10 years, 24-hour storm 1 0 Cost and Performance Baseline for Fossil Energy Plants 185 ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY AND FUEL GAS SATURATION Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1GasifierPressurized two-stage, slurry-feed entrained bed2,722 tonne/day, 4.2 MPa(3,000 tpd, 615 psia) 2 0 2Synthesis Gas CoolerFire-tube boiler309,804 kg/hr (683,000 lb/hr) 2 0 3Synthesis Gas CycloneHigh efficiency309,804 kg/hr (683,000 lb/hr) Design efficiency 90%

2 0 4Candle FilterPressurized filter with pulse-jet cleaningmetallic filters 2 0 5Syngas Scrubber Including Sour Water StripperVertical upflow264,898 kg/hr (584,000 lb/hr) 2 0 6Raw Gas CoolersShell and tube with condensate drain212,735 kg/hr (469,000 lb/hr) 8 0 7Raw Gas Knockout DrumVertical with mist eliminator212,281 kg/hr, 35°C, 3.9 MPa(468,000 lb/hr, 95°F, 560 psia) 2 0 8Saturation Water EconomizersShell and tube91 GJ/hr (86 MMBtu/hr) 2 0 9Fuel Gas SaturatorVertical tray tower235,868 kg/hr, 143°C, 3.3 MPa(520,000 lb/hr, 290°F, 480 psia) 2 0 10Saturator Water PumpCentrifugal2,271 lpm @ 12 m H2O(600 gpm @ 40 ft H2O) 2 2 11Synthesis Gas ReheaterShell and tube209,106 kg/hr (461,000 lb/hr) 2 0 12Flare StackSelf-supporting, carbon steel, stainless steel top, pilot ignition264,898 kg/hr (584,000 lb/hr) syngas 2 0 13ASU Main Air CompressorCentrifugal, multi-stage4,134 m3/min @ 1.3 MPa(146,000 scfm @ 190 psia) 2 0 14Cold BoxVendor design1,996 tonne/day (2,200 tpd) of 95% purity oxygen 2 0 15Oxygen CompressorCentrifugal, multi-stage1,019 m3/min (36,000 scfm)Suction - 0.9 MPa (130 psia)Discharge - 5.1 MPa (740 psia) 2 0 16Primary Nitrogen CompressorCentrifugal, multi-stage3,370 m3/min (119,000 scfm)Suction - 0.4 MPa (60 psia)Discharge - 2.7 MPa (390 psia) 2 0 17Secondary Nitrogen CompressorCentrifugal, single-stage481 m3/min (17,000 scfm)Suction - 1.2 MPa (180 psia)Discharge - 2.7 MPa (390 psia) 2 0 18Transport Nitrogen Boost CompressorCentrifugal, single-stage57 m3/min (2,000 scfm)Suction - 2.6 MPa (380 psia)Discharge - 5.4 MPa (790 psia) 2 0 19Extraction Air Heat ExchangerGas-to-gas, vendor design69,853 kg/hr, 432°C, 1.6 MPa(154,000 lb/hr, 810°F, 235 psia) 2 0 Cost and Performance Baseline for Fossil Energy Plants 186 ACCOUNT 5 SYNGAS CLEANUP ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES ACCOUNT 7 HRSG, STACK, AND DUCTING Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Mercury AdsorberSulfated carbon bed211,374 kg/hr (466,000 lb/hr) 35°C (95°F) 3.8 MPa (555 psia) 2 0 2Sulfur PlantClaus type138 tonne/day (152 tpd) 1 0 3COS Hydrolysis ReactorFixed bed, catalytic252,651 kg/hr (557,000 lb/hr)188°C (370°F)4.1 MPa (590 psia) 2 0 4Acid Gas Removal PlantMDEA224,528 kg/hr (495,000 lb/hr)34°C (94°F)3.8 MPa (550 psia) 2 0 5Hydrogenation ReactorFixed bed, catalytic28,108 kg/hr (61,967 lb/hr)232°C (450°F)0.4 MPa (58.9 psia) 1 0 6Tail Gas Recycle CompressorCentrifugal24,090 kg/hr (53,110 lb/hr) each 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Gas TurbineAdvanced F class232 MW 2 0 2Gas Turbine GeneratorTEWAC260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1StackCS plate, type 409SS liner76 m (250 ft) high x8.4 m (28 ft) diameter 1 0 2Heat Recovery Steam GeneratorDrum, multi-pressure with economizer section and integral deaeratorMain steam - 398,131 kg/hr, 12.4 MPa/561°C (877 , 728 lb/hr , 1 , 800 psig/1 , 041°F) Reheat steam - 358,685 kg/hr, 3.1 MPa/561°C (790 , 766 lb/hr , 452 psig/1 , 041°F)2 0 Cost and Performance Baseline for Fossil Energy Plants 187 ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES ACCOUNT 9 COOLING WATER SYSTEM Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Steam TurbineCommercially available advanced steam turbine289 MW 12.4 MPa/561°C/561°C (1 , 800 psig/ 1041°F/1041°F)1 0 2Steam Turbine GeneratorHydrogen cooled, static excitiation320 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0 3Steam BypassOne per HRSG50% steam flow @ design steam conditions 2 0 4Surface CondenserSingle pass, divided waterbox including vacuum pumps1,561 GJ/hr (1,480 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F)1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Circulating Water PumpsVertical, wet pit389,897 lpm @ 30 m(103,000 gpm @ 100 ft) 2 1 2Cooling TowerEvaporative, mechanical draft, multi-cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,173 GJ/hr (2,060 MMBtu/hr) heat duty 1 0 Cost and Performance Baseline for Fossil Energy Plants 188 ACCOUNT 10 SLAG RECOVERY AND HANDLING Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Slag Quench TankWater bath223,339 liters (59,000 gal) 2 0 2Slag CrusherRoll12 tonne/hr (13 tph) 2 0 3Slag DepressurizerProprietary12 tonne/hr (13 tph) 2 0 4Slag Receiving TankHorizontal, weir136,275 liters (36,000 gal) 2 0 5Black Water Overflow TankShop fabricated60,567 liters (16,000 gal) 2 6Slag ConveyorDrag chain12 tonne/hr (13 tph) 2 0 7Slag Separation ScreenVibrating12 tonne/hr (13 tph) 2 0 8Coarse Slag ConveyorBelt/bucket12 tonne/hr (13 tph) 2 0 9Fine Ash Settling TankVertical, gravity189,271 liters (50,000 gal) 2 0 10Fine Ash Recycle PumpsHorizontal centrifugal38 lpm @ 14 m H2O(10 gpm @ 46 ft H2O) 2 2 11Grey Water Storage TankField erected60,567 liters (16,000 gal) 2 0 12Grey Water PumpsCentrifugal227 lpm @ 433 m H2O(60 gpm @ 1,420 ft H2O) 2 2 13Slag Storage BinVertical, field erected816 tonne (900 tons) 2 0 14Unloading EquipmentTelescoping chute100 tonne/hr (110 tph) 1 0 Cost and Performance Baseline for Fossil Energy Plants 189 ACCOUNT 11 ACCESSORY ELECTRIC PLANT Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1CTG Step-up TransformerOil-filled24 kV/345 kV, 260 MVA, 3-ph, 60 Hz 2 0 2STG Step-up TransformerOil-filled24 kV/345 kV, 320 MVA, 3-ph, 60 Hz 1 0 3High Voltage Auxiliary TransformerOil-filled345 kV/13.8 kV, 47 MVA, 3-ph, 60 Hz 2 0 4Medium Voltage Auxiliary TransformerOil-filled24 kV/4.16 kV, 29 MVA, 3-ph, 60 Hz 1 1 5Low Voltage TransformerDry ventilated4.16 kV/480 V, 4 MVA, 3-ph, 60 Hz 1 1 6CTG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled24 kV, 3-ph, 60 Hz 2 0 7STG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled24 kV, 3-ph, 60 Hz 1 0 8Medium Voltage SwitchgearMetal clad4.16 kV, 3-ph, 60 Hz 1 1 9Low Voltage SwitchgearMetal enclosed480 V, 3-ph, 60 Hz 1 1 10Emergency Diesel GeneratorSized for emergency shutdown750 kW, 480 V, 3-ph, 60 Hz 1 0 Cost and Performance Baseline for Fossil Energy Plants 190 ACCOUNT 12 INSTRUMENTATION AND CONTROLS Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1DCS - Main ControlMonitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W)Operator stations/printers and engineering stations/printers 1 0 2DCS - ProcessorMicroprocessor with redundant input/outputN/A 1 0 3DCS - Data HighwayFiber opticFully redundant, 25% spare 1 0 Cost and Performance Baseline for Fossil Energy Plants 191 3.3.7 The cost estimating methodology was described previously in Section 2.6. Case 3 - Costs Estimating Results 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 owner's costs, TOC and TASC. Exhibit 3-57 shows the initial and annual O&M costs.

The estimated TOC of the CoP gasifier with no CO 2 capture is $

2,351/kW. Process contingency represents 2.1 percent of the TO C and project contingency is 10.9 percent. The COE is 74.0 mills/kWh.

Cost and Performance Baseline for Fossil Energy Plants 192 Exhibit 3-55 Case 3 Total Plant Cost Summary Client: USDOE/NETLReport Date:2010-Jan-14Project: Bituminous Baseline StudyCase: Case 3 - ConocoPhillips 625MW IGCC w/o CO2Plant Size: 625.1MW,netEstimate Type: ConceptualCost Base (Jun) 2007($x1000)AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING$13,783$2,561$10,689$0$0$27,033$2,454$0$5,897$35,384$57 2COAL & SORBENT PREP & FEED$23,433$4,283$14,157$0$0$41,873$3,759$0$9,126$54,759$88 3FEEDWATER & MISC. BOP SYSTEMS$9,806$8,188$9,436$0$0$27,429$2,581$0$6,822$36,832$59 4GASIFIER & ACCESSORIES4.1Gasifier, Syngas Cooler & Auxiliaries (E-GAS)$117,991$0$65,449$0$0$183,440$16,853$25,442$34,617$260,352$4174.2Syngas Coolingw/4.1$0w/ 4.1$0$0$0$0$0$0$0$04.3ASU/Oxidant Compression$145,765$0w/equip.$0$0$145,765$14,129$0$15,989$175,883$2814.4-4.9Other Gasification Equipment$17,104$9,335$11,583$0$0$38,023$3,633$0$9,003$50,658$81SUBTOTAL 4$280,861$9,335$77,032$0$0$367,228$34,614$25,442$59,609$486,893$779 5AGAS CLEANUP & PIPING$47,943$3,806$47,221$0$0$98,970$9,573$85$21,865$130,493$209 5BCO2 COMPRESSION

$0$0$0$0$0$0$0$0$0$0$0 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine Generator$85,751$0$6,269$0$0$92,021$8,724$4,601$10,535$115,881$1856.2-6.9Combustion Turbine Other

$0$806$892$0$0$1,699$159$0$557$2,415$4SUBTOTAL 6$85,751$806$7,162$0$0$93,719$8,883$4,601$11,092$118,295$189 7HRSG, DUCTING & STACK7.1Heat Recovery Steam Generator$35,467$0$5,043$0$0$40,510$3,852$0$4,436$48,798$787.2-7.9SCR System, Ductwork and Stack$3,335$2,378$3,114$0$0$8,827$818$0$1,570$11,215$18SUBTOTAL 7$38,802$2,378$8,157$0$0$49,337$4,670$0$6,006$60,013$96 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$28,970$0$4,963$0$0$33,934$3,256$0$3,719$40,909$658.2-8.9Turbine Plant Auxiliaries and Steam Piping$10,556$996$7,591$0$0$19,143$1,738$0$4,220$25,101$40SUBTOTAL 8$39,526$996$12,554$0$0$53,076$4,994$0$7,939$66,009$106 9COOLING WATER SYSTEM$9,144$8,826$7,504$0$0$25,474$2,366$0$5,687$33,527$54 10ASH/SPENT SORBENT HANDLING SYS$19,026$1,439$9,440$0$0$29,905$2,869$0$3,575$36,349$58 11ACCESSORY ELECTRIC PLANT$27,425$10,189$20,427$0$0$58,041$4,986$0$11,827$74,854$120 12INSTRUMENTATION & CONTROL$10,234$1,883$6,594$0$0$18,710$1,696$936$3,556$24,897$40 13IMPROVEMENTS TO SITE$3,328$1,962$8,212$0$0$13,503$1,333$0$4,451$19,287$31 14BUILDINGS & 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$1,913TOTAL PLANT COST

SUMMARY

Cost and Performance Baseline for Fossil Energy Plants 193 Exhibit 3-56 Case 3 Total Plant Cost Details AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING1.1Coal Receive & Unload$3,619$0$1,769$0$0$5,388$483$0$1,174$7,045$111.2Coal Stackout & Reclaim$4,677$0$1,134$0$0$5,811$509$0$1,264$7,584$121.3Coal Conveyors & Yd Crush$4,349$0$1,122$0$0$5,470$480$0$1,190$7,141$111.4Other Coal Handling$1,138$0$260$0$0$1,397$122$0$304$1,823$31.5Sorbent Receive & Unload

$0$0$0$0$0$0$0$0$0$0$01.6Sorbent Stackout & Reclaim

$0$0$0$0$0$0$0$0$0$0$01.7Sorbent Conveyors

$0$0$0$0$0$0$0$0$0$0$01.8Other Sorbent Handling

$0$0$0$0$0$0$0$0$0$0$01.9Coal & Sorbent Hnd.Foundations

$0$2,561$6,404$0$0$8,966$859$0$1,965$11,790$19SUBTOTAL 1.$13,783$2,561$10,689$0$0$27,033$2,454$0$5,897$35,384$57 2COAL & SORBENT PREP & FEED2.1Coal Crushing & Drying (incl. w/2.3)

$0$0$0$0$0$0$0$0$0$0$02.2Prepared Coal Storage & Feed$1,542$369$242$0$0$2,153$184$0$467$2,805$42.3Slurry Prep & Feed$21,042$0$9,358$0$0$30,400$2,714$0$6,623$39,737$642.4Misc.Coal Prep & Feed

$848$617$1,851$0$0$3,316$305$0$724$4,345$72.5Sorbent Prep Equipment

$0$0$0$0$0$0$0$0$0$0$02.6Sorbent Storage & Feed

$0$0$0$0$0$0$0$0$0$0$02.7Sorbent Injection System

$0$0$0$0$0$0$0$0$0$0$02.8Booster Air Supply System

$0$0$0$0$0$0$0$0$0$0$02.9Coal & Sorbent Feed Foundation

$0$3,297$2,707$0$0$6,004$556$0$1,312$7,871$13SUBTOTAL 2.$23,433$4,283$14,157$0$0$41,873$3,759$0$9,126$54,759$88 3FEEDWATER & MISC. BOP SYSTEMS3.1Feedwater System$3,157$5,422$2,862$0$0$11,440$1,060$0$2,500$15,000$243.2Water Makeup & Pretreating

$585$61$327$0$0$974$93$0$320$1,387$23.3Other Feedwater Subsystems$1,727$584$525$0$0$2,836$255$0$618$3,709$63.4Service Water Systems

$335$690$2,394$0$0$3,419$334$0$1,126$4,879$83.5Other Boiler Plant Systems$1,798$697$1,727$0$0$4,221$400$0$924$5,546$93.6FO Supply Sys & Nat Gas

$313$591$551$0$0$1,456$140$0$319$1,915$33.7Waste Treatment Equipment

$818$0$499$0$0$1,318$128$0$434$1,880$33.8Misc. Power Plant Equipment$1,072$143$550$0$0$1,765$170$0$581$2,517$4SUBTOTAL 3.$9,806$8,188$9,436$0$0$27,429$2,581$0$6,822$36,832$59 4GASIFIER & ACCESSORIES4.1Gasifier, Syngas Cooler & Auxiliaries (E-GAS)$117,991$0$65,449$0$0$183,440$16,853$25,442$34,617$260,352$4174.2Syngas Coolingw/4.1$0w/ 4.1$0$0$0$0$0$0$0$04.3ASU/Oxidant Compression$145,765$0w/equip.$0$0$145,765$14,129$0$15,989$175,883$2814.4LT Heat Recovery & FG Saturation$17,104$0$6,502$0$0$23,606$2,304$0$5,182$31,092$504.5Misc. Gasification Equipmentw/4.1&4.2$0w/4.1&4.2$0$0$0$0$0$0$0$04.6Flare Stack System

$0$1,503$612$0$0$2,114$203$0$463$2,780$44.8Major Component Riggingw/4.1&4.2$0w/4.1&4.2$0$0$0$0$0$0$0$04.9Gasification Foundations

$0$7,833$4,469$0$0$12,302$1,126$0$3,357$16,785$27SUBTOTAL 4.$280,861$9,335$77,032$0$0$367,228$34,614$25,442$59,609$486,893$779 Cost and Performance Baseline for Fossil Energy Plants 194 Exhibit 3-56 Case 3 Total Plant Cost Details (Continued) AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 5AGAS CLEANUP & PIPING5A.1MDEA-LT AGR $33,341$0$28,290$0$0$61,631$5,960$0$13,518$81,110$1305A.2Elemental Sulfur Plant$9,938$1,981$12,822$0$0$24,741$2,403$0$5,429$32,573$525A.3Mercury Removal

$970$0$738$0$0$1,708$165$85$392$2,350$45A.4COS Hydrolysis$3,196$0$4,173$0$0$7,369$717$0$1,617$9,703$165A.5Particulate Removal

$0$0$0$0$0$0$0$0$0$0$05A.6Blowback Gas Systems

$499$280$157$0$0$936$89$0$205$1,230$25A.7Fuel Gas Piping

$0$768$538$0$0$1,306$121$0$285$1,712$35A.9HGCU Foundations

$0$778$501$0$0$1,279$118$0$419$1,816$3SUBTOTAL 5A.$47,943$3,806$47,221$0$0$98,970$9,573$85$21,865$130,493$209 5BCO2 COMPRESSION5B.1CO2 Removal System

$0$0$0$0$0$0$0$0$0$0$05B.2CO2 Compression & Drying

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 5B.

$0$0$0$0$0$0$0$0$0$0$0 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine Generator$85,751$0$6,269$0$0$92,021$8,724$4,601$10,535$115,881$1856.2Open$0$0$0$0$0$0$0$0$0$0$06.3Compressed Air Piping

$0$0$0$0$0$0$0$0$0$0$06.9Combustion Turbine Foundations

$0$806$892$0$0$1,699$159$0$557$2,415$4SUBTOTAL 6.$85,751$806$7,162$0$0$93,719$8,883$4,601$11,092$118,295$189 7HRSG, DUCTING & STACK7.1Heat Recovery Steam Generator$35,467$0$5,043$0$0$40,510$3,852$0$4,436$48,798$787.2Open$0$0$0$0$0$0$0$0$0$0$07.3Ductwork$0$1,710$1,220$0$0$2,929$257$0$637$3,823$67.4Stack$3,335$0$1,253$0$0$4,588$440$0$503$5,530$97.9HRSG, Duct & Stack Foundations

$0$668$642$0$0$1,310$122$0$430$1,861$3SUBTOTAL 7.$38,802$2,378$8,157$0$0$49,337$4,670$0$6,006$60,013$96 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$28,970$0$4,963$0$0$33,934$3,256$0$3,719$40,909$658.2Turbine Plant Auxiliaries

$201$0$460$0$0$661$65$0$73$798$18.3Condenser & Auxiliaries$4,785$0$1,529$0$0$6,314$604$0$692$7,609$128.4Steam Piping$5,570$0$3,918$0$0$9,489$815$0$2,576$12,880$218.9TG Foundations

$0$996$1,683$0$0$2,679$254$0$880$3,813$6SUBTOTAL 8.$39,526$996$12,554$0$0$53,076$4,994$0$7,939$66,009$106 Cost and Performance Baseline for Fossil Energy Plants 195 Exhibit 3-56 Case 3 Total Plant Cost Details (Continued) AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 9COOLING WATER SYSTEM9.1Cooling Towers$6,338$0$1,153$0$0$7,491$713$0$1,231$9,434$159.2Circulating Water Pumps$1,648$0$113$0$0$1,761$149$0$287$2,197$49.3Circ.Water System Auxiliaries

$140$0$20$0$0$160$15$0$26$202$09.4Circ.Water Piping

$0$5,855$1,518$0$0$7,373$666$0$1,608$9,647$159.5Make-up Water System

$327$0$467$0$0$794$76$0$174$1,044$29.6Component Cooling Water Sys

$691$827$588$0$0$2,106$197$0$461$2,764$49.9Circ.Water System Foundations

$0$2,144$3,645$0$0$5,789$549$0$1,901$8,239$13SUBTOTAL 9.$9,144$8,826$7,504$0$0$25,474$2,366$0$5,687$33,527$54 10ASH/SPENT SORBENT HANDLING SYS10.1Slag Dewatering & Cooling$16,609$0$8,191$0$0$24,799$2,383$0$2,718$29,900$4810.2Gasifier Ash Depressurizationw/10.1w/10.1w/10.1$0$0$0$0$0$0$0$010.3Cleanup Ash Depressurizationw/10.1w/10.1w/10.1$0$0$0$0$0$0$0$010.4High Temperature Ash Piping

$0$0$0$0$0$0$0$0$0$0$010.5Other Ash Recovery Equipment

$0$0$0$0$0$0$0$0$0$0$010.6Ash Storage Silos

$548$0$596$0$0$1,144$111$0$188$1,443$210.7Ash Transport & Feed Equipment

$735$0$177$0$0$912$85$0$150$1,147$210.8Misc. Ash Handling Equipment$1,135$1,391$415$0$0$2,941$280$0$483$3,704$610.9Ash/Spent Sorbent Foundation

$0$48$61$0$0$109$10$0$36$155$0SUBTOTAL 10.$19,026$1,439$9,440$0$0$29,905$2,869$0$3,575$36,349$58 11ACCESSORY ELECTRIC PLANT11.1Generator Equipment

$951$0$940$0$0$1,891$181$0$207$2,279$411.2Station Service Equipment$3,741$0$337$0$0$4,078$376$0$445$4,900$811.3Switchgear & Motor Control $6,917$0$1,258$0$0$8,174$758$0$1,340$10,272$1611.4Conduit & Cable Tray

$0$3,213$10,599$0$0$13,812$1,336$0$3,787$18,935$3011.5Wire & Cable

$0$6,139$4,034$0$0$10,172$739$0$2,728$13,639$2211.6Protective Equipment

$0$680$2,474$0$0$3,153$308$0$519$3,980$611.7Standby Equipment

$234$0$229$0$0$463$44$0$76$583$111.8Main Power Transformers$15,583$0$145$0$0$15,727$1,190$0$2,538$19,454$3111.9Electrical Foundations

$0$157$412$0$0$569$54$0$187$810$1SUBTOTAL 11.$27,425$10,189$20,427$0$0$58,041$4,986$0$11,827$74,854$120 12INSTRUMENTATION & CONTROL12.1IGCC Control Equipmentw/4.1$0w/4.1$0$0$0$0$0$0$0$012.2Combustion Turbine Controlw/6.1$0w/6.1$0$0$0$0$0$0$0$012.3Steam Turbine Controlw/8.1$0w/8.1$0$0$0$0$0$0$0$012.4Other Major Component Control$1,010$0$675$0$0$1,685$159$84$289$2,218$412.5Signal Processing Equipmentw/12.7$0w/12.7$0$0$0$0$0$0$0$012.6Control Boards,Panels & Racks

$232$0$149$0$0$381$36$19$87$523$112.7Computer & Accessories$5,389$0$173$0$0$5,562$510$278$635$6,985$1112.8Instrument Wiring & Tubing

$0$1,883$3,849$0$0$5,731$486$287$1,626$8,130$1312.9Other I & C Equipment$3,602$0$1,749$0$0$5,352$504$268$918$7,041$11SUBTOTAL 12.$10,234$1,883$6,594$0$0$18,710$1,696$936$3,556$24,897$40 Cost and Performance Baseline for Fossil Energy Plants 196 Exhibit 3-56 Case 3 Total Plant Cost Details (Continued) AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 13IMPROVEMENTS TO SITE13.1Site Preparation

$0$104$2,232$0$0$2,336$232$0$771$3,339$513.2Site Improvements

$0$1,857$2,468$0$0$4,326$427$0$1,426$6,178$1013.3Site Facilities$3,328$0$3,512$0$0$6,841$674$0$2,255$9,770$16SUBTOTAL 13.$3,328$1,962$8,212$0$0$13,503$1,333$0$4,451$19,287$31 14BUILDINGS & STRUCTURES14.1Combustion Turbine Area

$0$265$150$0$0$414$36$0$90$541$114.2Steam Turbine Building

$0$2,435$3,468$0$0$5,903$543$0$967$7,413$1214.3Administration Building

$0$842$611$0$0$1,452$129$0$237$1,819$314.4Circulation Water Pumphouse

$0$166$88$0$0$254$22$0$41$317$114.5Water Treatment Buildings

$0$489$477$0$0$967$87$0$158$1,212$214.6Machine Shop

$0$431$295$0$0$726$64$0$119$909$114.7Warehouse

$0$696$449$0$0$1,145$101$0$187$1,433$214.8Other Buildings & Structures

$0$417$324$0$0$741$66$0$161$969$214.9Waste Treating Building & Str.

$0$931$1,780$0$0$2,711$253$0$593$3,557$6SUBTOTAL 14.

$0$6,670$7,642$0$0$14,313$1,303$0$2,553$18,169$29TOTAL COST$609,063$63,322$246,227$0$0$918,612$86,080$31,064$160,007$1,195,762$1,913Owner's CostsPreproduction Costs6 Months All Labor$12,309$201 Month Maintenance Materials$2,766$41 Month Non-fuel Consumables

$239$01 Month Waste Disposal

$279$025% of 1 Months Fuel Cost at 100% CF$1,603$32% of TPC$23,915$38Total$41,111$66Inventory Capital60 day supply of fuel and consumables at 100% CF$13,092$210.5% of TPC (spare parts)$5,979$10Total$19,071$31Initial Cost for Catalyst and Chemicals$1,084$2Land$900$1Other Owner's Costs$179,364$287Financing Costs$32,286$52Total Overnight Costs (TOC)$1,469,577$2,351TASC Multiplier(IOU, high-risk, 35 year)1.140Total As-Spent Cost (TASC)$1,675,318$2,680 Cost and Performance Baseline for Fossil Energy Plants 197 Exhibit 3-57 Case 3 Initial and Annual Operating and Maintenance Costs INITIAL & ANNUAL O&M EXPENSESCost Base (Jun):

2007Case 3 - ConocoPhillips 625MW IGCC w/o CO2Heat Rate-net(Btu/kWh):8,585 MWe-net: 625 Capacity Factor (%):

80OPERATING & MAINTENANCE LABOROperating Labor Operating Labor Rate(base):34.65$/hour Operating Labor Burden:30.00% of base Labor O-H Charge Rate:25.00% of laborTotal Operating Labor Requirements(O.J.)per Shift:1 unit/mod. Plant Skilled Operator2.02.0 Operator9.09.0 Foreman1.01.0 Lab Tech's, etc.3.03.0 TOTAL-O.J.'s15.015.0Annual CostAnnual Unit Cost

$$/kW-netAnnual Operating Labor Cost$5,918,913$9.469Maintenance Labor Cost$13,775,415$22.039Administrative & Support Labor$4,923,582$7.877Property Taxes and Insurance$23,935,631$38.293TOTAL FIXED OPERATING COSTS$48,553,541$77.678VARIABLE OPERATING COSTS$/kWh-netMaintenance Material Cost$26,551,568$0.00606ConsumablesConsumptionUnit Initial Fill Initial Fill /Day Cost CostWater (/1000 gallons) 03,144.241.08$0$993,106$0.00023ChemicalsMU & WT Chem. (lbs) 018,7320.17$0$946,662$0.00022Carbon (Mercury Removal) (lb)68,511 941.05$71,948$28,779$0.00001COS Catalyst (m3) 3270.222,397.36$784,204$156,841$0.00004Water Gas Shift Catalyst (ft3) 0 0498.83$0$0$0.00000MDEA Solution (gal)26,146 378.70$227,412$93,463$0.00002SCR Catalyst (m3) 0 00.00$0$0$0.00000Ammonia (19% NH3) (ton) 0 00.00$0$0$0.00000Claus Catalyst (ft3)w/equip.1.91131.27$0$73,243$0.00002Subtotal Chemicals$1,083,564$1,298,988$0.00030OtherSupplemental Fuel (MBtu) 0 00.00$0$0$0.00000Gases, N2 etc. (/100scf) 0 00.00$0$0$0.00000L.P. Steam (/1000 pounds) 0 00.00$0$0$0.00000Subtotal Other

$0$0$0.00000Waste DisposalSpent Mercury Catalyst (lb.)

0 940.42$0$11,430$0.00000Flyash (ton) 0 00.00$0$0$0.00000Slag (ton) 0 56316.23$0$2,669,064$0.00061 Subtotal-Waste Disposal

$0$2,680,493$0.00061By-products & EmissionsSulfur (ton) 0 1380.00$0$0$0.00000Subtotal By-Products

$0$0$0.00000TOTAL VARIABLE OPERATING COSTS$1,083,564$31,524,155$0.00720Fuel (ton) 05,51938.18$0$61,541,712$0.01405 Cost and Performance Baseline for Fossil Energy Plants 198 3.3.8 This case is configured to produce electric power with CO 2 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 CO 2 capture and compression process increases the auxiliary load on the plant, the net output is significantly reduced relative to Case 3.

Case 4 - E-GasŽ IGCC Power Plant with CO 2 Capture The process description for Case 4 is similar to Case 3 with several notable exceptions to accommodate CO 2 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.

No differences from Case 3.

Coal Preparation and Feed Systems 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).

Gasification Raw gas cooling and particulate removal are the same as Case 3 with the exception that approximately 418,710 kg/h r (923,082 lb/h r) of saturated steam at 13.8 MPa (2,000 psia) is generated in the SGC.

Raw Gas Cooling/Particulate Removal No differences from Case 3.

Syngas Scrubber/Sour Water Stripper The SGS process was described in Section Sour Gas Shift (SGS) 3.1.3. In Case 4 steam (stream

11) is added to the syngas exiting the scrubber to adjust the H 2O: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 CO 2 to 98.5 percent. The syngas exiting the final stage of SGS still contains 1.2 vol% CH 4 , which is subsequently oxidized to CO 2 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 is the same as in Case 3.

Mercury Removal and Acid Gas Removal

Cost and Performance Baseline for Fossil Energy Plants 199 Exhibit 3-58 Case 4 Block Flow Diagram , E-GasŽ IGCC with CO 2 Capture Cost and Performance Baseline for Fossil Energy Plants 200 Exhibit 3-59 Case 4 Stream Table , E-GasŽ IGCC with CO 2 Capture 1 2 3 4 5 6 7 8 9 10 11 12 13V-L Mole Fraction Ar0.00920.02090.03180.00230.03180.00000.00000.00000.00000.00000.00000.00540.0071 CH 40.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.01250.0164 CO0.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00280.0037 CO 20.00030.00710.00000.00000.00000.00000.00000.00000.00000.00000.00000.31030.4090COS0.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 H 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.41280.5441 H 2 O0.00990.17800.00000.00030.00001.00001.00000.00000.99630.00001.00000.23760.0015 HCl0.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00010.0000 H 2 S0.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00480.0063 N 20.77320.61870.01780.99190.01780.00000.00000.00000.00000.00000.00000.00900.0119 NH 30.00000.00000.00000.00000.00000.00000.00000.00000.00370.00000.00000.00460.0000 O 20.20740.17540.95040.00540.95040.00000.00000.00000.00000.00000.00000.00000.0000 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000Total1.00001.00001.00001.00001.00001.00001.00000.00001.00000.00001.00001.00001.0000V-L Flowrate (kgmol/hr)26,6851,231 14519,7045,3381,2874,969 05,009 09,35737,86626,948V-L Flowrate (kg/hr)770,04233,6034,654552,893171,78223,19389,523 090,226 0168,566748,369547,649Solids Flowrate (kg/hr) 0 0 0 0 0 0 0219,635 022,418 0 0 0Temperature

(°C)15 19 32 93 32 154 343 15 1711,038 288 204 35Pressure (MPa, abs)0.100.110.862.650.865.795.100.105.794.245.524.073.79Enthalpy (kJ/kg)

A30.2336.4926.6792.5026.67599.343,063.97---673.50---2,918.18873.7340.91Density (kg/m 3)1.21.511.024.411.0857.720.1---836.0---25.620.630.9V-L Molecular Weight28.85727.29532.18128.06032.18118.01518.015---18.012---18.01519.76420.322V-L Flowrate (lbmol/hr)58,8302,714 31943,44011,7682,83810,955 011,044 020,62883,47959,411V-L Flowrate (lb/hr)1,697,65274,08210,2601,218,920378,71551,133197,365 0198,914 0371,6251,649,8721,207,359Solids Flowrate (lb/hr) 0 0 0 0 0 0 0484,212 049,422 0 0 0Temperature

(°F)59 67 90 199 90 310 650 59 3401,900 550 400 95Pressure (psia)14.716.4125.0384.0125.0840.0740.014.7840.0615.0800.0590.0550.0Enthalpy (Btu/lb)

A13.015.711.539.811.5257.71,317.3---289.6---1,254.6375.617.6Density (lb/ft 3)0.0760.0950.6871.5210.68753.5431.257---52.192---1.5971.2851.928A - Reference conditions are 32.02 F & 0.089 PSIA Cost and Performance Baseline for Fossil Energy Plants 201 Exhibit 3-59 Case 4 Stream Table , E-GasŽ IGCC with CO 2 Capture (Continued) 14 15 16 17 18 19 20 21 22 23 24 25V-L Mole Fraction Ar0.00710.01190.01140.01140.00020.00110.00000.00680.00920.00900.00900.0000 CH 40.01590.02620.02510.02510.00080.00450.00000.00000.00000.00000.00000.0000 CO0.00380.00630.00600.00600.00010.00070.00000.00760.00000.00000.00000.0000 CO 20.41720.03520.03380.03380.99450.70210.00000.69070.00030.00820.00820.0000COS0.00000.00000.00000.00000.00000.00010.00000.00000.00000.00000.00000.0000 H 20.53410.89640.85880.85880.00440.05910.00000.20070.00000.00000.00000.0000 H 2 O0.00150.00010.04210.04210.00000.01620.00000.00170.00990.12460.12461.0000 HCl0.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 H 2 S0.00620.00000.00000.00000.00000.21530.00000.00260.00000.00000.00000.0000 N 20.01420.02390.02290.02290.00010.00100.00000.09010.77320.75290.75290.0000 NH 30.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 O 20.00000.00000.00000.00000.00000.00000.00000.00000.20740.10520.10520.0000 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000Total1.00001.00001.00001.00001.00001.00000.00001.00001.00001.00001.00001.0000V-L Flowrate (kgmol/hr)27,76116,43517,15517,15510,499 800 0 812110,253139,694139,69434,515V-L Flowrate (kg/hr)575,20883,81396,78096,780459,85531,069 027,5603,181,5573,831,2303,831,230621,792Solids Flowrate (kg/hr) 0 0 0 0 0 05,494 0 0 0 0 0Temperature

(°C)34 34 108 193 51 48 176 38 15 562 132 534Pressure (MPa, abs)3.83.7573.2063.17215.2700.1630.1195.5120.1010.1050.10512.512Enthalpy (kJ/kg)

A39.0196.106903.0631,360.503-162.34962.132---1.77430.227839.766348.1883,432.696Density (kg/m 3)31.37.45.64.6641.82.45,283.783.61.20.40.936.7V-L Molecular Weight 215.1005.6425.64243.80038.814---33.92528.85727.42627.42618.015V-L Flowrate (lbmol/hr)61,20236,23337,82037,82023,1461,765 01,791243,066307,972307,97276,092V-L Flowrate (lb/hr)1,268,117184,776213,363213,3631,013,80768,496 060,7597,014,1338,446,4178,446,4171,370,817Solids Flowrate (lb/hr) 0 0 0 0 0 012,112 0 0 0 0 0Temperature

(°F)94 94 227 380 124 119 349 100 591,044 270 994Pressure (psia)545.0545.0465.0460.02,214.723.717.3799.514.715.215.21,814.7Enthalpy (Btu/lb)

A16.884.3388.2584.9-69.826.7---0.813.0361.0149.71,475.8Density (lb/ft 3)20.4610.3520.28540.0670.149329.8515.2200.0760.0260.0532.293 Cost and Performance Baseline for Fossil Energy Plants 202 The AGR process in Case 4 is a two stage Selexol process where H 2S is removed in the first stage and CO 2 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 CO 2-rich stream

, and an acid gas feed to the Claus plant. The acid gas (stream 1

9) contains 21.5 percent H 2S and 70 percent CO 2 with the balance primarily H 2. The CO 2-rich stream is discussed further in the CO 2 compression section. CO 2 from the AGR process is flashed at three pressure levels to separate CO 2 and decrease H 2 losses to the CO 2 product pipeline. The HP CO 2 stream is flashed at 2.0 MPa (289.7 psia), compressed, and recycled back to the CO 2 absorber. The MP CO 2 stream is flashed at 1.0 MPa (149.7 psia). The LP CO 2 stream is flashed at 0.1 MPa (16.7 psia), compressed to 1.0 MPa (149.5 psia)

, and combined with the MP CO 2 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 CO 2 stream is dehydrated to a dewpoint of

-40ºC (-40°F) with triethylene glycol. The raw CO 2 stream from the Selexol process contains over 99 percent CO

2. The CO 2 (stream 1 8) is transported to the plant fence line and is sequestration ready. CO 2 TS&M costs were estimated using the methodology described in Section CO 2 Compression and Dehydration 2.7. The Claus plant is the same as Case 3 with the following exceptions:

Claus Unit 5, 494 kg/h r (12 , 1 12 lb/h r) of sulfur (stream

20) are produced The waste heat boiler generates 12 , 679 kg/h r (27 , 953 lb/h r) 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.

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 1

7) to 193°C (38 0°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.

Power Block 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. Air Separation Unit (ASU) 3.3.9 The Case 4 modeling assumptions were presented previously in Section Case 4 Performance Results 3.3.3.

Cost and Performance Baseline for Fossil Energy Plants 203 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 CO 2 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.

Cost and Performance Baseline for Fossil Energy Plants 204 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 CO 2 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 Plant 2 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 10 6 kJ/h r (10 6 Btu/h r) 1,403 (1,330)

CONSUMABLES As-Received Coal Feed, kg/h r (lb/h r) 219,635 (484,212)

Thermal Input 1, kWt 1,655,503 Raw Water Withdrawal, m 3/min (gpm) 21.6 (5,717)

Raw Water Consumption , m 3/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

Cost and Performance Baseline for Fossil Energy Plants 205 The environmental targets for emissions of Hg, NO x, SO 2, CO 2 , and PM were presented in Section Environmental Performance 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 kg/GJ (lb/10 6 Btu) Tonne/year (tons/year) 80% CF kg/MWh (lb/MWh) SO 2 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) Hg 2.46E-7 (5.71E-7) 0.010 (0.011) 2.08E-6 (4.59E-6) CO 2 8.5 (19.7) 354,267 (390,512) 72 (158) CO 2 1 98 (217) 1 CO 2 emissions based on net power instead of gross power The low level of SO 2 emissions is achieved by capture of the sulfur in the gas by the two

-stage Selexol AGR process. The CO 2 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 H 2 S-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 H 2S, and then recycled back to the Selexol, thereby eliminating the need for a tail gas treatment unit.

NO x emissions are limited by the use of humidification and nitrogen dilution to 15 ppmvd (NO 2 @ 15 percent O 2). 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 NO x 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 CO 2 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, CO 2 in the stack gas, ASU vent gas and the captured CO 2 product. The carbon capture efficiency is defined as the amount of carbon in the Cost and Performance Baseline for Fossil Energy Plants 206 CO 2 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 CO 2 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 CO 2 capture. In order to achieve 90 percent capture, the two-stage Selexol CO 2 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/h r (lb/hr) Coal 140,006 (308,659)

Slag 1,120 (2,469) Air (CO 2) 537 (1,185)

Stack Gas 13,796 (30,416)

ASU Vent 105 (231) CO 2 Product 125,522 (276,728)

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 CO 2 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/h r (lb/hr) Coal 5,505 (12,136)

Elemental Sulfur 5,494 (12,112)

Stack Gas 3 (6) CO 2 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 Case s 1 through 3.

Cost and Performance Baseline for Fossil Energy Plants 207 Exhibit 3-64 Case 4 Water Balance Water Use Water Demand, m 3/min (gpm) Internal Recycle, m 3/min (gpm) Raw Water Withdrawal, m 3/min (gpm)

Process Water Discharge, m 3/min (gpm) Raw Water Consumption, m 3/min (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 Gasifier Steam Shift Steam GT Steam Dilution BFW Makeup 4.5 (1,193) 1.5 (395) 2.8 (743) 0.21 (55) 0.0 (0) 4.5 (1,193) 1.5 (395) 2.8 (743) 0.21 (55) 0.0 (0) 4.5 (1,193)

Cooling Tower BFW Blowdown SWS Blowdown SWS Excess Water Humidifier Tower Blowdown 18.2 (4,798) 1.0 (274) 0.21 (55) 0.26 (68) 0.6 (152) 17.1 (4,524)

-0.21 (-55) -0.26 (-68) -0.6 (-152) 4.1 (1,079) 13.0 (3,445)

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 are shown for the following subsystems in Heat and Mass Balance Diagrams 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.

Cost and Performance Baseline for Fossil Energy Plants 208 This page intentionally left blank

Cost and Performance Baseline for Fossil Energy Plants 209 Exhibit 3-65 Case 4 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA DOE/NETL D UAL T RAIN IGCC P LANT C ASE 4 H EAT AND M ATERIAL F LOW D IAGRAM B ITUMINOUS BASELINE S TUDY C ASE 4 C O P G ASIFIER ASU AND G ASIFICATION DWG. NO.BB-HMB-CS-4-PG-1 P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas P AGES 1 OF 3 Ambient Air Four Stage Air Compressor Elevated Pressure ASU Four Stage N 2 Compressor Four Stage O 2 Compressor ASU Vent Water Steam Gross Plant Power

704 MWe Auxiliary Load

190 MWe Net Plant Power

514 MWe Net Plant Efficiency , HHV: 31.0%Net Plant Heat Rate

10 , 998 BTU/KWe N 2 to GT Combustor 1 , 697 , 652 W 59.0 T 14.7 P 13.0 H 378 , 715 W 90.0 T 125.0 P 11.5 H 378 , 715 W 223.0 T 740.0 P 37.5 H To Claus Plant 10 , 260 W 90.0 T 125.0 P 11.5 H 74 , 082 W 66.9 T 16.4 P 15.7 H 1 , 080 , 178 W 90.0 T 56.4 P 14.2 H 152 , 901 W 50.0 T 182.0 P 2.9 H 5 1 3 2 457 , 753 W 385.0 T 469.0 P 87.0 H Candle Filter Slurry Mix Tank E-Gas TM Gasifier Milled Coal Water Slag Raw Syngas to Scrubber Cyclones Syngas Recycle Saturated Steam to HRSG BFW from HRSG Blowdown to Flash Tank Fire Tube Boiler Steam Drum 484 , 212 W 59.0 T 14.7 P 198 , 914 W 340.0 T 840.0 P 289.6 H 49 , 422 W 1 , 355 , 003 W 600.0 T 605.0 P 485.6 H 761 , 167 W 385.0 T 384.0 P 87.2 H Fuel Gas 10 683 , 126 W 178.6 T 840.0 P 3 , 040.6 H 1 , 355 , 003 W 600.0 T 605.0 P 485.6 H 1 , 355 , 003 W 1 , 801.8 T 615.0 P 1 , 029.4 H Boost Compressor N 2 to GT Combustor 79 , 928 W 160.9 T 800.0 P 42.6 H N 2 Diluent Preheater 1 , 355 , 003 W 450.0 T 600.0 P 422.6 H 100.0 T 189.5 P 18.0 H 8 9 Steam Sour Water 7 6 197 , 365 W 650.0 T 740.0 P 1 , 316.8 H 51 , 133 W 310.0 T 840.0 P 257.7 H Syngas Recycle Compressor 79 , 928 W 105.0 T 585.0 P 21.6 H 4 Cost and Performance Baseline for Fossil Energy Plants 210 Exhibit 3-66 Case 4 Syngas Cleanup Heat and Mass Balance Schematic Mercury Removal Knock Out Drum Multistage Intercooled CO 2 Compressor Raw Syngas Syngas Preheater Fuel Gas to GT Sour Drum To Water Treatment Makeup Water Interstage Knockout Claus Plant Tail Gas Furnace Catalytic Reactor Beds Sulfur High Temperature Shift #1 Low Temperature Shift #2 Knock Out From ASU CO 2 Product Shift Steam Fuel Gas Humidification Syngas Coolers Sour Stripper Two-Stage Selexol Clean Gas CO 2 Acid Gas Syngas Scrubber Condensate to Deaerator Condensate 371 , 625 W 550.0 T 800.0 P 1 , 254.1 H 362.9 T 590.0 P 340.0 H 1 , 355 , 003 W 450.0 T 600.0 P 422.6 H 1 , 278 , 247 W 352.9 T 595.0 P 343.8 H 1 , 268 , 117 W 93.8 T 545.0 P 16.8 H 213 , 363 W 227.0 T 465.0 P 388.2 H 68 , 496 W 119.0 T 23.7 P 26.7 H 1 , 013 , 807 W 123.7 T 2 , 214.7 P 1 , 547 , 580 W 392.6 T 585.0 P 372.4 H 213 , 363 W 380.0 T 460.0 P 584.9 H 12 , 112 W 72 , 809 W 280.0 T 17.3 P 312.6 H 6 , 165 W 195.4 T 65.0 P 206.5 H 10 , 260 W 90.0 T 125.0 P 11.5 H N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA DOE/NETL D UAL T RAIN IGCC P LANT C ASE 4 H EAT AND M ATERIAL F LOW D IAGRAM B ITUMINOUS BASELINE S TUDY C ASE 4 C O P G ASIFIER G AS CLEANUP SYSTEM DWG. NO.BB-HMB-CS-4-PG-2 P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas P AGES 2 OF 3 Sour Gas Sour Water Water Steam Gross Plant Power

704 MWe Auxiliary Load

190 MWe Net Plant Power

514 MWe Net Plant Efficiency , HHV: 31.0%Net Plant Heat Rate

10 , 998 BTU/KWe 1 , 649 , 872 W 398.4 T 590.0 P 546.0 H 400.0 T 590.0 P 397.7 H 15 20 19 18 14 13 12 17 21 CO 2 Tailgas 65 , 864 W 120.0 T 10.6 P 106.8 H 1 , 207 , 359 W 94.6 T 550.0 P 17.6 H 12 , 050 W 111.6 T 10.6 P 37.1 H 1 , 014 , 845 W 60.0 T 135.0 P 3 Syngas Recycle 11 60 , 759 W 100.0 T 799.5 P 0.8 H 1 , 649 , 872 W 400.0 T 590.0 P 375.6 H 698.4 T 590.0 P 532.7 H 102 , 292 W 392.6 T 585.0 P 372.4 H Humidification 16 184 , 776 W 93.8 T 545.0 P 84.3 H Claus Oxygen Preheater 10 , 260 W 450.0 T 124.5 P 91.9 H Tail Gas Compressor Hydrogenation And Tail Gas Cooling Cost and Performance Baseline for Fossil Energy Plants 211 Exhibit 3-67 Case 4 Combined Cycle Power Generation Heat and Mass Balance Schematic HRSG HP Turbine IP Turbine Nitrogen Diluent Intake Ambient Air Steam Seal Regulator Gasifier and WGS Steam Ip Extraction Steam To 250 PSIA Header Blowdown Flash To WWT Gland Steam Condenser Condensate to Gasification Island HP BFW to Syngas Cooler HP Saturated Steam to HRSG Superheater LP Turbine Stack Expander Compressor Fuel Gas Deaerator IP BFW Generator Generator Condensate Pump HP Pump Steam Turbine LP Pump Advanced F

-Class Gas Turbine MP Flash Bottoms LP Flash Tops 1 , 218 , 920 W 7 , 014 , 133 W 59.0 T 14.7 P 13.0 H 2 , 068 , 816 W 101.1 T 1.0 P 69.1 H 8 , 446 , 417 W 270.0 T 15.2 P 149.7 H 213 , 363 W 380.0 T 460.0 P 584.9 H 8 , 446 , 417 W 1 , 043.7 T 15.2 P 361.0 H LP Process Header From Gasifier Island Preheating To Claus LP BFW 1 , 370 , 817 W 993.7 T 1 , 814.7 P 1 , 475.8 H 9 , 744 W 298.0 T 65.0 P 1 , 179.0 H 1 , 398 , 140 W 278.8 T 2 , 250.7 P 252.3 H 27 , 273 W 585.0 T 2 , 000.7 P 593.3 H 1 , 460 , 271 W 464.8 T 65.0 P 1 , 264.6 H 2 , 068 , 816 W 102.7 T 120.0 P 70.9 H 2 , 068 , 816 W 235.0 T 105.0 P 203.7 H 1 , 400 W 614.7 T 65.0 P 1 , 338.6 H 1 , 400 W 212.0 T 14.7 P 179.9 H IP Pump N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA DOE/NETL D UAL T RAIN IGCC P LANT C ASE 4 H EAT AND M ATERIAL F LOW D IAGRAM B ITUMINOUS BASELINE S TUDY C ASE 4 C O P G ASIFIER P OWER B LOCK S YSTEM DWG. NO.BB-HMB-CS-4-PG-3 P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas P AGES 3 OF 3 Sour Gas Sour Water Water Steam Gross Plant Power

704 MWe Auxiliary Load

190 MWe Net Plant Power

514 MWe Net Plant Efficiency , HHV: 31.0%Net Plant Heat Rate

10 , 998 BTU/KWe 22 23 25 17 24 Flue Gas HOT WELL CONDENSER Make-up 596 , 383 W 59.0 T 14.7 P 27.1 H 9 , 026 W 660.4 T 501.4 P 1 , 334.5 H 9 , 762 W 614.7 T 65.0 P 1 , 338.6 H 25 , 041 W 851.8 T 280.0 P 1 , 448.7 H 798 W 993.7 T 1 , 814.7 P 1 , 475.8 H 1 , 337 W 504.8 T 65.0 P 1 , 284.4 H Cost and Performance Baseline for Fossil Energy Plants 212 This page intentionally left blank

Cost and Performance Baseline for Fossil Energy Plants 213 Exhibit 3-68 Case 4 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total 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) CO 2 -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 Tower Loads*

755 (716) 755 (716) 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, CO 2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection) and extraction air cooler.

- Calculated by difference to close the energy balance

Cost and Performance Baseline for Fossil Energy Plants 214 3.3.10 Major equipment items for the CoP gasifier with CO 2 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 Case 4 - Major Equipment List 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 No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Bottom Trestle Dumper and Receiving HoppersN/A181 tonne (200 ton) 2 0 2FeederBelt572 tonne/hr (630 tph) 2 0 3Conveyor No. 1Belt1,134 tonne/hr (1,250 tph) 1 0 4Transfer Tower No. 1EnclosedN/A 1 0 5Conveyor No. 2Belt1,134 tonne/hr (1,250 tph) 1 0 6As-Received Coal Sampling SystemTwo-stageN/A 1 0 7Stacker/ReclaimerTraveling, linear1,134 tonne/hr (1,250 tph) 1 0 8Reclaim HopperN/A45 tonne (50 ton) 2 1 9FeederVibratory181 tonne/hr (200 tph) 2 1 10Conveyor No. 3Belt w/ tripper363 tonne/hr (400 tph) 1 0 11Crusher TowerN/AN/A 1 0 12Coal Surge Bin w/ Vent FilterDual outlet181 tonne (200 ton) 2 0 13CrusherImpactor reduction8 cm x 0 - 3 cm x 0(3" x 0 1/4" x 0) 2 0 14As-Fired Coal Sampling SystemSwing hammerN/A 1 1 15Conveyor No. 4Belt w/tripper363 tonne/hr (400 tph) 1 0 16Transfer Tower No. 2EnclosedN/A 1 0 17Conveyor No. 5Belt w/ tripper363 tonne/hr (400 tph) 1 0 18Coal Silo w/ Vent Filter and Slide GatesField erected363 tonne (400 ton) 6 0 Cost and Performance Baseline for Fossil Energy Plants 215 ACCOUNT 2 COAL PREPARATION AND FEED Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1FeederVibratory82 tonne/h (90 tph) 3 0 2Conveyor No. 6Belt w/tripper245 tonne/h (270 tph) 1 0 3Rod Mill Feed HopperDual Outlet481 tonne (530 ton) 1 0 4Weigh FeederBelt118 tonne/h (130 tph) 2 0 5Rod MillRotary118 tonne/h (130 tph) 2 0 6Slurry Water Storage Tank with AgitatorField erected298,179 liters (78,770 gal) 2 0 7Slurry Water PumpsCentrifugal833 lpm (220 gpm) 2 1 8Trommel ScreenCoarse172 tonne/h (190 tph) 2 0 9Rod Mill Discharge Tank with AgitatorField erected390,052 liters (103,040 gal) 2 0 10Rod Mill Product PumpsCentrifugal3,407 lpm (900 gpm) 2 2 11Slurry Storage Tank with AgitatorField erected1,170,080 liters (309,100 gal) 2 0 12Slurry Recycle PumpsCentrifugal6,435 lpm (1,700 gpm) 2 2 13Slurry Product PumpsPositive displacement3,407 lpm (900 gpm) 2 2 Cost and Performance Baseline for Fossil Energy Plants 216 ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Demineralized Water Storage TankVertical, cylindrical, outdoor1,101,555 liters (291,000 gal) 2 0 2Condensate PumpsVertical canned8,669 lpm @ 91 m H2O(2,290 gpm @ 300 ft H2O) 2 1 3Deaerator (integral w/ HRSG)Horizontal spray type606,907 kg/hr (1,338,000 lb/hr) 2 0 4Intermediate Pressure Feedwater PumpHorizontal centrifugal, single stage8,555 lpm @ 27 m H2O(2,260 gpm @ 90 ft H2O) 2 1 5High Pressure Feedwater Pump No. 1Barrel type, multi-stage, centrifugalHP water: 6,057 lpm @ 1,859 m H2O (1,600 gpm @ 6,100 ft H2O)2 1 6High Pressure Feedwater Pump No. 2Barrel type, multi-stage, centrifugalIP water: 1,287 lpm @ 223 m H2O (340 gpm @ 730 ft H2O) 2 1 7Auxiliary BoilerShop fabricated, water tube18,144 kg/hr, 2.8 MPa, 343°C(40,000 lb/hr, 400 psig, 650°F) 1 0 8Service Air CompressorsFlooded Screw28 m3/min @ 0.7 MPa(1,000 scfm @ 100 psig) 2 1 9Instrument Air DryersDuplex, regenerative28 m3/min (1,000 scfm) 2 1 10Closed Cylce Cooling Heat ExchangersPlate and frame430 GJ/hr (407 MMBtu/hr) each 2 0 11Closed Cycle Cooling Water PumpsHorizontal centrifugal154,066 lpm @ 21 m H2O(40,700 gpm @ 70 ft H2O) 2 1 12Engine-Driven Fire PumpVertical turbine, diesel engine3,785 lpm @ 107 m H2O(1,000 gpm @ 350 ft H2O) 1 1 13Fire Service Booster PumpTwo-stage horizontal centrifugal2,650 lpm @ 76 m H2O(700 gpm @ 250 ft H2O) 1 1 14Raw Water PumpsStainless steel, single suction5,602 lpm @ 18 m H2O(1,480 gpm @ 60 ft H2O) 2 1 15Ground Water PumpsStainless steel, single suction2,801 lpm @ 268 m H2O (740 gpm @ 880 ft H2O) 4 1 16Filtered Water PumpsStainless steel, single suction3,066 lpm @ 49 m H2O(810 gpm @ 160 ft H2O) 2 1 17Filtered Water TankVertical, cylindrical1,472,525 liter (389,000 gal) 2 0 18Makeup Water DemineralizerAnion, cation, and mixed bed1,855 lpm (490 gpm) 2 0 19Liquid Waste Treatment System10 years, 24-hour storm 1 0 Cost and Performance Baseline for Fossil Energy Plants 217 ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY AND FUEL GAS SATURATION Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1GasifierPressurized two-stage, slurry-feed entrained bed2,903 tonne/day, 4.2 MPa(3,200 tpd, 614.96 psia) 2 0 2Synthesis Gas CoolerFire-tube boiler337,926 kg/hr (745,000 lb/hr) 2 0 3Synthesis Gas CycloneHigh efficiency337,926 kg/hr (745,000 lb/hr) Design efficiency 90%

2 0 4Candle FilterPressurized filter with pulse-jet cleaningmetallic filters 2 0 5Syngas Scrubber Including Sour Water StripperVertical upflow337,926 kg/hr (745,000 lb/hr) 2 0 6Raw Gas CoolersShell and tube with condensate drain386,007 kg/hr (851,000 lb/hr) 8 0 7Raw Gas Knockout DrumVertical with mist eliminator303,000 kg/hr, 35°C, 3.8 MPa(668,000 lb/hr, 95°F, 555 psia) 2 0 8Saturation Water EconomizersShell and tube36 GJ/hr (34 MMBtu/hr) 2 0 9Fuel Gas SaturatorVertical tray tower53,070 kg/hr, 108°C, 3.8 MPa(117,000 lb/hr, 227°F, 545 psia) 2 0 10Saturator Water PumpCentrifugal757 lpm @ 12 m H2O(200 gpm @ 40 ft H2O) 2 2 11Synthesis Gas ReheaterShell and tube53,070 kg/hr (117,000 lb/hr) 2 0 12Flare StackSelf-supporting, carbon steel, stainless steel top, pilot ignition337,926 kg/hr (745,000 lb/hr) syngas 2 0 13ASU Main Air CompressorCentrifugal, multi-stage5,805 m3/min @ 1.3 MPa(205,000 scfm @ 190 psia) 2 0 14Cold BoxVendor design2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2 0 15Oxygen CompressorCentrifugal, multi-stage1,161 m3/min (41,000 scfm)Suction - 0.9 MPa (130 psia)Discharge - 5.1 MPa (740 psia) 2 0 16Primary Nitrogen CompressorCentrifugal, multi-stage3,794 m3/min (134,000 scfm)Suction - 0.4 MPa (60 psia)Discharge - 2.7 MPa (390 psia) 2 0 17Secondary Nitrogen CompressorCentrifugal, single-stage538 m3/min (19,000 scfm)Suction - 1.2 MPa (180 psia)Discharge - 2.7 MPa (390 psia) 2 0 18Gasifier Purge Nitrogen Boost CompressorCentrifugal, single-stage1,614 m3/min (57,000 scfm)Suction - 2.6 MPa (380 psia)Discharge - 3.2 MPa (470 psia) 2 0 Cost and Performance Baseline for Fossil Energy Plants 218 ACCOUNT 5A SOUR GAS SHIFT AND SYNGAS CLEANUP ACCOUNT 5B CO 2 COMPRESSION

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Mercury AdsorberSulfated carbon bed301,185 kg/hr (664,000 lb/hr) 35°C (95°F) 3.8 MPa (550 psia) 2 0 2Sulfur PlantClaus type145 tonne/day (160 tpd) 1 0 3Water Gas Shift ReactorsFixed bed, catalytic411,408 kg/hr (907,000 lb/hr) 204°C (400°F) 4.1 MPa (590 psia) 4 0 4Shift Reactor Heat Recovery ExchangersShell and TubeExchanger 1: 94 GJ/hr (89 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) 4 0 5Acid Gas Removal PlantTwo-stage Selexol316,154 kg/hr (697,000 lb/hr) 34°C (94°F) 3.8 MPa (545 psia) 2 0 6Hydrogenation ReactorFixed bed, catalytic36,328 kg/hr (80,090 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 1 0 7Tail Gas Recycle CompressorCentrifugal30,316 kg/hr (66,835 lb/hr) 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1CO2 CompressorIntegrally geared, multi-stage centrifugal1,141 m3/min @ 15.3 MPa (40,300 scfm @ 2,215 psia) 4 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Gas TurbineAdvanced F class232 MW 2 0 2Gas Turbine GeneratorTEWAC260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0 Cost and Performance Baseline for Fossil Energy Plants 219 ACCOUNT 7 HRSG, DUCTING, AND STACK ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1StackCS plate, type 409SS liner76 m (250 ft) high x8.5 m (28 ft) diameter 1 0 2Heat Recovery Steam GeneratorDrum, multi-pressure with economizer section and integral deaeratorMain steam - 341,986 kg/hr, 12.4 MPa/534°C (753 , 949 lb/hr , 1 , 800 psig/994°F) Reheat steam - 298,222 kg/hr, 3.1 MPa/534°C (657 , 466 lb/hr , 452 psig/994°F)2 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Steam TurbineCommercially available advanced steam turbine252 MW 12.4 MPa/534°C/534°C (1800 psig/ 994°F/994°F)1 0 2Steam Turbine GeneratorHydrogen cooled, static excitiation280 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0 3Steam BypassOne per HRSG50% steam flow @ design steam conditions 2 0 4Surface CondenserSingle pass, divided waterbox including vacuum pumps1,551 GJ/hr (1,470 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F)1 0 Cost and Performance Baseline for Fossil Energy Plants 220 ACCOUNT 9 COOLING WATER SYSTEM ACCOUNT 10 SLAG RECOVERY AND HANDLING Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Circulating Water PumpsVertical, wet pit469,391 lpm @ 30 m(124,000 gpm @ 100 ft) 2 1 2Cooling TowerEvaporative, mechanical draft, multi-cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2606 GJ/hr (2470 MMBtu/hr) heat duty 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Slag Quench TankWater bath234,696 liters (62,000 gal) 2 0 2Slag CrusherRoll13 tonne/hr (14 tph) 2 0 3Slag DepressurizerProprietary13 tonne/hr (14 tph) 2 0 4Slag Receiving TankHorizontal, weir140,060 liters (37,000 gal) 2 0 5Black Water Overflow TankShop fabricated64,352 liters (17,000 gal) 2 6Slag ConveyorDrag chain13 tonne/hr (14 tph) 2 0 7Slag Separation ScreenVibrating13 tonne/hr (14 tph) 2 0 8Coarse Slag ConveyorBelt/bucket13 tonne/hr (14 tph) 2 0 9Fine Ash Settling TankVertical, gravity200,627 liters (53,000 gal) 2 0 10Fine Ash Recycle PumpsHorizontal centrifugal38 lpm @ 14 m H2O(10 gpm @ 46 ft H2O) 2 2 11Grey Water Storage TankField erected64,352 liters (17,000 gal) 2 0 12Grey Water PumpsCentrifugal227 lpm @ 433 m H2O(60 gpm @ 1,420 ft H2O) 2 2 13Slag Storage BinVertical, field erected907 tonne (1,000 tons) 2 0 14Unloading EquipmentTelescoping chute100 tonne/hr (110 tph) 1 0 Cost and Performance Baseline for Fossil Energy Plants 221 ACCOUNT 11 ACCESSORY ELECTRIC PLANT ACCOUNT 12 INSTRUMENTATION AND CONTROLS Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1CTG Step-up TransformerOil-filled24 kV/345 kV, 260 MVA, 3-ph, 60 Hz 2 0 2STG Step-up TransformerOil-filled24 kV/345 kV, 280 MVA, 3-ph, 60 Hz 1 0 3High Voltage Auxiliary TransformerOil-filled345 kV/13.8 kV, 79 MVA, 3-ph, 60 Hz 2 0 4Medium Voltage Auxiliary TransformerOil-filled24 kV/4.16 kV, 51 MVA, 3-ph, 60 Hz 1 1 5Low Voltage TransformerDry ventilated4.16 kV/480 V, 8 MVA, 3-ph, 60 Hz 1 1 6CTG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled24 kV, 3-ph, 60 Hz 2 0 7STG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled24 kV, 3-ph, 60 Hz 1 0 8Medium Voltage SwitchgearMetal clad4.16 kV, 3-ph, 60 Hz 1 1 9Low Voltage SwitchgearMetal enclosed480 V, 3-ph, 60 Hz 1 1 10Emergency Diesel GeneratorSized for emergency shutdown750 kW, 480 V, 3-ph, 60 Hz 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1DCS - Main ControlMonitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W)Operator stations/printers and engineering stations/printers 1 0 2DCS - ProcessorMicroprocessor with redundant input/outputN/A 1 0 3DCS - Data HighwayFiber opticFully redundant, 25% spare 1 0 Cost and Performance Baseline for Fossil Energy Plants 222 3.3.11 The cost estimating methodology was described previously in Section 2.6. Case 4 - Cost Estimating Results 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 owner's costs. Exhibit 3-71 shows the initial and annual O&M costs.

The estimated TOC of the CoP gasifier with CO 2 capture is $

3,466/kW. Process contingency represents 3.5 percent of the TOC and project contingency represents 11.1 percent. The COE, including CO 2 TS&M costs of 5.6 mills/kWh, is 1 10.4 mills/kWh.

Cost and Performance Baseline for Fossil Energy Plants 223 Exhibit 3-69 Case 4 Total Plant Cost Summary Client: USDOE/NETLReport Date:2010-Jan-14Project: Bituminous Baseline StudyCase: Case 4 - ConocoPhillips 500MW IGCC w/ CO2Plant Size: 513.6MW,netEstimate Type: ConceptualCost Base (Jun) 2007($x1000)AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING$14,229$2,644$11,035$0$0$27,908$2,533$0$6,088$36,529$71 2COAL & SORBENT PREP & FEED$24,241$4,431$14,646$0$0$43,318$3,889$0$9,441$56,648$110 3FEEDWATER & MISC. BOP SYSTEMS$10,074$7,882$10,144$0$0$28,101$2,651$0$7,106$37,858$74 4GASIFIER & ACCESSORIES4.1Gasifier, Syngas Cooler & Auxiliaries (E-GAS)$114,050$0$63,266$0$0$177,316$16,295$24,521$33,478$251,609$4904.2Syngas Coolingw/4.1$0w/ 4.1$0$0$0$0$0$0$0$04.3ASU/Oxidant Compression$186,025$0w/equip.$0$0$186,025$18,031$0$20,406$224,461$4374.4-4.9Other Gasification Equipment$24,056$10,168$14,678$0$0$48,902$4,688$0$11,449$65,038$127SUBTOTAL 4$324,131$10,168$77,944$0$0$412,242$39,014$24,521$65,332$541,109$1,054 5AGAS CLEANUP & PIPING$89,500$3,812$77,878$0$0$171,190$16,546$26,077$42,894$256,707$500 5BCO2 COMPRESSION$18,339$0$11,242$0$0$29,581$2,849$0$6,486$38,916$76 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine Generator$92,027$0$6,583$0$0$98,609$9,348$9,861$11,782$129,600$2526.2-6.9Combustion Turbine Other

$0$806$892$0$0$1,699$159$0$557$2,415$5SUBTOTAL 6$92,027$806$7,475$0$0$100,308$9,507$9,861$12,339$132,015$257 7HRSG, DUCTING & STACK7.1Heat Recovery Steam Generator$33,631$0$4,782$0$0$38,414$3,652$0$4,207$46,272$907.2-7.9SCR System, Ductwork and Stack$3,377$2,407$3,153$0$0$8,938$829$0$1,589$11,355$22SUBTOTAL 7$37,008$2,407$7,935$0$0$47,351$4,481$0$5,796$57,628$112 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$26,321$0$4,278$0$0$30,600$2,935$0$3,353$36,888$728.2-8.9Turbine Plant Auxiliaries and Steam Piping$9,952$903$6,987$0$0$17,843$1,623$0$3,868$23,333$45SUBTOTAL 8$36,274$903$11,266$0$0$48,442$4,558$0$7,221$60,222$117 9COOLING WATER SYSTEM$10,387$9,859$8,527$0$0$28,773$2,673$0$6,406$37,852$74 10ASH/SPENT SORBENT HANDLING SYS$19,651$1,481$9,750$0$0$30,882$2,963$0$3,691$37,536$73 11ACCESSORY ELECTRIC PLANT$31,778$12,519$24,431$0$0$68,728$5,909$0$14,164$88,801$173 12INSTRUMENTATION & CONTROL$11,157$2,052$7,188$0$0$20,397$1,849$1,020$3,877$27,142$53 13IMPROVEMENTS TO SITE$3,416$2,014$8,429$0$0$13,859$1,368$0$4,568$19,796$39 14BUILDINGS & 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$2,817TOTAL PLANT COST

SUMMARY

Cost and Performance Baseline for Fossil Energy Plants 224 Exhibit 3-70 Case 4 Total Plant Cost Details AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING1.1Coal Receive & Unload$3,737$0$1,826$0$0$5,563$498$0$1,212$7,273$141.2Coal Stackout & Reclaim$4,829$0$1,171$0$0$5,999$526$0$1,305$7,830$151.3Coal Conveyors & Yd Crush$4,489$0$1,158$0$0$5,648$496$0$1,229$7,372$141.4Other Coal Handling$1,175$0$268$0$0$1,443$126$0$314$1,883$41.5Sorbent Receive & Unload

$0$0$0$0$0$0$0$0$0$0$01.6Sorbent Stackout & Reclaim

$0$0$0$0$0$0$0$0$0$0$01.7Sorbent Conveyors

$0$0$0$0$0$0$0$0$0$0$01.8Other Sorbent Handling

$0$0$0$0$0$0$0$0$0$0$01.9Coal & Sorbent Hnd.Foundations

$0$2,644$6,612$0$0$9,256$887$0$2,029$12,172$24SUBTOTAL 1.$14,229$2,644$11,035$0$0$27,908$2,533$0$6,088$36,529$71 2COAL & SORBENT PREP & FEED2.1Coal Crushing & Drying (incl. w/2.3)

$0$0$0$0$0$0$0$0$0$0$02.2Prepared Coal Storage & Feed$1,596$382$250$0$0$2,228$190$0$484$2,902$62.3Slurry Prep & Feed$21,768$0$9,681$0$0$31,449$2,808$0$6,851$41,108$802.4Misc.Coal Prep & Feed

$877$639$1,914$0$0$3,430$315$0$749$4,495$92.5Sorbent Prep Equipment

$0$0$0$0$0$0$0$0$0$0$02.6Sorbent Storage & Feed

$0$0$0$0$0$0$0$0$0$0$02.7Sorbent Injection System

$0$0$0$0$0$0$0$0$0$0$02.8Booster Air Supply System

$0$0$0$0$0$0$0$0$0$0$02.9Coal & Sorbent Feed Foundation

$0$3,411$2,800$0$0$6,211$575$0$1,357$8,143$16SUBTOTAL 2.$24,241$4,431$14,646$0$0$43,318$3,889$0$9,441$56,648$110 3FEEDWATER & MISC. BOP SYSTEMS3.1Feedwater System$2,834$4,868$2,570$0$0$10,272$952$0$2,245$13,468$263.2Water Makeup & Pretreating

$709$74$396$0$0$1,179$112$0$387$1,679$33.3Other Feedwater Subsystems$1,551$524$472$0$0$2,546$229$0$555$3,330$63.4Service Water Systems

$406$835$2,899$0$0$4,140$404$0$1,363$5,907$123.5Other Boiler Plant Systems$2,177$843$2,090$0$0$5,111$485$0$1,119$6,714$133.6FO Supply Sys & Nat Gas

$313$591$551$0$0$1,456$140$0$319$1,915$43.7Waste Treatment Equipment

$991$0$604$0$0$1,595$155$0$525$2,276$43.8Misc. Power Plant Equipment$1,094$146$562$0$0$1,802$174$0$593$2,569$5SUBTOTAL 3.$10,074$7,882$10,144$0$0$28,101$2,651$0$7,106$37,858$74 4GASIFIER & ACCESSORIES4.1Gasifier, Syngas Cooler & Auxiliaries (E-GAS)$114,050$0$63,266$0$0$177,316$16,295$24,521$33,478$251,609$4904.2Syngas Coolingw/4.1$0w/ 4.1$0$0$0$0$0$0$0$04.3ASU/Oxidant Compression$186,025$0w/equip.$0$0$186,025$18,031$0$20,406$224,461$4374.4LT Heat Recovery & FG Saturation$24,056$0$9,145$0$0$33,201$3,240$0$7,288$43,730$854.5Misc. Gasification Equipmentw/4.1&4.2$0w/4.1&4.2$0$0$0$0$0$0$0$04.6Flare Stack System

$0$1,643$669$0$0$2,312$222$0$507$3,041$64.8Major Component Riggingw/4.1&4.2$0w/4.1&4.2$0$0$0$0$0$0$0$04.9Gasification Foundations

$0$8,525$4,864$0$0$13,389$1,226$0$3,654$18,268$36SUBTOTAL 4.$324,131$10,168$77,944$0$0$412,242$39,014$24,521$65,332$541,109$1,054 Cost and Performance Baseline for Fossil Energy Plants 225 Exhibit 3-70 Case 4 Total Plant Cost Details (Continued) AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 5AGAS CLEANUP & PIPING5A.1Double Stage Selexol$70,224$0$59,586$0$0$129,810$12,554$25,962$33,665$201,991$3935A.2Elemental Sulfur Plant$10,291$2,051$13,278$0$0$25,620$2,489$0$5,622$33,730$665A.3Mercury Removal$1,302$0$991$0$0$2,294$222$115$526$3,156$65A.4Shift Reactors$7,138$0$2,873$0$0$10,011$960$0$2,194$13,164$265A.5Particulate Removalw/4.1$0w/4.1$0$0$0$0$0$0$0$05A.6Blowback Gas Systems

$545$306$172$0$0$1,023$98$0$224$1,345$35A.7Fuel Gas Piping

$0$723$506$0$0$1,229$114$0$269$1,612$35A.9HGCU Foundations

$0$732$472$0$0$1,204$111$0$394$1,709$3SUBTOTAL 5A.$89,500$3,812$77,878$0$0$171,190$16,546$26,077$42,894$256,707$500 5BCO2 COMPRESSION5B.1CO2 Removal System

$0$0$0$0$0$0$0$0$0$0$05B.2CO2 Compression & Drying$18,339$0$11,242$0$0$29,581$2,849$0$6,486$38,916$76SUBTOTAL 5B.$18,339$0$11,242$0$0$29,581$2,849$0$6,486$38,916$76 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine Generator$92,027$0$6,583$0$0$98,609$9,348$9,861$11,782$129,600$2526.2Open$0$0$0$0$0$0$0$0$0$0$06.3Compressed Air Piping

$0$0$0$0$0$0$0$0$0$0$06.9Combustion Turbine Foundations

$0$806$892$0$0$1,699$159$0$557$2,415$5SUBTOTAL 6.$92,027$806$7,475$0$0$100,308$9,507$9,861$12,339$132,015$257 7HRSG, DUCTING & STACK7.1Heat Recovery Steam Generator$33,631$0$4,782$0$0$38,414$3,652$0$4,207$46,272$907.2Open$0$0$0$0$0$0$0$0$0$0$07.3Ductwork$0$1,731$1,235$0$0$2,966$260$0$645$3,871$87.4Stack$3,377$0$1,269$0$0$4,645$445$0$509$5,599$117.9HRSG,Duct & Stack Foundations

$0$677$650$0$0$1,326$123$0$435$1,885$4SUBTOTAL 7.$37,008$2,407$7,935$0$0$47,351$4,481$0$5,796$57,628$112 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$26,321$0$4,278$0$0$30,600$2,935$0$3,353$36,888$728.2Turbine Plant Auxiliaries

$182$0$417$0$0$599$59$0$66$724$18.3Condenser & Auxiliaries$4,762$0$1,521$0$0$6,284$601$0$688$7,573$158.4Steam Piping$5,008$0$3,523$0$0$8,531$733$0$2,316$11,580$238.9TG Foundations

$0$903$1,526$0$0$2,429$230$0$798$3,457$7SUBTOTAL 8.$36,274$903$11,266$0$0$48,442$4,558$0$7,221$60,222$117 Cost and Performance Baseline for Fossil Energy Plants 226 Exhibit 3-70 Case 4 Total Plant Cost Details (Continued) AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 9COOLING WATER SYSTEM9.1Cooling Towers$7,196$0$1,401$0$0$8,597$819$0$1,412$10,828$219.2Circulating Water Pumps$1,877$0$136$0$0$2,013$170$0$327$2,510$59.3Circ.Water System Auxiliaries

$157$0$22$0$0$179$17$0$29$226$09.4Circ.Water Piping

$0$6,545$1,697$0$0$8,241$745$0$1,797$10,783$219.5Make-up Water System

$384$0$549$0$0$933$90$0$205$1,227$29.6Component Cooling Water Sys

$773$924$657$0$0$2,354$221$0$515$3,090$69.9Circ.Water System Foundations

$0$2,391$4,064$0$0$6,455$612$0$2,120$9,187$18SUBTOTAL 9.$10,387$9,859$8,527$0$0$28,773$2,673$0$6,406$37,852$74 10ASH/SPENT SORBENT HANDLING SYS10.1Slag Dewatering & Cooling$17,164$0$8,464$0$0$25,628$2,462$0$2,809$30,900$6010.2Gasifier Ash Depressurizationw/10.1w/10.1w/10.1$0$0$0$0$0$0$0$010.3Cleanup Ash Depressurization w/10.1w/10.1w/10.1$0$0$0$0$0$0$0$010.4High Temperature Ash Piping

$0$0$0$0$0$0$0$0$0$0$010.5Other Ash Recovery Equipment

$0$0$0$0$0$0$0$0$0$0$010.6Ash Storage Silos

$564$0$613$0$0$1,177$114$0$194$1,485$310.7Ash Transport & Feed Equipment

$756$0$182$0$0$938$88$0$154$1,180$210.8Misc. Ash Handling Equipment$1,168$1,431$427$0$0$3,026$288$0$497$3,811$710.9Ash/Spent Sorbent Foundation

$0$50$63$0$0$112$11$0$37$160$0SUBTOTAL 10.$19,651$1,481$9,750$0$0$30,882$2,963$0$3,691$37,536$73 11ACCESSORY ELECTRIC PLANT11.1Generator Equipment

$924$0$914$0$0$1,839$176$0$201$2,216$411.2Station Service Equipment$4,676$0$421$0$0$5,097$470$0$557$6,124$1211.3Switchgear & Motor Control $8,644$0$1,572$0$0$10,216$948$0$1,675$12,838$2511.4Conduit & Cable Tray

$0$4,015$13,247$0$0$17,262$1,670$0$4,733$23,665$4611.5Wire & Cable

$0$7,672$5,041$0$0$12,713$924$0$3,409$17,046$3311.6Protective Equipment

$0$680$2,474$0$0$3,153$308$0$519$3,980$811.7Standby Equipment

$229$0$223$0$0$452$43$0$74$570$111.8Main Power Transformers$17,305$0$140$0$0$17,445$1,319$0$2,815$21,579$4211.9Electrical Foundations

$0$152$398$0$0$550$53$0$181$784$2SUBTOTAL 11.$31,778$12,519$24,431$0$0$68,728$5,909$0$14,164$88,801$173 12INSTRUMENTATION & CONTROL12.1IGCC Control Equipmentw/4.1$0w/4.1$0$0$0$0$0$0$0$012.2Combustion Turbine Controlw/6.1$0w/6.1$0$0$0$0$0$0$0$012.3Steam Turbine Controlw/8.1$0w/8.1$0$0$0$0$0$0$0$012.4Other Major Component Control$1,101$0$735$0$0$1,837$174$92$315$2,418$512.5Signal Processing Equipmentw/12.7$0w/12.7$0$0$0$0$0$0$0$012.6Control Boards,Panels & Racks

$253$0$162$0$0$415$39$21$95$571$112.7Computer & Accessories$5,875$0$188$0$0$6,063$557$303$692$7,615$1512.8Instrument Wiring & Tubing

$0$2,052$4,196$0$0$6,248$530$312$1,773$8,863$1712.9Other I & C Equipment$3,927$0$1,907$0$0$5,834$549$292$1,001$7,676$15SUBTOTAL 12.$11,157$2,052$7,188$0$0$20,397$1,849$1,020$3,877$27,142$53 Cost and Performance Baseline for Fossil Energy Plants 227 Exhibit 3-70 Case 4 Total Plant Cost Details (Continued) AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 13IMPROVEMENTS TO SITE13.1Site Preparation

$0$107$2,291$0$0$2,398$238$0$791$3,427$713.2Site Improvements

$0$1,906$2,533$0$0$4,440$438$0$1,463$6,341$1213.3Site Facilities$3,416$0$3,605$0$0$7,021$692$0$2,314$10,027$20SUBTOTAL 13.$3,416$2,014$8,429$0$0$13,859$1,368$0$4,568$19,796$39 14BUILDINGS & STRUCTURES14.1Combustion Turbine Area

$0$265$150$0$0$414$36$0$90$541$114.2Steam Turbine Building

$0$2,246$3,200$0$0$5,445$501$0$892$6,838$1314.3Administration Building

$0$870$631$0$0$1,501$134$0$245$1,880$414.4Circulation Water Pumphouse

$0$163$86$0$0$250$22$0$41$312$114.5Water Treatment Buildings

$0$592$578$0$0$1,171$106$0$191$1,468$314.6Machine Shop

$0$445$305$0$0$750$67$0$122$939$214.7Warehouse

$0$719$464$0$0$1,183$105$0$193$1,481$314.8Other Buildings & Structures

$0$431$335$0$0$766$68$0$167$1,001$214.9Waste Treating Building & Str.

$0$963$1,840$0$0$2,802$261$0$613$3,676$7SUBTOTAL 14.

$0$6,693$7,589$0$0$14,282$1,300$0$2,555$18,136$35TOTAL COST$722,212$67,672$295,478$0$0$1,085,363$102,090$61,479$197,964$1,446,895$2,817Owner's CostsPreproduction Costs6 Months All Labor$13,491$261 Month Maintenance Materials$2,999$61 Month Non-fuel Consumables

$385$11 Month Waste Disposal

$295$125% of 1 Months Fuel Cost at 100% CF$1,687$32% of TPC$28,938$56Total$47,793$93Inventory Capital60 day supply of fuel and consumables at 100% CF$13,995$270.5% of TPC (spare parts)$7,234$14Total$21,230$41Initial Cost for Catalyst and Chemicals$7,371$14Land$900$2Other Owner's Costs$217,034$423Financing Costs$39,066$76Total Overnight Costs (TOC)$1,780,290$3,466TASC Multiplier(IOU, high-risk, 35 year)1.140Total As-Spent Cost (TASC)$2,029,531$3,952 Cost and Performance Baseline for Fossil Energy Plants 228 Exhibit 3-71 Case 4 Initial and Annual Operating and Maintenance Costs INITIAL & ANNUAL O&M EXPENSESCost Base (Jun):

2007Case 4 - ConocoPhillips 500MW IGCC w/ CO2Heat Rate-net (Btu/kWh):10,998 MWe-net: 514Capacity Factor (%):

80OPERATING & MAINTENANCE LABOROperating Labor Operating Labor Rate(base):34.65$/hour Operating Labor Burden:30.00% of base Labor O-H Charge Rate:25.00% of laborTotal Operating Labor Requirements(O.J.)per Shift:1 unit/mod. Plant Skilled Operator2.02.0 Operator10.010.0 Foreman1.01.0 Lab Tech's, etc.3.03.0 TOTAL-O.J.'s16.016.0Annual CostAnnual Unit Cost

$$/kW-netAnnual Operating Labor Cost$6,313,507$12.292Maintenance Labor Cost$15,271,560$29.734Administrative & Support Labor$5,396,267$10.507Property Taxes and Insurance$28,937,909$56.342TOTAL FIXED OPERATING COSTS$55,919,243$108.875VARIABLE OPERATING COSTS$/kWh-netMaintenance Material Cost$28,787,121$0.00800ConsumablesConsumptionUnit Initial Fill Initial Fill /Day Cost Cost Water(/1000 gallons) 04,1161.08$0$1,300,111$0.00036ChemicalsMU & WT Chem. (lbs) 024,5230.17$0$1,239,310$0.00034Carbon (Mercury Removal) (lb)104,394 1431.05$109,631$43,852$0.00001COS Catalyst (m3) 0 02,397.36$0$0$0.00000Water Gas Shift Catalyst (ft3)6,4844.44498.83$3,234,413$646,883$0.00018Selexol Solution (gal)300,533 9813.40$4,026,613$384,543$0.00011SCR Catalyst (m3) 0 00.00$0$0$0.00000Ammonia (19% NH3) (ton) 0 00.00$0$0$0.00000Claus Catalyst (ft3)w/equip.2.00131.27$0$76,827$0.00002Subtotal Chemicals$7,370,657$2,391,415$0.00066OtherSupplemental Fuel (MBtu) 0 00.00$0$0$0.00000Gases, N2 etc. (/100scf) 0 00.00$0$0$0.00000L.P. Steam (/1000 pounds) 0 00.00$0$0$0.00000Subtotal Other

$0$0$0.00000Waste DisposalSpent Mercury Catalyst (lb.)

0 1430.42$0$17,416$0.00000Flyash (ton) 0 00.00$0$0$0.00000Slag (ton) 0 59316.23$0$2,809,802$0.00078Subtotal Waste Disposal

$0$2,827,218$0.00079By-products & EmissionsSulfur (ton) 0 1450.00$0$0$0.00000Subtotal By-products

$0$0$0.00000TOTAL VARIABLE OPERATING COSTS$7,370,657$35,305,866$0.00981Fuel (ton) 05,81138.18$0$64,786,772$0.01800 Cost and Performance Baseline for Fossil Energy Plants 229 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 SG S reactors, CO 2 absorption/regeneration

, and compression/transport systems. There are no provisions for CO 2 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 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.

Gasifier Background 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 Shell's 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 Shell's 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 syste m 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, Cost and Performance Baseline for Fossil Energy Plants 230 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 Nm 3/h r and three of the same size in construction. Another three ranging from 150,000

-250,000 Nm 3/h r are also in construction

[61Distinguishing 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.

]. 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 Nm 3/h r (5.6 million scf/h r) with an energy content of about 1,792 MMkJ/h r (1,700 MMBtu/h r) (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

. 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 H 2S/CO 2 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.

Cost and Performance Baseline for Fossil Energy Plants 231 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 In this section the overall Shell gasification process for Case 5 is described. The system description follows the BFD in Process Description 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 receiving and handling is common to all cases and was covered in Section Coal Preparation and Feed Systems 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.

Cost and Performance Baseline for Fossil Energy Plants 232 Exhibit 3-72 Case 5 Block Flow Diagram, Shell IGCC without CO 2 Capture Cost and Performance Baseline for Fossil Energy Plants 233 Exhibit 3-73 Case 5 Stream Table, Shell IGCC without CO 2 Capture 1 2 3 4 5 6 7 8 9 10 11 12 13 14V-L Mole Fraction Ar0.00920.02620.03180.00230.03180.00000.00230.01000.00000.00000.00000.00950.00950.0096 CH 40.00000.00000.00000.00000.00000.00000.00000.00060.00000.00000.00000.00060.00060.0006 CO0.00000.00000.00000.00000.00000.00000.00000.59800.00000.00000.00000.57970.57970.5833 CO 20.00030.00920.00000.00000.00000.00000.00000.01580.00000.00000.00000.01430.01430.0151COS0.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00070.00070.0000 H 20.00000.00000.00000.00000.00000.00000.00000.31420.00000.80900.00000.30060.30060.3024 H 2 O0.00990.23780.00000.00030.00001.00000.00040.00130.00000.09350.00000.02520.02520.0194 HCl0.00000.00000.00000.00000.00000.00000.00000.00000.00000.00300.00000.00090.00090.0001 H 2 S0.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00810.00810.0089 N 20.77320.50180.01780.99190.01780.00000.99190.06010.00000.01630.00000.05670.05670.0570 NH 30.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00360.00360.0036 O 20.20740.22510.95040.00540.95040.00000.00540.00000.00000.07820.00000.00000.00000.0000 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000Total1.00001.00001.00001.00001.00001.00001.00001.00000.00001.00000.00001.00001.00001.0000V-L Flowrate (kgmol/hr)18,364 812 8816,3754,5911,061 882 252 0 0 025,09617,56717,460V-L Flowrate (kg/hr)529,93521,9172,828459,480147,75219,11124,7475,088 0 0 0509,993356,995354,790Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0198,059185,22219,837 0 0 0Temperature (°C) 15 21 32 93 32 343 32 45 15 161,4271,079 191 177Pressure (MPa, abs)0.100.110.862.650.865.105.413.650.105.794.244.244.033.90Enthalpy (kJ/kg)

A30.2337.3226.6792.5226.673,063.9721.2260.75---0.000.000.00325.96297.28Density (kg/m 3)1.21.611.024.411.020.160.527.8---16.5---7.621.020.9V-L Molecular Weight28.85726.99232.18128.06032.18118.01528.06020.195---------20.32220.32220.320V-L Flowrate (lbmol/hr)40,4861,790 19436,10110,1222,3391,944 555 0 0 055,32838,72938,493V-L Flowrate (lb/hr)1,168,30748,3196,2361,012,980325,73842,13254,55711,218 0 0 01,124,342787,039782,178Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0436,646408,34543,732 0 0 0Temperature (°F) 59 70 90 199 90 650 90 112 59 602,6001,974 375 351Pressure (psia)14.716.4125.0384.0125.0740.0785.0530.014.7840.0615.0615.0585.0565.0Enthalpy (Btu/lb)

A13.016.011.539.811.51,317.39.126.1---140.1127.8Density (lb/ft 3)0.0760.1010.6871.5210.6871.2573.7741.734---1.029---0.4751.3101.303A - Reference conditions are 32.02 F & 0.089 PSIA Cost and Performance Baseline for Fossil Energy Plants 234 Exhibit 3-73 Case 5 Stream Table, Shell IGCC without CO 2 Capture (Continued) 15 16 17 18 19 20 21 22 23 24 25 26 27V-L Mole Fraction Ar0.00980.00980.01000.00790.00790.00040.00000.00580.00920.00920.00860.00860.0000 CH 40.00060.00060.00060.00050.00050.00000.00000.00000.00000.00000.00000.00000.0000 CO0.59620.58450.59800.47410.47410.01670.00000.10340.00000.00000.00000.00000.0000 CO 20.01550.02570.01580.01250.01250.44600.00000.26130.00030.00030.07520.07520.0000COS0.00000.00000.00000.00000.00000.00000.00000.00060.00000.00000.00000.00000.0000 H 20.30910.30720.31420.24910.24910.00960.00000.04290.00000.00000.00000.00000.0000 H 2 O0.00140.00150.00130.20830.20830.00630.00000.42590.00990.00990.09060.09061.0000 HCl0.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 H 2 S0.00910.00890.00000.00000.00000.38720.00000.00160.00000.00000.00000.00000.0000 N 20.05830.06180.06010.04760.04760.13380.00000.15850.77320.77320.72100.72100.0000 NH 30.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 O 20.00000.00000.00000.00000.00000.00000.00000.00000.20740.20740.10460.10460.0000 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000Total1.00001.00001.00001.00001.00001.00000.00001.00001.00001.00001.00001.00001.0000V-L Flowrate (kgmol/hr)17,08117,42616,77121,15521,155 402 0 510110,2534,410137,428137,42839,521V-L Flowrate (kg/hr)347,994358,740338,688417,666417,66614,964 013,7233,181,557127,2623,962,1543,962,154711,987Solids Flowrate (kg/hr) 0 0 0 0 0 04,959 0 0 0 0 0 0Temperature (°C) 35 34 45 161 193 45 178 232 15 432 587 132 559Pressure (MPa, abs)3.723.693.653.213.23.6540.4090.4060.1011.6190.1050.10512.512Enthalpy (kJ/kg)

A0.0044.2660.750.00762.913.883---1,007.13530.227463.785791.043280.1313,496.259Density (kg/m 3)29.529.627.817.716.260.95,278.62.61.27.90.40.935.2V-L Molecular Weight20.37320.58720.19519.743 2037.190---26.92328.85728.85728.83128.83118.015V-L Flowrate (lbmol/hr)37,65738,41736,97446,63946,639 887 01,124243,0669,723302,978302,97887,130V-L Flowrate (lb/hr)767,195790,887746,680920,797920,79732,989 030,2537,014,133280,5658,735,0538,735,0531,569,662Solids Flowrate (lb/hr) 0 0 0 0 0 010,933 0 0 0 0 0 0Temperature (°F) 94 94 112 321 380 112 353 450 59 8101,088 2701,038Pressure (psia)540.0535.0530.0465.0460.0530.059.358.914.7234.915.215.21,814.7Enthalpy (Btu/lb)

A19.026.1328.06.0---433.013.0199.4340.1120.41,503.1Density (lb/ft 3)1.8441.8501.7341.103 13.805329.5350.1630.0760.4950.0260.0562.200 Cost and Performance Baseline for Fossil Energy Plants 235 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.

Gasifier The gasifier includes a refractory

-lined water wall that is also protected by molten slag that solidifies on the cooled walls.

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 maintain s the syngas temperature at 1 ,427°C (2 ,600°F). The product gas from the gasifier is cooled to approximately 1,093 C (2,000F) 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 (2,000F) to 316C (600F), and produce HP steam for use in the steam cycle.

Raw Gas Cooling/Particulate Removal 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

. 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. Quench Gas Compressor The raw syngas exiting the final raw gas cooler at 191C (3 75F) (stream 13) then enters the scrubber for removal of chlorides, SO 2, NH 3 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.

Syngas Scrubber/Sour Water Stripper The sour water stripper removes NH 3, SO 2, 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 Cost and Performance Baseline for Fossil Energy Plants 236 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. H 2S and COS are at significant concentrations, requiring removal for the power plant to achieve the low design level of SO 2 emissions. H 2S is removed in an AGR process; however, because COS is not readily removable, it is first catalytically converted to H 2S in a COS hydrolysis unit.

COS Hydrolysis, Mercury Removal and AGR Following the water scrubber, the gas is reheated to 177 C (350F) and fed to the COS hydrolysis reactor. The COS in the sour gas is hydrolyzed with steam over a catalyst bed t o H 2S, which is more easily removed by the AGR solvent. Before the raw fuel gas can be treated in the AGR process (stream 1 4), it must be cooled to about 35 C (95F). During this cooling through a series of heat exchangers, part of the water vapor condenses. This water, which contains some NH 3, 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 H 2S, COS, CO 2, and small amounts of H 2 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 H 2S 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 H 2 and CO, at 0.8 MPa (118 psia) and 38C (101F). 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 H 2S, COS, and CO 2 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 CO 2 along with the H 2S and COS. The acid gas fed to the SRU contains 39 vol% H 2S and 45 vol% CO 2. The CO 2 passes through the SRU, the TGTU and ultimately is vented through the coal dryer. Since the amount of CO 2 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.

Cost and Performance Baseline for Fossil Energy Plants 237 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 H 2S in the feed to SO 2, then reacting the H 2S and SO 2 to sulfur and water. The use of Claus technology results in an overall sulfur recovery exceeding 99 percent.

Claus Unit 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 (13 1 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/h r (26,435 lb/h r) 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.

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/10 38°F) steam cycle.

Power Block The ASU is designed to produce a nominal output of 3, 614 tonnes/day (3,984 TPD) of 95 mol% O 2 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.

Air Separation Unit (ASU)

Balance of plant items were covered in Sections Balance of Plant 3.1.9 , 3.1.10 and 3.1.11. 3.4.3 System assumptions for Cases 5 and 6, Shell IGCC with and without CO 2 capture, are compiled in Key System Assumptions Exhibit 3-74.

Cost and Performance Baseline for Fossil Energy Plants 238 The balance of plant assumptions are common to all cases and were presented previously in Balance of Plant

- Cases 5 and 6 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) O 2:Coal Ratio, kg O 2/kg dry coal 0.84 0.84 Carbon Conversion, %

99.5 99.5 Syngas HHV at Gasifier Outlet, kJ/Nm 3 (Btu/scf) 10, 841 (29 1) 10, 849 (2 9 1) Steam Cycle, MPa/°C/°C (psig/ F/ F) 12.4/559/5 59 (1800/10 38/10 38) 12.4/53 4/53 4 (1800/993/993) Condenser Pressure, mm Hg (in Hg) 51 (2.0) 51 (2.0) CT 2x Advanced F Class (232 MW output each) 2x Advanced F Class (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 H 2S Separation Sulfinol-M Selexol 1 st Stage Sulfur Removal, %

99.7 99.9 Sulfur Recovery Claus Plant with Tail Gas Treatment / Elemental Sulfur Claus Plant with Tail Gas Treatment / Elemental Sulfur Particulate Control Cyclone, Candle Filter, Scrubber, and AGR Absorber Cyclone, Candle Filter, Scrubber, and AGR Absorber Mercury Control Carbon Bed Carbon Bed NOx Control MNQC (LNB), N 2 Dilution, Humidification and steam dilution MNQC (LNB), N 2 Dilution and Humidification CO 2 Separation N/A Selexol 2nd Stage Overall CO2 Capture N/A 90.1% CO 2 Sequestration N/A Off-site Saline Formation

Cost and Performance Baseline for Fossil Energy Plants 239 3.4.4 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.

Sparing Philosophy 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 The plant produces a net output of 6 2 9 MWe at a net plant efficiency of 4 2.1 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

[Case 5 Performance Results 62Overall performance for the entire plant is summarized in

]. 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.

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.

Cost and Performance Baseline for Fossil Energy Plants 240 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 27 3 , 0 00 TOTAL POWER, kWe 73 7 , 0 00 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 Plant 2 3,000 Transformer Losses 2,520 TOTAL AUXILIARIES, kWe 1 08 , 02 0 NET POWER, kWe 62 8 , 98 0 Net Plant Efficiency, % (HHV) 4 2.1 Net Plant Heat Rate, kJ/kWh (Btu/kWh) 8,545 (8,099)

CONDENSER COOLING DUTY 10 6 kJ/h r (10 6 Btu/h r) 1,393 (1,320)

CONSUMABLES As-Received Coal Feed, kg/h r (lb/h r) 198,059 (436,646)

Thermal Input 1, kWt 1,492,878 Raw Water Withdrawal, m 3/min (gpm) 15.7 (4,142)

Raw Water Consumption , m 3/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

Cost and Performance Baseline for Fossil Energy Plants 241 The environmental targets for emissions of Hg, NOx, SO 2 , and PM were presented in Section 2.4. A summary of the plant air emissions for Case 5 is presented in Environmental Performance Exhibit 3-76. Exhibit 3-76 Case 5 Air Emissions kg/GJ (lb/10 6 Btu) Tonne/year (ton/year) 80% capacity factor kg/MWh (lb/MWh) SO 2 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) CO 2 84.7 (196.9) 3,188,643 (3,514,877) 617 (1,361)

CO 2 1 723 (1,595) 1 CO 2 emissions based on net power instead of gross power The low level of SO 2 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 H 2 S-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 SO 2 emissions in Exhibit 3-76 include both the stack emissions and the coal dryer emissions.

NO x emissions are limited by the use of nitrogen dilution, humidification and steam dilution to 15 ppmvd (as NO 2 @ 15 percent O 2). 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 NO x 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.

CO 2 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 CO 2 in the wastewater blowdown stream, and as CO 2 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.

Cost and Performance Baseline for Fossil Energy Plants 242 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 (CO 2) 508 (1,120)

Stack Gas 124,177 (273,764)

ASU Vent 89 (197) CO 2 Product 0 (0) Dryer Stack Gas 1,863 (4,106)

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) CO 2 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.

Cost and Performance Baseline for Fossil Energy Plants 243 Exhibit 3-79 Case 5 Water Balance Water Use Water Demand, m 3/min (gpm) Internal Recycle, m 3/min (gpm) Raw Water Withdrawal, m 3/min (gpm) Process Water Discharge, m 3/min (gpm) Raw Water Consumption, m 3/min (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 Gasifier Steam Shift Steam GT Steam Dilution BFW Makeup 1.1 (282) 0.3 (84) 0.5 (135) 0.2 (62) 0.0 (0) 1.1 (282) 0.3 (84) 0.5 (135) 0.2 (62) 0.0 (0) 1.1 (282) Cooling Tower BFW Blowdown SWS Blowdown SWS Excess Water Humidifier Tower Blowdown 13.2 (3,494) 0.25 (67) 0.23 (62) 0.02 (4) 0.0 (0) 13.0 (3,427)

-0.23 (-62) -0.02 (-4) 3.0 (786) 10.0 (2,641)

Total 16.1 (4,254) 0.4 (112) 15.7 (4,142) 3.0 (786) 12.7 (3,356)

Heat and mass balance diagrams are shown for the following subsystems in Heat and Mass Balance Diagrams 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.

Cost and Performance Baseline for Fossil Energy Plants 244 This page intentionally left blank

Cost and Performance Baseline for Fossil Energy Plants 245 Exhibit 3-80 Case 5 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic N OTES: DOE/NETL D UAL T RAIN IGCC P LANT C ASE 5 H EAT AND M ATERIAL F LOW D IAGRAM B ITUMINOUS BASELINE S TUDY C ASE 5 S HELL G ASIFIER ASU , G ASIFICATION , AND G AS C OOLING DWG. NO.BB-HMB-CS-5-PG-1 P LANT P ERFORMANCE S UMMARY L EGEND Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas P AGES 1 OF 3 Ambient Air Intercooled Air Compressor Elevated Pressure ASU Intercooled Nitrogen Compressor Intercooled Oxygen Compressor Milled Coal Sour Gas Sour Water ASU VENT Water Steam Slag Removal Slag G ROSS P LANT P OWER: 737 MW E A UXILIARY L OAD: 108 MW E N ET P LANT P OWER: 629 MW E N ET P LANT E FFICIENCY , HHV: 42.1%N ET P LANT H EAT R ATE: 8 , 099 BTU/KW E Dry Coal Coal Feeding Steam Air from GT Compressor Candle Filter Cyclone Blowdown to Flash Tank BFW from HRSG Saturated Steam to HRSG N 2 to GT Combustor Boost Compressor Recycle Compressor Raw Syngas to Scrubber Steam Drum 220.0 T 224.9 P 50.9 H 393.5 T 625.0 P 146.7 H To Claus Plant 9 10 1 3 4 7 6 11 13 2 1 , 168 , 307 W 59.0 T 14.7 P 48 , 319 W 69.5 T 16.4 P 937 , 042 W 90.0 T 56.4 P 14.2 H 130 , 495 W 50.0 T 182.0 P 2.9 H 6 , 236 W 90.0 T 125.0 P 11.5 H 325 , 738 W 90.0 T 125.0 P 11.5 H 325 , 738 W 241.2 T 940.0 P 40.8 H 54 , 557 W 376.3 T 785.0 P 436 , 646 W 59.0 T 14.7 P 408 , 345 W 60.0 T 840.0 P 1 , 526.1 H 43 , 732 W 2 , 600.0 T 615.0 P 1 , 124 , 342 W 1 , 974.4 T 615.0 P 750.2 H 787 , 039 W 375.0 T 585.0 P 140.1 H 280 , 565 W 809.8 T 234.9 P 199.4 H P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB/HR H E NTHALPY , B TU/L B MW E P OWER , M EGAWATTS E LECTRICAL 1 , 012 , 980 W 389.0 T 384.0 P 88.2 H 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA 5 42 , 132 W 650.0 T 740.0 P 1 , 317.3 H Coal Drying Incinerator Syngas Slip Stream Incinerator Air Flue Gas/Combustion Products Incinerator Exhaust 11 , 218 W 112.2 T 530.0 P 26.1 H 53 , 179 W 59.0 T 14.7 P 92 , 698 W 290.0 T 14.4 P 12 8 Raw Gas Cooler 199.0 T 384.0 P 39.8 H 1 , 124 , 342 W 600.0 T 595.0 P 221.1 H 337 , 303 W 375.0 T 585.0 P 140.1 H Syngas Cooler Duct Cooler Steam Generation Shell Gasifier Cost and Performance Baseline for Fossil Energy Plants 246 Exhibit 3-81 Case 5 Syngas Cleanup Heat and Mass Balance Schematic N OTES: DOE/NETL D UAL T RAIN IGCC P LANT C ASE 5 H EAT AND M ATERIAL F LOW D IAGRAM B ITUMINOUS BASELINE S TUDY C ASE 5 S HELL G ASIFIER G AS C LEANUP S YSTEM P LANT P ERFORMANCE S UMMARY L EGEND Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas Mercury Removal Knock Out Drum Raw Syngas Sour Drum To Water Treatment Makeup Water Claus Plant Tail Gas Furnace Catalytic Reactor Beds Sulfur COS Hydrolysis Sour Water Reboiler Acid Gas Tailgas Carbon Dioxide Sour Gas Sulfur Hydrogen DWG. NO.BB-HMB-CS-5-PG-2 P AGES 2 OF 3 Sour Stripper Clean Gas Acid Gas Syngas Scrubber G ROSS P LANT P OWER: 737 MW E A UXILIARY L OAD: 108 MW E N ET P LANT P OWER: 629 MW E N ET P LANT E FFICIENCY , HHV: 42.1%N ET P LANT H EAT R ATE: 8 , 099 BTU/KW E Water 13 AGR- Sulfinol 15 16 20 21 22 787 , 039 W 375.0 T 585.0 P 140.1 H 23 , 692 W 100.0 T 799.5 P 4.8 H 782 , 178 W 200.9 T 580.0 P 74.7 H 351.2 T 565.0 P 127.8 H 790 , 887 W 93.9 T 535.0 P 19.0 H Syngas Coolers HP BFW 746 , 680 W 112.2 T 530.0 P 26.1 H 10 , 933 W 353.2 T 59.3 P From ASU 11 , 669 W 90.0 T 125.0 P 11.5 H 1 , 962 W 141.5 T 65.0 P 75.9 H 30 , 253 W 450.0 T 58.9 P 32 , 989 W 112.2 T 530.0 P Knock Out Tailgas to AGR HP BFW 350.0 T 575.0 P 128.0 H 767 , 195 W 94.4 T 540.0 P 19.5 H P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB/HR H E NTHALPY , B TU/L B MW E P OWER , M EGAWATTS E LECTRICAL 6 , 561 W 118.9 T 56.8 P 45.2 H Treated Syngas 14 Slip Stream to Coal Dryer 17 Humidification 18 Humidified Fuel Gas 19 8 Tailgas Recycle Compressor Hydrogenation And Tail Gas Cooling 24 , 042 W 120.0 T 56.8 P Cost and Performance Baseline for Fossil Energy Plants 247 Exhibit 3-82 Case 5 Combined Cycle Power Generation Heat and Mass Balance Schematic N OTES: DOE/NETL D UAL T RAIN IGCC P LANT C ASE 5 H EAT AND M ATERIAL F LOW D IAGRAM B ITUMINOUS B ASELINE S TUDY C ASE 5 S HELL G ASIFIER P OWER B LOCK S YSTEM P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB/HR H E NTHALPY , B TU/L B MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Synthesis Gas HRSG HP Turbine IP Turbine Nitrogen Dilution Intake Ambient Air Steam Seal Regulator IP Extraction Steam to 250 PSIA Header Blowdown Flash To WWT Make-up Gland Steam Condenser Condensate to Gasification Island HP BFW to Raw Gas Coolers HP Saturated Steam to HRSG Superheater LP Turbine Stack Expander Compressor Humidified Fuel Gas Air to ASU Deaerator IP BFW Generator Generator Condensate Pump HP Pump Steam Turbine LP Pump Water Steam DWG. NO.BB-HMB-CS-5-PG-3 P AGES 3 OF 3 Advanced F

-Class Gas Turbine G ROSS P LANT P OWER: 737 MW E A UXILIARY L OAD: 108 MW E N ET P LANT P OWER: 629 MW E N ET P LANT E FFICIENCY , HHV: 42.1%N ET P LANT H EAT R ATE: 8 , 099 BTU/KW E Flue Gas/Combustion Products To Gasifier MP Flash Bottoms LP Flash Tops LP Process Header From Gasifier Island Preheating To Claus LP BFW IP Pump 23 24 4 19 25 26 27 7 , 014 , 133 W 59.0 T 14.7 P 280 , 565 W 809.8 T 234.9 P 920 , 797 W 380.0 T 460.0 P 328.0 H 1 , 012 , 980 W 385.0 T 389.0 P 8 , 735 , 053 W 1 , 088.0 T 15.2 P 340.1 H 1 , 569 , 662 W 1 , 038.0 T 1 , 814.7 P 1 , 503.1 H 103.2 T 120.0 P 71.5 H 34 , 923 W 585.0 T 2 , 000.7 P 592.9 H 12 , 478 W 298.0 T 65.0 P 1 , 178.6 H 1 , 395 , 354 W 537.3 T 65.0 P 1 , 300.5 H 8 , 735 , 053 W 269.6 T 15.2 P 120.4 H 1 , 548 , 142 W 235.0 T 105.0 P 203.3 H 140 , 851 W 59.0 T 14.7 P 27.1 H 1 , 604 , 593 W 278.8 T 2 , 250.7 P 251.9 H 1 , 548 , 142 W 101.1 T 1.0 P 69.1 H 1 , 400 W 657.5 T 65.0 P 1 , 359.7 H 1 , 400 W 212.0 T 14.7 P 179.9 H 26 , 045 W 893.6 T 280.0 P 1 , 470.5 H HOT WELL CONDENSER Steam Dilution 67 , 709 W 475.0 T 460.0 P 80 , 190 W 298.0 T 65.0 P 1 , 178.6 H 40 , 813 W 537.3 T 65.0 P 1 , 300.5 H Cost and Performance Baseline for Fossil Energy Plants 248 This page intentionally left blank

Cost and Performance Baseline for Fossil Energy Plants 249 Exhibit 3-83 Case 5 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total 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) CO 2 Cooling Tower Blowdown 22.1 (20.9) 22 (21) HRSG Flue Gas 1,110 (1,052) 1,110 (1,052)

Condenser 1,397 (1,324) 1,397 (1,324)

Non-Condenser Cooling Tower Loads*

215 (204) 215 (204) 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, CO 2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection) and extraction air cooler.

- Calculated by difference to close the energy balance

.

Cost and Performance Baseline for Fossil Energy Plants 250 3.4.6 Major equipment items for the Shell gasifier with no CO 2 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 Case 5 - Major Equipment List 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 No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Bottom Trestle Dumper and Receiving HoppersN/A181 tonne (200 ton) 2 0 2FeederBelt572 tonne/hr (630 tph) 2 0 3Conveyor No. 1Belt1,134 tonne/hr (1,250 tph) 1 0 4Transfer Tower No. 1EnclosedN/A 1 0 5Conveyor No. 2Belt1,134 tonne/hr (1,250 tph) 1 0 6As-Received Coal Sampling SystemTwo-stageN/A 1 0 7Stacker/ReclaimerTraveling, linear1,134 tonne/hr (1,250 tph) 1 0 8Reclaim HopperN/A45 tonne (50 ton) 2 1 9FeederVibratory163 tonne/hr (180 tph) 2 1 10Conveyor No. 3Belt w/ tripper327 tonne/hr (360 tph) 1 0 11Crusher TowerN/AN/A 1 0 12Coal Surge Bin w/ Vent FilterDual outlet163 tonne (180 ton) 2 0 13CrusherImpactor reduction8 cm x 0 - 3 cm x 0(3" x 0 1/4" x 0) 2 0 14As-Fired Coal Sampling SystemSwing hammerN/A 1 1 15Conveyor No. 4Belt w/tripper327 tonne/hr (360 tph) 1 0 16Transfer Tower No. 2EnclosedN/A 1 0 17Conveyor No. 5Belt w/ tripper327 tonne/hr (360 tph) 1 0 18Coal Silo w/ Vent Filter and Slide GatesField erected726 tonne (800 ton) 3 0 Cost and Performance Baseline for Fossil Energy Plants 251 ACCOUNT 2 COAL PREPARATION AND FEED Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1FeederVibratory73 tonne/hr (80 tph) 3 0 2Conveyor No. 6Belt w/tripper218 tonne/hr (240 tph) 1 0 3Roller Mill Feed HopperDual Outlet435 tonne (480 ton) 1 0 4Weigh FeederBelt109 tonne/hr (120 tph) 2 0 5Coal Dryer and PulverizerRotary109 tonne/hr (120 tph) 2 0 6Coal Dryer Feed HopperVertical Hopper218 tonne (240 ton) 2 0 Cost and Performance Baseline for Fossil Energy Plants 252 ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Demineralized Water Storage TankVertical, cylindrical, outdoor1,165,907 liters (308,000 gal) 2 0 2Condensate PumpsVertical canned6,473 lpm @ 91 m H2O(1,710 gpm @ 300 ft H2O) 2 1 3Deaerator (integral w/ HRSG)Horizontal spray type436,356 kg/hr (962,000 lb/hr) 2 0 4Intermediate Pressure Feedwater PumpHorizontal centrifugal, single stage7,419 lpm @ 27 m H2O(1,960 gpm @ 90 ft H2O) 2 1 5High Pressure Feedwater Pump No. 1Barrel type, multi-stage, centrifugalHP water: 6,927 lpm @ 1,859 m H2O (1,830 gpm @ 6,100 ft H2O)2 1 6High Pressure Feedwater Pump No. 2Barrel type, multi-stage, centrifugalIP water: 2,461 lpm @ 223 m H2O (650 gpm @ 730 ft H2O) 2 1 7Auxiliary BoilerShop fabricated, water tube18,144 kg/hr, 2.8 MPa, 343°C(40,000 lb/hr, 400 psig, 650°F) 1 0 8Service Air CompressorsFlooded Screw28 m3/min @ 0.7 MPa(1,000 scfm @ 100 psig) 2 1 9Instrument Air DryersDuplex, regenerative28 m3/min (1,000 scfm) 2 1 10Closed Cylce Cooling Heat ExchangersPlate and frame133 GJ/hr (126 MMBtu/hr) each 2 0 11Closed Cycle Cooling Water PumpsHorizontal centrifugal47,696 lpm @ 21 m H2O(12,600 gpm @ 70 ft H2O) 2 1 12Engine-Driven Fire PumpVertical turbine, diesel engine3,785 lpm @ 107 m H2O(1,000 gpm @ 350 ft H2O) 1 1 13Fire Service Booster PumpTwo-stage horizontal centrifugal2,650 lpm @ 76 m H2O(700 gpm @ 250 ft H2O) 1 1 14Raw Water PumpsStainless steel, single suction4,391 lpm @ 18 m H2O(1,160 gpm @ 60 ft H2O) 2 1 15Ground Water PumpsStainless steel, single suction2,915 lpm @ 268 m H2O (770 gpm @ 880 ft H2O) 3 1 16Filtered Water PumpsStainless steel, single suction1,779 lpm @ 49 m H2O(470 gpm @ 160 ft H2O) 2 1 17Filtered Water TankVertical, cylindrical851,718 liter (225,000 gal) 2 0 18Makeup Water DemineralizerAnion, cation, and mixed bed341 lpm (90 gpm) 2 0 19Liquid Waste Treatment System10 years, 24-hour storm 1 0 Cost and Performance Baseline for Fossil Energy Plants 253 ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY AND FUEL GAS SATURATION Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1GasifierPressurized dry-feed, entrained bed2,631 tonne/day, 4.2 MPa(2,900 tpd, 615 psia) 2 0 2Synthesis Gas CoolerConvective spiral-wound tube boiler280,320 kg/hr (618,000 lb/hr) 2 0 3Synthesis Gas CycloneHigh efficiency280,320 kg/hr (618,000 lb/hr) Design efficiency 90%

2 0 4Candle FilterPressurized filter with pulse-jet cleaningmetallic filters 2 0 5Syngas Scrubber Including Sour Water StripperVertical upflow196,405 kg/hr (433,000 lb/hr) 2 0 6Raw Gas CoolersShell and tube with condensate drain192,777 kg/hr (425,000 lb/hr) 8 0 7Raw Gas Knockout DrumVertical with mist eliminator191,870 kg/hr, 35°C, 3.8 MPa(423,000 lb/hr, 94°F, 545 psia) 2 0 8Saturation Water EconomizersShell and tube131 GJ/hr (124 MMBtu/hr) 2 0 9Fuel Gas SaturatorVertical tray tower229,518 kg/hr, 161°C, 3.3 MPa(506,000 lb/hr, 321°F, 480 psia) 2 0 10Saturator Water PumpCentrifugal3,407 lpm @ 12 m H2O(900 gpm @ 40 ft H2O) 2 2 11Synthesis Gas ReheaterShell and tube186,426 kg/hr (411,000 lb/hr) 2 0 12Flare StackSelf-supporting, carbon steel, stainless steel top, pilot ignition196,405 kg/hr (433,000 lb/hr) syngas 2 0 13ASU Main Air CompressorCentrifugal, multi-stage3,993 m3/min @ 1.3 MPa(141,000 scfm @ 190 psia) 2 0 14Cold BoxVendor design1,996 tonne/day (2,200 tpd) of 95% purity oxygen 2 0 15Oxygen CompressorCentrifugal, multi-stage991 m3/min (35,000 scfm)Suction - 0.9 MPa (130 psia)Discharge - 6.5 MPa (940 psia) 2 0 16Primary Nitrogen CompressorCentrifugal, multi-stage3,285 m3/min (116,000 scfm)Suction - 0.4 MPa (60 psia)Discharge - 2.7 MPa (390 psia) 2 0 17Secondary Nitrogen CompressorCentrifugal, single-stage453 m3/min (16,000 scfm)Suction - 1.2 MPa (180 psia)Discharge - 2.7 MPa (390 psia) 2 0 18Transport Nitrogen Boost CompressorCentrifugal, single-stage198 m3/min (7,000 scfm)Suction - 2.6 MPa (380 psia)Discharge - 5.4 MPa (790 psia) 2 0 19Extraction Air Heat ExchangerGas-to-gas, vendor design69,853 kg/hr, 432°C, 1.6 MPa(154,000 lb/hr, 810°F, 235 psia) 2 0 Cost and Performance Baseline for Fossil Energy Plants 2 54 ACCOUNT 5 SYNGAS CLEANUP ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

ACCOUNT 7 HRSG, DUCTING AND STACK Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Mercury AdsorberSulfated carbon bed191,416 kg/hr (422,000 lb/hr) 35°C (94°F) 3.7 MPa (540 psia) 2 0 2Sulfur PlantClaus type131 tonne/day (144 tpd) 1 0 3COS Hydrolysis ReactorFixed bed, catalytic195,045 kg/hr (430,000 lb/hr)177°C (350°F)4.0 MPa (580 psia) 2 0 4Acid Gas Removal PlantSulfinol197,313 kg/hr (435,000 lb/hr)34°C (94°F)3.7 MPa (535 psia) 2 0 5Hydrogenation ReactorFixed bed, catalytic13,723 kg/hr (30,253 lb/hr)232°C (450°F)0.4 MPa (58.9 psia) 1 0 6Tail Gas Recycle CompressorCentrifugal10,747 kg/hr (23,692 lb/hr) each 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Gas TurbineAdvanced F class232 MW 2 0 2Gas Turbine GeneratorTEWAC260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1StackCS plate, type 409SS liner76 m (250 ft) high x8.4 m (28 ft) diameter 1 0 2Heat Recovery Steam GeneratorDrum, multi-pressure with economizer section and integral deaeratorMain steam - 393,555 kg/hr, 12.4 MPa/559°C (867 , 640 lb/hr , 1 , 800 psig/1 , 038°F) Reheat steam - 362,720 kg/hr, 3.1 MPa/559°C (799 , 662 lb/hr , 452 psig/1 , 038°F)2 0 Cost and Performance Baseline for Fossil Energy Plants 255 ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES ACCOUNT 9 COOLING WATER SYSTEM Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Steam TurbineCommercially available advanced steam turbine289 MW 12.4 MPa/559°C/559°C (1 , 800 psig/ 1038°F/1038°F)1 0 2Steam Turbine GeneratorHydrogen cooled, static excitiation320 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0 3Steam BypassOne per HRSG50% steam flow @ design steam conditions 2 0 4Surface CondenserSingle pass, divided waterbox including vacuum pumps1,540 GJ/hr (1,460 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F)1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Circulating Water PumpsVertical, wet pit340,687 lpm @ 30 m(90,000 gpm @ 100 ft) 2 1 2Cooling TowerEvaporative, mechanical draft, multi-cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 1,899 GJ/hr (1,800 MMBtu/hr) heat duty 1 0 Cost and Performance Baseline for Fossil Energy Plants 256 ACCOUNT 10 SLAG RECOVERY AND HANDLING Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Slag Quench TankWater bath208,198 liters (55,000 gal) 2 0 2Slag CrusherRoll11 tonne/hr (12 tph) 2 0 3Slag DepressurizerLock Hopper11 tonne/hr (12 tph) 2 0 4Slag Receiving TankHorizontal, weir124,919 liters (33,000 gal) 2 0 5Black Water Overflow TankShop fabricated56,781 liters (15,000 gal) 2 6Slag ConveyorDrag chain11 tonne/hr (12 tph) 2 0 7Slag Separation ScreenVibrating11 tonne/hr (12 tph) 2 0 8Coarse Slag ConveyorBelt/bucket11 tonne/hr (12 tph) 2 0 9Fine Ash Settling TankVertical, gravity177,914 liters (47,000 gal) 2 0 10Fine Ash Recycle PumpsHorizontal centrifugal38 lpm @ 14 m H2O(10 gpm @ 46 ft H2O) 2 2 11Grey Water Storage TankField erected56,781 liters (15,000 gal) 2 0 12Grey Water PumpsCentrifugal189 lpm @ 433 m H2O(50 gpm @ 1,420 ft H2O) 2 2 13Slag Storage BinVertical, field erected816 tonne (900 tons) 2 0 14Unloading EquipmentTelescoping chute91 tonne/hr (100 tph) 1 0 Cost and Performance Baseline for Fossil Energy Plants 257 ACCOUNT 11 ACCESSORY ELECTRIC PLANT ACCOUNT 12 INSTRUMENTATION AND CONTROLS Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1CTG Step-up TransformerOil-filled24 kV/345 kV, 260 MVA, 3-ph, 60 Hz 2 0 2STG Step-up TransformerOil-filled24 kV/345 kV, 320 MVA, 3-ph, 60 Hz 1 0 3High Voltage Auxiliary TransformerOil-filled345 kV/13.8 kV, 47 MVA, 3-ph, 60 Hz 2 0 4Medium Voltage Auxiliary TransformerOil-filled24 kV/4.16 kV, 27 MVA, 3-ph, 60 Hz 1 1 5Low Voltage TransformerDry ventilated4.16 kV/480 V, 4 MVA, 3-ph, 60 Hz 1 1 6CTG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled24 kV, 3-ph, 60 Hz 2 0 7STG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled24 kV, 3-ph, 60 Hz 1 0 8Medium Voltage SwitchgearMetal clad4.16 kV, 3-ph, 60 Hz 1 1 9Low Voltage SwitchgearMetal enclosed480 V, 3-ph, 60 Hz 1 1 10Emergency Diesel GeneratorSized for emergency shutdown750 kW, 480 V, 3-ph, 60 Hz 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1DCS - Main ControlMonitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W)Operator stations/printers and engineering stations/printers 1 0 2DCS - ProcessorMicroprocessor with redundant input/outputN/A 1 0 3DCS - Data HighwayFiber opticFully redundant, 25% spare 1 0 Cost and Performance Baseline for Fossil Energy Plants 258 3.4.7 Case 5 - Cost Estimating The cost estimating methodology was described previously in Section 2.6. Costs Results 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 owner's costs, TOC and TASC. Exhibit 3-86 shows the initial and annual O&M costs.

The estimated TOC of the Shell gasifier with no CO 2 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.

Cost and Performance Baseline for Fossil Energy Plants 259 Exhibit 3-84 Case 5 Total Plant Cost Summary Client: USDOE/NETLReport Date:2010-Jan-14Project: Bituminous Baseline StudyCase: Case 5 - Shell 600MW IGCC w/o CO2Plant Size: 629.0MW,netEstimate Type: ConceptualCost Base (Jun) 2007($x1000)AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING$13,346$2,480$10,349$0$0$26,175$2,376$0$5,710$34,261$54 2COAL & SORBENT PREP & FEED$105,424$8,399$17,537$0$0$131,359$11,391$0$28,550$171,300$272 3FEEDWATER & MISC. BOP SYSTEMS$9,632$8,082$9,224$0$0$26,938$2,534$0$6,691$36,163$57 4GASIFIER & ACCESSORIES4.1Gasifier, Syngas Cooler & Auxiliaries (Shell)$171,446$0$73,699$0$0$245,145$21,883$34,079$46,149$347,255$5524.2Syngas Coolingw/4.1$0w/ 4.1$0$0$0$0$0$0$0$04.3ASU/Oxidant Compression$148,365$0w/equip.$0$0$148,365$14,381$0$16,275$179,021$2854.4-4.9Other Gasification Equipment$15,541$9,100$10,950$0$0$35,592$3,394$0$8,498$47,483$75SUBTOTAL 4$335,353$9,100$84,649$0$0$429,102$39,657$34,079$70,922$573,760$912 5AGAS CLEANUP & PIPING$50,101$3,724$47,806$0$0$101,630$9,827$86$22,447$133,990$213 5BCO2 REMOVAL & COMPRESSION

$0$0$0$0$0$0$0$0$0$0$0 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine Generator$85,752$0$6,269$0$0$92,021$8,724$4,601$10,535$115,881$1846.2-6.9Combustion Turbine Other

$0$806$892$0$0$1,699$159$0$557$2,415$4SUBTOTAL 6$85,752$806$7,162$0$0$93,720$8,883$4,601$11,092$118,296$188 7HRSG, DUCTING & STACK7.1Heat Recovery Steam Generator$35,374$0$5,030$0$0$40,404$3,842$0$4,425$48,670$777.2-7.9Ductwork and Stack$3,337$2,379$3,116$0$0$8,833$819$0$1,571$11,222$18SUBTOTAL 7$38,712$2,379$8,146$0$0$49,237$4,661$0$5,995$59,893$95 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$28,830$0$4,946$0$0$33,776$3,241$0$3,702$40,718$658.2-8.9Turbine Plant Auxiliaries and Steam Piping$10,446$993$7,524$0$0$18,963$1,722$0$4,181$24,865$40SUBTOTAL 8$39,276$993$12,470$0$0$52,739$4,963$0$7,883$65,584$104 9COOLING WATER SYSTEM$8,350$8,140$6,922$0$0$23,411$2,174$0$5,234$30,819$49 10ASH/SPENT SORBENT HANDLING SYS$17,858$1,384$8,862$0$0$28,104$2,696$0$3,366$34,166$54 11ACCESSORY ELECTRIC PLANT$26,986$10,003$20,101$0$0$57,090$4,905$0$11,625$73,620$117 12INSTRUMENTATION & CONTROL$10,318$1,898$6,648$0$0$18,864$1,710$943$3,585$25,102$40 13IMPROVEMENTS TO SITE$3,326$1,960$8,206$0$0$13,492$1,332$0$4,447$19,272$31 14BUILDINGS & 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$2,217TOTAL PLANT COST

SUMMARY

Cost and Performance Baseline for Fossil Energy Plants 260 Exhibit 3-85 Case 5 Total Plant Cost Details Client: USDOE/NETLReport Date:2010-Jan-14Project: Bituminous Baseline StudyCase: Case 5 - Shell 600MW IGCC w/o CO2Plant Size: 629.0MW,netEstimate Type: ConceptualCost Base (Jun) 2007($x1000)AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING1.1Coal Receive & Unload$3,505$0$1,713$0$0$5,217$467$0$1,137$6,822$111.2Coal Stackout & Reclaim$4,529$0$1,098$0$0$5,627$493$0$1,224$7,344$121.3Coal Conveyors & Yd Crush$4,211$0$1,086$0$0$5,297$465$0$1,152$6,914$111.4Other Coal Handling$1,102$0$251$0$0$1,353$118$0$294$1,766$31.5Sorbent Receive & Unload

$0$0$0$0$0$0$0$0$0$0$01.6Sorbent Stackout & Reclaim

$0$0$0$0$0$0$0$0$0$0$01.7Sorbent Conveyors

$0$0$0$0$0$0$0$0$0$0$01.8Other Sorbent Handling

$0$0$0$0$0$0$0$0$0$0$01.9Coal & Sorbent Hnd.Foundations

$0$2,480$6,201$0$0$8,681$832$0$1,903$11,416$18SUBTOTAL 1.$13,346$2,480$10,349$0$0$26,175$2,376$0$5,710$34,261$54 2COAL & SORBENT PREP & FEED2.1Coal Crushing & Drying$40,051$2,406$5,836$0$0$48,294$4,167$0$10,492$62,953$1002.2Prepared Coal Storage & Feed$1,897$454$297$0$0$2,648$226$0$575$3,450$52.3Dry Coal Injection System$62,432$725$5,798$0$0$68,955$5,939$0$14,979$89,872$1432.4Misc.Coal Prep & Feed$1,043$759$2,276$0$0$4,078$375$0$891$5,344$82.5Sorbent Prep Equipment

$0$0$0$0$0$0$0$0$0$0$02.6Sorbent Storage & Feed

$0$0$0$0$0$0$0$0$0$0$02.7Sorbent Injection System

$0$0$0$0$0$0$0$0$0$0$02.8Booster Air Supply System

$0$0$0$0$0$0$0$0$0$0$02.9Coal & Sorbent Feed Foundation

$0$4,055$3,329$0$0$7,384$684$0$1,614$9,681$15SUBTOTAL 2.$105,424$8,399$17,537$0$0$131,359$11,391$0$28,550$171,300$272 3FEEDWATER & MISC. BOP SYSTEMS3.1Feedwater System$3,130$5,375$2,837$0$0$11,343$1,051$0$2,479$14,872$243.2Water Makeup & Pretreating

$564$59$315$0$0$938$89$0$308$1,335$23.3Other Feedwater Subsystems$1,713$579$521$0$0$2,812$253$0$613$3,678$63.4Service Water Systems

$323$664$2,306$0$0$3,293$321$0$1,084$4,699$73.5Other Boiler Plant Systems$1,732$671$1,663$0$0$4,065$386$0$890$5,341$83.6FO Supply Sys & Nat Gas

$313$591$551$0$0$1,454$140$0$319$1,913$33.7Waste Treatment Equipment

$788$0$481$0$0$1,269$124$0$418$1,810$33.8Misc. Power Plant Equipment$1,071$143$550$0$0$1,764$170$0$580$2,514$4SUBTOTAL 3.$9,632$8,082$9,224$0$0$26,938$2,534$0$6,691$36,163$57 4GASIFIER & ACCESSORIES4.1Gasifier, Syngas Cooler & Auxiliaries (Shell)$171,446$0$73,699$0$0$245,145$21,883$34,079$46,149$347,255$5524.2Syngas Coolingw/4.1$0w/ 4.1$0$0$0$0$0$0$0$04.3ASU/Oxidant Compression$148,365$0w/equip.$0$0$148,365$14,381$0$16,275$179,021$2854.4LT Heat Recovery & FG Saturation$15,541$0$5,908$0$0$21,449$2,093$0$4,709$28,251$454.5Misc. Gasification Equipmentw/4.1&4.2$0w/4.1&4.2$0$0$0$0$0$0$0$04.6Flare Stack System

$0$921$375$0$0$1,296$124$0$284$1,704$34.8Major Component Riggingw/4.1&4.2$0w/4.1&4.2$0$0$0$0$0$0$0$04.9Gasification Foundations

$0$8,179$4,667$0$0$12,847$1,176$0$3,506$17,528$28SUBTOTAL 4.$335,353$9,100$84,649$0$0$429,102$39,657$34,079$70,922$573,760$912TOTAL PLANT COST

SUMMARY

Cost and Performance Baseline for Fossil Energy Plants 261 Exhibit 3-85 Case 5 Total Plant Cost Details (Continued) AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 5AGAS CLEANUP & PIPING5A.1Sulfinol System$35,020$0$29,715$0$0$64,735$6,261$0$14,199$85,194$1355A.2Elemental Sulfur Plant$9,609$1,915$12,397$0$0$23,921$2,324$0$5,249$31,494$505A.3Mercury Removal

$976$0$743$0$0$1,720$166$86$394$2,366$45A.4COS Hydrolysis$2,882$0$3,764$0$0$6,646$646$0$1,459$8,751$145A.5Particulate Removalw/4.1$0w/4.1$0$0$0$0$0$0$0$05A.6Blowback Gas Systems$1,613$271$153$0$0$2,037$193$0$446$2,677$45A.7Fuel Gas Piping

$0$764$535$0$0$1,298$120$0$284$1,703$35A.9HGCU Foundations

$0$773$499$0$0$1,272$117$0$417$1,805$3SUBTOTAL 5A.$50,101$3,724$47,806$0$0$101,630$9,827$86$22,447$133,990$213 5BCO2 REMOVAL & COMPRESSION5B.1CO2 Removal System

$0$0$0$0$0$0$0$0$0$0$05B.2CO2 Compression & Drying

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 5B.

$0$0$0$0$0$0$0$0$0$0$0 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine Generator$85,752$0$6,269$0$0$92,021$8,724$4,601$10,535$115,881$1846.2Open$0$0$0$0$0$0$0$0$0$0$06.3Compressed Air Piping

$0$0$0$0$0$0$0$0$0$0$06.9Combustion Turbine Foundations

$0$806$892$0$0$1,699$159$0$557$2,415$4SUBTOTAL 6.$85,752$806$7,162$0$0$93,720$8,883$4,601$11,092$118,296$188 7HRSG, DUCTING & STACK7.1Heat Recovery Steam Generator$35,374$0$5,030$0$0$40,404$3,842$0$4,425$48,670$777.2Open$0$0$0$0$0$0$0$0$0$0$07.3Ductwork$0$1,711$1,220$0$0$2,931$257$0$638$3,826$67.4Stack$3,337$0$1,254$0$0$4,591$440$0$503$5,534$97.9HRSG,Duct & Stack Foundations

$0$669$642$0$0$1,311$122$0$430$1,863$3SUBTOTAL 7.$38,712$2,379$8,146$0$0$49,237$4,661$0$5,995$59,893$95 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$28,830$0$4,946$0$0$33,776$3,241$0$3,702$40,718$658.2Turbine Plant Auxiliaries

$200$0$459$0$0$659$64$0$72$796$18.3Condenser & Auxiliaries$4,740$0$1,514$0$0$6,254$598$0$685$7,537$128.4Steam Piping$5,506$0$3,873$0$0$9,379$806$0$2,546$12,731$208.9TG Foundations

$0$993$1,678$0$0$2,671$253$0$877$3,801$6SUBTOTAL 8.$39,276$993$12,470$0$0$52,739$4,963$0$7,883$65,584$104 9COOLING WATER SYSTEM9.1Cooling Towers$5,766$0$1,049$0$0$6,815$649$0$1,120$8,584$149.2Circulating Water Pumps$1,500$0$99$0$0$1,599$135$0$260$1,993$39.3Circ.Water System Auxiliaries

$129$0$18$0$0$148$14$0$24$186$09.4Circ.Water Piping

$0$5,400$1,400$0$0$6,800$615$0$1,483$8,897$149.5Make-up Water System

$317$0$453$0$0$769$74$0$169$1,012$29.6Component Cooling Water Sys

$637$762$542$0$0$1,942$182$0$425$2,549$49.9Circ.Water System Foundations

$0$1,977$3,361$0$0$5,339$506$0$1,753$7,598$12SUBTOTAL 9.$8,350$8,140$6,922$0$0$23,411$2,174$0$5,234$30,819$49 Cost and Performance Baseline for Fossil Energy Plants 262 Exhibit 3-85 Case 5 Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 10ASH/SPENT SORBENT HANDLING SYS10.1Slag Dewatering & Cooling$15,534$0$7,661$0$0$23,194$2,229$0$2,542$27,965$4410.2Gasifier Ash Depressurizationw/10.1w/10.1w/10.1$0$0$0$0$0$0$0$010.3Cleanup Ash Depressurizationw/10.1w/10.1w/10.1$0$0$0$0$0$0$0$010.4High Temperature Ash Piping

$0$0$0$0$0$0$0$0$0$0$010.5Other Ash Recovery Equipment

$0$0$0$0$0$0$0$0$0$0$010.6Ash Storage Silos

$527$0$573$0$0$1,100$107$0$181$1,387$210.7Ash Transport & Feed Equipment

$706$0$170$0$0$877$82$0$144$1,102$210.8Misc. Ash Handling Equipment$1,091$1,337$399$0$0$2,827$269$0$464$3,561$610.9Ash/Spent Sorbent Foundation

$0$47$59$0$0$105$10$0$34$149$0SUBTOTAL 10.$17,858$1,384$8,862$0$0$28,104$2,696$0$3,366$34,166$54 11ACCESSORY ELECTRIC PLANT11.1Generator Equipment

$950$0$939$0$0$1,889$180$0$207$2,276$411.2Station Service Equipment$3,667$0$330$0$0$3,998$369$0$437$4,803$811.3Switchgear & Motor Control $6,780$0$1,233$0$0$8,013$743$0$1,313$10,069$1611.4Conduit & Cable Tray

$0$3,149$10,390$0$0$13,539$1,309$0$3,712$18,561$3011.5Wire & Cable

$0$6,017$3,954$0$0$9,971$724$0$2,674$13,369$2111.6Protective Equipment

$0$679$2,471$0$0$3,150$308$0$519$3,976$611.7Standby Equipment

$234$0$228$0$0$462$44$0$76$583$111.8Main Power Transformers$15,356$0$144$0$0$15,500$1,173$0$2,501$19,174$3011.9Electrical Foundations

$0$157$411$0$0$568$54$0$187$810$1SUBTOTAL 11.$26,986$10,003$20,101$0$0$57,090$4,905$0$11,625$73,620$117 12INSTRUMENTATION & CONTROL12.1IGCC Control Equipmentw/4.1$0w/4.1$0$0$0$0$0$0$0$012.2Combustion Turbine Controlw/6.1$0w/6.1$0$0$0$0$0$0$0$012.3Steam Turbine Controlw/8.1$0w/8.1$0$0$0$0$0$0$0$012.4Other Major Component Control$1,019$0$680$0$0$1,699$161$85$292$2,236$412.5Signal Processing Equipmentw/12.7$0w/12.7$0$0$0$0$0$0$0$012.6Control Boards,Panels & Racks

$234$0$150$0$0$384$36$19$88$528$112.7Computer & Accessories$5,433$0$174$0$0$5,607$515$280$640$7,043$1112.8Instrument Wiring & Tubing

$0$1,898$3,880$0$0$5,778$490$289$1,639$8,197$1312.9Other I & C Equipment$3,632$0$1,764$0$0$5,396$508$270$926$7,099$11SUBTOTAL 12.$10,318$1,898$6,648$0$0$18,864$1,710$943$3,585$25,102$40 Cost and Performance Baseline for Fossil Energy Plants 263 Exhibit 3-85 Case 5 Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 13IMPROVEMENTS TO SITE13.1Site Preparation

$0$104$2,230$0$0$2,335$232$0$770$3,336$513.2Site Improvements

$0$1,856$2,466$0$0$4,322$426$0$1,425$6,173$1013.3Site Facilities$3,326$0$3,509$0$0$6,835$674$0$2,253$9,762$16SUBTOTAL 13.$3,326$1,960$8,206$0$0$13,492$1,332$0$4,447$19,272$31 14BUILDINGS & STRUCTURES14.1Combustion Turbine Area

$0$265$150$0$0$414$36$0$90$541$114.2Steam Turbine Building

$0$2,428$3,459$0$0$5,887$542$0$964$7,394$1214.3Administration Building

$0$841$610$0$0$1,452$129$0$237$1,818$314.4Circulation Water Pumphouse

$0$166$88$0$0$254$22$0$41$317$114.5Water Treatment Buildings

$0$471$460$0$0$931$84$0$152$1,168$214.6Machine Shop

$0$431$295$0$0$725$64$0$118$908$114.7Warehouse

$0$695$449$0$0$1,144$101$0$187$1,432$214.8Other Buildings & Structures

$0$416$324$0$0$741$66$0$161$968$214.9Waste Treating Building & Str.

$0$931$1,779$0$0$2,710$253$0$592$3,555$6SUBTOTAL 14.

$0$6,644$7,614$0$0$14,258$1,298$0$2,544$18,100$29TOTAL COST$744,432$65,991$255,695$0$0$1,066,118$98,407$39,709$190,092$1,394,325$2,217Owner's CostsPreproduction Costs6 Months All Labor$12,811$201 Month Maintenance Materials$2,891$51 Month Non-fuel Consumables

$407$11 Month Waste Disposal

$260$025% of 1 Months Fuel Cost at 100% CF$1,521$22% of TPC$27,887$44Total$45,778$73Inventory Capital60 day supply of fuel and consumables at 100% CF$12,790$200.5% of TPC (spare parts)$6,972$11Total$19,762$31Initial Cost for Catalyst and Chemicals

$963$2Land$900$1Other Owner's Costs$209,149$333Financing Costs$37,647$60Total Overnight Costs (TOC)$1,708,524$2,716TASC Multiplier(IOU, high-risk, 35 year)1.140Total As-Spent Cost (TASC)$1,947,717$3,097 Cost and Performance Baseline for Fossil Energy Plants 264 Exhibit 3-86 Case 5 Initial and Annual Operating and Maintenance Costs INITIAL & ANNUAL O&M EXPENSESCost Base (Jun):

2007Case 5 - Shell 600MW IGCC w/o CO2Heat Rate-net (Btu/kWh):8,099 MWe-net: 629 Capacity Factor (%):

80OPERATING & MAINTENANCE LABOROperating Labor Operating Labor Rate(base):34.65$/hour Operating Labor Burden:30.00% of base Labor O-H Charge Rate:25.00% of laborTotal Operating Labor Requirements(O.J.)per Shift:1 unit/mod. Plant Skilled Operator2.02.0 Operator9.09.0 Foreman1.01.0 Lab Tech's, etc.3.03.0 TOTAL-O.J.'s15.015.0Annual CostAnnual Unit Cost

$$/kW-netAnnual Operating Labor Cost$5,918,913$9.410Maintenance Labor Cost$14,578,930$23.179Administrative & Support Labor$5,124,461$8.147Property Taxes and Insurance$27,886,508$44.336TOTAL FIXED OPERATING COSTS$53,508,812$85.072VARIABLE OPERATING COSTS$/kWh-netMaintenance Material Cost$27,756,840$0.00630ConsumablesConsumptionUnit Initial Fill Initial Fill /Day Cost CostWater (/1000 gallons) 02,9821.08$0$941,938$0.00021ChemicalsMU & WT Chem. (lbs) 017,7670.17$0$897,887$0.00020Carbon (Mercury Removal) (lb)69,345 951.05$72,824$29,130$0.00001COS Catalyst (m3) 2620.182,397.36$627,613$125,523$0.00003Water Gas Shift Catalyst (ft3) 0 0498.83$0$0$0.00000Sulfinol Solution (gal)26,146 62910.05$262,733$1,846,503$0.00042SCR Catalyst (m3) 0 00.00$0$0$0.00000Ammonia (19% NH3) (ton) 0 00.00$0$0$0.00000Claus Catalyst (ft3)w/equip.1.82131.27$0$69,945$0.00002Subtotal Chemicals$963,170$2,968,988$0.00067OtherSupplemental Fuel (MBtu) 0 00.00$0$0$0.00000Gases, N2 etc. (/100scf) 0 00.00$0$0$0.00000L.P. Steam (/1000 pounds) 0 00.00$0$0$0.00000Subtotal Other

$0$0$0.00000Waste DisposalSpent Mercury Catalyst (lb.)

0 950.42$0$11,569$0.00000Flyash (ton) 0 00.00$0$0$0.00000Slag (ton) 0 52516.23$0$2,486,313$0.00056 Subtotal-Waste Disposal

$0$2,497,882$0.00057By-products & EmissionsSulfur (ton) 0 1310.00$0$0$0.00000Subtotal By-Products

$0$0$0.00000TOTAL VARIABLE OPERATING COSTS$963,170$34,165,649$0.00775Fuel (ton) 05,24038.18$0$58,422,569$0.01325 Cost and Performance Baseline for Fossil Energy Plants 265 3.4.8 This case is configured to produce electric power with CO 2 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 CO 2 capture and compression process increases the auxiliary load on the plant, the net output is significantly reduced relative to Case 5 (49 7 MW versus 629 MW). Case 6 - Shell IGCC Power Plant with CO 2 Capture The process description for Case 6 is similar to Case 5 with several notable exceptions to accommodate CO 2 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.

No differences from Case 5.

Coal Preparation and Feed Systems The gasification process is the same as Case 5 with the following exceptions:

Gasification 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)

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. Raw Gas Cooling/Particulate Removal Syngas exits the scrubber at 191°C (376°F). Syngas Scrubber/Sour Water Stripper The SGS process was described in Section Sour Gas Shift (SGS) 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 H 2O: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 9 7.8 percent overall conversion of the CO to CO

2. 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.

Cost and Performance Baseline for Fossil Energy Plants 266 Mercury removal is the same as in Case 5

. Mercury Removal and AGR The AGR process in Case 6 is a two stage Selexol process where H 2S is removed in the first stage and CO 2 in the second stage of absorption. The process results in three product streams, the clean syngas (stream 18), a CO 2-rich stream and an acid gas feed to the Claus plant (stream 22). The acid gas contains 34 percent H 2S and 51 percent CO 2 with the balance primarily H 2. The CO 2-rich stream is discussed further in the CO 2 compression section.

CO 2 from the AGR process is flashed at three pressure levels to separate CO 2 and decrease H 2 losses to the CO 2 product pipeline. The HP CO 2 stream is flashed at 2.0 MPa (289.7 psia), compressed, and recycled back to the CO 2 absorber. The MP CO 2 stream is flashed at 1.0 MPa (149.7 psia). The LP CO 2 stream is flashed at 0.1 MPa (16.7 psia), compressed to 1.0 MPa (149.5 psia), and combined with the MP CO 2 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 CO 2 stream is dehydrated to a dewpoint of

-40ºC (-40°F) with triethylene glycol. The raw CO 2 stream from the Selexol process contains over 99 percent CO

2. The CO 2 (stream 21) is transported to the plant fence line and is sequestration ready. CO 2 TS&M costs were estimated using the methodology described in Section 2.7.

CO 2 Compression and Dehydration The Claus plant is the same as Case 5 with the following exceptions:

Claus Unit 5,277 kg/h r (11,634 lb/h r) of sulfur (stream 23) are produced The waste heat boiler generates 13,697 kg/h r (30,197 lb/h r) 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.

Clean syngas from the AGR plant is combined with a small amount of clean gas from the CO 2 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.

Power Block 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. Air Separation Unit (ASU)

Cost and Performance Baseline for Fossil Energy Plants 267 Balance of plant items were covered in Sections Balance of Plant 3.1.9 , 3.1.10 and 3.1.11.

Cost and Performance Baseline for Fossil Energy Plants 268 Exhibit 3-87 Case 6 Block Flow Diagram, Shell IGCC with CO 2 Capture Cost and Performance Baseline for Fossil Energy Plants 269 Exhibit 3-88 Case 6 Stream Table, Shell IGCC with CO 2 Capture 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15V-L Mole Fraction Ar0.00920.02300.03180.00230.03180.00000.00230.00960.00000.00000.00000.00850.00610.00000.0047 CH 40.00000.00000.00000.00000.00000.00000.00000.00060.00000.00000.00000.00050.00040.00000.0003 CO0.00000.00000.00000.00000.00000.00000.00000.01300.00000.00000.00000.51870.37120.00000.2873 CO 20.00030.00790.00000.00000.00000.00000.00000.04550.00000.00000.00000.01260.00900.00000.0070COS0.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00060.00040.00000.0003 H 20.00000.00000.00000.00000.00000.00000.00000.87270.00000.80900.00000.26910.19260.00000.1491 H 2 O0.00990.19840.00000.00030.00001.00000.00040.00010.00000.09350.00000.12780.37581.00000.5172 HCl0.00000.00000.00000.00000.00000.00000.00000.00000.00000.00300.00000.00080.00060.00000.0001 H 2 S0.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00730.00520.00000.0040 N 20.77320.57590.01780.99190.01780.00000.99190.05850.00000.01630.00000.05070.03630.00000.0281 NH 30.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00330.00240.00000.0019 O 20.20740.19480.95040.00540.95040.00000.00540.00000.00000.07820.00000.00000.00000.00000.0000 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000Total1.00001.00001.00001.00001.00001.00001.00001.00000.00001.00000.00001.00001.00001.00001.0000V-L Flowrate (kgmol/hr)24,2771,004 10217,3104,8861,130 940 308 05,809 026,49329,24911,00337,783V-L Flowrate (kg/hr)700,54827,3283,289485,713157,22520,36326,3681,900 037,081 0531,672569,894198,213723,426Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0211,040160,28121,137 0 0 0 0Temperature (°C) 15 20 32 93 32 343 32 35 15 161,4271,082 232 288 217Pressure (MPa, abs)0.100.110.862.650.865.105.623.590.105.794.244.244.035.523.96Enthalpy (kJ/kg)

A30.2336.9026.6792.5126.673,063.9720.78163.14---3,549.69---2,043.241,217.352,918.181,541.02Density (kg/m 3)1.21.511.024.411.020.162.88.5---16.5---7.519.125.619.5V-L Molecular Weight28.85727.20632.18128.06032.18118.01528.0606.159---6.383---20.06919.48418.01519.147V-L Flowrate (lbmol/hr)53,5212,215 22538,16210,7712,4922,072 680 012,807 058,40764,48224,25683,298V-L Flowrate (lb/hr)1,544,44560,2497,2501,070,813346,62244,89458,1324,188 081,749 01,172,1371,256,401436,9861,594,881Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0465,264353,35946,599 0 0 0 0Temperature (°F) 59 68 90 199 90 650 90 94 59 602,6001,980 450 550 422Pressure (psia)14.716.4125.0384.0125.0740.0815.0520.014.7840.0615.0615.0585.0800.0575.0Enthalpy (Btu/lb)

A13.015.911.539.811.51,317.38.970.1---1,526.1---878.4523.41,254.6662.5Density (lb/ft 3)0.0760.0970.6871.5210.6871.2573.9180.531---1.029---0.4681.1901.5971.218A - Reference conditions are 32.02 F & 0.089 PSIA Cost and Performance Baseline for Fossil Energy Plants 270 Exhibit 3-88 Case 6 Stream Table (Continued) 16 17 18 19 20 21 22 23 24 25 26 27 28 29V-L Mole Fraction Ar0.00620.00620.00960.00860.00860.00020.00170.00000.00650.01020.00920.00880.00880.0000 CH 40.00040.00040.00060.00050.00050.00000.00020.00000.00000.00000.00000.00000.00000.0000 CO0.00840.00840.01300.01160.01160.00020.00250.00000.11430.00600.00000.00000.00000.0000 CO 20.37760.38100.04550.04070.04070.99440.51410.00000.28660.62570.00030.00800.00800.0000COS0.00000.00000.00000.00000.00000.00000.00020.00000.00040.00000.00000.00000.00000.0000 H 20.56330.55930.87270.78190.78190.00500.10680.00000.06590.26940.00000.00000.00000.0000 H 2 O0.00160.00160.00010.10410.10410.00000.03000.00000.47150.00170.00990.13740.13741.0000 HCl0.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 H 2 S0.00570.00570.00000.00000.00000.00000.33980.00000.00140.00570.00000.00000.00000.0000 N 20.03680.03740.05850.05240.05240.00020.00470.00000.05160.08130.77320.73970.73970.0000 NH 30.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 O 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.20740.10600.10600.0000 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00180.00000.00000.00000.00000.0000Total1.00001.00001.00001.00001.00001.00001.00000.00001.00001.00001.00001.00001.00001.0000V-L Flowrate (kgmol/hr)28,83729,23718,31220,43820,43810,099 488 0 630 400110,253139,892139,89228,855V-L Flowrate (kg/hr)562,223574,690112,786151,092151,092442,27017,202 016,58512,4663,181,5573,818,3623,818,362519,836Solids Flowrate (kg/hr) 0 0 0 0 0 0 05,277 0 0 0 0 0 0Temperature (°C) 35 35 35 137 193 51 48 178 232 38 15 562 132 534Pressure (MPa, abs)3.623.63.5853.2063.17215.2700.1630.1190.0855.510.1010.1050.10512.512Enthalpy (kJ/kg)

A45.3344.5163.1441,181.2361,416.715-161.70485.006---1,114.4988.3030.227866.140371.2883,431.999Density (kg/m 3)28.128.18.56.96.0639.82.25,279.40.574.41.20.40.836.8V-L Molecular Weight19.496 206.1597.3937.39343.79235.245---26.33631.16028.85727.29527.29518.015V-L Flowrate (lbmol/hr)63,57664,45840,37145,05945,05922,2651,076 01,388 882243,066308,408308,40863,615V-L Flowrate (lb/hr)1,239,4911,266,974248,650333,100333,100975,03837,925 036,56327,4847,014,1338,418,0478,418,0471,146,042Solids Flowrate (lb/hr) 0 0 0 0 0 0 011,634 0 0 0 0 0 0Temperature (°F) 95 94 94 278 380 124 119 352 450 100 591,043 270 993Pressure (psia)525.0520.0520.0465.0460.02,214.723.717.312.3799.514.715.215.21,814.7Enthalpy (Btu/lb)

A19.519.170.1507.8609.1-69.536.5---479.13.613.0372.4159.61,475.5Density (lb/ft 3)1.753 20.5310.4310.37439.9420.135329.5840.0334.6460.0760.0260.0532.295 Cost and Performance Baseline for Fossil Energy Plants 271 3.4.9 The Case 6 modeling assumptions were presented previously in Section Case 6 Performance Results 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 CO 2 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.

Cost and Performance Baseline for Fossil Energy Plants 272 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 67 3 , 4 00 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 CO 2 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 Plant 2 3,000 Transformer Losses 2,530 TOTAL AUXILIARIES, kWe 17 6 ,5 4 0 NET POWER, kWe 496,860 Net Plant Efficiency, % (HHV) 3 1.2 Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,526 (10,924)

CONDENSER COOLING DUTY 10 6 kJ/h r (10 6 Btu/h r) 1,340 (1,270)

CONSUMABLES As-Received Coal Feed, kg/h r (lb/h r) 211,040 (465,264)

Thermal Input 1, kWt 1,590,722 Raw Water Withdrawal, m 3/min (gpm) 21.3 (5,6 3 3) Raw Water Consumption , m 3/min (gpm) 17.5 (4,6 16) 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 Cost and Performance Baseline for Fossil Energy Plants 273 The environmental targets for emissions of Hg, NO x, SO 2, CO 2 , and PM were presented in Section 2.4. A summary of the plant air emissions for Case 6 is presented in Environmental Performance Exhibit 3-90. Exhibit 3-90 Case 6 Air Emissions kg/GJ (lb/10 6 Btu) Tonne/year (ton/year) 80% CF kg/MWh (lb/MWh) SO 2 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) CO 2 8.6 (20.0) 344,507 (379,754) 73 (161) CO 2 1 99 (218) 1 CO 2 emissions based on net power instead of gross power The low level of SO 2 emissions is achieved by capture of the sulfur in the gas by the two

-stage Selexol AGR process. The CO 2 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 H 2 S-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.

NO x emissions are limited by the use of nitrogen dilution and humidification to 15 ppmvd (as NO 2 @ 15 percent O 2). 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 NO x 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 CO 2 from the syngas is captured in the AGR system and compressed for sequestration. Because not all CO is converted to CO 2 in the shift reactors, the overall CO 2 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, CO 2 in the stack gas, coal dryer vent gas, ASU vent gas and the captured CO 2 product. The carbon capture efficiency is defined as the amount of carbon in the CO 2 product stream relative to the amount of carbon in the coal less carbon contained in the slag, represented by the following fraction:

Cost and Performance Baseline for Fossil Energy Plants 274 (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/h r (lb/hr) Coal 134,527 (296,581)

Slag 673 (1,483)

Air (CO 2) 532 (1,173)

Stack Gas 13,416 (29,578)

ASU Vent 95 (210) CO 2 Product 120,652 (265,992)

Coal Dryer Stack Gas 223 (491) 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 5,290 (11,661)

Elemental Sulfur 5,277 (11,634)

Stack Gas 3 (6) CO 2 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

.

Cost and Performance Baseline for Fossil Energy Plants 275 Exhibit 3-93 Case 6 Water Balance Water Use Water Demand, m 3/min (gpm) Internal Recycle, m 3/min (gpm) Raw Water Withdrawal, m 3/min (gpm) Process Water Discharge, m 3/min (gpm) Raw Water Consumption, m 3/min (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 Gasifier Steam Shift Steam GT Steam Dilution BFW Makeup 3.8 (1,012) 0.3 (90) 3.3 (874) 0.18 (48) 0.0 (0) 3.8 (1,012) 0.3 (90) 3.3 (874) 0.18 (48) 0.0 (0) 3.8 (1,012)

Cooling Tower BFW Blowdown SWS Blowdown

SWS Excess Water Humidifier Tower Blowdown 17.0 (4,490) 0.45 (119) 0.18 (48) 0.27 (71) 16.5 (4,371)

-0.18 (-48) -0.27 (-71) 3.8 (1,010) 12.7 (3,361)

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 are shown for the following subsystems in Heat and Mass Balance Diagrams 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.

Cost and Performance Baseline for Fossil Energy Plants 276 This page intentionally left blank

Cost and Performance Baseline for Fossil Energy Plants 277 Exhibit 3-94 Case 6 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic N OTES: DOE/NETL D UAL T RAIN IGCC P LANT C ASE 6 H EAT AND M ATERIAL F LOW D IAGRAM B ITUMINOUS BASELINE S TUDY C ASE 6 S HELL G ASIFIER ASU , G ASIFICATION , AND G AS C OOLING DWG. NO.BB-HMB-CS-6-PG-1 P LANT P ERFORMANCE S UMMARY L EGEND Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas P AGES 1 OF 3 Ambient Air Intercooled Air Compressor Elevated Pressure ASU Intercooled Nitrogen Compressor Intercooled Oxygen Compressor Milled Coal Sour Gas Sour Water ASU VENT Water Steam Slag Removal Slag G ROSS P LANT P OWER: 673 MW E A UXILIARY L OAD: 177 MW E N ET P LANT P OWER: 497 MW E N ET P LANT E FFICIENCY , HHV: 31.2%N ET P LANT H EAT R ATE: 10 , 924 BTU/KW E Dry Coal Coal Feeding Steam Candle Filter Cyclone N 2 to GT Combustor Boost Compressor Recycle Compressor Raw Syngas to Scrubber 519.9 T 625.0 P 551.7 H To Claus Plant 9 10 1 3 7 6 11 13 2 1 , 544 , 445 W 59.0 T 14.7 P 13.0 H 60 , 249 W 67.9 T 16.4 P 15.9 H 989 , 843 W 90.0 T 56.4 P 14.2 H 139 , 103 W 50.0 T 182.0 P 2.9 H 7 , 250 W 90.0 T 125.0 P 11.5 H 346 , 622 W 90.0 T 125.0 P 11.5 H 346 , 622 W 241.2 T 940.0 P 40.8 H 58 , 132 W 386.6 T 815.0 P 86.8 H 465 , 264 W 59.0 T 14.7 P 435 , 108 W 60.0 T 840.0 P 1 , 526.1 H 46 , 599 W 2 , 600.0 T 615.0 P 1 , 172 , 137 W 1 , 979.6 T 615.0 P 878.4 H 1 , 256 , 401 W 450.0 T 585.0 P 523.4 H P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB/HR H E NTHALPY , B TU/L B MW E P OWER , M EGAWATTS E LECTRICAL 687 , 451 W 385.0 T 384.0 P 87.2 H 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA 5 44 , 894 W 650.0 T 740.0 P 1 , 317.3 H Coal Drying Incinerator Syngas Slip Stream Incinerator Air Flue Gas/Combustion Products Incinerator Exhaust 4 , 188 W 94.4 T 520.0 P 70.1 H 63 , 439 W 59.0 T 14.7 P 13.4 H 97 , 783 W 290.0 T 14.4 P 8 199.0 T 384.0 P 39.8 H 333 , 980 W 450.0 T 585.0 P 523.4 H Syngas Quench Cooler Quench Water 418 , 244 W 420.0 T 1 , 200.0 P 387.9 H Shift Steam For WGF Reactors Saturated Steam To HRSG HP BFW IP BFW N 2 Compressor N 2 to GT Combustor Saturated Steam To HRSG HP BFW 12 1 , 650.0 T 605.0 P 739.8 H 600.0 T 595.0 P 585.2 H 1 , 590 , 381 W 750.0 T 605.0 P 647.4 H 100.0 T 189.5 P 18.0 H 383 , 362 W 385.0 T 469.0 P 87.0 H Syngas Cooler Duct Cooler Steam Generation Shell Gasifier 4 Cost and Performance Baseline for Fossil Energy Plants 278 Exhibit 3-95 Case 6 Syngas Cleanup Heat and Mass Balance Schematic N OTES: DOE/NETL D UAL T RAIN IGCC P LANT C ASE 6 H EAT AND M ATERIAL F LOW D IAGRAM B ITUMINOUS BASELINE S TUDY C ASE 6 S HELL G ASIFIER G AS C LEANUP S YSTEM P LANT P ERFORMANCE S UMMARY L EGEND Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas Mercury Removal Knock Out Drum Raw Syngas Sour Drum To Water Treatment Makeup Water Claus Plant Tail Gas Furnace Catalytic Reactor Beds Sulfur Sour Water Reboiler Acid Gas Tailgas Carbon Dioxide Sour Gas Sulfur Hydrogen DWG. NO.BB-HMB-CS-6-PG-2 P AGES 2 OF 3 Sour Stripper Syngas Scrubber G ROSS P LANT P OWER: 673 MW E A UXILIARY L OAD: 177 MW E N ET P LANT P OWER: 497 MW E N ET P LANT E FFICIENCY , HHV: 31.2%N ET P LANT H EAT R ATE: 10 , 924 BTU/KW E Water 13 16 17 22 23 24 1 , 256 , 401 W 450.0 T 585.0 P 523.4 H 27 , 484 W 100.0 T 799.5 P 3.6 H 436 , 986 W 550.0 T 800.0 P 1 , 254.1 H 1 , 594 , 881 W 484.5 T 565.0 P 423.7 H 1 , 266 , 974 W 94.4 T 520.0 P 19.1 H Syngas Coolers 248 , 650 W 94.4 T 520.0 P 70.1 H 11 , 634 W 352.5 T 17.3 P From ASU 3 , 022 W 227.6 T 65.0 P 370.2 H 36 , 563 W 450.0 T 12.3 P 479.1 H 37 , 925 W 119.0 T 23.7 P 36.5 H Knock Out Tailgas to AGR 1 , 594 , 881 W 422.2 T 575.0 P 662.5 H 1 , 239 , 491 W 94.8 T 525.0 P 19.5 H P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB/HR H E NTHALPY , B TU/L B MW E P OWER , M EGAWATTS E LECTRICAL 9 , 080 W 114.5 T 10.6 P 40.3 H Treated Syngas Slip Stream to Coal Dryer 18 Humidification 19 Humidified Fuel Gas 20 8 Shift Steam High Temperature Shift #1 Low Temperature Shift #2 Fuel Gas Humidification 1 , 157 , 895 W 375.6 T 580.0 P 435.0 H 385.6 T 575.0 P 439.1 H 477.9 T 560.0 P 420.7 H WGS and Steam Cycle Steam 14 15 Two-Stage Selexol Clean Gas CO 2 Acid Gas Interstage Knockout CO 2 Product 21 Multistage Intercooled CO 2 Compressor 7 , 250 W 450.0 T 124.5 P 91.9 H 975 , 038 W 124.0 T 2 , 214.7 P 25 Tailgas Recycle Compressor Hydrogenation And Tail Gas Cooling Cost and Performance Baseline for Fossil Energy Plants 279 Exhibit 3-96 Case 6 Combined Cycle Power Generation Heat and Mass Balance Schematic N OTES: DOE/NETL D UAL T RAIN IGCC P LANT C ASE 6 H EAT AND M ATERIAL F LOW D IAGRAM B ITUMINOUS B ASELINE S TUDY C ASE 6 S HELL G ASIFIER P OWER B LOCK S YSTEM P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB/HR H E NTHALPY , B TU/L B MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Synthesis Gas HRSG HP Turbine IP Turbine Nitrogen Dilution Intake Ambient Air Steam Seal Regulator IP Extraction Steam to 250 PSIA Header LP Process Header Blowdown Flash To WWT Make-up Gland Steam Condenser Condensate to Gasification Island HP& IP BFW to Raw Gas Coolers HP & IP Saturated Steam to HRSG Superheater LP Turbine Stack Expander Compressor Humidified Fuel Gas Deaerator IP BFW Generator Generator Condensate Pump HP Pump Steam Turbine LP Pump Water Steam DWG. NO.BB-HMB-CS-6-PG-3 P AGES 3 OF 3 Advanced F

-Class Gas Turbine G ROSS P LANT P OWER: 673 MW E A UXILIARY L OAD: 177 MW E N ET P LANT P OWER: 497 MW E N ET P LANT E FFICIENCY , HHV: 31.2%N ET P LANT H EAT R ATE: 10 , 924 BTU/KW E Flue Gas/Combustion Products To Gasifier MP Flash Bottoms LP Flash Tops From Gasifier Island Preheating To Claus LP BFW IP Pump 26 4 20 27 28 29 7 , 014 , 133 W 59.0 T 14.7 P 13.0 H 333 , 100 W 380.0 T 460.0 P 609.1 H 1 , 070 , 813 W 199.0 T 384.0 P 39.8 H 8 , 418 , 047 W 1 , 043.2 T 15.2 P 372.4 H 1 , 146 , 042 W 993.2 T 1 , 814.7 P 1 , 475.5 H 1 , 911 , 334 W 102.8 T 120.0 P 71.1 H 23 , 308 W 585.0 T 2 , 000.7 P 592.9 H 8 , 328 W 298.0 T 65.0 P 1 , 178.6 H 1 , 393 , 094 W 439.8 T 65.0 P 1 , 252.2 H 8 , 418 , 047 W 270.0 T 15.2 P 159.6 H 1 , 911 , 334 W 235.0 T 105.0 P 203.3 H 506 , 076 W 59.0 T 14.7 P 27.1 H 1 , 169 , 363 W 278.8 T 2 , 250.7 P 251.9 H 1 , 911 , 334 W 101.1 T 1.0 P 69.1 H 1 , 400 W 614.2 T 65.0 P 1 , 338.3 H 1 , 400 W 212.0 T 14.7 P 179.9 H 26 , 345 W 851.0 T 280.0 P 1 , 448.2 H HOT WELL CONDENSER 217 , 834 W 298.0 T 65.0 P 1 , 178.6 H Cost and Performance Baseline for Fossil Energy Plants 280 This page intentionally left blank

Cost and Performance Baseline for Fossil Energy Plants 281 Exhibit 3-97 Case 6 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total 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) CO 2 -71.5 (-67.8) -72 (-68) Cooling Tower Blowdown 28.4 (26.9) 28 (27) HRSG Flue Gas 1,418 (1,344) 1,418 (1,344)

Condenser 1,335 (1,265) 1,335 (1,265)

Non-Condenser Cooling Tower Loads* 687 (651) 687 (651) 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, CO 2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection) and extraction air cooler.

- Calculated by difference to close the energy balance

.

Cost and Performance Baseline for Fossil Energy Plants 282 3.4.10 Major equipment items for the Shell gasifier with CO 2 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 Case 6 - Major Equipment List 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 No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Bottom Trestle Dumper and Receiving HoppersN/A181 tonne (200 ton) 2 0 2FeederBelt572 tonne/hr (630 tph) 2 0 3Conveyor No. 1Belt1,134 tonne/hr (1,250 tph) 1 0 4Transfer Tower No. 1EnclosedN/A 1 0 5Conveyor No. 2Belt1,134 tonne/hr (1,250 tph) 1 0 6As-Received Coal Sampling SystemTwo-stageN/A 1 0 7Stacker/ReclaimerTraveling, linear1,134 tonne/hr (1,250 tph) 1 0 8Reclaim HopperN/A45 tonne (50 ton) 2 1 9FeederVibratory172 tonne/hr (190 tph) 2 1 10Conveyor No. 3Belt w/ tripper345 tonne/hr (380 tph) 1 0 11Crusher TowerN/AN/A 1 0 12Coal Surge Bin w/ Vent FilterDual outlet172 tonne (190 ton) 2 0 13CrusherImpactor reduction8 cm x 0 - 3 cm x 0(3" x 0 1/4" x 0) 2 0 14As-Fired Coal Sampling SystemSwing hammerN/A 1 1 15Conveyor No. 4Belt w/tripper345 tonne/hr (380 tph) 1 0 16Transfer Tower No. 2EnclosedN/A 1 0 17Conveyor No. 5Belt w/ tripper345 tonne/hr (380 tph) 1 0 18Coal Silo w/ Vent Filter and Slide GatesField erected816 tonne (900 ton) 3 0 Cost and Performance Baseline for Fossil Energy Plants 283 ACCOUNT 2 COAL PREPARATION AND FEED Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1FeederVibratory82 tonne/hr (90 tph) 3 0 2Conveyor No. 6Belt w/tripper236 tonne/hr (260 tph) 1 0 3Roller Mill Feed HopperDual Outlet463 tonne (510 ton) 1 0 4Weigh FeederBelt118 tonne/hr (130 tph) 2 0 5Coal Dryer and PulverizerRotary118 tonne/hr (130 tph) 2 0 6Coal Dryer Feed HopperVertical Hopper236 tonne (260 ton) 2 0 Cost and Performance Baseline for Fossil Energy Plants 284 ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Demineralized Water Storage TankVertical, cylindrical, outdoor987,992 liters (261,000 gal) 2 0 2Condensate PumpsVertical canned7,987 lpm @ 91 m H2O(2,110 gpm @ 300 ft H2O) 2 1 3Deaerator (integral w/ HRSG)Horizontal spray type551,115 kg/hr (1,215,000 lb/hr) 2 0 4Intermediate Pressure Feedwater PumpHorizontal centrifugal, single stage7,987 lpm @ 27 m H2O(2,110 gpm @ 90 ft H2O) 2 1 5High Pressure Feedwater Pump No. 1Barrel type, multi-stage, centrifugalHP water: 5,072 lpm @ 1,859 m H2O (1,340 gpm @ 6,100 ft H2O)2 1 6High Pressure Feedwater Pump No. 2Barrel type, multi-stage, centrifugalIP water: 1,211 lpm @ 223 m H2O (320 gpm @ 730 ft H2O) 2 1 7Auxiliary BoilerShop fabricated, water tube18,144 kg/hr, 2.8 MPa, 343°C(40,000 lb/hr, 400 psig, 650°F) 1 0 8Service Air CompressorsFlooded Screw28 m3/min @ 0.7 MPa(1,000 scfm @ 100 psig) 2 1 9Instrument Air DryersDuplex, regenerative28 m3/min (1,000 scfm) 2 1 10Closed Cylce Cooling Heat ExchangersPlate and frame393 GJ/hr (372 MMBtu/hr) each 2 0 11Closed Cycle Cooling Water PumpsHorizontal centrifugal140,817 lpm @ 21 m H2O(37,200 gpm @ 70 ft H2O) 2 1 12Engine-Driven Fire PumpVertical turbine, diesel engine3,785 lpm @ 107 m H2O(1,000 gpm @ 350 ft H2O) 1 1 13Fire Service Booster PumpTwo-stage horizontal centrifugal2,650 lpm @ 76 m H2O(700 gpm @ 250 ft H2O) 1 1 14Raw Water PumpsStainless steel, single suction5,943 lpm @ 18 m H2O(1,570 gpm @ 60 ft H2O) 2 1 15Ground Water PumpsStainless steel, single suction2,953 lpm @ 268 m H2O (780 gpm @ 880 ft H2O) 4 1 16Filtered Water PumpsStainless steel, single suction4,656 lpm @ 49 m H2O(1,230 gpm @ 160 ft H2O) 2 1 17Filtered Water TankVertical, cylindrical2,225,822 liter (588,000 gal) 2 0 18Makeup Water DemineralizerAnion, cation, and mixed bed2,082 lpm (550 gpm) 2 0 19Liquid Waste Treatment System10 years, 24-hour storm 1 0 Cost and Performance Baseline for Fossil Energy Plants 285 ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY AND FUEL GAS SATURATION Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1GasifierPressurized dry-feed, entrained bed2,812 tonne/day, 4.2 MPa(3,100 tpd, 615 psia) 2 0 2Synthesis Gas CoolerConvective spiral-wound tube boiler396,893 kg/hr (875,000 lb/hr) 2 0 3Synthesis Gas CycloneHigh efficiency313,432 kg/hr (691,000 lb/hr) Design efficiency 90%

2 0 4Candle FilterPressurized filter with pulse-jet cleaningmetallic filters 2 0 5Syngas Scrubber Including Sour Water StripperVertical upflow313,432 kg/hr (691,000 lb/hr) 2 0 6Raw Gas CoolersShell and tube with condensate drain397,801 kg/hr (877,000 lb/hr) 8 0 7Raw Gas Knockout DrumVertical with mist eliminator309,804 kg/hr, 35°C, 3.7 MPa(683,000 lb/hr, 95°F, 530 psia) 2 0 8Saturation Water EconomizersShell and tube78 GJ/hr (74 MMBtu/hr) 2 0 9Fuel Gas SaturatorVertical tray tower83,007 kg/hr, 137°C, 3.6 MPa(183,000 lb/hr, 278°F, 520 psia) 2 0 10Saturator Water PumpCentrifugal1,893 lpm @ 12 m H2O(500 gpm @ 40 ft H2O) 2 2 11Synthesis Gas ReheaterShell and tube83,007 kg/hr (183,000 lb/hr) 2 0 12Flare StackSelf-supporting, carbon steel, stainless steel top, pilot ignition313,432 kg/hr (691,000 lb/hr) syngas 2 0 13ASU Main Air CompressorCentrifugal, multi-stage5,267 m3/min @ 1.3 MPa(186,000 scfm @ 190 psia) 2 0 14Cold BoxVendor design2,087 tonne/day (2,300 tpd) of 95% purity oxygen 2 0 15Oxygen CompressorCentrifugal, multi-stage1,048 m3/min (37,000 scfm)Suction - 0.9 MPa (130 psia)Discharge - 6.5 MPa (940 psia) 2 0 16Primary Nitrogen CompressorCentrifugal, multi-stage3,483 m3/min (123,000 scfm)Suction - 0.4 MPa (60 psia)Discharge - 2.7 MPa (390 psia) 2 0 17Secondary Nitrogen CompressorCentrifugal, single-stage481 m3/min (17,000 scfm)Suction - 1.2 MPa (180 psia)Discharge - 2.7 MPa (390 psia) 2 0 18Gasifier Purge Nitrogen Boost CompressorCentrifugal, single-stage1,359 m3/min (48,000 scfm)Suction - 2.6 MPa (380 psia)Discharge - 3.2 MPa (470 psia) 2 0 Cost and Performance Baseline for Fossil Energy Plants 286 ACCOUNT 5 SYNGAS CLEANUP ACCOUNT 5B CO 2 COMPRESSION

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Mercury AdsorberSulfated carbon bed309,350 kg/hr (682,000 lb/hr) 35°C (95°F) 3.6 MPa (525 psia) 2 0 2Sulfur PlantClaus type139 tonne/day (154 tpd) 1 0 3Water Gas Shift ReactorsFixed bed, catalytic397,801 kg/hr (877,000 lb/hr) 216°C (420°F) 4.0 MPa (580 psia) 4 0 4Shift Reactor Heat Recovery ExchangersShell and TubeExchanger 1: 121 GJ/hr (114 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) 4 0 5Acid Gas Removal PlantTwo-stage Selexol316,154 kg/hr (697,000 lb/hr) 35°C (94°F) 3.6 MPa (520 psia) 2 0 6Hydrogenation ReactorFixed bed, catalytic18,243 kg/hr (40,220 lb/hr)232°C (450°F) 0.1 MPa (12.3 psia) 1 0 7Tail Gas Recycle CompressorCentrifugal13,713 kg/hr (30,232 lb/hr) 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1CO2 CompressorIntegrally geared, multi-stage centrifugal1,096 m3/min @ 15.3 MPa (38,700 scfm @ 2,215 psia) 4 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Gas TurbineAdvanced F class232 MW 2 0 2Gas Turbine GeneratorTEWAC260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0 Cost and Performance Baseline for Fossil Energy Plants 287 ACCOUNT 7 HRSG, DUCTING, AND STACK ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1StackCS plate, type 409SS liner76 m (250 ft) high x8.5 m (28 ft) diameter 1 0 2Heat Recovery Steam GeneratorDrum, multi-pressure with economizer section and integral deaeratorMain steam - 285,910 kg/hr, 12.4 MPa/534°C (630,323 lb/hr, 1,800 psig/993°F) Reheat steam - 244,783 kg/hr, 3.1 MPa/534°C (539,654 lb/hr, 452 psig/993°F) 2 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Steam TurbineCommercially available advanced steam turbine220 MW 12.4 MPa/534°C/534°C (1800 psig/ 993°F/993°F) 1 0 2Steam Turbine GeneratorHydrogen cooled, static excitiation240 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0 3Steam BypassOne per HRSG50% steam flow @ design steam conditions 2 0 4Surface CondenserSingle pass, divided waterbox including vacuum pumps1,467 GJ/hr (1,390 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F)1 0 Cost and Performance Baseline for Fossil Energy Plants 288 ACCOUNT 9 COOLING WATER SYSTEM ACCOUNT 10 SLAG RECOVERY AND HANDLING Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Circulating Water PumpsVertical, wet pit439,108 lpm @ 30 m(116,000 gpm @ 100 ft) 2 1 2Cooling TowerEvaporative, mechanical draft, multi-cell11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2437 GJ/hr (2310 MMBtu/hr) heat duty 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Slag Quench TankWater bath223,339 liters (59,000 gal) 2 0 2Slag CrusherRoll12 tonne/hr (13 tph) 2 0 3Slag DepressurizerLock Hopper12 tonne/hr (13 tph) 2 0 4Slag Receiving TankHorizontal, weir132,489 liters (35,000 gal) 2 0 5Black Water Overflow TankShop fabricated60,567 liters (16,000 gal) 2 6Slag ConveyorDrag chain12 tonne/hr (13 tph) 2 0 7Slag Separation ScreenVibrating12 tonne/hr (13 tph) 2 0 8Coarse Slag ConveyorBelt/bucket12 tonne/hr (13 tph) 2 0 9Fine Ash Settling TankVertical, gravity189,271 liters (50,000 gal) 2 0 10Fine Ash Recycle PumpsHorizontal centrifugal38 lpm @ 14 m H2O(10 gpm @ 46 ft H2O) 2 2 11Grey Water Storage TankField erected60,567 liters (16,000 gal) 2 0 12Grey Water PumpsCentrifugal227 lpm @ 433 m H2O(60 gpm @ 1,420 ft H2O) 2 2 13Slag Storage BinVertical, field erected816 tonne (900 tons) 2 0 14Unloading EquipmentTelescoping chute100 tonne/hr (110 tph) 1 0 Cost and Performance Baseline for Fossil Energy Plants 289 ACCOUNT 11 ACCESSORY ELECTRIC PLANT ACCOUNT 12 INSTRUMENTATION AND CONTROLS Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1CTG Step-up TransformerOil-filled24 kV/345 kV, 260 MVA, 3-ph, 60 Hz 2 0 2STG Step-up TransformerOil-filled24 kV/345 kV, 240 MVA, 3-ph, 60 Hz 1 0 3High Voltage Auxiliary TransformerOil-filled345 kV/13.8 kV, 74 MVA, 3-ph, 60 Hz 2 0 4Medium Voltage Auxiliary TransformerOil-filled24 kV/4.16 kV, 46 MVA, 3-ph, 60 Hz 1 1 5Low Voltage TransformerDry ventilated4.16 kV/480 V, 7 MVA, 3-ph, 60 Hz 1 1 6CTG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled24 kV, 3-ph, 60 Hz 2 0 7STG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled24 kV, 3-ph, 60 Hz 1 0 8Medium Voltage SwitchgearMetal clad4.16 kV, 3-ph, 60 Hz 1 1 9Low Voltage SwitchgearMetal enclosed480 V, 3-ph, 60 Hz 1 1 10Emergency Diesel GeneratorSized for emergency shutdown750 kW, 480 V, 3-ph, 60 Hz 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1DCS - Main ControlMonitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W)Operator stations/printers and engineering stations/printers 1 0 2DCS - ProcessorMicroprocessor with redundant input/outputN/A 1 0 3DCS - Data HighwayFiber opticFully redundant, 25% spare 1 0 Cost and Performance Baseline for Fossil Energy Plants 290 3.4.11 The cost estimating methodology was described previously in Section Case 6 - Cost Estimating 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 owner's costs, TOC and TASC. Exhibit 3-100 shows the initial and annual O&M costs.

The estimated TOC of the Shell gasifier with CO 2 capture is $

3,904/kW. Process contingenc y represents 3.4 percent of the TOC and project contingency represents 11.4 percent. The COE, including CO 2 TS&M costs of 5.7 mills/kWh, is 1 1 9.5 mills/kWh.

Cost and Performance Baseline for Fossil Energy Plants 291 Exhibit 3-98 Case 6 Total Plant Cost Summary Client: USDOE/NETLReport Date:2010-Jan-14Project: Bituminous Baseline StudyCase: Case 6 - Shell 500MW IGCC w/ CO2Plant Size: 496.9MW,netEstimate Type: ConceptualCost Base (Jun) 2007($x1000)AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING$13,881$2,580$10,765$0$0$27,226$2,471$0$5,939$35,636$72 2COAL & SORBENT PREP & FEED$109,935$8,758$18,287$0$0$136,980$11,879$0$29,772$178,630$360 3FEEDWATER & MISC. BOP SYSTEMS$9,471$7,207$9,699$0$0$26,377$2,492$0$6,717$35,585$72 4GASIFIER & ACCESSORIES4.1Gasifier, Syngas Cooler & Auxiliaries$144,815$0$61,614$0$0$206,430$18,447$28,271$38,955$292,103$5884.2Syngas Cooling (w/4.1)w/4.1$0w/ 4.1$0$0$0$0$0$0$0$04.3ASU/Oxidant Compression$173,504$0w/equip.$0$0$173,504$16,818$0$19,032$209,354$4214.4-4.9Other Gasification Equipment$25,591$9,849$15,118$0$0$50,557$4,851$0$11,805$67,213$135SUBTOTAL 4$343,911$9,849$76,732$0$0$430,492$40,115$28,271$69,793$568,670$1,145 5AGas Cleanup & Piping$91,097$3,993$77,814$0$0$172,904$16,706$26,070$43,284$258,964$521 5B CO 2 REMOVAL & COMPRESSION$17,811$0$10,524$0$0$28,335$2,728$0$6,213$37,276$75 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine Generator$92,026$0$6,583$0$0$98,609$9,348$9,861$11,782$129,599$2616.2-6.9Combustion Turbine Other

$0$806$892$0$0$1,699$159$0$557$2,415$5SUBTOTAL 6$92,026$806$7,475$0$0$100,307$9,507$9,861$12,339$132,014$266 7HRSG, DUCTING & STACK7.1Heat Recovery Steam Generator$33,709$0$4,793$0$0$38,502$3,661$0$4,216$46,379$937.2-7.9Ductwork and Stack$3,380$2,410$3,156$0$0$8,946$829$0$1,591$11,367$23SUBTOTAL 7$37,089$2,410$7,949$0$0$47,448$4,490$0$5,807$57,745$116 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$23,934$0$4,000$0$0$27,935$2,680$0$3,061$33,676$688.2-8.9Turbine Plant Auxiliaries and Steam Piping$9,162$818$6,331$0$0$16,312$1,486$0$3,487$21,285$43SUBTOTAL 8$33,096$818$10,332$0$0$44,246$4,166$0$6,549$54,961$111 9COOLING WATER SYSTEM$9,932$9,472$8,108$0$0$27,512$2,555$0$6,134$36,202$73 10ASH/SPENT SORBENT HANDLING SYS$18,585$1,433$9,223$0$0$29,241$2,805$0$3,501$35,547$72 11ACCESSORY ELECTRIC PLANT$30,536$12,099$23,664$0$0$66,300$5,703$0$13,663$85,666$172 12INSTRUMENTATION & CONTROL$11,002$2,024$7,089$0$0$20,115$1,823$1,006$3,823$26,766$54 13IMPROVEMENTS TO SITE$3,346$1,972$8,255$0$0$13,572$1,340$0$4,474$19,386$39 14BUILDINGS & 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$3,181TOTAL PLANT COST

SUMMARY

Cost and Performance Baseline for Fossil Energy Plants 292 Exhibit 3-99 Case 6 Total Plant Cost Details AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING1.1Coal Receive & Unload$3,645$0$1,781$0$0$5,427$486$0$1,183$7,095$141.2Coal Stackout & Reclaim$4,711$0$1,142$0$0$5,853$513$0$1,273$7,639$151.3Coal Conveyors & Yd Crush$4,380$0$1,130$0$0$5,510$484$0$1,199$7,192$141.4Other Coal Handling$1,146$0$261$0$0$1,407$123$0$306$1,836$41.5Sorbent Receive & Unload

$0$0$0$0$0$0$0$0$0$0$01.6Sorbent Stackout & Reclaim

$0$0$0$0$0$0$0$0$0$0$01.7Sorbent Conveyors

$0$0$0$0$0$0$0$0$0$0$01.8Other Sorbent Handling

$0$0$0$0$0$0$0$0$0$0$01.9Coal & Sorbent Hnd.Foundations

$0$2,580$6,450$0$0$9,030$865$0$1,979$11,874$24SUBTOTAL 1.$13,881$2,580$10,765$0$0$27,226$2,471$0$5,939$35,636$72 2COAL & SORBENT PREP & FEED2.1Coal Crushing & Drying$41,765$2,509$6,086$0$0$50,360$4,346$0$10,941$65,647$1322.2Prepared Coal Storage & Feed$1,978$473$310$0$0$2,762$236$0$600$3,598$72.3Dry Coal Injection System$65,103$756$6,046$0$0$71,905$6,193$0$15,620$93,718$1892.4Misc.Coal Prep & Feed$1,088$792$2,373$0$0$4,253$391$0$929$5,573$112.5Sorbent Prep Equipment

$0$0$0$0$0$0$0$0$0$0$02.6Sorbent Storage & Feed

$0$0$0$0$0$0$0$0$0$0$02.7Sorbent Injection System

$0$0$0$0$0$0$0$0$0$0$02.8Booster Air Supply System

$0$0$0$0$0$0$0$0$0$0$02.9Coal & Sorbent Feed Foundation

$0$4,228$3,471$0$0$7,700$713$0$1,683$10,095$20SUBTOTAL 2.$109,935$8,758$18,287$0$0$136,980$11,879$0$29,772$178,630$360 3FEEDWATER & MISC. BOP SYSTEMS3.1Feedwater System$2,492$4,279$2,259$0$0$9,029$836$0$1,973$11,839$243.2Water Makeup & Pretreating

$701$73$392$0$0$1,167$111$0$383$1,661$33.3Other Feedwater Subsystems$1,363$461$415$0$0$2,238$201$0$488$2,928$63.4Service Water Systems

$401$827$2,869$0$0$4,097$400$0$1,349$5,845$123.5Other Boiler Plant Systems$2,154$835$2,069$0$0$5,057$480$0$1,107$6,644$133.6FO Supply Sys & Nat Gas

$313$591$551$0$0$1,454$140$0$319$1,913$43.7Waste Treatment Equipment

$981$0$598$0$0$1,579$154$0$520$2,252$53.8Misc. Power Plant Equipment$1,066$143$547$0$0$1,756$170$0$578$2,503$5SUBTOTAL 3.$9,471$7,207$9,699$0$0$26,377$2,492$0$6,717$35,585$72 4GASIFIER & ACCESSORIES4.1Gasifier, Syngas Cooler & Auxiliaries (Shell)$144,815$0$61,614$0$0$206,430$18,447$28,271$38,955$292,103$5884.2Syngas Coolingw/4.1$0w/ 4.1$0$0$0$0$0$0$0$04.3ASU/Oxidant Compression$173,504$0w/equip.$0$0$173,504$16,818$0$19,032$209,354$4214.4LT Heat Recovery & FG Saturation$25,591$0$9,728$0$0$35,319$3,447$0$7,753$46,519$944.5Misc. Gasification Equipmentw/4.1&4.2$0w/4.1&4.2$0$0$0$0$0$0$0$04.6Flare Stack System

$0$1,406$572$0$0$1,978$190$0$433$2,601$54.8Major Component Riggingw/4.1&4.2$0w/4.1&4.2$0$0$0$0$0$0$0$04.9Gasification Foundations

$0$8,443$4,818$0$0$13,261$1,214$0$3,619$18,094$36SUBTOTAL 4.$343,911$9,849$76,732$0$0$430,492$40,115$28,271$69,793$568,670$1,145 Cost and Performance Baseline for Fossil Energy Plants 293 Exhibit 3-99 Case 6 Total Plant Cost Details (Continued) AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 5AGAS CLEANUP & PIPING5A.1Double Stage Selexol$70,179$0$59,549$0$0$129,728$12,546$25,946$33,644$201,864$4065A.2Elemental Sulfur Plant$10,017$1,996$12,924$0$0$24,937$2,422$0$5,472$32,831$665A.3Mercury Removal$1,410$0$1,073$0$0$2,483$240$124$569$3,417$75A.4Shift Reactors$7,366$0$2,965$0$0$10,330$990$0$2,264$13,585$275A.5Particulate Removalw/4.1$0w/4.1$0$0$0$0$0$0$0$05A.5Blowback Gas Systems$2,125$358$201$0$0$2,684$255$0$588$3,526$75A.6Fuel Gas Piping

$0$814$570$0$0$1,384$128$0$303$1,815$45A.9HGCU Foundations

$0$824$532$0$0$1,356$125$0$444$1,925$4SUBTOTAL 5A.$91,097$3,993$77,814$0$0$172,904$16,706$26,070$43,284$258,964$521 5BCO2 COMPRESSION5B.1CO2 Removal System

$0$0$0$0$0$0$0$0$0$0$05B.2CO2 Compression & Drying$17,811$0$10,524$0$0$28,335$2,728$0$6,213$37,276$75SUBTOTAL 5B.$17,811$0$10,524$0$0$28,335$2,728$0$6,213$37,276$75 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine Generator$92,026$0$6,583$0$0$98,609$9,348$9,861$11,782$129,599$2616.2Open$0$0$0$0$0$0$0$0$0$0$06.3Compressed Air Piping

$0$0$0$0$0$0$0$0$0$0$06.9Combustion Turbine Foundations

$0$806$892$0$0$1,699$159$0$557$2,415$5SUBTOTAL 6.$92,026$806$7,475$0$0$100,307$9,507$9,861$12,339$132,014$266 7HRSG, DUCTING & STACK7.1Heat Recovery Steam Generator$33,709$0$4,793$0$0$38,502$3,661$0$4,216$46,379$937.2Open$0$0$0$0$0$0$0$0$0$0$07.3Ductwork$0$1,733$1,236$0$0$2,969$260$0$646$3,875$87.4Stack$3,380$0$1,270$0$0$4,650$445$0$510$5,605$117.9HRSG,Duct & Stack Foundations

$0$677$650$0$0$1,328$124$0$435$1,887$4SUBTOTAL 7.$37,089$2,410$7,949$0$0$47,448$4,490$0$5,807$57,745$116 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$23,934$0$4,000$0$0$27,935$2,680$0$3,061$33,676$688.2Turbine Plant Auxiliaries

$165$0$378$0$0$543$53$0$60$656$18.3Condenser & Auxiliaries$4,579$0$1,463$0$0$6,042$578$0$662$7,282$158.4Steam Piping$4,418$0$3,108$0$0$7,526$647$0$2,043$10,215$218.9TG Foundations

$0$818$1,383$0$0$2,201$209$0$723$3,132$6SUBTOTAL 8.$33,096$818$10,332$0$0$44,246$4,166$0$6,549$54,961$111 9COOLING WATER SYSTEM9.1Cooling Towers$6,867$0$1,249$0$0$8,116$773$0$1,333$10,222$219.2Circulating Water Pumps$1,791$0$127$0$0$1,919$162$0$312$2,393$59.3Circ.Water System Auxiliaries

$151$0$21$0$0$172$16$0$28$217$09.4Circ.Water Piping

$0$6,288$1,630$0$0$7,918$716$0$1,727$10,360$219.5Make-up Water System

$381$0$544$0$0$925$89$0$203$1,217$29.6Component Cooling Water Sys

$742$888$632$0$0$2,262$212$0$495$2,968$69.9Circ.Water System Foundations

$0$2,296$3,904$0$0$6,200$588$0$2,037$8,825$18SUBTOTAL 9.$9,932$9,472$8,108$0$0$27,512$2,555$0$6,134$36,202$73 Cost and Performance Baseline for Fossil Energy Plants 294 Exhibit 3-99 Case 6 Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 10ASH/SPENT SORBENT HANDLING SYS10.1Slag Dewatering & Cooling$16,178$0$7,978$0$0$24,156$2,321$0$2,648$29,125$5910.2Gasifier Ash Depressurizationw/10.1w/10.1w/10.1$0$0$0$0$0$0$0$010.3Cleanup Ash Depressurizationw/10.1w/10.1w/10.1$0$0$0$0$0$0$0$010.4High Temperature Ash Piping

$0$0$0$0$0$0$0$0$0$0$010.5Other Ash Recovery Equipment

$0$0$0$0$0$0$0$0$0$0$010.6Ash Storage Silos

$546$0$594$0$0$1,139$111$0$187$1,437$310.7Ash Transport & Feed Equipment

$732$0$177$0$0$908$85$0$149$1,142$210.8Misc. Ash Handling Equipment$1,130$1,385$414$0$0$2,929$279$0$481$3,689$710.9Ash/Spent Sorbent Foundation

$0$48$61$0$0$109$10$0$36$155$0SUBTOTAL 10.$18,585$1,433$9,223$0$0$29,241$2,805$0$3,501$35,547$72 11ACCESSORY ELECTRIC PLANT11.1Generator Equipment

$901$0$891$0$0$1,792$171$0$196$2,159$411.2Station Service Equipment$4,510$0$406$0$0$4,916$453$0$537$5,906$1211.3Switchgear & Motor Control $8,338$0$1,516$0$0$9,854$914$0$1,615$12,383$2511.4Conduit & Cable Tray

$0$3,873$12,777$0$0$16,650$1,610$0$4,565$22,826$4611.5Wire & Cable

$0$7,400$4,862$0$0$12,262$891$0$3,288$16,442$3311.6Protective Equipment

$0$679$2,471$0$0$3,150$308$0$519$3,976$811.7Standby Equipment

$224$0$219$0$0$443$42$0$73$558$111.8Main Power Transformers$16,564$0$136$0$0$16,699$1,263$0$2,694$20,656$4211.9Electrical Foundations

$0$147$386$0$0$534$51$0$175$760$2SUBTOTAL 11.$30,536$12,099$23,664$0$0$66,300$5,703$0$13,663$85,666$172 12INSTRUMENTATION & CONTROL12.1IGCC Control Equipmentw/4.1$0w/4.1$0$0$0$0$0$0$0$012.2Combustion Turbine Controlw/6.1$0w/6.1$0$0$0$0$0$0$0$012.3Steam Turbine Controlw/8.1$0w/8.1$0$0$0$0$0$0$0$012.4Other Major Component Control$1,086$0$725$0$0$1,811$171$91$311$2,384$512.5Signal Processing Equipmentw/12.7$0w/12.7$0$0$0$0$0$0$0$012.6Control Boards,Panels & Racks

$250$0$160$0$0$410$39$20$94$563$112.7Computer & Accessories$5,794$0$185$0$0$5,979$549$299$683$7,510$1512.8Instrument Wiring & Tubing

$0$2,024$4,137$0$0$6,161$523$308$1,748$8,740$1812.9Other I & C Equipment$3,873$0$1,881$0$0$5,753$541$288$987$7,570$15SUBTOTAL 12.$11,002$2,024$7,089$0$0$20,115$1,823$1,006$3,823$26,766$54 Cost and Performance Baseline for Fossil Energy Plants 295 Exhibit 3-99 Case 6 Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 13IMPROVEMENTS TO SITE13.1Site Preparation

$0$105$2,244$0$0$2,349$233$0$775$3,356$713.2Site Improvements

$0$1,867$2,481$0$0$4,348$429$0$1,433$6,210$1213.3Site Facilities$3,346$0$3,530$0$0$6,876$678$0$2,266$9,820$20SUBTOTAL 13.$3,346$1,972$8,255$0$0$13,572$1,340$0$4,474$19,386$39 14BUILDINGS & STRUCTURES14.1Combustion Turbine Area

$0$265$150$0$0$414$36$0$90$541$114.2Steam Turbine Building

$0$2,071$2,950$0$0$5,021$462$0$822$6,306$1314.3Administration Building

$0$857$622$0$0$1,479$132$0$242$1,853$414.4Circulation Water Pumphouse

$0$161$85$0$0$246$22$0$40$308$114.5Water Treatment Buildings

$0$586$572$0$0$1,158$105$0$189$1,452$314.6Machine Shop

$0$439$300$0$0$739$66$0$121$926$214.7Warehouse

$0$709$457$0$0$1,166$103$0$190$1,460$314.8Other Buildings & Structures

$0$424$330$0$0$755$67$0$164$987$214.9Waste Treating Building & Str.

$0$949$1,813$0$0$2,762$257$0$604$3,623$7SUBTOTAL 14.

$0$6,461$7,281$0$0$13,741$1,250$0$2,463$17,455$35TOTAL COST$821,717$69,882$293,196$0$0$1,184,795$110,031$65,208$220,470$1,580,505$3,181Owner's CostsPreproduction Costs6 Months All Labor$13,300$271 Month Maintenance Materials$2,951$61 Month Non-fuel Consumables

$378$11 Month Waste Disposal

$278$125% of 1 Months Fuel Cost at 100% CF$1,621$32% of TPC$31,610$64Total$50,138$101Inventory Capital60 day supply of fuel and consumables at 100% CF$13,459$270.5% of TPC (spare parts)$7,903$16Total$21,361$43Initial Cost for Catalyst and Chemicals$7,224$15Land$900$2Other Owner's Costs$237,076$477Financing Costs$42,674$86Total Overnight Costs (TOC)$1,939,878$3,904TASC Multiplier(IOU, high-risk, 35 year)1.140Total As-Spent Cost (TASC)$2,211,461$4,451 Cost and Performance Baseline for Fossil Energy Plants 296 Exhibit 3-100 Case 6 Initial and Annual Operating and Maintenance Costs INITIAL & ANNUAL O&M EXPENSESCost Base (Jun):

2007Case 6 - Shell 500MW IGCC w/ CO2Heat Rate-net (Btu/kWh):10,924 MWe-net: 497 Capacity Factor (%):

80OPERATING & MAINTENANCE LABOROperating Labor Operating Labor Rate(base):34.65$/hour Operating Labor Burden:30.00% of base Labor O-H Charge Rate:25.00% of laborTotal Operating Labor Requirements(O.J.)per Shift:1 unit/mod. Plant Skilled Operator2.02.0 Operator10.010.0 Foreman1.01.0 Lab Tech's, etc.3.03.0 TOTAL-O.J.'s16.016.0Annual CostAnnual Unit Cost

$$/kW-netAnnual Operating Labor Cost$6,313,507$12.707Maintenance Labor Cost$14,966,466$30.122Administrative & Support Labor$5,319,993$10.707Property Taxes and Insurance$31,610,092$63.620TOTAL FIXED OPERATING COSTS$58,210,058$117.156VARIABLE OPERATING COSTS$/kWh-netMaintenance Material Cost$28,329,484$0.00814ConsumablesConsumptionUnit Initial Fill Initial Fill /Day Cost CostWater (/1000 gallons) 04,0561.08$0$1,281,009$0.00037ChemicalsMU & WT Chem. (lbs) 024,1630.17$0$1,221,101$0.00035Carbon (Mercury Removal) (lb)117,815 1611.05$123,726$49,490$0.00001COS Catalyst (m3) 0 02,397.36$0$0$0.00000Water Gas Shift Catalyst (ft3)6,4704.43498.83$3,227,388$645,478$0.00019Selexol Solution (gal)289,068 9213.40$3,873,002$360,241$0.00010SCR Catalyst (m3) 0 00.00$0$0$0.00000Ammonia (19% NH3) (ton) 0 00.00$0$0$0.00000Claus Catalyst (ft3)w/equip.1.93131.27$0$74,040$0.00002Subtotal Chemicals$7,224,116$2,350,349$0.00068OtherSupplemental Fuel (MBtu) 0 00.00$0$0$0.00000Gases, N2 etc. (/100scf) 0 00.00$0$0$0.00000L.P. Steam (/1000 pounds) 0 00.00$0$0$0.00000Subtotal Other

$0$0$0.00000Waste DisposalSpent Mercury Catalyst (lb.)

0 1610.42$0$19,655$0.00001Flyash (ton) 0 00.00$0$0$0.00000Slag (ton) 0 55916.23$0$2,649,268$0.00076 Subtotal-Waste Disposal

$0$2,668,923$0.00077By-products & EmissionsSulfur (ton) 0 1400.00$0$0$0.00000Subtotal By-Products

$0$0$0.00000TOTAL VARIABLE OPERATING COSTS$7,224,116$34,629,764$0.00995Fuel (ton) 05,58338.18$0$62,251,620$0.01788 Cost and Performance Baseline for Fossil Energy Plants 297 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 1 CF is 80% for all IGCC case s 2 COE and LCOE are defined in Section 2.7. PERFORMANCECase 1Case 2Case 3Case 4Case 5Case 6CO2 Capture 0%90%0%90%0%90%Gross Power Output (kWe)747,800734,000738,200703,700737,000673,400Auxiliary Power Requirement (kWe)125,750190,750113,140190,090108,020176,540Net Power Output (kWe)622,050543,250625,060513,610628,980496,860Coal Flowrate (lb/hr)466,901487,011459,958484,212436,646465,264Natural Gas Flowrate (lb/hr)N/AN/AN/AN/AN/AN/AHHV Thermal Input (kWth)1,596,3201,665,0741,572,5821,655,5031,492,8781,590,722Net Plant HHV Efficiency (%)39.0%32.6%39.7%31.0%42.1%31.2%Net Plant HHV Heat Rate (Btu/kWh)8,75610,4588,58510,9988,09910,924Raw Water Withdrawal (gpm/MWnet)7.610.77.011.16.611.3Process Water Discharge (gpm/MWnet)1.62.01.42.11.22.0Raw Water Consumption (gpm/MWnet)6.08.75.59.05.39.3 CO 2 Emissions (lb/MMBtu) 197 20 199 20 197 20 CO 2 Emissions (lb/MWhgross)1,434 1521,448 1581,361 161 CO 2 Emissions (lb/MWhnet)1,723 2061,710 2171,595 218 SO 2 Emissions (lb/MMBtu)0.00120.00220.01170.00220.00420.0021 SO 2 Emissions (lb/MWhgross)0.00900.01660.08520.01730.02900.0171NOx Emissions (lb/MMBtu)0.0590.0490.0600.0490.0590.049NOx Emissions (lb/MWhgross)0.4300.3760.4340.3960.4090.396PM Emissions (lb/MMBtu)0.00710.00710.00710.00710.00710.0071PM Emissions (lb/MWhgross)0.0520.0550.0520.0570.0490.057Hg Emissions (lb/TBtu)0.5710.5710.5710.5710.5710.571Hg Emissions (lb/MWhgross)4.16E-064.42E-064.15E-064.59E-063.95E-064.61E-06COSTTotal Plant Cost (2007$/kW)1,9872,7111,9132,8172,2173,181Total Overnight Cost (2007$/kW)2,4473,3342,3513,4662,7163,904 Bare Erected Cost1,5282,0321,4702,1131,6952,385 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 723Total Overnight Cost (2007$ x 1,000)1,521,8801,811,4111,469,5771,780,2901,708,5241,939,878Total As Spent Capital (2007$/kW)2,7893,8012,6803,9523,0974,451COE (mills/kWh, 2007$)1,276.3105.674.0110.381.3119.4 CO2 TS&M Costs0.05.20.05.50.05.6 Fuel Costs14.317.114.018.013.317.9 Variable Costs7.39.37.29.87.89.9 Fixed Costs11.314.811.115.512.116.7 Capital Costs43.459.141.761.548.269.2LCOE (mills/kWh, 2007$)1,296.7133.993.8139.9103.1151.4Integrated Gasification Combined CycleGEE R+QCoP E-Gas FSQShell Cost and Performance Baseline for Fossil Energy Plants 298 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 1 6 percent higher.

Exhibit 3-102 Plant Capital Cost for IGCC Cases The GEE gasifier is the low cost technology in the CO 2 capture cases, with CoP about 4 percent higher and Shell about 1 7 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.

2,4473,3342,3513,4662,7163,9042,7893,8012,6803,9523,0974,451 01,0002,0003,0004,0005,0006,0007,000TOCTASCTOCTASCTOCTASCTOCTASCTOCTASCTOCTASCGEEGEE w/ CO2 CaptureCoPCoP w/ CO2 CaptureShellShell w/ CO2 CaptureTOC or TASC, $/kW (2007$)TASCOwner's CostProcess ContingencyProject ContingencyHome Office ExpenseBare Erected Cost Cost and Performance Baseline for Fossil Energy Plants 299 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 CO 2 capture averages 42 percent ($3,5 68/kW versus

$2 , 504/kW). The COE is shown for the IGCC cases in Exhibit 3-103. Exhibit 3-103 COE for IGCC Cases The following observations can be made:

The COE is dominated by capital costs, at least 5 6 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 i s 10 percent higher than CoP (compared to 1 6 percent higher T OC). 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 1 05.7 mills/kWh for GEE to 1 1 9.5 mills/kWh for Shell with CoP intermediate at 1 10.4 mills/kWh. The COE CO 2 capture premium for the IGCC cases averages 4 5 percent (range of 3 9 to 4 9 percent). 43.459.141.761.548.269.211.314.811.115.512.116.77.39.37.29.87.89.914.317.114.018.013.317.95.35.65.7 0 20 40 60 80 100 120 140 160GEEGEE w/CO2 CaptureCoPCoP w/ CO2 CaptureShellShell w/ CO2 CaptureCOE, mills/kWh (2007$)CO2 TS&M CostsFuel CostsVariable CostsFixed CostsCapital Costs Cost and Performance Baseline for Fossil Energy Plants 300 The CO 2 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 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 CO 2 capture was calculated as an avoided cost. The results for the IGCC CO 2 capture cases are shown in Exhibit 3-106. The first year cost of CO 2 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 CO 2 avoided is higher when using SC PC without CO 2 capture as the technology reference. Avoided costs average $75/tonne ($68/ton) with a range of

$66.1-$86/tonne ($60-$7 8/ton). The avoided cost is elevated because SC PC without capture has a significantly lower COE than any IGCC technology

. 0 50 100 150 200 250 300 0 10 20 30 40 50 60 70 80 90 100COE, mills/kWh (2007$)Capacity Factor, %Shell w/CO2 CaptureCoP w/CO2 CaptureGEE w/CO2 CaptureShell No CaptureGEE No CaptureCoP No CaptureCoal = $1.64/MMBtu Cost and Performance Baseline for Fossil Energy Plants 301 Exhibit 3-105 Coal Price Sensitivity of IGCC Cases Exhibit 3-106 Cost of CO 2 Avoided in IGCC Cases 0 20 40 60 80 100 120 140 160 00.5 11.5 22.5 33.5 4COE, mills/kWh (2007$)Coal Price, $/MMBtuShell w/CO2 CaptureCoP w/CO2 CaptureGEE w/CO2 CaptureShell No CaptureGEE No CaptureCoP No CaptureCapacity factor = 80%

43 54 61 66 73 86 0102030405060708090100GEECoPShellFirst Year CO 2Avoided Cost, $/tonne (2007$)Avoided Cost (Analogous Technology w/o Capture Reference)Avoided Cost (SC PC w/o Capture Reference)

Cost and Performance Baseline for Fossil Energy Plants 302 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 CO 2 capture cases the efficiency of the three gasifiers rang es 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 CO 2 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 CO 2 capture is 1 6.3 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 CO 2 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.

CO 2 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 Cost and Performance Baseline for Fossil Energy Plants 303 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 O 2 for both "standard" syngas in the non

-capture cases and for high hydrogen syngas in the CO 2 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 SO 2 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 SO 2 emissions (0.005 kg/GJ (0.012 lb/MMBtu)) of the six IGCC cases because refrigerated MDEA has the lowest H 2 S removal efficiency of the AGR technologies. The two-stage Selexol process used for each of the CO 2 capture cases resulted in lower SO 2 emissions because the unit was designed to meet the CO 2 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 7 3-7 5 percent in CO 2 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 CO 2 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 CO 2 capture cases also shows little variation with GEE the lowest, CoP only 3.4 percent higher and Shell about 7 percent higher.

Cost and Performance Baseline for Fossil Energy Plants 304 Exhibit 3-108 Raw Water Withdrawal and Consumption in IGCC Cases 0 2 4 6 8 10 12GEEGEE w/CO2 CaptureCoPCoP w/ CO2 CaptureShellShell w/ CO2 Capture7.610.77.011.16.611.36.08.75.59.05.39.3Water, gpm/MWnetRaw Water WithdrawalProcess DischargeRaw Water Consumption Cost and Performance Baseline for Fossil Energy Plants 305 4. 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.

PULVERIZED COAL RANKINE CYCLE PLANTS The PC cases are evaluated with and without CO 2 capture on a common 550 MWe net basis. The designs that include CO 2 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 CO 2 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 For subcritical cases (9 and 10)

- 16.5 MPa/566°C/566°C (2

, 400 psig/1 ,050°F/1 ,050°F) ]. Based on the OEM responses, the following single

-reheat steam conditions were selected for the study: 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 study's 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]).

Cost and Performance Baseline for Fossil Energy Plants 306 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 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).

Coal and Sorbent Receiving and Storage 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 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. Steam Generator and Ancillaries 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

.

Cost and Performance Baseline for Fossil Energy Plants 307 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.

The steam generator includes the following for both subcritical and SC PCs: Scope Drum-type evaporator (subcritical only)

Economizer OFA system Once-through type steam generator (SC only) Spray type desuperheater Forced draft (FD) fans Startup circuit, including integral separators (SC only) Soot blower system Primary air (PA) fans Water-cooled furnace, dry bottom Air preheaters (Ljungstrom type)

Induced draft (ID) fans 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:

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.

Feedwater and Steam 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 economize r 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.

Cost and Performance Baseline for Fossil Energy Plants 308 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 int er-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.

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.

Air and Combustion Products 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. 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

[Fuel Feed 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.

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 Secti on Ash Removal 4.1.9. The steam generator incorporates fly ash hoppers under the economizer outlet and air heater outlet. 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.

Burners Cost and Performance Baseline for Fossil Energy Plants 309 Oil-fired pilot torches are provided for each coal burner for ignition, warm

-up and flame stabilization at startup and low loads.

Each steam generator is furnished with two vertical

-shaft Ljungstrom regenerative type air preheaters. These units are driven by electric motors through gear reducers.

Air Preheaters 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.

Soot Blowers 4.1.3 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.

NO x Control System 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 N 2 and H 2O. 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.

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 (500F) to 455°C (850F). 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.

SCR Operation Description The ammonia storage and injection system consists of the unloading facilities, bulk storage tank, vaporizers, dilution air skid, and injection grid.

Cost and Performance Baseline for Fossil Energy Plants 310 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 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

[Particulate Control 68 4.1.5 ]. 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.

Mercury removal is based on a coal Hg content of 0.15 ppmd. The basis for the coal Hg concentration was discussed in Section Mercury Removal 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 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 SO 2 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 CO 2 capture, the SO 2 content of the scrubbed gases must be further reduced to approximately 10 ppmv to minimize formation of amine heat stable salts

(HSS) during the CO 2 absorption process. The CDR unit includes a polishing scrubber to reduce the FG SO 2 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:

Flue Gas Desulfurization Limestone Handling and Reagent Preparation FGD Scrubber Byproduct Dewatering

Cost and Performance Baseline for Fossil Energy Plants 311 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.

Reagent Preparation System 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.

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.

FGD Scrubber 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

-CO 2 capture cases) or 32°C (89°F) (CO 2 capture cases) is not necessary.

Cost and Performance Baseline for Fossil Energy Plants 312 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.

Byproduct Dewatering 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 CaCO 3 and CaSO 42O 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. 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.

Hydrocyclones 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.

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 Horizontal Vacuum Belt Filters

Cost and Performance Baseline for Fossil Energy Plants 313 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 A Carbon Dioxide Recovery (CDR) facility is used in Cases 10 and 12 to remove 90 percent of the CO 2 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 CO 2 than the raw flue gas because of the CO 2 liberated from the limestone in the FGD absorber vessel. The CDR is comprised of th e flue gas supply, SO 2 polishing, CO 2 absorption, solvent stripping and reclaiming, and CO 2 compression and drying.

Carbon Dioxide Recovery Facility The CO 2 absorption/stripping/solvent reclaim process for Cases 10 and 12 is based on the Fluo r Econamine FG Plus SM technology

[69 , 70Exhibit 4-1]. A typical flowsheet is shown in

. The Econamine FG Plus process uses a formulation of MEA and a proprietary corrosion inhibitor to recover CO 2 from the flue gas. This process is designed to recover high

-purity CO 2 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 200 3 IEA study, [

71 The complexity of the control and operation of the plant is significantly decreased

] in the following ways:

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 ].

Cost and Performance Baseline for Fossil Energy Plants 314 Exhibit 4-1 Fluor Econamine FG Plus SM Typical Flow Diagram

Cost and Performance Baseline for Fossil Energy Plants 315 To minimize the accumulation of HSS, the incoming flue gas must have an SO 2 concentration of 10 ppmv or less. The gas exiting the FGD system passes through an SO 2 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 SO 2 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.

SO 2 Polishing and FG Cooling and Supply 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 CO 2 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 CO 2 absorber tower.

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 CO 2 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 ,000-2 00,000 gpm).

Circulating Water System The cooled flue gas enters the bottom of the CO 2 Absorber and flows up through the tower countercurrent to a stream of lean MEA

-based solvent. Approximately 90 percent of the CO 2 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 CO 2 from the FG and leaves the bottom of the absorber with the absorbed CO

2. 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 CO 2 carrying capacity of the solvent is increased at lower temperature, which reduces the solvent circulation rate.

CO 2 Absorption 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 CO 2 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 Water Wash Section

Cost and Performance Baseline for Fossil Energy Plants 316 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 CO 2 Absorber. The wash water level is maintained by wash water makeup.

The rich solvent from the bottom of the CO 2 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 CO

2. 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 CO 2 Absorber, completing the circulating solvent circuit. Rich/Lean Amine Heat Exchange System The purpose of the Solvent Stripper is to separate the CO 2 from the rich solvent feed exiting the bottom of the CO 2 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 CO 2 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 CO 2, 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 CO 2-rich gas is then delivered to the CO 2 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 CO 2 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 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.

Solvent Reclaimer 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 Steam Condensate

Cost and Performance Baseline for Fossil Energy Plants 317 Condensate Drum and returned to the steam cycle between BFW heaters 4 a nd 5 via the Solvent Reboiler Condensate Pumps

. A proprietary corrosion inhibitor is intermittently injected into the CO 2 Absorber rich solvent bottoms outlet line. This additive is to help control the rate of corrosion throughout the CO 2 recovery plant system.

Corrosion Inhibitor System In the compression section, the CO 2 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 Gas Compression and Drying System Exhibit 4-2. Exhibit 4-2 CO 2 Compressor Interstage Pressures Stage Outlet Pressure, 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 CO 2 stream is dehydrated to a dewpoint of

-40ºC (-40°F) with triethylene glycol. The virtually moisture

-free SC CO 2 stream is delivered to the plant battery limit as sequestration ready. CO 2 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 CO 2 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 CO 2 compression intercooling configuration to enable integration into a LiBr

-H 2O absorption refrigeration system, where water is the refrigerant. In the CO 2 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 CO 2 compression to the LiBr

-H 2O 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 CO 2 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 Cost and Performance Baseline for Fossil Energy Plants 318 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 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 ). Power Generation 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

[74The 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.

]. 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.

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 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.

Balance of Plant

Cost and Performance Baseline for Fossil Energy Plants 319 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 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 a nd 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. 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.

Feedwater 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.

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.

Main and Reheat Steam

Cost and Performance Baseline for Fossil Energy Plants 320 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. The function of the extraction steam system is to convey steam from turbine extraction points through the following routes:

Extraction Steam 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.

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.

Circulating Water System 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.

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 Ash Handling System

Cost and Performance Baseline for Fossil Energy Plants 321 collectors, and bottom ash hoppers to the hydrobins (for bottom ash) and truck filling stations (for fly ash). The system is designed to support sho rt-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.

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.

Ducting and Stack 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.

Waste Treatment/Miscellaneous Systems 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.

Cost and Performance Baseline for Fossil Energy Plants 322 Foundations are provided for the support structures, pumps, tanks, and other plant components. The following buildings are included in the design basis:

Buildings and Structures Steam turbine building Fuel oil pump house Guard house Boiler building Coal crusher building Runoff water pump house Administration and service building Continuous emissions monitoring building Industrial waste treatment building Makeup water and pretreatment building Pump house and electrical equipment building FGD system buildings 4.1.10 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.

Accessory Electric Plant 4.1.11 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.

Instrumentation and Control 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/1050F/1050F) cycle. The only difference between the two plants is that Case 10 includes CO 2 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.

Cost and Performance Baseline for Fossil Energy Plants 323 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 In this section the subcritical PC process without CO 2 capture is described. The system description follows the BFD in Process Description 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.

Cost and Performance Baseline for Fossil Energy Plants 324 Exhibit 4-3 Case 9 Block Flow Diagram, Subcritical Unit without CO 2 Capture Cost and Performance Baseline for Fossil Energy Plants 325 Exhibit 4-4 Case 9 Stream Table, Subcritical Unit without CO 2 Capture 1 2 3 4 5 6 7 8 9 10 11 12V-L Mole Fraction Ar0.00920.00920.00920.00920.00920.00920.00920.00000.00000.00870.00000.0087 CO 20.00030.00030.00030.00030.00030.00030.00030.00000.00000.14470.00000.1447 H 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 H 2 O0.00990.00990.00990.00990.00990.00990.00990.00000.00000.08680.00000.0868 N 20.77320.77320.77320.77320.77320.77320.77320.00000.00000.73250.00000.7325 O 20.20740.20740.20740.20740.20740.20740.20740.00000.00000.02500.00000.0250 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00210.00000.0021Total1.00001.00001.00001.00001.00001.00001.00000.00000.00001.00000.00001.0000V-L Flowrate (kgmol/hr)51,81751,8171,53515,91815,9182,1911,195 0 072,904 072,904V-L Flowrate (kg/hr)1,495,2851,495,28544,287459,336459,33663,21734,480 0 02,168,255 02,168,255Solids Flowrate (kg/hr) 0 0 0 0 0 0 0198,3913,84815,39015,390 0Temperature (°C) 15 19 19 15 25 25 15 15 15 169 15 169Pressure (MPa, abs)0.100.110.110.100.110.110.100.100.100.100.100.10Enthalpy (kJ/kg)

A30.2334.3634.3630.2340.7840.7830.23------327.06---308.70Density (kg/m 3)1.21.21.21.21.31.31.2------0.8---0.8V-L Molecular Weight28.85728.85728.85728.85728.85728.85728.857------29.741---29.741V-L Flowrate (lbmol/hr)114,237114,2373,38335,09235,0924,8302,634 0 0160,726 0160,726V-L Flowrate (lb/hr)3,296,5403,296,54097,6371,012,6631,012,663139,36976,015 0 04,780,183 04,780,183Solids Flowrate (lb/hr) 0 0 0 0 0 0 0437,3788,48233,92933,929 0Temperature (°F) 59 66 66 59 78 78 59 59 59 337 59 337Pressure (psia)14.715.315.314.716.116.114.714.714.714.414.714.2Enthalpy (Btu/lb)

A13.014.814.813.017.517.513.0------140.6---132.7Density (lb/ft 3)0.0760.0780.0780.0760.0810.0810.076------0.050---0.049A - Reference conditions are 32.02 F & 0.089 PSIA Cost and Performance Baseline for Fossil Energy Plants 326 Exhibit 4-4 Case 9 Stream Table, Subcritical Unit without CO 2 Capture (Continued) 13 14 15 16 17 18 19 20 21 22 23V-L Mole Fraction Ar0.00870.00000.00000.01280.00000.00820.00000.00000.00000.00000.0000 CO 20.14470.00000.00000.00050.00040.13500.00000.00000.00000.00000.0000 H 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 H 2 O0.08681.00001.00000.00620.99950.15171.00001.00001.00001.00001.0000 N 20.73250.00000.00000.75060.00000.68080.00000.00000.00000.00000.0000 O 20.02500.00000.00000.23000.00000.02430.00000.00000.00000.00000.0000 SO 20.00210.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000Total1.00001.00001.00001.00001.00001.00001.00001.00001.00001.00001.0000V-L Flowrate (kgmol/hr)72,9042,53010,275 775 18879,30093,36685,85185,85176,80577,739V-L Flowrate (kg/hr)2,168,25545,571185,10622,5093,3832,287,9031,682,0171,546,6281,546,6281,383,6631,400,483Solids Flowrate (kg/hr) 019,690 0 030,645 0 0 0 0 0 0Temperature (°C) 181 15 15 167 57 57 566 363 566 38 39Pressure (MPa, abs)0.110.100.100.310.100.1016.654.283.900.011.69Enthalpy (kJ/kg)

A320.79----46.80177.65---297.693,472.333,120.823,594.062,016.19165.31Density (kg/m 3)0.8---1,003.12.5---1.147.715.710.30.1993.3V-L Molecular Weight29.741---18.01529.029---28.85118.01518.01518.01518.01518.015V-L Flowrate (lbmol/hr)160,7265,57722,6521,709 414174,826205,837189,269189,269169,326171,384V-L Flowrate (lb/hr)4,780,183100,467408,09049,6257,4595,043,9633,708,2123,409,7303,409,7303,050,4543,087,536Solids Flowrate (lb/hr) 043,410 0 067,561 0 0 0 0 0 0Temperature (°F) 357 59 59 333 135 1351,050 6861,050 101 103Pressure (psia)15.315.014.745.014.814.82,415.0620.5565.51.0245.0Enthalpy (Btu/lb)

A137.9----20.176.4---128.01,492.81,341.71,545.2866.871.1Density (lb/ft 3)0.052---62.6220.154---0.0672.9770.9830.6430.00462.010 Cost and Performance Baseline for Fossil Energy Plants 327 4.2.2 System assumptions for Cases 9 and 10 , subcritical PC with and without CO 2 capture, are compiled in Key System Assumptions Exhibit 4-5. Exhibit 4-5 Subcritical PC Plant Study Configuration Matrix Case 9 w/o CO 2 Capture Case 10 w/CO 2 Capture Steam Cycle , MPa/°C/°C (psig/°F/°F) 16.5/566/566 (2400/1050/1050) 16.5/566/566 (2400/1050/1050)

Coal Illinois No. 6 Illinois No. 6 Condenser pressure, mm Hg (in Hg) 50.8 (2) 50.8 (2) Boiler Efficiency , % 8 8 8 8 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) SO 2 Control Wet Limestone Forced Oxidation Wet Limestone Forced Oxidation FGD Efficiency , % (A) 98 98 (B , C) NOx Control LNB w/OFA and SCR LNB w/OFA and SCR SCR Efficiency, % (A) 86 86 Ammonia Slip (end of catalyst life), ppmv 2 2 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 CO 2 Control N/A Econamine Overall CO 2 Capture (A)

N/A 90.2% CO 2 Sequestration N/A Off-site Saline Formation A. Removal efficiencies are based on the FG content B. An SO 2 polishing step is included to meet more stringent SOx content limits in the FG (< 10 ppmv) to reduce formation of amine HSS during the CO 2 absorption process C. SO 2 exiting the post

-FGD polishing step is absorbed in the CO 2 capture process making stack emissions negligible The balance of plant assumptions are common to all cases and are presented in Balance of Plant

- Cases 9 and 10 Exhibit 4-6.

Cost and Performance Baseline for Fossil Energy Plants 328 Exhibit 4-6 Balance of Plant Assumptions Recirculating Wet Cooling Tower Cooling system 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 5,000 hp 4,160 volt 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.

Cost and Performance Baseline for Fossil Energy Plants 329 4.2.3 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:

Sparing Philosophy 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 CO 2 absorption systems, with each system consisting of two absorbers, strippers and ancillary equipment (2 x 50%)

4.2.4 The plant produces a net output of 550 MWe at a net plant efficiency of 3 6.8 percent (HHV basis). Overall performance for the plant is summarized in Case 9 Performance Results Exhibit 4-7 , which includes auxiliary power requirements.

Cost and Performance Baseline for Fossil Energy Plants 330 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 Miscellaneous Balance of Plant2,3 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, 0 2 0 Net Plant Efficiency (HHV) 3 6.8% Net Plant Heat Rate

, kJ/kWh (Btu/kWh) 9,7 88 (9, 277) CONDENSER COOLING DUTY 10 6 kJ/h r (10 6 Btu/h r) 2,566 (2,432)

CONSUMABLES As-Received Coal Feed, kg/h r (lb/h r) 198,391 (437,378) Limestone Sorbent Feed, kg/h r (lb/h r) 19, 691 (43, 410) Thermal Input, kWt 1 1,495,379 Raw Water Withdrawal, m 3/min (gpm) 22.3 (5,89

6) Raw Water Consumption, m 3/min (gpm) 17.7 (4,6 80) 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

Cost and Performance Baseline for Fossil Energy Plants 331 The environmental targets for emissions of Hg, NOx, SO 2 , and PM were presented in Section 2.4. A summary of the plant air emissions for Case 9 is presented in Environmental Performance Exhibit 4-8. Exhibit 4-8 Case 9 Air Emissions kg/GJ (lb/10 6 Btu) Tonne/year (ton/year) 85% CF kg/MWh (lb/MWh) SO 2 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)

Hg 4.91E-7 (1.14E-6) 0.020 (0.022) 4.54E-6 (1.00E-5) CO 2 87.5 (203.5) 3,507,605 (3,866,472) 809 (1,783)

CO 2 1 856 (1,888) 1 CO 2 emissions based on net power instead of gross power SO 2 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/10 6 Btu through the use of LNBs and OFA. An SCR unit then further reduces the NOx concentration by 86 percent to 0.07 lb/10 6 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.

CO 2 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 CO 2 through the stack but also leaves as gypsum.

Cost and Performance Baseline for Fossil Energy Plants 332 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 (CO 2) 275 (607) FGD Product 174 (383) FGD Reagent 1,998 (4,405)

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.

Cost and Performance Baseline for Fossil Energy Plants 333 Exhibit 4-11 Case 9 Water Balance Water Use Water Demand, m 3/min (gpm) Internal Recycle, m 3/min (gpm) Raw Water Withdrawal, m 3/min (gpm) Process Water Discharge, m 3/min (gpm) Raw Water Consumption, m 3/min (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)

A heat and mass balance diagram is shown for the Case 9 PC boiler, the FGD unit

, and steam cycle as shown in Heat and Mass Balance Diagrams 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.

Cost and Performance Baseline for Fossil Energy Plants 334 This page intentionally left blank

Cost and Performance Baseline for Fossil Energy Plants 335 Exhibit 4-12 Case 9 Heat and Mass Balance, Subcritical PC Boiler without CO 2 Capture N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA H EAT AND M ATERIAL F LOW D IAGRAM P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Ash Slurry Synthesis Gas Sour Gas Sour Water Water Steam P AGES 1 OF 2 B ITUMINOUS B ASELINE S TUDY C ASE 9 S UBCRITICAL P ULVERIZED C OAL B OILER AND G AS C LEANUP S YSTEMS DWG. NO.BB-HMB-CS-9-PG-1 Pulverized Coal Boiler SCR AMMONIA INFILTRATION AIR AIR AIR COAL ASH From Feedwater Heaters Single Reheat To IP Turbine Throttle Steam To HP Turbine FGD ASH FORCED DRAFT FANS PRIMARY AIR FANS STACK 437 , 378 W 77.8 T 16.1 P 17.5 H 66.4 T 15.3 P 14.8 H 3 , 708 , 212 W 1 , 050.0 T 2 , 415.0 P 1 , 492.8 H 3 , 409 , 730 W 1 , 050.0 T 565.5 P 1 , 545.2 H Single Reheat Extraction from HP Turbine 1 , 012 , 663 W 59.0 T 14.7 P 13.0 H 3 , 296 , 540 W 59.0 T 14.7 P 13.0 H 76 , 015 W 59.0 T 14.7 P 13.0 H 4 , 814 , 113 W 337.0 T 14.4 P 140.6 H 8 , 482 W 33 , 929 W 3 , 409 , 730 W 686.0 T 620.5 P 1 , 341.7 H 3 , 708 , 212 W 484.4 T 3 , 100.5 P 469.5 H 5 5 , 043 , 963 W 135.0 T 14.8 P 128.0 H 1 2 4 7 9 ID FANS 4 , 780 , 183 W 337.0 T 14.2 P 132.7 H Gross Plant Power

583 MWe Auxiliary Load

33 MWe Net Plant Power

550 MWe Net Plant Efficiency , HHV: 36.8%Net Plant Heat Rate

9 , 277 BTU/KWe Lime/Ash Flue Gas OXIDATION AIR MAKE-UP WATER LIMESTONE SLURRY GYPSUM 15 14 11 357.4 T 15.3 P 137.9 H 143 , 877 W 59.0 T 15.0 P 49 , 625 W 332.9 T 45.0 P 408 , 090 W 59.0 T 14.7 P 75 , 020 W 135.0 T 14.8 P Baghouse 3 6 8 10 12 13 16 17 18 19 20 21 DOE/NETL SC PC P LANT C ASE 9 Cost and Performance Baseline for Fossil Energy Plants 336 Exhibit 4-13 Case 9 Heat and Mass Balance, Subcritical Steam Cycle N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA H EAT AND M ATERIAL F LOW D IAGRAM P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas Sour Gas Sour Water Water Steam P AGES 2 OF 2 DWG. NO.BB-HMB-CS-9-PG-2 B ITUMINOUS B ASELINE S TUDY C ASE 9 S UBCRITICAL P ULVERIZED C OAL P OWER B LOCK S YSTEMS LP TURBINE GENERATOR HP TURBINE IP TURBINE CONDENSER HOT WELL P-1028 P-1048 To Boiler BOILER FEED PUMP TURBINE DRIVES STEAM SEAL REGULATOR Throttle Steam Single Reheat Extraction From Boiler GLAND SEAL CONDENSER CONDENSATE PUMPS 3 , 708 , 212 W 1 , 050.0 T 2 , 415.0 P 1 , 492.8 H 226 , 208 W 915.9 T 323.0 P 1 , 480.7 H 254 , 026 W 682.6 T 589.7 P 1 , 341.7 H 3 , 409 , 730 W 686.0 T 620.5 P 1 , 341.7 H 620.5 P 620.5 P 620.5 P 350.5 P 167.7 P 167.7 P 154 , 414 W 734.9 T 164.3 P 1 , 393.4 H 154 , 414 W 126.1 T 2.0 P 1 , 097.1 H 2 , 388 , 619 W 101.1 T 1.0 P 1 , 017.1 H 2 , 793 W 212.0 T 14.7 P 179.9 H 64.2 P 41.6 P 11.8 P 101.4 T 250.0 P 70.0 H 2 , 793 W 712.8 T 167.7 P 1 , 381.9 H 3 , 087 , 536 W 101.1 T 1.0 P 69.1 H 3 , 087 , 536 W 102.5 T 245.0 P 71.1 H 3 , 087 , 536 W 152.8 T 240.0 P 121.2 H 501 , 326 W 112.5 T 1.4 P 80.4 H 370 , 446 W 162.8 T 5.1 P 130.6 H 3 , 087 , 536 W 284.7 T 220.0 P 253.9 H 480 , 234 W 364.6 T 323.0 P 337.0 H 3 , 087 , 536 W 257.7 T 230.0 P 226.5 H 254 , 026 W 436.2 T 366.7 P 414.3 H 3 , 708 , 212 W 426.2 T 3 , 105.5 P 406.0 H DEAERATOR BOILER FEED PUMPS 3 , 708 , 212 W 484.4 T 3 , 100.5 P 469.5 H 3 , 409 , 730 W 1 , 050.0 T 565.5 P 1 , 545.2 H 80 , 030 W 267.7 T 40.3 P 236.3 H 267 , 224 W 200.5 T 11.7 P 168.3 H 3 , 087 , 536 W 190.5 T 235.0 P 158.8 H 177 , 524 W 728.1 T 130.0 P 1 , 391.5 H 80 , 030 W 524.8 T 57.3 P 1 , 294.9 H 187 , 193 W 439.2 T 37.1 P 1 , 255.2 H 103 , 223 W 228.6 T 10.5 P 1 , 159.5 H 130 , 880 W 157.8 T 4.5 P 1 , 120.2 H 2 , 415.0 P 3 , 037 , 555 W 734.9 T 164.3 P 1 , 393.4 H 2 , 883 , 141 W 734.9 T 164.3 P 1 , 393.4 H 5.0 P Steam Turbine Makeup 354.6 T 3 , 110.5 P 330.9 H 3 , 708 , 212 W 347.3 T 130.0 P 318.5 H 3 , 301 W 712.8 T 167.7 P 1 , 381.9 H Gross Plant Power

583 MWe Auxiliary Load

33 MWe Net Plant Power

550 MWe Net Plant Efficiency , HHV: 36.8%Net Plant Heat Rate

9 , 277 BTU/KWe FWH 1 FWH 2 FWH 3 FWH 4 FWH 6 FWH 7 6 , 805 W 712.8 T 167.7 P 1 , 381.9 H 19 23 DOE/NETL SC PC P LANT C ASE 9 2 , 415.0 P 21 1 , 850.0 P Single Reheat Extraction to Boiler 20 3 , 442 , 057 W 1 , 048.6 T 565.5 P 1 , 544.4 H 37 , 082 W 59.0 T 14.7 P 27.1 H Cost and Performance Baseline for Fossil Energy Plants 337 Exhibit 4-14 Case 9 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total 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.

Cost and Performance Baseline for Fossil Energy Plants 338 4.2.5 Major equipment items for the subcritical PC plant with no CO 2 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 Case 9 - Major Equipment List 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 No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Bottom Trestle Dumper and Receiving HoppersN/A181 tonne (200 ton) 2 0 2FeederBelt572 tonne/hr (630 tph) 2 0 3Conveyor No. 1Belt1,134 tonne/hr (1,250 tph) 1 0 4Transfer Tower No. 1EnclosedN/A 1 0 5Conveyor No. 2Belt1,134 tonne/hr (1,250 tph) 1 0 6As-Received Coal Sampling SystemTwo-stageN/A 1 0 7Stacker/ReclaimerTraveling, linear1,134 tonne/hr (1,250 tph) 1 0 8Reclaim HopperN/A45 tonne (50 ton) 2 1 9FeederVibratory163 tonne/hr (180 tph) 2 1 10Conveyor No. 3Belt w/ tripper327 tonne/hr (360 tph) 1 0 11Crusher TowerN/AN/A 1 0 12Coal Surge Bin w/ Vent FilterDual outlet163 tonne (180 ton) 2 0 13CrusherImpactor reduction8 cm x 0 - 3 cm x 0(3 in x 0 1/4 in x 0) 2 0 14As-Fired Coal Sampling SystemSwing hammerN/A 1 1 15Conveyor No. 4Belt w/tripper327 tonne/hr (360 tph) 1 0 16Transfer Tower No. 2EnclosedN/A 1 0 17Conveyor No. 5Belt w/ tripper327 tonne/hr (360 tph) 1 0 18Coal Silo w/ Vent Filter and Slide GatesField erected726 tonne (800 ton) 3 0 19Limestone Truck Unloading HopperN/A36 tonne (40 ton) 1 0 20Limestone FeederBelt82 tonne/hr (90 tph) 1 0 21Limestone Conveyor No. L1Belt82 tonne/hr (90 tph) 1 0 22Limestone Reclaim HopperN/A18 tonne (20 ton) 1 0 23Limestone Reclaim FeederBelt64 tonne/hr (70 tph) 1 0 24Limestone Conveyor No. L2Belt64 tonne/hr (70 tph) 1 0 25Limestone Day Binw/ actuator263 tonne (290 ton) 2 0 Cost and Performance Baseline for Fossil Energy Plants 33 9 ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Coal FeederGravimetric36 tonne/hr (40 tph) 6 0 2Coal PulverizerBall type or equivalent36 tonne/hr (40 tph) 6 0 3Limestone Weigh FeederGravimetric22 tonne/hr (24 tph) 1 1 4Limestone Ball MillRotary22 tonne/hr (24 tph) 1 1 5Limestone Mill Slurry Tank with AgitatorN/A83,279 liters (22,000 gal) 1 1 6Limestone Mill Recycle PumpsHorizontal centrifugal1,401 lpm @ 12m H2O (370 gpm @ 40 ft H2O) 1 1 7Hydroclone Classifier4 active cyclones in a 5 cyclone bank341 lpm (90 gpm) per cyclone 1 1 8Distribution Box2-wayN/A 1 1 9Limestone Slurry Storage Tank with AgitatorField erected469,391 liters (124,000 gal) 1 1 10Limestone Slurry Feed PumpsHorizontal centrifugal984 lpm @ 9m H2O (260 gpm @ 30 ft H2O) 1 1 Cost and Performance Baseline for Fossil Energy Plants 340 ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Demineralized Water Storage TankVertical, cylindrical, outdoor1,112,911 liters (294,000 gal) 2 0 2Condensate PumpsVertical canned25,741 lpm @ 213 m H2O (6,800 gpm @ 700 ft H2O) 1 1 3Deaerator and Storage TankHorizontal spray type1,850,203 kg/hr (4,079,000 lb/hr), 5 min. tank 1 0 4Boiler Feed Pump/TurbineBarrel type, multi-stage, centrifugal31,040 lpm @ 2,530 m H2O (8,200 gpm @ 8,300 ft H2O) 1 1 5Startup Boiler Feed Pump, Electric Motor DrivenBarrel type, multi-stage, centrifugal9,085 lpm @ 2,530 m H2O (2,400 gpm @ 8,300 ft H2O) 1 0 6LP Feedwater Heater 1A/1BHorizontal U-tube771,107 kg/hr (1,700,000 lb/hr) 2 0 7LP Feedwater Heater 2A/2BHorizontal U-tube771,107 kg/hr (1,700,000 lb/hr) 2 0 8LP Feedwater Heater 3A/3BHorizontal U-tube771,107 kg/hr (1,700,000 lb/hr) 2 0 9LP Feedwater Heater 4A/4BHorizontal U-tube771,107 kg/hr (1,700,000 lb/hr) 2 0 10HP Feedwater Heater 6Horizontal U-tube1,850,657 kg/hr (4,080,000 lb/hr) 1 0 11HP Feedwater Heater 7Horizontal U-tube1,850,657 kg/hr (4,080,000 lb/hr) 1 0 12Auxiliary BoilerShop fabricated, water tube18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0 13Fuel Oil SystemNo. 2 fuel oil for light off1,135,624 liter (300,000 gal) 1 0 14Service Air CompressorsFlooded Screw28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1 15Instrument Air DryersDuplex, regenerative28 m3/min (1,000 scfm) 2 1 16Closed Cycle Cooling Heat ExchangersShell and tube53 GJ/hr (50 MMBtu/hr) each 2 0 17Closed Cycle Cooling Water PumpsHorizontal centrifugal20,820 lpm @ 30 m H2O (5,500 gpm @ 100 ft H2O) 2 1 18Engine-Driven Fire PumpVertical turbine, diesel engine3,785 lpm @ 88 m H2O (1,000 gpm @ 290 ft H2O) 1 1 19Fire Service Booster PumpTwo-stage horizontal centrifugal2,650 lpm @ 64 m H2O (700 gpm @ 210 ft H2O) 1 1 20Raw Water PumpsStainless steel, single suction6,549 lpm @ 18 m H2O (1,730 gpm @ 60 ft H2O) 2 1 21Ground Water PumpsStainless steel, single suction2,612 lpm @ 268 m H2O (690 gpm @ 880 ft H2O) 5 1 22Filtered Water PumpsStainless steel, single suction2,006 lpm @ 49 m H2O (530 gpm @ 160 ft H2O) 2 1 23Filtered Water TankVertical, cylindrical1,919,204 liter (507,000 gal) 1 0 24Makeup Water DemineralizerMulti-media filter, cartridge filter, RO membrane assembly, electrodeionization unit606 lpm (160 gpm) 1 1 25Liquid Waste Treatment System--10 years, 24-hour storm 1 0 Cost and Performance Baseline for Fossil Energy Plants 341 ACCOUNT 4 BOILER AND ACCESSORI ES Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1BoilerSubcritical, drum wall-fired, low NOx burners, overfire air1,850,657 kg/hr steam @ 17.9 MPa/574°C/574°C (4,080,000 lb/hr steam @ 2,600 psig/1,065°F/1,065°F) 1 0 2Primary Air FanCentrifugal252,651 kg/hr, 3,446 m3/min @ 123 cm WG (557,000 lb/hr, 121,700 acfm @ 48 in. WG) 2 0 3Forced Draft FanCentrifugal822,363 kg/hr, 11,222 m3/min @ 47 cm WG (1,813,000 lb/hr, 396,300 acfm @ 19 in. WG) 2 0 4Induced Draft FanCentrifugal1,192,494 kg/hr, 25,114 m3/min @ 91 cm WG (2,629,000 lb/hr, 886,900 acfm @ 36 in. WG) 2 0 5SCR Reactor VesselSpace for spare layer2,385,896 kg/hr (5,260,000 lb/hr) 2 0 6SCR Catalyst

3 0 7Dilution Air BlowerCentrifugal142 m3/min @ 108 cm WG (5,000 acfm @ 42 in. WG) 2 1 8Ammonia StorageHorizontal tank155,202 liter (41,000 gal) 5 0 9Ammonia Feed PumpCentrifugal30 lpm @ 91 m H2O (8 gpm @ 300 ft H2O) 2 1 Cost and Performance Baseline for Fossil Energy Plants 342 ACCOUNT 5 FLUE GAS CLEANUP ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES N/A Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Fabric FilterSingle stage, high-ratio with pulse-jet online cleaning system1,192,494 kg/hr (2,629,000 lb/hr) 99.8% efficiency 2 0 2Absorber ModuleCounter-current open spray47,912 m3/min (1,692,000 acfm) 1 0 3Recirculation PumpsHorizontal centrifugal166,558 lpm @ 64 m H2O (44,000 gpm @ 210 ft H2O) 5 1 4Bleed PumpsHorizontal centrifugal4,240 lpm (1,120 gpm) at 20 wt% solids 2 1 5Oxidation Air BlowersCentrifugal84 m3/min @ 0.3 MPa (2,960 acfm @ 37 psia) 2 1 6AgitatorsSide entering50 hp 5 1 7Dewatering CyclonesRadial assembly, 5 units each1,060 lpm (280 gpm) per cyclone 2 0 8Vacuum Filter BeltHorizontal belt34 tonne/hr (37 tph) of 50 wt % slurry 2 1 9Filtrate Water Return PumpsHorizontal centrifugal644 lpm @ 12 m H2O (170 gpm @ 40 ft H2O) 1 1 10Filtrate Water Return Storage TankVertical, lined416,395 lpm (110,000 gal) 1 0 11Process Makeup Water PumpsHorizontal centrifugal3,407 lpm @ 21 m H2O (900 gpm @ 70 ft H2O) 1 1 Cost and Performance Baseline for Fossil Energy Plants 343 ACCOUNT 7 HRSG, DUCTING & STA CK ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES ACCOUNT 9 COOLING WATER SYSTEM Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1StackReinforced concrete with FRP liner152 m (500 ft) high x5.8 m (19 ft) diameter 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Steam TurbineCommercially available advanced steam turbine613 MW16.5 MPa/566°C/566°C (2400.3 psig/ 1050°F/1050°F) 1 0 2Steam Turbine GeneratorHydrogen cooled, static excitation680 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0 3Surface CondenserSingle pass, divided waterbox including vacuum pumps2,828 GJ/hr (2,680 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Circulating Water PumpsVertical, wet pit526,200 lpm @ 30 m(139,000 gpm @ 100 ft) 2 1 2Cooling TowerEvaporative, mechanical draft, multi-cell11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2944 GJ/hr (2790 MMBtu/hr) heat duty 1 0 Cost and Performance Baseline for Fossil Energy Plants 344 ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Economizer Hopper (part of boiler scope of supply)

4 0 2Bottom Ash Hopper (part of boiler scope of supply)

2 0 3Clinker Grinder

--4.5 tonne/hr (5 tph) 1 1 4Pyrites Hopper (part of pulverizer scope of supply included with boiler)

6 0 5Hydroejectors

12 6Economizer /Pyrites Transfer Tank----1 0 7Ash Sluice PumpsVertical, wet pit151 lpm @ 17 m H2O (40 gpm @ 56 ft H2O) 1 1 8Ash Seal Water PumpsVertical, wet pit7,571 lpm @ 9 m H2O (2000 gpm @ 28 ft H2O) 1 1 9Hydrobins--151 lpm (40 gpm) 1 1 10Baghouse Hopper (part of baghouse scope of supply)

24 0 11Air Heater Hopper (part of boiler scope of supply)

10 0 12Air Blower

--16 m3/min @ 0.2 MPa (550 scfm @ 24 psi) 1 1 13Fly Ash SiloReinforced concrete998 tonne (1,100 ton) 2 0 14Slide Gate Valves

2 0 15Unloader----1 0 16Telescoping Unloading Chute

--91 tonne/hr (100 tph) 1 0 Cost and Performance Baseline for Fossil Energy Plants 345 ACCOUNT 11 ACCESSORY ELECTRIC PLANT ACCOUNT 12 INSTRUMENTATION AND CONTROL Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1STG TransformerOil-filled24 kV/345 kV, 650 MVA, 3-ph, 60 Hz 1 0 2Auxiliary TransformerOil-filled24 kV/4.16 kV, 34 MVA, 3-ph, 60 Hz 1 1 3Low Voltage TransformerDry ventilated4.16 kV/480 V, 5 MVA, 3-ph, 60 Hz 1 1 4STG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled24 kV, 3-ph, 60 Hz 1 0 5Medium Voltage SwitchgearMetal clad4.16 kV, 3-ph, 60 Hz 1 1 6Low Voltage SwitchgearMetal enclosed480 V, 3-ph, 60 Hz 1 1 7Emergency Diesel GeneratorSized for emergency shutdown750 kW, 480 V, 3-ph, 60 Hz 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1DCS - Main ControlMonitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W)Operator stations/printers and engineering stations/printers 1 0 2DCS - ProcessorMicroprocessor with redundant input/outputN/A 1 0 3DCS - Data HighwayFiber opticFully redundant, 25% spare 1 0 Cost and Performance Baseline for Fossil Energy Plants 346 4.2.6 The cost estimating methodology was described previously in Section 2.6. Case 9 - Cost Estimating 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 owner's 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 CO 2 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.

Cost and Performance Baseline for Fossil Energy Plants 347 Exhibit 4-15 Case 9 Total Plant Cost Summary Client: USDOE/NETLReport Date:2010-Jan-14Project: Bituminous Baseline StudyCase: Case 9 - 1x550 MWnet SubCritical PCPlant Size:

550MW,netEstimate Type: ConceptualCost Base (Jun) 2007($x1000)AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING$17,068$4,598$10,229$0$0$31,895$2,862$0$5,214$39,970$73 2COAL & SORBENT PREP & FEED$11,494$665$2,916$0$0$15,075$1,321$0$2,459$18,855$34 3FEEDWATER & MISC. BOP SYSTEMS$39,707$0$19,059$0$0$58,766$5,391$0$10,518$74,674$136 4PC BOILER4.1PC Boiler & Accessories$134,824$0$86,704$0$0$221,527$21,582$0$24,311$267,420$4864.2SCR (w/4.1)

$0$0$0$0$0$0$0$0$0$0$04.3Open$0$0$0$0$0$0$0$0$0$0$04.4-4.9Boiler BoP (w/ ID Fans)

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 4$134,824$0$86,704$0$0$221,527$21,582$0$24,311$267,420$486 5FLUE GAS CLEANUP$83,799$0$28,488$0$0$112,287$10,747$0$12,303$135,338$246 5B CO 2 REMOVAL & COMPRESSION

$0$0$0$0$0$0$0$0$0$0$0 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine GeneratorN/A$0N/A$0$0$0$0$0$0$0$06.2-6.9Combustion Turbine Other

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 6

$0$0$0$0$0$0$0$0$0$0$0 7HRSG, DUCTING & STACK7.1Heat Recovery Steam GeneratorN/A$0N/A$0$0$0$0$0$0$0$07.2-7.9HRSG Accessories, Ductwork and Stack$18,242$1,049$12,388$0$0$31,679$2,908$0$4,516$39,104$71SUBTOTAL 7$18,242$1,049$12,388$0$0$31,679$2,908$0$4,516$39,104$71 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$49,912$0$6,242$0$0$56,154$5,380$0$6,153$67,688$1238.2-8.9Turbine Plant Auxiliaries and Steam Piping$23,604$1,092$12,657$0$0$37,354$3,294$0$5,668$46,316$84SUBTOTAL 8$73,516$1,092$18,900$0$0$93,508$8,674$0$11,822$114,004$207 9COOLING WATER SYSTEM$13,230$6,710$12,250$0$0$32,189$3,030$0$4,784$40,003$73 10ASH/SPENT SORBENT HANDLING SYS$4,573$145$6,114$0$0$10,833$1,042$0$1,222$13,096$24 11ACCESSORY ELECTRIC PLANT$17,808$6,355$18,529$0$0$42,692$3,765$0$5,747$52,203$95 12INSTRUMENTATION & CONTROL$8,665$0$8,786$0$0$17,451$1,582$0$2,338$21,371$39 13IMPROVEMENTS TO SITE$2,974$1,710$5,995$0$0$10,679$1,054$0$2,347$14,079$26 14BUILDINGS & 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$1,622TOTAL PLANT COST

SUMMARY

Cost and Performance Baseline for Fossil Energy Plants 348 Exhibit 4-16 Case 9 Total Plant Cost Details AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING1.1Coal Receive & Unload$3,508$0$1,602$0$0$5,110$457$0$835$6,402$121.2Coal Stackout & Reclaim$4,533$0$1,027$0$0$5,561$487$0$907$6,954$131.3Coal Conveyors$4,215$0$1,016$0$0$5,231$458$0$853$6,543$121.4Other Coal Handling$1,103$0$235$0$0$1,338$117$0$218$1,673$31.5Sorbent Receive & Unload

$140$0$42$0$0$183$16$0$30$229$01.6Sorbent Stackout & Reclaim$2,269$0$416$0$0$2,685$234$0$438$3,357$61.7Sorbent Conveyors

$810$175$199$0$0$1,183$102$0$193$1,479$31.8Other Sorbent Handling

$489$115$257$0$0$860$76$0$140$1,077$21.9Coal & Sorbent Hnd.Foundations

$0$4,308$5,435$0$0$9,743$915$0$1,599$12,257$22SUBTOTAL 1.$17,068$4,598$10,229$0$0$31,895$2,862$0$5,214$39,970$73 2COAL & SORBENT PREP & FEED2.1Coal Crushing & Drying$2,014$0$393$0$0$2,407$210$0$393$3,009$52.2Coal Conveyor to Storage$5,158$0$1,126$0$0$6,284$549$0$1,025$7,858$142.3Coal Injection System

$0$0$0$0$0$0$0$0$0$0$02.4Misc.Coal Prep & Feed

$0$0$0$0$0$0$0$0$0$0$02.5Sorbent Prep Equipment$3,857$166$801$0$0$4,824$420$0$787$6,031$112.6Sorbent Storage & Feed

$465$0$178$0$0$643$57$0$105$805$12.7Sorbent Injection System

$0$0$0$0$0$0$0$0$0$0$02.8Booster Air Supply System

$0$0$0$0$0$0$0$0$0$0$02.9Coal & Sorbent Feed Foundation

$0$499$419$0$0$917$85$0$150$1,153$2SUBTOTAL 2.$11,494$665$2,916$0$0$15,075$1,321$0$2,459$18,855$34 3FEEDWATER & MISC. BOP SYSTEMS3.1Feedwater System$16,257$0$5,611$0$0$21,868$1,915$0$3,567$27,351$503.2Water Makeup & Pretreating $4,751$0$1,529$0$0$6,280$594$0$1,375$8,248$153.3Other Feedwater Subsystems$5,318$0$2,248$0$0$7,566$678$0$1,237$9,480$173.4Service Water Systems

$931$0$507$0$0$1,438$135$0$315$1,888$33.5Other Boiler Plant Systems$6,259$0$6,179$0$0$12,438$1,181$0$2,043$15,662$283.6FO Supply Sys & Nat Gas

$256$0$320$0$0$575$54$0$94$724$13.7Waste Treatment Equipment$3,221$0$1,836$0$0$5,057$492$0$1,110$6,659$123.8Misc. Equip.(cranes,AirComp.,Comm.)$2,715$0$829$0$0$3,544$341$0$777$4,662$8SUBTOTAL 3.$39,707$0$19,059$0$0$58,766$5,391$0$10,518$74,674$136 4PC BOILER & ACCESSORIES4.1PC Boiler & Accessories$134,824$0$86,704$0$0$221,527$21,582$0$24,311$267,420$4864.2SCR (w/4.1)

$0$0$0$0$0$0$0$0$0$0$04.3Open$0$0$0$0$0$0$0$0$0$0$04.4Boiler BoP (w/ ID Fans)

$0$0$0$0$0$0$0$0$0$0$04.5Primary Air Systemw/4.1$0w/4.1$0$0$0$0$0$0$0$04.6Secondary Air Systemw/4.1$0w/4.1$0$0$0$0$0$0$0$04.8Major Component Rigging

$0w/4.1w/4.1$0$0$0$0$0$0$0$04.9Boiler Foundations

$0w/14.1w/14.1$0$0$0$0$0$0$0$0SUBTOTAL 4.$134,824$0$86,704$0$0$221,527$21,582$0$24,311$267,420$486 Cost and Performance Baseline for Fossil Energy Plants 349 Exhibit 4-16 Case 9 Total Plant Cost Details (Continued) AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 5FLUE GAS CLEANUP5.1Absorber Vessels & Accessories$58,362$0$12,564$0$0$70,926$6,762$0$7,769$85,456$1555.2Other FGD$3,046$0$3,451$0$0$6,497$631$0$713$7,840$145.3Bag House & Accessories$16,493$0$10,467$0$0$26,959$2,598$0$2,956$32,513$595.4Other Particulate Removal Materials$1,116$0$1,194$0$0$2,310$224$0$253$2,788$55.5Gypsum Dewatering System$4,783$0$812$0$0$5,595$533$0$613$6,741$125.6Mercury Removal System

$0$0$0$0$0$0$0$0$0$0$05.9Open$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 5.$83,799$0$28,488$0$0$112,287$10,747$0$12,303$135,338$246 5B CO 2 REMOVAL & COMPRESSION5B.1 CO 2 Removal System

$0$0$0$0$0$0$0$0$0$0$05B.2 CO 2 Compression & Drying

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 5B.

$0$0$0$0$0$0$0$0$0$0$0 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine GeneratorN/A$0N/A$0$0$0$0$0$0$0$06.2Open$0$0$0$0$0$0$0$0$0$0$06.3Compressed Air Piping

$0$0$0$0$0$0$0$0$0$0$06.9Combustion Turbine Foundations

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 6.

$0$0$0$0$0$0$0$0$0$0$0 7HRSG, DUCTING & STACK7.1Heat Recovery Steam GeneratorN/A$0N/A$0$0$0$0$0$0$0$07.2HRSG Accessories

$0$0$0$0$0$0$0$0$0$0$07.3Ductwork$9,097$0$5,845$0$0$14,942$1,303$0$2,437$18,682$347.4Stack$9,145$0$5,351$0$0$14,496$1,396$0$1,589$17,481$327.9Duct & Stack Foundations

$0$1,049$1,192$0$0$2,241$210$0$490$2,941$5SUBTOTAL 7.$18,242$1,049$12,388$0$0$31,679$2,908$0$4,516$39,104$71 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$49,912$0$6,242$0$0$56,154$5,380$0$6,153$67,688$1238.2Turbine Plant Auxiliaries

$348$0$746$0$0$1,094$107$0$120$1,321$28.3Condenser & Auxiliaries$7,251$0$2,295$0$0$9,545$913$0$1,046$11,504$218.4Steam Piping$16,005$0$7,891$0$0$23,896$2,008$0$3,886$29,790$548.9TG Foundations

$0$1,092$1,726$0$0$2,818$267$0$617$3,701$7SUBTOTAL 8.$73,516$1,092$18,900$0$0$93,508$8,674$0$11,822$114,004$207 Cost and Performance Baseline for Fossil Energy Plants 350 Exhibit 4-16 Case 9 Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 9COOLING WATER SYSTEM9.1Cooling Towers$9,783$0$3,046$0$0$12,829$1,227$0$1,406$15,461$289.2Circulating Water Pumps$2,033$0$128$0$0$2,161$182$0$234$2,578$59.3Circ.Water System Auxiliaries

$531$0$71$0$0$602$57$0$66$725$19.4Circ.Water Piping

$0$4,210$4,080$0$0$8,290$776$0$1,360$10,427$199.5Make-up Water System

$462$0$618$0$0$1,080$103$0$177$1,361$29.6Component Cooling Water Sys

$421$0$335$0$0$755$72$0$124$951$29.9Circ.Water System Foundations & Structures

$0$2,500$3,972$0$0$6,471$612$0$1,417$8,500$15SUBTOTAL 9.$13,230$6,710$12,250$0$0$32,189$3,030$0$4,784$40,003$73 10ASH/SPENT SORBENT HANDLING SYS10.1Ash CoolersN/A$0N/A$0$0$0$0$0$0$0$010.2Cyclone Ash LetdownN/A$0N/A$0$0$0$0$0$0$0$010.3HGCU Ash LetdownN/A$0N/A$0$0$0$0$0$0$0$010.4High Temperature Ash PipingN/A$0N/A$0$0$0$0$0$0$0$010.5Other Ash Recovery EquipmentN/A$0N/A$0$0$0$0$0$0$0$010.6Ash Storage Silos

$612$0$1,885$0$0$2,497$245$0$274$3,017$510.7Ash Transport & Feed Equipment$3,961$0$4,058$0$0$8,019$767$0$879$9,664$1810.8Misc. Ash Handling Equipment

$0$0$0$0$0$0$0$0$0$0$010.9Ash/Spent Sorbent Foundation

$0$145$171$0$0$317$30$0$69$416$1SUBTOTAL 10.$4,573$145$6,114$0$0$10,833$1,042$0$1,222$13,096$24 11ACCESSORY ELECTRIC PLANT11.1Generator Equipment$1,602$0$260$0$0$1,862$173$0$153$2,187$411.2Station Service Equipment$2,904$0$954$0$0$3,858$361$0$316$4,535$811.3Switchgear & Motor Control $3,339$0$567$0$0$3,906$362$0$427$4,695$911.4Conduit & Cable Tray

$0$2,093$7,238$0$0$9,331$903$0$1,535$11,769$2111.5Wire & Cable

$0$3,950$7,625$0$0$11,575$975$0$1,882$14,432$2611.6Protective Equipment

$270$0$918$0$0$1,188$116$0$130$1,434$311.7Standby Equipment$1,279$0$29$0$0$1,308$120$0$143$1,571$311.8Main Power Transformers$8,414$0$172$0$0$8,587$652$0$924$10,162$1811.9Electrical Foundations

$0$312$765$0$0$1,077$103$0$236$1,416$3SUBTOTAL 11.$17,808$6,355$18,529$0$0$42,692$3,765$0$5,747$52,203$95 12INSTRUMENTATION & CONTROL12.1PC Control Equipmentw/12.7$0w/12.7$0$0$0$0$0$0$0$012.2Combustion Turbine ControlN/A$0N/A$0$0$0$0$0$0$0$012.3Steam Turbine Controlw/8.1$0w/8.1$0$0$0$0$0$0$0$012.4Other Major Component Control

$0$0$0$0$0$0$0$0$0$0$012.5Signal Processing Equipmentw/12.7$0w/12.7$0$0$0$0$0$0$0$012.6Control Boards,Panels & Racks

$446$0$267$0$0$713$67$0$117$898$212.7Distributed Control System Equipment$4,504$0$787$0$0$5,291$491$0$578$6,360$1212.8Instrument Wiring & Tubing$2,442$0$4,844$0$0$7,285$621$0$1,186$9,092$1712.9Other I & C Equipment$1,273$0$2,888$0$0$4,161$403$0$456$5,021$9SUBTOTAL 12.$8,665$0$8,786$0$0$17,451$1,582$0$2,338$21,371$39 Cost and Performance Baseline for Fossil Energy Plants 351 Exhibit 4-16 Case 9 Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 13IMPROVEMENTS TO SITE13.1Site Preparation

$0$50$1,000$0$0$1,050$104$0$231$1,385$313.2Site Improvements

$0$1,660$2,061$0$0$3,721$367$0$818$4,906$913.3Site Facilities$2,974$0$2,933$0$0$5,908$582$0$1,298$7,788$14SUBTOTAL 13.$2,974$1,710$5,995$0$0$10,679$1,054$0$2,347$14,079$26 14BUILDINGS & STRUCTURES14.1Boiler Building

$0$8,519$7,491$0$0$16,010$1,439$0$4,362$21,811$4014.2Turbine Building

$0$12,310$11,473$0$0$23,784$2,144$0$6,482$32,409$5914.3Administration Building

$0$587$621$0$0$1,208$110$0$329$1,647$314.4Circulation Water Pumphouse

$0$168$134$0$0$302$27$0$82$411$114.5Water Treatment Buildings

$0$603$549$0$0$1,152$104$0$314$1,570$314.6Machine Shop

$0$393$264$0$0$657$58$0$179$893$214.7Warehouse

$0$266$267$0$0$533$48$0$145$727$114.8Other Buildings & Structures

$0$217$185$0$0$403$36$0$110$548$114.9Waste Treating Building & Str.

$0$416$1,263$0$0$1,680$159$0$460$2,299$4SUBTOTAL 14.

$0$23,479$22,248$0$0$45,727$4,125$0$12,463$62,315$113TOTAL COST$425,899$45,804$252,606$0$0$724,309$68,082$0$100,043$892,433$1,622Owner's CostsPreproduction Costs6 Months All Labor$7,104$131 Month Maintenance Materials

$859$21 Month Non-fuel Consumables

$956$21 Month Waste Disposal

$251$025% of 1 Months Fuel Cost at 100% CF$1,524$32% of TPC$17,849$32Total$28,543$52Inventory Capital60 day supply of fuel and consumables at 100% CF$13,824$250.5% of TPC (spare parts)$4,462$8Total$18,287$33Initial Cost for Catalyst and Chemicals

$0$0Land$900$2Other Owner's Costs$133,865$243Financing Costs$24,096$44Total Overnight Costs (TOC)$1,098,124$1,996TASC Multiplier(IOU, low-risk, 35 year)1.134Total As-Spent Cost (TASC)$1,245,272$2,264 Cost and Performance Baseline for Fossil Energy Plants 352 Exhibit 4-17 Case 9 Initial and Annual Operating and Maintenance Costs INITIAL & ANNUAL O&M EXPENSESCost Base (Jun):

2007Case 9 - 1x550 MWnet SubCritical PCHeat Rate-net (Btu/kWh):9,276 MWe-net: 550Capacity Factor (%):

85OPERATING & MAINTENANCE LABOROperating Labor Operating Labor Rate(base):34.65$/hour Operating Labor Burden:30.00% of base Labor O-H Charge Rate:25.00% of laborTotal Operating Labor Requirements(O.J.)per Shift:1 unit/mod. Plant Skilled Operator2.02.0 Operator9.09.0 Foreman1.01.0 Lab Tech's, etc.2.02.0 TOTAL-O.J.'s14.014.0Annual CostAnnual Unit Cost

$$/kW-netAnnual Operating Labor Cost$5,524,319$10.043Maintenance Labor Cost$5,842,145$10.621Administrative & Support Labor$2,841,616$5.166Property Taxes and Insurance$17,848,664$32.449TOTAL FIXED OPERATING COSTS$32,056,744$58.280VARIABLE OPERATING COSTS$/kWh-netMaintenance Material Cost$8,763,218$0.00214ConsumablesConsumptionUnit Initial Fill Initial Fill /Day Cost CostWater (/1000 gallons) 04,245.121.08$0$1,424,619$0.00035ChemicalsMU & WT Chem.(lbs) 020,5490.17$0$1,103,371$0.00027Limestone (ton) 0 52121.63$0$3,496,290$0.00085Carbon (Mercury Removal) (lb) 0 01.05$0$0$0.00000MEA Solvent (ton) 0 02,249.89$0$0$0.00000NaOH (tons) 0 0433.68$0$0$0.00000H2SO4 (tons) 0 0138.78$0$0$0.00000Corrosion Inhibitor 0 00.00$0$0$0.00000Activated Carbon (lb) 0 01.05$0$0$0.00000Ammonia (19% NH3) ton 0 78129.80$0$3,136,289$0.00077Subtotal Chemicals

$0$7,735,950$0.00189Other Supplemental Fuel (MBtu) 0 00.00$0$0$0.00000SCR Catalyst (m3)w/equip.0.335,775.94$0$592,641$0.00014Emission Penalties 0 00.00$0$0$0.00000Subtotal Other

$0$592,641$0.00014Waste Disposal Fly Ash (ton) 0 40716.23$0$2,049,540$0.00050Bottom Ash (ton) 0 10216.23$0$512,385$0.00013 Subtotal-Waste Disposal

$0$2,561,926$0.00063By-products & Emissions Gypsum (tons) 0 8110.00$0$0$0.00000Subtotal By-Products

$0$0$0.00000TOTAL VARIABLE OPERATING COSTS

$0$21,078,354$0.00515Fuel (ton) 05,24838.18$0$62,175,757$0.01518 Cost and Performance Baseline for Fossil Energy Plants 353 4.2.7 The plant configuration for Case 10, subcritical PC, is the same as Case 9 with the exception that the Econamine technology was added for CO 2 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.

Case 10 - PC Subcritical Unit with CO 2 Capture The process description for Case 10 is essentially the same as Case 9 with one notable exception , the addition of CO 2 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 The Case 10 modeling assumptions were presented previously in Section Case 10 Performance Results 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 CO 2 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.

Cost and Performance Baseline for Fossil Energy Plants 354 Exhibit 4-18 Case 10 Block Flow Diagram, Subcritical Unit with CO 2 Capture Cost and Performance Baseline for Fossil Energy Plants 355 Exhibit 4-19 Case 10 Stream Table, Subcritical Unit with CO 2 Capture 1 2 3 4 5 6 7 8 9 10 11 12 13 14V-L Mole Fraction Ar0.00920.00920.00920.00920.00920.00920.00920.00000.00000.00870.00000.00870.00870.0000 CO 20.00030.00030.00030.00030.00030.00030.00030.00000.00000.14500.00000.14500.14500.0000 H 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 H 2 O0.00990.00990.00990.00990.00990.00990.00990.00000.00000.08700.00000.08700.08701.0000 N 20.77320.77320.77320.77320.77320.77320.77320.00000.00000.73240.00000.73240.73240.0000 O 20.20740.20740.20740.20740.20740.20740.20740.00000.00000.02470.00000.02470.02470.0000 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00210.00000.00210.00210.0000Total1.00001.00001.00001.00001.00001.00001.00000.00000.00001.00000.00001.00001.00001.0000V-L Flowrate (kgmol/hr)72,69172,6912,16322,33022,3303,0631,680 0 0102,289 0102,289102,2893,643V-L Flowrate (kg/hr)2,097,6422,097,64262,415644,374644,37488,39648,482 0 03,042,405 03,042,4053,042,40565,636Solids Flowrate (kg/hr) 0 0 0 0 0 0 0278,9565,41021,64021,640 0 028,403Temperature (°C) 15 19 19 15 25 25 15 15 15 169 15 169 182 15Pressure (MPa, abs)0.100.110.110.100.110.110.100.100.100.100.100.100.110.10Enthalpy (kJ/kg)

A30.2334.3634.3630.2340.7840.7830.23------327.39---308.96322.83---Density (kg/m 3)1.21.21.21.21.31.31.2------0.8---0.80.8---V-L Molecular Weight28.85728.85728.85728.85728.85728.85728.857------29.743---29.74329.743---V-L Flowrate (lbmol/hr)160,256160,2564,76849,22949,2296,7533,704 0 0225,509 0225,509225,5098,032V-L Flowrate (lb/hr)4,624,5104,624,510137,6011,420,6011,420,601194,880106,884 0 06,707,354 06,707,3546,707,354144,703Solids Flowrate (lb/hr) 0 0 0 0 0 0 0614,99411,92747,70847,708 0 062,618Temperature (°F) 59 66 66 59 78 78 59 59 59 337 59 337 360 59Pressure (psia)14.715.315.314.716.116.114.714.714.714.414.714.215.415.0Enthalpy (Btu/lb)

A13.014.814.813.017.517.513.0------140.8---132.8138.8---Density (lb/ft 3)0.0760.0780.0780.0760.0810.0810.076------0.050---0.0490.052---A - Reference conditions are 32.02 F & 0.089 PSIA Cost and Performance Baseline for Fossil Energy Plants 356 Exhibit 4-19 Case 10 Stream Table, Subcritical Unit with CO 2 Capture (Continued) 15 16 17 18 19 20 21 22 23 24 25 26 27 28V-L Mole Fraction Ar0.00000.01280.00000.00810.01080.00000.00000.00000.00000.00000.00000.00000.00000.0000 CO 20.00000.00050.00040.13500.01790.99610.99850.00000.00000.00000.00000.00000.00000.0000 H 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 H 2 O1.00000.00620.99960.15370.03830.00390.00151.00001.00001.00001.00001.00001.00001.0000 N 20.00000.75060.00000.67930.90130.00000.00000.00000.00000.00000.00000.00000.00000.0000 O 20.00000.23000.00000.02380.03160.00000.00000.00000.00000.00000.00000.00000.00000.0000 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000Total1.00001.00001.00001.00001.00001.00001.00001.00001.00001.00001.00001.00001.00001.0000V-L Flowrate (kgmol/hr)14,7321,049 269111,45383,99613,59813,56648,63248,632131,223121,115121,11560,50461,816V-L Flowrate (kg/hr)265,39330,4614,8453,213,2612,366,318597,086596,497876,112876,1122,364,0212,181,9122,181,9121,089,9941,113,634Solids Flowrate (kg/hr) 0 043,806 0 0 0 0 0 0 0 0 0 0 0Temperature (°C) 15 181 58 58 32 21 35 296 151 566 363 566 38 39Pressure (MPa, abs)0.100.310.100.100.100.1615.270.510.9016.654.283.900.011.69Enthalpy (kJ/kg)

A-46.80191.62---301.4393.8619.49-211.713,054.75636.273,472.333,120.823,594.062,028.64165.87Density (kg/m 3)1,003.12.4---1.11.12.9795.92.0916.047.715.710.30.1993.3V-L Molecular Weight18.01529.029---28.83128.17243.90843.97118.01518.01518.01518.01518.01518.01518.015V-L Flowrate (lbmol/hr)32,4782,313 593245,711185,17929,97929,907107,214107,214289,297267,012267,012133,388136,281V-L Flowrate (lb/hr)585,09267,15410,6827,084,0275,216,8391,316,3491,315,0511,931,4971,931,4975,211,7744,810,2934,810,2932,403,0242,455,142Solids Flowrate (lb/hr) 0 096,577 0 0 0 0 0 0 0 0 0 0 0Temperature (°F) 59 357 136 136 89 69 95 565 3041,050 6861,050 101 103Pressure (psia)14.745.014.914.914.723.52,214.573.5130.02,415.0620.5565.51.0245.0Enthalpy (Btu/lb)

A-20.182.4---129.640.48.4-91.01,313.3273.51,492.81,341.71,545.2872.271.3Density (lb/ft 3)62.6220.149---0.0670.0700.18449.6840.12257.1832.9770.9830.6430.00462.007 Cost and Performance Baseline for Fossil Energy Plants 357 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 CO 2 Compression 48,790 Miscellaneous Balance of Plant2,3 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, 74 0 NET POWER, kWe 5 49,96 0 Net Plant Efficiency (HHV) 26.2% Net Plant Heat Rate

, kJ/kWh (Btu/kWh

) 13,764 (13,046

) CONDENSER COOLING DUTY 10 6 kJ/h r (10 6 Btu/h r) 2,034 (1,928)

CONSUMABLES As-Received Coal Feed, kg/h r (lb/h r) 278,956 (614,994)

Limestone Sorbent Feed, kg/h r (lb/h r) 28,404 (62,618) Thermal Input, kWt 1 2, 102,643 Raw Water Withdrawal, m 3/min (gpm) 42.5 (11,224)

Raw Water Consumption, m 3/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.

Cost and Performance Baseline for Fossil Energy Plants 358 The environmental targets for emissions of Hg, NOx, SO 2, and PM were presented in Section 2.4. A summary of the plant air emissions for Case 10 is presented in Environmental Performance Exhibit 4-21. Exhibit 4-21 Case 10 Air Emissions kg/GJ (lb/10 6 Btu) Tonne/year (ton/year) 85% CF kg/MWh (lb/MWh) SO 2 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) CO 2 8.8 (20.4) 493,198 (543,658) 98 (217) CO 2 1 120 (2 66) 1 CO 2 emissions based on net power instead of gross power SO 2 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 SO 2 emissions are further reduced to 10 ppmv using a NaOH based polishing scrubber in the CDR facility. The remaining low concentration of SO 2 is essentially completely removed in the CDR absorber vessel resulting in very low SO 2 emissions.

NOx emissions are controlled to about 0.5 lb/10 6 Btu through the use of LNBs and OFA. An SCR unit then further reduces the NOx concentration by 86 percent to 0.07 lb/10 6 Bt u. 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 CO 2 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 CO 2 in the stack gas, carbon in the FGD product, and the captured CO 2 product. The CO 2 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 Cost and Performance Baseline for Fossil Energy Plants 359 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 (CO 2) 386 (850) FGD Product 317 (699) FGD Reagent 2,882 (6,354)

CO 2 Product 162,694 (358,679)

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 Scrubber/H S S 137 (302) 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 Water Use Water Demand, m 3/min (gpm) Internal Recycle, m 3/min (gpm) Raw Water Withdrawal, m 3/min (gpm) Process Water Discharge, m 3/min (gpm) Raw Water Consumption, m 3/min (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)

Cost and Performance Baseline for Fossil Energy Plants 360 A heat and mass balance diagram is shown for the Case 10 PC boiler, the FGD unit, CDR system and steam cycle in Heat and Mass Balance Diagrams 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 CO 2 compressor intercooler load is included in the Econamine process heat out stream.

Cost and Performance Baseline for Fossil Energy Plants 361 Exhibit 4-25 Case 10 Heat and Mass Balance, Subcritical PC Boiler with CO 2 Capture Cost and Performance Baseline for Fossil Energy Plants 362 Exhibit 4-26 Case 10 Heat and Mass Balance, Subcritical Steam Cycle N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA H EAT AND M ATERIAL F LOW D IAGRAM P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas Sour Gas Sour Water Water Steam P AGES 2 OF 2 DWG. NO.BB-HMB-CS-10-PG-2 B ITUMINOUS B ASELINE S TUDY C ASE 10 S UBCRITICAL P ULVERIZED C OAL P OWER B LOCK S YSTEMS LP TURBINE GENERATOR HP TURBINE IP TURBINE CONDENSER HOT WELL P-1028 P-1048 To Boiler BOILER FEED PUMP TURBINE DRIVES STEAM SEAL REGULATOR Throttle Steam Single Reheat Extraction From Boiler GLAND SEAL CONDENSER CONDENSATE PUMPS 5 , 211 , 774 W 1 , 050.0 T 2 , 415.0 P 1 , 492.8 H 493 , 596 W 916.3 T 323.0 P 1 , 480.9 H 357 , 025 W 682.6 T 589.7 P 1 , 341.7 H 4 , 810 , 293 W 686.0 T 620.5 P 1 , 341.7 H 620.5 P 620.5 P 620.5 P 350.5 P 75.0 P 75.0 P 284 , 197 W 564.7 T 73.5 P 1 , 313.3 H 284 , 197 W 126.1 T 2.0 P 1 , 088.1 H 1 , 715 , 276 W 101.1 T 1.0 P 1 , 020.0 H 2 , 793 W 212.0 T 14.7 P 179.9 H 64.2 P 41.6 P 11.8 P 101.4 T 250.0 P 70.0 H 2 , 793 W 634.8 T 75.0 P 1 , 347.9 H 2 , 455 , 142 W 101.1 T 1.0 P 69.1 H 2 , 455 , 142 W 102.8 T 245.0 P 71.3 H 2 , 455 , 142 W 152.8 T 240.0 P 121.2 H 397 , 457 W 112.8 T 1.4 P 80.6 H 293 , 413 W 162.8 T 5.1 P 130.6 H 2 , 455 , 142 W 284.7 T 220.0 P 253.9 H 850 , 621 W 319.4 T 323.0 P 289.8 H 2 , 455 , 142 W 257.7 T 230.0 P 226.5 H 357 , 025 W 436.2 T 366.7 P 414.3 H 5 , 211 , 774 W 426.2 T 3 , 105.5 P 406.0 H DEAERATOR BOILER FEED PUMPS 5 , 211 , 774 W 484.4 T 3 , 100.5 P 469.5 H 4 , 810 , 293 W 1 , 050.0 T 565.5 P 1 , 545.2 H 63 , 337 W 267.7 T 40.3 P 236.3 H 211 , 580 W 200.5 T 11.7 P 168.3 H 2 , 455 , 142 W 190.5 T 235.0 P 158.8 H 26 , 631 W 577.8 T 70.0 P 1 , 320.0 H 63 , 337 W 535.0 T 57.3 P 1 , 300.0 H 148 , 243 W 448.7 T 37.1 P 1 , 259.8 H 81 , 833 W 236.1 T 10.5 P 1 , 163.0 H 104 , 045 W 157.8 T 4.5 P 1 , 116.3 H 2 , 415.0 P 4 , 325 , 282 W 564.7 T 73.5 P 1 , 313.3 H 2 , 109 , 588 W 564.7 T 73.5 P 1 , 313.3 H 5.0 P Steam Turbine Makeup 309.4 T 3 , 110.5 P 284.6 H 5 , 211 , 774 W 302.9 T 70.0 P 272.3 H 3 , 301 W 634.8 T 75.0 P 1 , 347.9 H Gross Plant Power

673 MWe Auxiliary Load

123 MWe Net Plant Power

550 MWe Net Plant Efficiency , HHV: 26.2%Net Plant Heat Rate

13 , 046 BTU/KWe FWH 1 FWH 2 FWH 3 FWH 4 FWH 6 FWH 7 3 , 145 W 634.8 T 75.0 P 1 , 347.9 H 24 28 DOE/NETL SC PC P LANT C ASE 10 2 , 415.0 P 26 1 , 850.0 P Single Reheat Extraction to Boiler 25 4 , 842 , 620 W 1 , 049.0 T 565.5 P 1 , 544.6 H 52 , 118 W 48.0 T 11.4 P 16.1 H Econamine Steam Econamine Condensate 1 , 931 , 497 W 304.0 T 130.0 P 273.5 H 1 , 931 , 497 W 564.7 T 73.5 P 1 , 313.3 H Cost and Performance Baseline for Fossil Energy Plants 363 Exhibit 4-27 Case 10 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total 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)

CO 2 -126 (-120) -126 (-120) Cooling Tower Blowdown 73.2 (69.4) 73.2 (69.4)

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.

Cost and Performance Baseline for Fossil Energy Plants 364 4.2.9 Major equipment items for the subcritical PC plant with CO 2 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 Case 10 - Major Equipment List 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 No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Bottom Trestle Dumper and Receiving HoppersN/A181 tonne (200 ton) 2 0 2FeederBelt572 tonne/hr (630 tph) 2 0 3Conveyor No. 1Belt1,134 tonne/hr (1,250 tph) 1 0 4Transfer Tower No. 1EnclosedN/A 1 0 5Conveyor No. 2Belt1,134 tonne/hr (1,250 tph) 1 0 6As-Received Coal Sampling SystemTwo-stageN/A 1 0 7Stacker/ReclaimerTraveling, linear1,134 tonne/hr (1,250 tph) 1 0 8Reclaim HopperN/A54 tonne (60 ton) 2 1 9FeederVibratory227 tonne/hr (250 tph) 2 1 10Conveyor No. 3Belt w/ tripper463 tonne/hr (510 tph) 1 0 11Crusher TowerN/AN/A 1 0 12Coal Surge Bin w/ Vent FilterDual outlet227 tonne (250 ton) 2 0 13CrusherImpactor reduction8 cm x 0 - 3 cm x 0(3 in x 0 1/4 in x 0) 2 0 14As-Fired Coal Sampling SystemSwing hammerN/A 1 1 15Conveyor No. 4Belt w/tripper463 tonne/hr (510 tph) 1 0 16Transfer Tower No. 2EnclosedN/A 1 0 17Conveyor No. 5Belt w/ tripper463 tonne/hr (510 tph) 1 0 18Coal Silo w/ Vent Filter and Slide GatesField erected998 tonne (1,100 ton) 3 0 19Limestone Truck Unloading HopperN/A36 tonne (40 ton) 1 0 20Limestone FeederBelt118 tonne/hr (130 tph) 1 0 21Limestone Conveyor No. L1Belt118 tonne/hr (130 tph) 1 0 22Limestone Reclaim HopperN/A27 tonne (30 ton) 1 0 23Limestone Reclaim FeederBelt91 tonne/hr (100 tph) 1 0 24Limestone Conveyor No. L2Belt91 tonne/hr (100 tph) 1 0 25Limestone Day Binw/ actuator372 tonne (410 ton) 2 0 Cost and Performance Baseline for Fossil Energy Plants 365 ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Coal FeederGravimetric54 tonne/hr (60 tph) 6 0 2Coal PulverizerBall type or equivalent54 tonne/hr (60 tph) 6 0 3Limestone Weigh FeederGravimetric31 tonne/hr (34 tph) 1 1 4Limestone Ball MillRotary31 tonne/hr (34 tph) 1 1 5Limestone Mill Slurry Tank with AgitatorN/A121,133 liters (32,000 gal) 1 1 6Limestone Mill Recycle PumpsHorizontal centrifugal2,006 lpm @ 12m H2O (530 gpm @ 40 ft H2O) 1 1 7Hydroclone Classifier4 active cyclones in a 5 cyclone bank492 lpm (130 gpm) per cyclone 1 1 8Distribution Box2-wayN/A 1 1 9Limestone Slurry Storage Tank with AgitatorField erected673,803 liters (178,000 gal) 1 1 10Limestone Slurry Feed PumpsHorizontal centrifugal1,401 lpm @ 9m H2O (370 gpm @ 30 ft H2O) 1 1 Cost and Performance Baseline for Fossil Energy Plants 366 ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Demineralized Water Storage TankVertical, cylindrical, outdoor1,563,375 liters (413,000 gal) 2 0 2Condensate PumpsVertical canned20,441 lpm @ 213 m H2O (5,400 gpm @ 700 ft H2O) 1 1 3Deaerator and Storage TankHorizontal spray type2,600,445 kg/hr (5,733,000 lb/hr), 5 min. tank 1 0 4Boiler Feed Pump/TurbineBarrel type, multi-stage, centrifugal43,532 lpm @ 2,591 m H2O (11,500 gpm @ 8,500 ft H2O) 1 1 5Startup Boiler Feed Pump, Electric Motor DrivenBarrel type, multi-stage, centrifugal12,870 lpm @ 2,591 m H2O (3,400 gpm @ 8,500 ft H2O) 1 0 6LP Feedwater Heater 1A/1BHorizontal U-tube612,350 kg/hr (1,350,000 lb/hr) 2 0 7LP Feedwater Heater 2A/2BHorizontal U-tube612,350 kg/hr (1,350,000 lb/hr) 2 0 8LP Feedwater Heater 3A/3BHorizontal U-tube612,350 kg/hr (1,350,000 lb/hr) 2 0 9LP Feedwater Heater 4A/4BHorizontal U-tube612,350 kg/hr (1,350,000 lb/hr) 2 0 10HP Feedwater Heater 6Horizontal U-tube2,599,084 kg/hr (5,730,000 lb/hr) 1 0 11HP Feedwater Heater 7Horizontal U-tube2,599,084 kg/hr (5,730,000 lb/hr) 1 0 12Auxiliary BoilerShop fabricated, water tube18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0 13Fuel Oil SystemNo. 2 fuel oil for light off1,135,624 liter (300,000 gal) 1 0 14Service Air CompressorsFlooded Screw28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1 15Instrument Air DryersDuplex, regenerative28 m3/min (1,000 scfm) 2 1 16Closed Cycle Cooling Heat ExchangersShell and tube53 GJ/hr (50 MMBtu/hr) each 2 0 17Closed Cycle Cooling Water PumpsHorizontal centrifugal20,820 lpm @ 30 m H2O (5,500 gpm @ 100 ft H2O) 2 1 18Engine-Driven Fire PumpVertical turbine, diesel engine3,785 lpm @ 88 m H2O (1,000 gpm @ 290 ft H2O) 1 1 19Fire Service Booster PumpTwo-stage horizontal centrifugal2,650 lpm @ 64 m H2O (700 gpm @ 210 ft H2O) 1 1 20Raw Water PumpsStainless steel, single suction12,265 lpm @ 18 m H2O (3,240 gpm @ 60 ft H2O) 2 1 21Ground Water PumpsStainless steel, single suction4,921 lpm @ 268 m H2O (1,300 gpm @ 880 ft H2O) 5 1 22Filtered Water PumpsStainless steel, single suction2,953 lpm @ 49 m H2O (780 gpm @ 160 ft H2O) 2 1 23Filtered Water TankVertical, cylindrical2,839,059 liter (750,000 gal) 1 0 24Makeup Water DemineralizerMulti-media filter, cartridge filter, RO membrane assembly, electrodeionization unit1,022 lpm (270 gpm) 1 1 25Liquid Waste Treatment System--10 years, 24-hour storm 1 0 Cost and Performance Baseline for Fossil Energy Plants 367 ACCOUNT 4 BOILER AND ACCESSORI ES Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1BoilerSubcritical, drum wall-fired, low NOx burners, overfire air2,599,084 kg/hr steam @ 17.9 MPa/574°C/574°C (5,730,000 lb/hr steam @ 2,600 psig/1,065°F/1,065°F) 1 0 2Primary Air FanCentrifugal354,256 kg/hr, 4,837 m3/min @ 123 cm WG (781,000 lb/hr, 170,800 acfm @ 48 in. WG) 2 0 3Forced Draft FanCentrifugal1,153,485 kg/hr, 15,744 m3/min @ 47 cm WG (2,543,000 lb/hr, 556,000 acfm @ 19 in. WG) 2 0 4Induced Draft FanCentrifugal1,673,302 kg/hr, 35,314 m3/min @ 104 cm WG (3,689,000 lb/hr, 1,247,100 acfm @ 41 in. WG) 2 0 5SCR Reactor VesselSpace for spare layer3,347,512 kg/hr (7,380,000 lb/hr) 2 0 6SCR Catalyst

3 0 7Dilution Air BlowerCentrifugal198 m3/min @ 108 cm WG (7,000 acfm @ 42 in. WG) 2 1 8Ammonia StorageHorizontal tank219,554 liter (58,000 gal) 5 0 9Ammonia Feed PumpCentrifugal42 lpm @ 91 m H2O (11 gpm @ 300 ft H2O) 2 1 Cost and Performance Baseline for Fossil Energy Plants 368 ACCOUNT 5 FLUE GAS CLEANUP Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Fabric FilterSingle stage, high-ratio with pulse-jet online cleaning system1,673,302 kg/hr (3,689,000 lb/hr) 99.8% efficiency 2 0 2Absorber ModuleCounter-current open spray66,913 m3/min (2,363,000 acfm) 1 0 3Recirculation PumpsHorizontal centrifugal230,910 lpm @ 64 m H2O (61,000 gpm @ 210 ft H2O) 5 1 4Bleed PumpsHorizontal centrifugal6,095 lpm (1,610 gpm) at 20 wt% solids 2 1 5Oxidation Air BlowersCentrifugal117 m3/min @ 0.3 MPa (4,130 acfm @ 37 psia) 2 1 6AgitatorsSide entering50 hp 5 1 7Dewatering CyclonesRadial assembly, 5 units each1,514 lpm (400 gpm) per cyclone 2 0 8Vacuum Filter BeltHorizontal belt48 tonne/hr (53 tph) of 50 wt % slurry 2 1 9Filtrate Water Return PumpsHorizontal centrifugal908 lpm @ 12 m H2O (240 gpm @ 40 ft H2O) 1 1 10Filtrate Water Return Storage TankVertical, lined605,666 lpm (160,000 gal) 1 0 11Process Makeup Water PumpsHorizontal centrifugal4,883 lpm @ 21 m H2O (1,290 gpm @ 70 ft H2O) 1 1 Cost and Performance Baseline for Fossil Energy Plants 369 ACCOUNT 5B CARBON DIOXIDE RECOVERY ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES N/A ACCOUNT 7 HRSG, DUCTING & STAC K ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Econamine FG PlusAmine-based CO2 capture technology1,767,196 kg/h (3,896,000 lb/h) 20.6 wt % CO2 concentration 2 0 2Econamine Condensate PumpCentrifugal18,435 lpm @ 52 m H2O (4,870 gpm @ 170 ft H2O) 1 1 3CO2 CompressorIntegrally geared, multi-stage centrifugal327,872 kg/h @ 15.3 MPa (722,834 lb/h @ 2,215 psia) 2 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1StackReinforced concrete with FRP liner152 m (500 ft) high x5.8 m (19 ft) diameter 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Steam TurbineCommercially available advanced steam turbine708 MW16.5 MPa/566°C/566°C (2400.3 psig/ 1050°F/1050°F) 1 0 2Steam Turbine GeneratorHydrogen cooled, static excitation790 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0 3Surface CondenserSingle pass, divided waterbox including vacuum pumps2,237 GJ/hr (2,120 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1 0 Cost and Performance Baseline for Fossil Energy Plants 370 ACCOUNT 9 COOLING WATER SYSTEM Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Circulating Water PumpsVertical, wet pit1,128,100 lpm @ 30 m(298,000 gpm @ 100 ft) 2 1 2Cooling TowerEvaporative, mechanical draft, multi-cell11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 6299 GJ/hr (5970 MMBtu/hr) heat duty 1 0 Cost and Performance Baseline for Fossil Energy Plants 371 ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Economizer Hopper (part of boiler scope of supply)

4 0 2Bottom Ash Hopper (part of boiler scope of supply)

2 0 3Clinker Grinder

--6.4 tonne/hr (7 tph) 1 1 4Pyrites Hopper (part of pulverizer scope of supply included with boiler)

6 0 5Hydroejectors

12 6Economizer /Pyrites Transfer Tank----1 0 7Ash Sluice PumpsVertical, wet pit227 lpm @ 17 m H2O (60 gpm @ 56 ft H2O) 1 1 8Ash Seal Water PumpsVertical, wet pit7,571 lpm @ 9 m H2O (2000 gpm @ 28 ft H2O) 1 1 9Hydrobins--227 lpm (60 gpm) 1 1 10Baghouse Hopper (part of baghouse scope of supply)

24 0 11Air Heater Hopper (part of boiler scope of supply)

10 0 12Air Blower

--22 m3/min @ 0.2 MPa (770 scfm @ 24 psi) 1 1 13Fly Ash SiloReinforced concrete1,451 tonne (1,600 ton) 2 0 14Slide Gate Valves

2 0 15Unloader----1 0 16Telescoping Unloading Chute

--136 tonne/hr (150 tph) 1 0 Cost and Performance Baseline for Fossil Energy Plants 372 ACCOUNT 11 ACCESSORY ELECTRIC PLANT ACCOUNT 12 INSTRUMENTATION AND CONTROL Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1STG TransformerOil-filled24 kV/345 kV, 650 MVA, 3-ph, 60 Hz 1 0 2Auxiliary TransformerOil-filled24 kV/4.16 kV, 134 MVA, 3-ph, 60 Hz 1 1 3Low Voltage TransformerDry ventilated4.16 kV/480 V, 20 MVA, 3-ph, 60 Hz 1 1 4STG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled24 kV, 3-ph, 60 Hz 1 0 5Medium Voltage SwitchgearMetal clad4.16 kV, 3-ph, 60 Hz 1 1 6Low Voltage SwitchgearMetal enclosed480 V, 3-ph, 60 Hz 1 1 7Emergency Diesel GeneratorSized for emergency shutdown750 kW, 480 V, 3-ph, 60 Hz 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1DCS - Main ControlMonitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W)Operator stations/printers and engineering stations/printers 1 0 2DCS - ProcessorMicroprocessor with redundant input/outputN/A 1 0 3DCS - Data HighwayFiber opticFully redundant, 25% spare 1 0 Cost and Performance Baseline for Fossil Energy Plants 373 4.2.10 The cost estimating methodology was described previously in Section Case 10 - Cost Estimating 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 owner's costs, TOC

, and TASC. Exhibit 4-30 shows the initial and annual O&M costs.

The estimated TOC of the subcritical PC boiler with CO 2 capture is $

3, 610/kW. Process contingency represents 2.9 percent of the TOC and project contingency represents 10.2 percent. The COE, including CO 2 TS&M costs of 5.9 mills/kWh, is 1 09.7 mills/kWh.

Cost and Performance Baseline for Fossil Energy Plants 374 Exhibit 4-28 Case 10 Total Plant Cost Summary Client: USDOE/NETLReport Date:2010-Jan-14Project: Bituminous Baseline StudyCase: Case 10 - 1x550 MWnet SubCritical PC w/ CO2 CapturePlant Size: 550.0MW,netEstimate Type: ConceptualCost Base (Jun) 2007($x1000)AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING$21,191$5,688$12,662$0$0$39,542$3,548$0$6,463$49,553$90 2COAL & SORBENT PREP & FEED$14,465$844$3,675$0$0$18,984$1,664$0$3,097$23,744$43 3FEEDWATER & MISC. BOP SYSTEMS$52,748$0$25,315$0$0$78,063$7,174$0$14,102$99,339$181 4PC BOILER4.1PC Boiler & Accessories$171,007$0$109,973$0$0$280,980$27,374$0$30,835$339,189$6174.2SCR (w/4.1)

$0$0$0$0$0$0$0$0$0$0$04.3Open$0$0$0$0$0$0$0$0$0$0$04.4-4.9Boiler BoP (w/ ID Fans)

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 4$171,007$0$109,973$0$0$280,980$27,374$0$30,835$339,189$617 5FLUE GAS CLEANUP$107,581$0$36,768$0$0$144,350$13,816$0$15,817$173,983$316 5B CO 2 REMOVAL & COMPRESSION$247,434$0$75,421$0$0$322,855$30,869$56,959$82,137$492,819$896 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine GeneratorN/A$0N/A$0$0$0$0$0$0$0$06.2-6.9Combustion Turbine Other

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 6

$0$0$0$0$0$0$0$0$0$0$0 7HRSG, DUCTING & STACK7.1Heat Recovery Steam GeneratorN/A$0N/A$0$0$0$0$0$0$0$07.2-7.9HRSG Accessories, Ductwork and Stack$19,509$1,069$13,214$0$0$33,792$3,095$0$4,848$41,735$76SUBTOTAL 7$19,509$1,069$13,214$0$0$33,792$3,095$0$4,848$41,735$76 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$55,209$0$6,905$0$0$62,114$5,951$0$6,806$74,871$1368.2-8.9Turbine Plant Auxiliaries and Steam Piping$26,840$1,213$15,303$0$0$43,356$3,796$0$6,701$53,853$98SUBTOTAL 8$82,049$1,213$22,207$0$0$105,470$9,747$0$13,507$128,724$234 9COOLING WATER SYSTEM$22,313$10,599$19,714$0$0$52,626$4,953$0$7,745$65,324$119 10ASH/SPENT SORBENT HANDLING SYS$5,525$176$7,387$0$0$13,088$1,258$0$1,477$15,823$29 11ACCESSORY ELECTRIC PLANT$25,948$11,057$31,311$0$0$68,316$6,043$0$9,343$83,703$152 12INSTRUMENTATION & CONTROL$9,942$0$10,082$0$0$20,024$1,816$1,001$2,805$25,646$47 13IMPROVEMENTS TO SITE$3,344$1,922$6,739$0$0$12,006$1,184$0$2,638$15,828$29 14BUILDINGS & 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$2,942TOTAL PLANT COST

SUMMARY

Cost and Performance Baseline for Fossil Energy Plants 375 Exhibit 4-29 Case 10 Total Plant Cost Details AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING1.1Coal Receive & Unload$4,333$0$1,979$0$0$6,313$564$0$1,031$7,908$141.2Coal Stackout & Reclaim$5,600$0$1,269$0$0$6,869$601$0$1,120$8,590$161.3Coal Conveyors$5,207$0$1,255$0$0$6,462$566$0$1,054$8,083$151.4Other Coal Handling$1,362$0$290$0$0$1,653$144$0$270$2,067$41.5Sorbent Receive & Unload

$178$0$54$0$0$231$20$0$38$289$11.6Sorbent Stackout & Reclaim$2,869$0$526$0$0$3,395$296$0$554$4,244$81.7Sorbent Conveyors$1,024$221$251$0$0$1,496$129$0$244$1,869$31.8Other Sorbent Handling

$618$145$324$0$0$1,088$96$0$178$1,361$21.9Coal & Sorbent Hnd.Foundations

$0$5,322$6,714$0$0$12,036$1,130$0$1,975$15,141$28SUBTOTAL 1.$21,191$5,688$12,662$0$0$39,542$3,548$0$6,463$49,553$90 2COAL & SORBENT PREP & FEED2.1Coal Crushing & Drying$2,523$0$492$0$0$3,014$263$0$492$3,768$72.2Coal Conveyor to Storage$6,459$0$1,410$0$0$7,869$688$0$1,283$9,840$182.3Coal Injection System

$0$0$0$0$0$0$0$0$0$0$02.4Misc.Coal Prep & Feed

$0$0$0$0$0$0$0$0$0$0$02.5Sorbent Prep Equipment$4,894$211$1,016$0$0$6,121$533$0$998$7,652$142.6Sorbent Storage & Feed

$590$0$226$0$0$815$72$0$133$1,021$22.7Sorbent Injection System

$0$0$0$0$0$0$0$0$0$0$02.8Booster Air Supply System

$0$0$0$0$0$0$0$0$0$0$02.9Coal & Sorbent Feed Foundation

$0$633$531$0$0$1,164$108$0$191$1,463$3SUBTOTAL 2.$14,465$844$3,675$0$0$18,984$1,664$0$3,097$23,744$43 3FEEDWATER & MISC. BOP SYSTEMS3.1Feedwater System$20,624$0$7,119$0$0$27,743$2,430$0$4,526$34,699$633.2Water Makeup & Pretreating $7,503$0$2,415$0$0$9,919$938$0$2,171$13,028$243.3Other Feedwater Subsystems$6,747$0$2,851$0$0$9,599$860$0$1,569$12,027$223.4Service Water Systems$1,471$0$800$0$0$2,271$214$0$497$2,982$53.5Other Boiler Plant Systems$8,081$0$7,979$0$0$16,060$1,526$0$2,638$20,224$373.6FO Supply Sys & Nat Gas

$278$0$348$0$0$626$59$0$103$788$13.7Waste Treatment Equipment$5,087$0$2,900$0$0$7,987$777$0$1,753$10,517$193.8Misc. Equip.(cranes,AirComp.,Comm.)$2,955$0$903$0$0$3,858$371$0$846$5,075$9SUBTOTAL 3.$52,748$0$25,315$0$0$78,063$7,174$0$14,102$99,339$181 4PC BOILER4.1PC Boiler & Accessories$171,007$0$109,973$0$0$280,980$27,374$0$30,835$339,189$6174.2SCR (w/4.1)

$0$0$0$0$0$0$0$0$0$0$04.3Open$0$0$0$0$0$0$0$0$0$0$04.4Boiler BoP (w/ ID Fans)

$0$0$0$0$0$0$0$0$0$0$04.5Primary Air Systemw/4.1$0w/4.1$0$0$0$0$0$0$0$04.6Secondary Air Systemw/4.1$0w/4.1$0$0$0$0$0$0$0$04.8Major Component Rigging

$0w/4.1w/4.1$0$0$0$0$0$0$0$04.9Boiler Foundations

$0w/14.1w/14.1$0$0$0$0$0$0$0$0SUBTOTAL 4.$171,007$0$109,973$0$0$280,980$27,374$0$30,835$339,189$617 Cost and Performance Baseline for Fossil Energy Plants 376 Exhibit 4-29 Case 10 Total Plant Cost Details (Continued) AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 5FLUE GAS CLEANUP5.1Absorber Vessels & Accessories$74,713$0$16,084$0$0$90,797$8,656$0$9,945$109,399$1995.2Other FGD$3,899$0$4,418$0$0$8,317$807$0$912$10,037$185.3Bag House & Accessories$21,582$0$13,697$0$0$35,279$3,400$0$3,868$42,546$775.4Other Particulate Removal Materials$1,461$0$1,563$0$0$3,023$293$0$332$3,648$75.5Gypsum Dewatering System$5,926$0$1,007$0$0$6,933$660$0$759$8,352$155.6Mercury Removal System

$0$0$0$0$0$0$0$0$0$0$05.9Open$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 5.$107,581$0$36,768$0$0$144,350$13,816$0$15,817$173,983$316 5B CO 2 REMOVAL & COMPRESSION5B.1 CO 2 Removal System$218,463$0$66,332$0$0$284,795$27,229$56,959$73,796$442,779$8055B.2 CO 2 Compression & Drying$28,971$0$9,089$0$0$38,060$3,640$0$8,340$50,040$91SUBTOTAL 5B.$247,434$0$75,421$0$0$322,855$30,869$56,959$82,137$492,819$896 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine GeneratorN/A$0N/A$0$0$0$0$0$0$0$06.2Open$0$0$0$0$0$0$0$0$0$0$06.3Compressed Air Piping

$0$0$0$0$0$0$0$0$0$0$06.9Combustion Turbine Foundations

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 6.

$0$0$0$0$0$0$0$0$0$0$0 7HRSG, DUCTING & STACK7.1Heat Recovery Steam GeneratorN/A$0N/A$0$0$0$0$0$0$0$07.2HRSG Accessories

$0$0$0$0$0$0$0$0$0$0$07.3Ductwork$10,193$0$6,549$0$0$16,743$1,460$0$2,730$20,933$387.4Stack$9,316$0$5,451$0$0$14,766$1,422$0$1,619$17,807$327.9Duct & Stack Foundations

$0$1,069$1,214$0$0$2,283$214$0$499$2,996$5SUBTOTAL 7.$19,509$1,069$13,214$0$0$33,792$3,095$0$4,848$41,735$76 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$55,209$0$6,905$0$0$62,114$5,951$0$6,806$74,871$1368.2Turbine Plant Auxiliaries

$387$0$828$0$0$1,215$119$0$133$1,467$38.3Condenser & Auxiliaries$6,154$0$2,549$0$0$8,702$835$0$954$10,490$198.4Steam Piping$20,300$0$10,009$0$0$30,310$2,547$0$4,928$37,784$698.9TG Foundations

$0$1,213$1,917$0$0$3,130$296$0$685$4,111$7SUBTOTAL 8.$82,049$1,213$22,207$0$0$105,470$9,747$0$13,507$128,724$234 9COOLING WATER SYSTEM9.1Cooling Towers$16,661$0$5,188$0$0$21,850$2,090$0$2,394$26,333$489.2Circulating Water Pumps$3,467$0$260$0$0$3,727$315$0$404$4,446$89.3Circ.Water System Auxiliaries

$839$0$112$0$0$951$90$0$104$1,146$29.4Circ.Water Piping

$0$6,653$6,448$0$0$13,101$1,226$0$2,149$16,476$309.5Make-up Water System

$680$0$909$0$0$1,589$152$0$261$2,002$49.6Component Cooling Water Sys

$665$0$529$0$0$1,194$113$0$196$1,503$39.9Circ.Water System Foundations & Structures

$0$3,946$6,269$0$0$10,214$966$0$2,236$13,417$24SUBTOTAL 9.$22,313$10,599$19,714$0$0$52,626$4,953$0$7,745$65,324$119 Cost and Performance Baseline for Fossil Energy Plants 377 Exhibit 4-29 Case 10 Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 10ASH/SPENT SORBENT HANDLING SYS10.1Ash CoolersN/A$0N/A$0$0$0$0$0$0$0$010.2Cyclone Ash LetdownN/A$0N/A$0$0$0$0$0$0$0$010.3HGCU Ash LetdownN/A$0N/A$0$0$0$0$0$0$0$010.4High Temperature Ash PipingN/A$0N/A$0$0$0$0$0$0$0$010.5Other Ash Recovery EquipmentN/A$0N/A$0$0$0$0$0$0$0$010.6Ash Storage Silos

$739$0$2,278$0$0$3,017$296$0$331$3,645$710.7Ash Transport & Feed Equipment$4,786$0$4,902$0$0$9,688$926$0$1,061$11,676$2110.8Misc. Ash Handling Equipment

$0$0$0$0$0$0$0$0$0$0$010.9Ash/Spent Sorbent Foundation

$0$176$207$0$0$383$36$0$84$502$1SUBTOTAL 10.$5,525$176$7,387$0$0$13,088$1,258$0$1,477$15,823$29 11ACCESSORY ELECTRIC PLANT11.1Generator Equipment$1,742$0$283$0$0$2,025$188$0$166$2,379$411.2Station Service Equipment$5,148$0$1,691$0$0$6,839$639$0$561$8,039$1511.3Switchgear & Motor Control $5,918$0$1,006$0$0$6,924$642$0$757$8,322$1511.4Conduit & Cable Tray

$0$3,710$12,830$0$0$16,540$1,601$0$2,721$20,862$3811.5Wire & Cable

$0$7,001$13,516$0$0$20,517$1,729$0$3,337$25,582$4711.6Protective Equipment

$270$0$918$0$0$1,188$116$0$130$1,434$311.7Standby Equipment$1,370$0$31$0$0$1,401$128$0$153$1,682$311.8Main Power Transformers$11,500$0$191$0$0$11,691$886$0$1,258$13,835$2511.9Electrical Foundations

$0$345$846$0$0$1,191$114$0$261$1,566$3SUBTOTAL 11.$25,948$11,057$31,311$0$0$68,316$6,043$0$9,343$83,703$152 12INSTRUMENTATION & CONTROL12.1PC Control Equipmentw/12.7$0w/12.7$0$0$0$0$0$0$0$012.2Combustion Turbine ControlN/A$0N/A$0$0$0$0$0$0$0$012.3Steam Turbine Controlw/8.1$0w/8.1$0$0$0$0$0$0$0$012.4Other Major Component Control

$0$0$0$0$0$0$0$0$0$0$012.5Signal Processing Equipmentw/12.7$0w/12.7$0$0$0$0$0$0$0$012.6Control Boards,Panels & Racks

$512$0$307$0$0$819$77$41$141$1,077$212.7Distributed Control System Equipment$5,168$0$903$0$0$6,071$563$304$694$7,632$1412.8Instrument Wiring & Tubing$2,802$0$5,558$0$0$8,359$712$418$1,423$10,913$2012.9Other I & C Equipment$1,460$0$3,314$0$0$4,774$463$239$548$6,024$11SUBTOTAL 12.$9,942$0$10,082$0$0$20,024$1,816$1,001$2,805$25,646$47 Cost and Performance Baseline for Fossil Energy Plants 378 Exhibit 4-29 Case 10 Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 13IMPROVEMENTS TO SITE13.1Site Preparation

$0$56$1,124$0$0$1,180$117$0$260$1,557$313.2Site Improvements

$0$1,866$2,318$0$0$4,184$413$0$919$5,516$1013.3Site Facilities$3,344$0$3,298$0$0$6,642$655$0$1,459$8,756$16SUBTOTAL 13.$3,344$1,922$6,739$0$0$12,006$1,184$0$2,638$15,828$29 14BUILDINGS & STRUCTURES14.1Boiler Building

$0$9,158$8,054$0$0$17,212$1,547$0$2,814$21,573$3914.2Turbine Building

$0$13,420$12,507$0$0$25,927$2,337$0$4,240$32,503$5914.3Administration Building

$0$646$684$0$0$1,330$121$0$218$1,668$314.4Circulation Water Pumphouse

$0$176$140$0$0$317$28$0$52$397$114.5Water Treatment Buildings

$0$952$868$0$0$1,819$164$0$297$2,281$414.6Machine Shop

$0$432$290$0$0$723$64$0$118$905$214.7Warehouse

$0$293$294$0$0$587$53$0$96$736$114.8Other Buildings & Structures

$0$239$204$0$0$443$40$0$72$555$114.9Waste Treating Building & Str.

$0$458$1,391$0$0$1,849$176$0$304$2,329$4SUBTOTAL 14.

$0$25,775$24,432$0$0$50,207$4,529$0$8,210$62,947$114TOTAL COST$783,055$58,343$398,903$0$0$1,240,301$117,071$57,960$203,025$1,618,357$2,942Owner's CostsPreproduction Costs6 Months All Labor$10,547$191 Month Maintenance Materials$1,534$31 Month Non-fuel Consumables$1,789$31 Month Waste Disposal

$353$125% of 1 Months Fuel Cost at 100% CF$2,143$42% of TPC$32,367$59Total$48,733$89Inventory Capital60 day supply of fuel and consumables at 100% CF$20,189$370.5% of TPC (spare parts)$8,092$15Total$28,281$51Initial Cost for Catalyst and Chemicals$2,712$5Land$900$2Other Owner's Costs$242,754$441Financing Costs$43,696$79Total Overnight Costs (TOC)$1,985,432$3,610TASC Multiplier(IOU, high-risk, 35 year)1.140Total As-Spent Cost (TASC)$2,263,393$4,115 Cost and Performance Baseline for Fossil Energy Plants 379 Exhibit 4-30 Case 10 Initial and Annual Operating and Maintenance Costs INITIAL & ANNUAL O&M EXPENSESCost Base (Jun):

2007Case 10 - 1x550 MWnet SubCritical PC w/ CO2 CaptureHeat Rate-net (Btu/kWh):13,044 MWe-net: 550Capacity Factor (%):

85OPERATING & MAINTENANCE LABOROperating Labor Operating Labor Rate(base):34.65$/hour Operating Labor Burden:30.00% of base Labor O-H Charge Rate:25.00% of laborTotal Operating Labor Requirements(O.J.)per Shift:1 unit/mod. Plant Skilled Operator2.02.0 Operator11.311.3 Foreman1.01.0 Lab Tech's, etc.2.02.0 TOTAL-O.J.'s16.316.3Annual CostAnnual Unit Cost

$$/kW-netAnnual Operating Labor Cost$6,444,907$11.718Maintenance Labor Cost$10,429,543$18.962Administrative & Support Labor$4,218,612$7.670Property Taxes and Insurance$32,367,148$58.848TOTAL FIXED OPERATING COSTS$53,460,210$97.199VARIABLE OPERATING COSTS$/kWh-netMaintenance Material Cost$15,644,314$0.00382ConsumablesConsumptionUnit Initial Fill Initial Fill /Day Cost CostWater(/1000 gallons) 08,0811.08$0$2,711,996$0.00066ChemicalsMU & WT Chem.(lbs) 039,1190.17$0$2,100,447$0.00051Limestone (ton) 0 75121.63$0$5,043,346$0.00123Carbon (Mercury Removal) (lb) 0 01.05$0$0$0.00000MEA Solvent (ton)1,1171.582,249.89$2,513,263$1,105,563$0.00027NaOH (tons) 797.89433.68$34,221$1,061,704$0.00026H2SO4 (tons) 757.53138.78$10,450$324,217$0.00008Corrosion Inhibitor 0 00.00$154,511$7,358$0.00000Activated Carbon (lb) 01,8921.05$0$616,433$0.00015Ammonia (19% NH3) ton 0 110129.80$0$4,446,378$0.00109Subtotal Chemicals$2,712,445$14,705,446$0.00359OtherSupplemental Fuel (MBtu) 0 00.00$0$0$0.00000SCR Catalyst (m3)w/equip.0.465,775.94$0$831,516$0.00020Emission Penalties 0 00.00$0$0$0.00000Subtotal Other

$0$831,516$0.00020Waste DisposalFly Ash (ton) 0 57216.23$0$2,881,846$0.00070Bottom Ash (ton) 0 14316.23$0$720,462$0.00018 Subtotal-Waste Disposal

$0$3,602,308$0.00088By-products & Emissions Gypsum (tons) 01,1590.00$0$0$0.00000Subtotal By-Products

$0$0$0.00000TOTAL VARIABLE OPERATING COSTS$2,712,445$37,495,580$0.00916Fuel(ton)07,38038.18$0$87,425,787$0.02135 Cost and Performance Baseline for Fossil Energy Plants 380 4.3 SUPERCRITICAL PC CAS ES 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

, 100F/1 , 100F) cycle. The only difference between the two plants is that Case 12 includes CO 2 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 In this section the SC PC process without CO 2 capture is described. The system description is nearly identical to the subcritical PC case without CO 2 capture but is repeated here for completeness. The description follows the BFD in Process Description 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

.

Cost and Performance Baseline for Fossil Energy Plants 381 Exhibit 4-31 Case 11 Block Flow Diagram, Supercritical Unit without CO 2 Capture Cost and Performance Baseline for Fossil Energy Plants 382 Exhibit 4-32 Case 11 Stream Table, Supercritical Unit without CO 2 Capture 1 2 3 4 5 6 7 8 9 10 11 12V-L Mole Fraction Ar0.00920.00920.00920.00920.00920.00920.00920.00000.00000.00870.00000.0087 CO 20.00030.00030.00030.00030.00030.00030.00030.00000.00000.14500.00000.1450 H 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 H 2 O0.00990.00990.00990.00990.00990.00990.00990.00000.00000.08700.00000.0870 N 20.77320.77320.77320.77320.77320.77320.77320.00000.00000.73240.00000.7324 O 20.20740.20740.20740.20740.20740.20740.20740.00000.00000.02470.00000.0247 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00210.00000.0021Total1.00001.00001.00001.00001.00001.00001.00000.00000.00001.00000.00001.0000V-L Flowrate (kgmol/hr)48,41448,4141,43414,87214,8722,0471,119 0 068,126 068,126V-L Flowrate (kg/hr)1,397,0671,397,06741,378429,164429,16459,06432,284 0 02,026,262 02,026,262Solids Flowrate (kg/hr) 0 0 0 0 0 0 0185,7593,60314,41014,410 0Temperature (°C) 15 19 19 15 25 25 15 15 15 169 15 169Pressure (MPa, abs)0.100.110.110.100.110.110.100.100.100.100.100.10Enthalpy (kJ/kg)

A30.2334.3634.3630.2340.7840.7830.23------327.37---308.94Density (kg/m 3)1.21.21.21.21.31.31.2------0.8---0.8V-L Molecular Weight28.85728.85728.85728.85728.85728.85728.857------29.743---29.743V-L Flowrate (lbmol/hr)106,734106,7343,16132,78732,7874,5122,466 0 0150,191 0150,191V-L Flowrate (lb/hr)3,080,0063,080,00691,224946,145946,145130,21571,175 0 04,467,142 04,467,142Solids Flowrate (lb/hr) 0 0 0 0 0 0 0409,5287,94231,76931,769 0Temperature (°F) 59 66 66 59 78 78 59 59 59 337 59 337Pressure (psia)14.715.315.314.716.116.114.714.714.714.414.714.2Enthalpy (Btu/lb)

A13.014.814.813.017.517.513.0------140.7---132.8Density (lb/ft 3)0.0760.0780.0780.0760.0810.0810.076------0.050---0.049A - Reference conditions are 32.02 F & 0.089 PSIA Cost and Performance Baseline for Fossil Energy Plants 383 Exhibit 4-32 Case 11 Stream Table, Supercritical Unit without CO 2 Capture (Continued) 13 14 15 16 17 18 19 20 21 22 23V-L Mole Fraction Ar0.00870.00000.00000.01280.00000.00820.00000.00000.00000.00000.0000 CO 20.14500.00000.00000.00050.00040.13530.00000.00000.00000.00000.0000 H 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 H 2 O0.08701.00001.00000.00620.99950.15171.00001.00001.00001.00001.0000 N 20.73240.00000.00000.75060.00000.68080.00000.00000.00000.00000.0000 O 20.02470.00000.00000.23000.00000.02400.00000.00000.00000.00000.0000 SO 20.00210.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000Total1.00001.00001.00001.00001.00001.00001.00001.00001.00001.00001.0000V-L Flowrate (kgmol/hr)68,1262,3699,597 726 17674,09192,38976,59176,59169,89169,891V-L Flowrate (kg/hr)2,026,26242,682172,89821,0763,1682,137,8811,664,4211,379,8031,379,8031,259,0991,259,099Solids Flowrate (kg/hr) 018,437 0 028,694 0 0 0 0 0 0Temperature (°C) 181 15 15 167 57 57 593 354 593 38 39Pressure (MPa, abs)0.110.100.100.310.100.1024.234.904.520.011.69Enthalpy (kJ/kg)

A321.02----46.80177.65---297.663,476.623,082.883,652.221,985.85165.59Density (kg/m 3)0.8---1,003.12.5---1.169.218.711.60.1993.3V-L Molecular Weight29.743---18.01529.029---28.85518.01518.01518.01518.01518.015V-L Flowrate (lbmol/hr)150,1915,22321,1581,601 387163,343203,684168,854168,854154,082154,082V-L Flowrate (lb/hr)4,467,14294,099381,17446,4656,9854,713,2213,669,4213,041,9463,041,9462,775,8392,775,839Solids Flowrate (lb/hr) 040,646 0 063,259 0 0 0 0 0 0Temperature (°F) 357 59 59 333 135 1351,100 6691,100 101 103Pressure (psia)15.315.014.745.014.814.83,514.7710.8655.81.0245.0Enthalpy (Btu/lb)

A138.0----20.176.4---128.01,494.71,325.41,570.2853.871.2Density (lb/ft 3)0.052---62.6220.154---0.0674.3191.1650.7220.00462.009 Cost and Performance Baseline for Fossil Energy Plants 384 4.3.2 System assumptions for Cases 11 and 12 , SC PC with and without CO 2 capture, are compiled in Key System Assumptions Exhibit 4-33. Exhibit 4-33 Supercritical PC Plant Study Configuration Matrix Case 11 w/o CO 2 Capture Case 1 2 w/CO 2 Capture Steam Cycle , MPa/°C/°C (psig/°F/°F) 24.1/593/593 (35 00/1100/1100) 24.1/593/593 (35 00/1100/1100)

Coal Illinois No. 6 Illinois No. 6 Condenser pressure, mm Hg (in Hg) 50.8 (2) 50.8 (2) Boiler Efficiency , % 88 8 8 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) SO 2 Control Wet Limestone Forced Oxidation Wet Limestone Forced Oxidation FGD Efficiency , % (A) 98 98 (B , C) NOx Control LNB w/OFA and SCR LNB w/OFA and SCR SCR Efficiency , % (A) 86 86 Ammonia Slip (end of catalyst life), ppm v 2 2 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 CO 2 Control N/A Econamine Overall CO 2 Capture (A)

N/A 90.2% CO 2 Sequestration N/A Off-site Saline Formation A. Removal efficiencies are based on the FG content B. An SO 2 polishing step is included to meet more stringent SOx content limits in the FG (< 10 ppmv) to reduce formation of amine HSS during the CO 2 absorption process C. SO 2 exiting the post

-FGD polishing step is absorbed in the CO 2 capture process making stack emissions negligible The balance of plant assumptions are common to all cases and were presented previously in Balance of Plant

- Cases 11 and 12 Exhibit 4-6.

Cost and Performance Baseline for Fossil Energy Plants 385 4.3.3 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:

Sparing Philosophy 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 CO 2 absorption systems, with each system consisting of two absorbers, strippers

, and ancillary equipment (2 x 50%)

4.3.4 The plant produces a net output of 550 MWe at a net plant efficiency of 39.3 percent (HHV basis). Case 11 Performance Results Overall performance for the plant is summarized in Exhibit 4-34 , which includes auxiliary power requirements.

Cost and Performance Baseline for Fossil Energy Plants 386 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 5 80 , 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 Miscellaneous Balance of Plant2,3 2,000 Steam Turbine Auxiliaries 400 Condensate Pumps 800 Circulating Water Pum ps 4,730 Ground Water Pumps 48 0 Cooling Tower Fans 2,440 Transformer Losses 1,820 TOTAL AUXILIARIES, kWe 30, 41 0 NET POWER, kWe 5 49 , 99 0 Net Plant Efficiency (HHV) 3 9.3% Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,16 5 (8,68 7) CONDENSER COOLING DUTY, 10 6 kJ/h r (10 6 Btu/h r) 2,298 (2,178)

CONSUMABLES As-Received Coal Feed, kg/h r (lb/h r) 185,759 (409,528)

Limestone Sorbent Feed, kg/h r (lb/h r) 18, 437 (40, 646) Thermal Input, kWt 1 1, 4 00 , 1 62 Raw Water Withdrawal, m 3/min (gpm) 20.1 (5,321)

Raw Water Consumption, m 3/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

Cost and Performance Baseline for Fossil Energy Plants 387 The environmental targets for emissions of Hg, NOx, SO 2 , and PM were presented in Section 2.4. A summary of the plant air emissions for Case 11 is presented in Environmental Performance Exhibit 4-35. Exhibit 4-35 Case 11 Air Emissions kg/GJ (lb/10 6 Btu) Tonne/year (ton/year) 85% CF kg/MWh (lb/MWh) SO 2 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) CO 2 87.5 (203.5) 3,284,245 (3,620,261) 760 (1,675)

CO 2 1 80 2 (1,7 68) 1 CO 2 emissions based on net power instead of gross power SO 2 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/10 6 Btu through the use of LNBs and OFA. An SCR unit then further reduces the NOx concentration by 86 percent to 0.07 lb/10 6 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.

CO 2 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 CO 2 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 (CO 2) 257 (567) FGD Product 163 (358) FGD Reagent 1,871 (4,124)

Total 120,539 (265,744)

Cost and Performance Baseline for Fossil Energy Plants 388 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 Water Use Water Demand, m 3/min (gpm) Internal Recycle, m 3/min (gpm) Raw Water Withdrawal, m 3/min (gpm) Process Water Discharge, m 3/min (gpm) Raw Water Consumption, m 3/min (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)

Cost and Performance Baseline for Fossil Energy Plants 389 A heat and mass balance diagram is shown for the Case 11 PC boiler, the FGD unit and steam cycle in Heat and Mass Balance Diagrams 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.

Cost and Performance Baseline for Fossil Energy Plants 390 This page intentionally left blank

Cost and Performance Baseline for Fossil Energy Plants 391 Exhibit 4-39 Case 11 Heat and Mass Balance, Supercritical PC Boiler without CO 2 Capture N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA H EAT AND M ATERIAL F LOW D IAGRAM P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Ash Slurry Synthesis Gas Sour Gas Sour Water Water Steam P AGES 1 OF 2 B ITUMINOUS B ASELINE S TUDY C ASE 11 S UPERCRITICAL P ULVERIZED C OAL B OILER AND G AS C LEANUP S YSTEMS DWG. NO.BB-HMB-CS-11-PG-1 Pulverized Coal Boiler SCR AMMONIA INFILTRATION AIR AIR AIR COAL ASH From Feedwater Heaters Single Reheat To IP Turbine Throttle Steam To HP Turbine FGD ASH FORCED DRAFT FANS PRIMARY AIR FANS STACK 409 , 528 W 77.8 T 16.1 P 17.5 H 66.4 T 15.3 P 14.8 H 3 , 669 , 421 W 1 , 100.0 T 3 , 514.7 P 1 , 494.7 H 3 , 041 , 946 W 1 , 100.0 T 655.8 P 1 , 570.2 H Single Reheat Extraction from HP Turbine 946 , 145 W 59.0 T 14.7 P 13.0 H 3 , 080 , 006 W 59.0 T 14.7 P 13.0 H 71 , 175 W 59.0 T 14.7 P 13.0 H 4 , 498 , 911 W 337.0 T 14.4 P 140.7 H 7 , 942 W 31 , 769 W 3 , 041 , 946 W 669.2 T 710.8 P 1 , 325.4 H 3 , 669 , 421 W 556.6 T 4 , 185.0 P 552.5 H 5 4 , 713 , 221 W 135.0 T 14.8 P 128.0 H 1 2 4 7 9 ID FANS 4 , 467 , 142 W 337.0 T 14.2 P 132.8 H Gross Plant Power

580 MWe Auxiliary Load

30 MWe Net Plant Power

550 MWe Net Plant Efficiency , HHV: 39.3%Net Plant Heat Rate

8 , 687 BTU/KWe Lime/Ash Flue Gas OXIDATION AIR MAKE-UP WATER LIMESTONE SLURRY GYPSUM 15 14 11 357.4 T 15.3 P 138.0 H 134 , 744 W 59.0 T 15.0 P 46 , 465 W 332.9 T 45.0 P 381 , 174 W 59.0 T 14.7 P 70 , 244 W 135.0 T 14.8 P Baghouse 3 6 8 10 12 13 16 17 18 19 20 21 DOE/NETL SC PC P LANT C ASE 11 Cost and Performance Baseline for Fossil Energy Plants 392 Exhibit 4-40 Case 11 Heat and Mass Balance, Supercritical Steam Cycle N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA H EAT AND M ATERIAL F LOW D IAGRAM P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas Sour Gas Sour Water Water Steam P AGES 2 OF 2 DWG. NO.BB-HMB-CS-11-PG-2 B ITUMINOUS B ASELINE S TUDY C ASE 11 S UPERCRITICAL P ULVERIZED C OAL P OWER B LOCK S YSTEMS LP TURBINE GENERATOR HP TURBINE IP TURBINE CONDENSER HOT WELL P-1028 P-1048 To Boiler BOILER FEED PUMP TURBINE DRIVES STEAM SEAL REGULATOR Throttle Steam Single Reheat Extraction From Boiler GLAND SEAL CONDENSER CONDENSATE PUMPS 3 , 669 , 421 W 1 , 100.0 T 3 , 514.7 P 1 , 494.7 H 2 , 900.0 P 169 , 635 W 888.4 T 300.8 P 1 , 467.0 H 327 , 489 W 663.9 T 689.5 P 1 , 323.6 H Single Reheat Extraction to Boiler 3 , 041 , 946 W 669.2 T 710.8 P 1 , 325.4 H 710.8 P 1 , 115.5 P 269 , 128 W 772.0 T 1 , 085.0 P 1 , 367.5 H 710.8 P 710.8 P 310.1 P 137.7 P 137.7 P 223 , 857 W 687.5 T 134.9 P 1 , 370.8 H 223 , 857 W 126.1 T 2.0 P 1 , 093.5 H 2 , 775 , 839 W 101.1 T 1.0 P 853.8 H 2 , 793 W 212.0 T 14.7 P 179.9 H 72.7 P 19.2 P 8.4 P 101.4 T 250.0 P 70.0 H 2 , 793 W 713.5 T 137.7 P 1 , 383.8 H 2 , 775 , 839 W 101.1 T 1.0 P 69.1 H 2 , 775 , 839 W 102.6 T 245.0 P 71.2 H 2 , 775 , 839 W 141.4 T 240.0 P 109.8 H 480 , 444 W 112.6 T 1.4 P 80.5 H 388 , 060 W 151.4 T 3.9 P 119.2 H 2 , 775 , 839 W 296.9 T 225.0 P 266.5 H 766 , 252 W 369.5 T 172.2 P 341.9 H 2 , 775 , 839 W 218.0 T 230.0 P 186.4 H 596 , 617 W 429.6 T 342.2 P 407.0 H 269 , 128 W 511.5 T 753.7 P 501.2 H 3 , 669 , 421 W 419.6 T 4 , 195.0 P 400.2 H 3 , 669 , 421 W 501.5 T 4 , 190.0 P 488.9 H DEAERATOR BOILER FEED PUMPS 3 , 669 , 421 W 556.6 T 4 , 185.0 P 552.5 H 3 , 041 , 946 W 1 , 100.0 T 655.8 P 1 , 570.2 H 200 , 638 W 228.0 T 20.0 P 196.0 H 299 , 542 W 188.4 T 9.0 P 156.2 H 2 , 775 , 839 W 178.4 T 235.0 P 146.7 H 127 , 330 W 696.6 T 133.6 P 1 , 375.5 H 200 , 638 W 545.6 T 69.0 P 1 , 304.2 H 98 , 904 W 293.8 T 18.2 P 1 , 188.3 H 88 , 519 W 211.3 T 8.1 P 1 , 152.2 H 92 , 383 W 146.4 T 3.4 P 1 , 077.8 H 2 , 900.0 P 2 , 762 , 263 W 687.5 T 134.9 P 2 , 538 , 406 W 687.5 T 134.9 P 1 , 370.8 H 3.5 P 2 , 900.0 P 359.5 T 4 , 200.0 P 337.6 H 3 , 669 , 421 W 349.4 T 133.6 P 320.7 H 3 , 301 W 713.5 T 137.7 P 1 , 383.8 H Gross Plant Power

580 MWe Auxiliary Load

30 MWe Net Plant Power

550 MWe Net Plant Efficiency , HHV: 39.3%Net Plant Heat Rate

8 , 687 BTU/KWe FWH 1 FWH 2 FWH 3 FWH 4 FWH 6 FWH 7 FWH 8 7 , 482 W 713.5 T 137.7 P 1 , 383.8 H 19 20 21 22 23 DOE/NETL SC PC P LANT C ASE 11 Cost and Performance Baseline for Fossil Energy Plants 393 Exhibit 4-41 Case 11 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total 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 Blowdown 30.8 (29.2) 30.8 (29.2)

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.

Cost and Performance Baseline for Fossil Energy Plants 394 4.3.5 Major equipment items for the SC PC plant with no CO 2 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 Case 11 - Major Equipment List 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 No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Bottom Trestle Dumper and Receiving HoppersN/A181 tonne (200 ton) 2 0 2FeederBelt572 tonne/hr (630 tph) 2 0 3Conveyor No. 1Belt1,134 tonne/hr (1,250 tph) 1 0 4Transfer Tower No. 1EnclosedN/A 1 0 5Conveyor No. 2Belt1,134 tonne/hr (1,250 tph) 1 0 6As-Received Coal Sampling SystemTwo-stageN/A 1 0 7Stacker/ReclaimerTraveling, linear1,134 tonne/hr (1,250 tph) 1 0 8Reclaim HopperN/A36 tonne (40 ton) 2 1 9FeederVibratory154 tonne/hr (170 tph) 2 1 10Conveyor No. 3Belt w/ tripper308 tonne/hr (340 tph) 1 0 11Crusher TowerN/AN/A 1 0 12Coal Surge Bin w/ Vent FilterDual outlet154 tonne (170 ton) 2 0 13CrusherImpactor reduction8 cm x 0 - 3 cm x 0(3 in x 0 1/4 in x 0) 2 0 14As-Fired Coal Sampling SystemSwing hammerN/A 1 1 15Conveyor No. 4Belt w/tripper308 tonne/hr (340 tph) 1 0 16Transfer Tower No. 2EnclosedN/A 1 0 17Conveyor No. 5Belt w/ tripper308 tonne/hr (340 tph) 1 0 18Coal Silo w/ Vent Filter and Slide GatesField erected726 tonne (800 ton) 3 0 19Limestone Truck Unloading HopperN/A36 tonne (40 ton) 1 0 20Limestone FeederBelt82 tonne/hr (90 tph) 1 0 21Limestone Conveyor No. L1Belt82 tonne/hr (90 tph) 1 0 22Limestone Reclaim HopperN/A18 tonne (20 ton) 1 0 23Limestone Reclaim FeederBelt64 tonne/hr (70 tph) 1 0 24Limestone Conveyor No. L2Belt64 tonne/hr (70 tph) 1 0 25Limestone Day Binw/ actuator245 tonne (270 ton) 2 0 Cost and Performance Baseline for Fossil Energy Plants 395 ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Coal FeederGravimetric36 tonne/hr (40 tph) 6 0 2Coal PulverizerBall type or equivalent36 tonne/hr (40 tph) 6 0 3Limestone Weigh FeederGravimetric20 tonne/hr (22 tph) 1 1 4Limestone Ball MillRotary20 tonne/hr (22 tph) 1 1 5Limestone Mill Slurry Tank with AgitatorN/A75,708 liters (20,000 gal) 1 1 6Limestone Mill Recycle PumpsHorizontal centrifugal1,287 lpm @ 12m H2O (340 gpm @ 40 ft H2O) 1 1 7Hydroclone Classifier4 active cyclones in a 5 cyclone bank341 lpm (90 gpm) per cyclone 1 1 8Distribution Box2-wayN/A 1 1 9Limestone Slurry Storage Tank with AgitatorField erected439,108 liters (116,000 gal) 1 1 10Limestone Slurry Feed PumpsHorizontal centrifugal908 lpm @ 9m H2O (240 gpm @ 30 ft H2O) 1 1 Cost and Performance Baseline for Fossil Energy Plants 396 ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Demineralized Water Storage TankVertical, cylindrical, outdoor1,101,555 liters (291,000 gal) 2 0 2Condensate PumpsVertical canned23,091 lpm @ 213 m H2O (6,100 gpm @ 700 ft H2O) 1 1 3Deaerator and Storage TankHorizontal spray type1,830,699 kg/hr (4,036,000 lb/hr), 5 min. tank 1 0 4Boiler Feed Pump/TurbineBarrel type, multi-stage, centrifugal30,662 lpm @ 3,444 m H2O (8,100 gpm @ 11,300 ft H2O) 1 1 5Startup Boiler Feed Pump, Electric Motor DrivenBarrel type, multi-stage, centrifugal9,085 lpm @ 3,444 m H2O (2,400 gpm @ 11,300 ft H2O) 1 0 6LP Feedwater Heater 1A/1BHorizontal U-tube693,996 kg/hr (1,530,000 lb/hr) 2 0 7LP Feedwater Heater 2A/2BHorizontal U-tube693,996 kg/hr (1,530,000 lb/hr) 2 0 8LP Feedwater Heater 3A/3BHorizontal U-tube693,996 kg/hr (1,530,000 lb/hr) 2 0 9LP Feedwater Heater 4A/4BHorizontal U-tube693,996 kg/hr (1,530,000 lb/hr) 2 0 10HP Feedwater Heater 6Horizontal U-tube1,832,513 kg/hr (4,040,000 lb/hr) 1 0 11HP Feedwater Heater 7Horizontal U-tube1,832,513 kg/hr (4,040,000 lb/hr) 1 0 12HP Feedwater heater 8Horizontal U-tube1,832,513 kg/hr (4,040,000 lb/hr) 1 0 13Auxiliary BoilerShop fabricated, water tube18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0 14Fuel Oil SystemNo. 2 fuel oil for light off1,135,624 liter (300,000 gal) 1 0 15Service Air CompressorsFlooded Screw28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1 16Instrument Air DryersDuplex, regenerative28 m3/min (1,000 scfm) 2 1 17Closed Cycle Cooling Heat ExchangersShell and tube53 GJ/hr (50 MMBtu/hr) each 2 0 18Closed Cycle Cooling Water PumpsHorizontal centrifugal20,820 lpm @ 30 m H2O (5,500 gpm @ 100 ft H2O) 2 1 19Engine-Driven Fire PumpVertical turbine, diesel engine3,785 lpm @ 88 m H2O (1,000 gpm @ 290 ft H2O) 1 1 20Fire Service Booster PumpTwo-stage horizontal centrifugal2,650 lpm @ 64 m H2O (700 gpm @ 210 ft H2O) 1 1 21Raw Water PumpsStainless steel, single suction5,943 lpm @ 18 m H2O (1,570 gpm @ 60 ft H2O) 2 1 22Ground Water PumpsStainless steel, single suction2,385 lpm @ 268 m H2O (630 gpm @ 880 ft H2O) 5 1 23Filtered Water PumpsStainless steel, single suction1,893 lpm @ 49 m H2O (500 gpm @ 160 ft H2O) 2 1 24Filtered Water TankVertical, cylindrical1,816,998 liter (480,000 gal) 1 0 25Makeup Water DemineralizerMulti-media filter, cartridge filter, RO membrane assembly, electrodeionization unit606 lpm (160 gpm) 1 1 26Liquid Waste Treatment System--10 years, 24-hour storm 1 0 Cost and Performance Baseline for Fossil Energy Plants 397 ACCOUNT 4 BOILER AND ACCESSORI ES Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1BoilerSupercritical, drum, wall-fired, low NOx burners, overfire air1,832,513 kg/hr steam @ 25.5 MPa/602°C/602°C (4,040,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) 1 0 2Primary Air FanCentrifugal235,868 kg/hr, 3,220 m3/min @ 123 cm WG (520,000 lb/hr, 113,700 acfm @ 48 in. WG) 2 0 3Forced Draft FanCentrifugal768,385 kg/hr, 10,486 m3/min @ 47 cm WG (1,694,000 lb/hr, 370,300 acfm @ 19 in. WG) 2 0 4Induced Draft FanCentrifugal1,114,476 kg/hr, 23,469 m3/min @ 91 cm WG (2,457,000 lb/hr, 828,800 acfm @ 36 in. WG) 2 0 5SCR Reactor VesselSpace for spare layer2,227,139 kg/hr (4,910,000 lb/hr) 2 0 6SCR Catalyst

3 0 7Dilution Air BlowerCentrifugal133 m3/min @ 108 cm WG (4,700 acfm @ 42 in. WG) 2 1 8Ammonia StorageHorizontal tank147,631 liter (39,000 gal) 5 0 9Ammonia Feed PumpCentrifugal28 lpm @ 91 m H2O (7 gpm @ 300 ft H2O) 2 1 Cost and Performance Baseline for Fossil Energy Plants 398 ACCOUNT 5 FLUE GAS CLEANUP ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES N/A Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Fabric FilterSingle stage, high-ratio with pulse-jet online cleaning system1,114,476 kg/hr (2,457,000 lb/hr) 99.8% efficiency 2 0 2Absorber ModuleCounter-current open spray44,769 m3/min (1,581,000 acfm) 1 0 3Recirculation PumpsHorizontal centrifugal155,202 lpm @ 64 m H2O (41,000 gpm @ 210 ft H2O) 5 1 4Bleed PumpsHorizontal centrifugal3,975 lpm (1,050 gpm) at 20 wt% solids 2 1 5Oxidation Air BlowersCentrifugal78 m3/min @ 0.3 MPa (2,770 acfm @ 37 psia) 2 1 6AgitatorsSide entering50 hp 5 1 7Dewatering CyclonesRadial assembly, 5 units each984 lpm (260 gpm) per cyclone 2 0 8Vacuum Filter BeltHorizontal belt32 tonne/hr (35 tph) of 50 wt % slurry 2 1 9Filtrate Water Return PumpsHorizontal centrifugal606 lpm @ 12 m H2O (160 gpm @ 40 ft H2O) 1 1 10Filtrate Water Return Storage TankVertical, lined378,541 lpm (100,000 gal) 1 0 11Process Makeup Water PumpsHorizontal centrifugal3,180 lpm @ 21 m H2O (840 gpm @ 70 ft H2O) 1 1 Cost and Performance Baseline for Fossil Energy Plants 399 ACCOUNT 7 HRSG, DUCTING & STAC K ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES ACCOUNT 9 COOLING WATER SYSTEM Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1StackReinforced concrete with FRP liner152 m (500 ft) high x5.6 m (19 ft) diameter 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Steam TurbineCommercially available advanced steam turbine611 MW24.1 MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 1 0 2Steam Turbine GeneratorHydrogen cooled, static excitation680 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0 3Surface CondenserSingle pass, divided waterbox including vacuum pumps2,532 GJ/hr (2,400 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Circulating Water PumpsVertical, wet pit473,200 lpm @ 30 m(125,000 gpm @ 100 ft) 2 1 2Cooling TowerEvaporative, mechanical draft, multi-cell11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2648 GJ/hr (2510 MMBtu/hr) heat duty 1 0 Cost and Performance Baseline for Fossil Energy Plants 400 ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Economizer Hopper (part of boiler scope of supply)

4 0 2Bottom Ash Hopper (part of boiler scope of supply)

2 0 3Clinker Grinder

--3.6 tonne/hr (4 tph) 1 1 4Pyrites Hopper (part of pulverizer scope of supply included with boiler)

6 0 5Hydroejectors

12 6Economizer /Pyrites Transfer Tank----1 0 7Ash Sluice PumpsVertical, wet pit151 lpm @ 17 m H2O (40 gpm @ 56 ft H2O) 1 1 8Ash Seal Water PumpsVertical, wet pit7,571 lpm @ 9 m H2O (2000 gpm @ 28 ft H2O) 1 1 9Hydrobins--151 lpm (40 gpm) 1 1 10Baghouse Hopper (part of baghouse scope of supply)

24 0 11Air Heater Hopper (part of boiler scope of supply)

10 0 12Air Blower

--14 m3/min @ 0.2 MPa (510 scfm @ 24 psi) 1 1 13Fly Ash SiloReinforced concrete907 tonne (1,000 ton) 2 0 14Slide Gate Valves

2 0 15Unloader----1 0 16Telescoping Unloading Chute

--91 tonne/hr (100 tph) 1 0 Cost and Performance Baseline for Fossil Energy Plants 401 ACCOUNT 11 ACCESSORY ELECTRIC PLANT ACCOUNT 12 INSTRUMENTATION AND CONTROL Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1STG TransformerOil-filled24 kV/345 kV, 650 MVA, 3-ph, 60 Hz 1 0 2Auxiliary TransformerOil-filled24 kV/4.16 kV, 32 MVA, 3-ph, 60 Hz 1 1 3Low Voltage TransformerDry ventilated4.16 kV/480 V, 5 MVA, 3-ph, 60 Hz 1 1 4STG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled24 kV, 3-ph, 60 Hz 1 0 5Medium Voltage SwitchgearMetal clad4.16 kV, 3-ph, 60 Hz 1 1 6Low Voltage SwitchgearMetal enclosed480 V, 3-ph, 60 Hz 1 1 7Emergency Diesel GeneratorSized for emergency shutdown750 kW, 480 V, 3-ph, 60 Hz 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1DCS - Main ControlMonitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W)Operator stations/printers and engineering stations/printers 1 0 2DCS - ProcessorMicroprocessor with redundant input/outputN/A 1 0 3DCS - Data HighwayFiber opticFully redundant, 25% spare 1 0 Cost and Performance Baseline for Fossil Energy Plants 402 4.3.6 The cost estimating methodology was described previously in Section Case 11 - Costs Estimating Results 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 owner's 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 CO 2 capture is $

2,02 4/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 5 8.9 mills/kWh.

Cost and Performance Baseline for Fossil Energy Plants 403 Exhibit 4-42 Case 11 Total Plant Cost Summary Client: USDOE/NETLReport Date:2010-Jan-14Project: Bituminous Baseline StudyCase: Case 11 - 1x550 MWnet SuperCritical PCPlant Size: 550.0MW,netEstimate Type: ConceptualCost Base (Jun) 2007($x1000)AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING$16,381$4,414$9,819$0$0$30,614$2,747$0$5,004$38,365$70 2COAL & SORBENT PREP & FEED$11,008$637$2,793$0$0$14,438$1,265$0$2,356$18,059$33 3FEEDWATER & MISC. BOP SYSTEMS$42,453$0$19,927$0$0$62,380$5,705$0$11,064$79,149$144 4PC BOILER4.1PC Boiler & Accessories$157,253$0$88,235$0$0$245,488$23,891$0$26,938$296,317$5394.2SCR (w/4.1)

$0$0$0$0$0$0$0$0$0$0$04.3Open$0$0$0$0$0$0$0$0$0$0$04.4-4.9Boiler BoP (w/ ID Fans)

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 4$157,253$0$88,235$0$0$245,488$23,891$0$26,938$296,317$539 5FLUE GAS CLEANUP$79,643$0$27,049$0$0$106,692$10,211$0$11,690$128,593$234 5B CO 2 REMOVAL & COMPRESSION

$0$0$0$0$0$0$0$0$0$0$0 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine GeneratorN/A$0N/A$0$0$0$0$0$0$0$06.2-6.9Combustion Turbine Other

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 6

$0$0$0$0$0$0$0$0$0$0$0 7HRSG, DUCTING & STACK7.1Heat Recovery Steam GeneratorN/A$0N/A$0$0$0$0$0$0$0$07.2-7.9HRSG Accessories, Ductwork and Stack$17,397$1,000$11,814$0$0$30,211$2,773$0$4,307$37,291$68SUBTOTAL 7$17,397$1,000$11,814$0$0$30,211$2,773$0$4,307$37,291$68 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$51,625$0$6,866$0$0$58,491$5,606$0$6,410$70,507$1288.2-8.9Turbine Plant Auxiliaries and Steam Piping$22,954$1,089$12,590$0$0$36,633$3,228$0$5,580$45,441$83SUBTOTAL 8$74,579$1,089$19,456$0$0$95,124$8,833$0$11,990$115,948$211 9COOLING WATER SYSTEM$12,303$6,296$11,466$0$0$30,066$2,830$0$4,475$37,370$68 10ASH/SPENT SORBENT HANDLING SYS$4,409$140$5,895$0$0$10,444$1,004$0$1,178$12,627$23 11ACCESSORY ELECTRIC PLANT$17,541$6,187$18,041$0$0$41,769$3,682$0$5,617$51,068$93 12INSTRUMENTATION & CONTROL$8,739$0$8,862$0$0$17,601$1,596$0$2,358$21,555$39 13IMPROVEMENTS TO SITE$2,969$1,707$5,984$0$0$10,660$1,052$0$2,342$14,054$26 14BUILDINGS & 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$1,647TOTAL PLANT COST

SUMMARY

Cost and Performance Baseline for Fossil Energy Plants 404 Exhibit 4-43 Case 11 Total Plant Cost Details AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING1.1Coal Receive & Unload$3,368$0$1,538$0$0$4,906$438$0$802$6,146$111.2Coal Stackout & Reclaim$4,352$0$986$0$0$5,338$467$0$871$6,676$121.3Coal Conveyors$4,046$0$976$0$0$5,022$440$0$819$6,282$111.4Other Coal Handling$1,059$0$226$0$0$1,284$112$0$209$1,606$31.5Sorbent Receive & Unload

$135$0$41$0$0$175$15$0$29$219$01.6Sorbent Stackout & Reclaim$2,176$0$399$0$0$2,574$224$0$420$3,218$61.7Sorbent Conveyors

$776$168$190$0$0$1,135$98$0$185$1,418$31.8Other Sorbent Handling

$469$110$246$0$0$825$73$0$135$1,032$21.9Coal & Sorbent Hnd.Foundations

$0$4,136$5,218$0$0$9,354$879$0$1,535$11,767$21SUBTOTAL 1.$16,381$4,414$9,819$0$0$30,614$2,747$0$5,004$38,365$70 2COAL & SORBENT PREP & FEED2.1Coal Crushing & Drying$1,929$0$376$0$0$2,305$201$0$376$2,881$52.2Coal Conveyor to Storage$4,939$0$1,078$0$0$6,017$526$0$981$7,524$142.3Coal Injection System

$0$0$0$0$0$0$0$0$0$0$02.4Misc.Coal Prep & Feed

$0$0$0$0$0$0$0$0$0$0$02.5Sorbent Prep Equipment$3,695$159$768$0$0$4,622$402$0$754$5,778$112.6Sorbent Storage & Feed

$445$0$171$0$0$616$55$0$101$771$12.7Sorbent Injection System

$0$0$0$0$0$0$0$0$0$0$02.8Booster Air Supply System

$0$0$0$0$0$0$0$0$0$0$02.9Coal & Sorbent Feed Foundation

$0$478$401$0$0$879$81$0$144$1,105$2SUBTOTAL 2.$11,008$637$2,793$0$0$14,438$1,265$0$2,356$18,059$33 3FEEDWATER & MISC. BOP SYSTEMS3.1FeedwaterSystem$18,623$0$6,016$0$0$24,638$2,153$0$4,019$30,810$563.2Water Makeup & Pretreating $4,460$0$1,436$0$0$5,895$557$0$1,291$7,743$143.3Other Feedwater Subsystems$5,701$0$2,409$0$0$8,111$727$0$1,326$10,163$183.4Service Water Systems

$874$0$476$0$0$1,350$127$0$295$1,772$33.5Other Boiler Plant Systems$6,807$0$6,721$0$0$13,528$1,285$0$2,222$17,035$313.6FO Supply Sys & Nat Gas

$255$0$319$0$0$574$54$0$94$723$13.7Waste Treatment Equipment$3,024$0$1,724$0$0$4,747$462$0$1,042$6,251$113.8Misc. Equip.(cranes,AirComp.,Comm.)$2,709$0$828$0$0$3,536$340$0$775$4,652$8SUBTOTAL 3.$42,453$0$19,927$0$0$62,380$5,705$0$11,064$79,149$144 4PC BOILER4.1PC Boiler & Accessories$157,253$0$88,235$0$0$245,488$23,891$0$26,938$296,317$5394.2SCR (w/4.1)

$0$0$0$0$0$0$0$0$0$0$04.3Open$0$0$0$0$0$0$0$0$0$0$04.4Boiler BoP (w/ ID Fans)

$0$0$0$0$0$0$0$0$0$0$04.5Primary Air Systemw/4.1$0w/4.1$0$0$0$0$0$0$0$04.6Secondary Air Systemw/4.1$0w/4.1$0$0$0$0$0$0$0$04.8Major Component Rigging

$0w/4.1w/4.1$0$0$0$0$0$0$0$04.9Boiler Foundations

$0w/14.1w/14.1$0$0$0$0$0$0$0$0SUBTOTAL 4.$157,253$0$88,235$0$0$245,488$23,891$0$26,938$296,317$539 Cost and Performance Baseline for Fossil Energy Plants 405 Exhibit 4-43 Case 11 Total Plant Cost Details (Continued) AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 5FLUE GAS CLEANUP5.1Absorber Vessels & Accessories$55,471$0$11,942$0$0$67,413$6,427$0$7,384$81,224$1485.2Other FGD$2,895$0$3,280$0$0$6,175$599$0$677$7,452$145.3Bag House & Accessories$15,622$0$9,914$0$0$25,536$2,461$0$2,800$30,797$565.4Other Particulate Removal Materials$1,057$0$1,131$0$0$2,189$212$0$240$2,641$55.5Gypsum Dewatering System$4,598$0$781$0$0$5,379$512$0$589$6,480$125.6Mercury Removal System

$0$0$0$0$0$0$0$0$0$0$05.9Open$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 5.$79,643$0$27,049$0$0$106,692$10,211$0$11,690$128,593$234 5B CO 2 REMOVAL & COMPRESSION5B.1 CO 2 Removal System

$0$0$0$0$0$0$0$0$0$0$05B.2 CO 2 Compression & Drying

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 5.

$0$0$0$0$0$0$0$0$0$0$0 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine GeneratorN/A$0N/A$0$0$0$0$0$0$0$06.2Open$0$0$0$0$0$0$0$0$0$0$06.3Compressed Air Piping

$0$0$0$0$0$0$0$0$0$0$06.9Combustion Turbine Foundations

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 6.

$0$0$0$0$0$0$0$0$0$0$0 7HRSG, DUCTING & STACK7.1Heat Recovery Steam GeneratorN/A$0N/A$0$0$0$0$0$0$0$07.2HRSG Accessories

$0$0$0$0$0$0$0$0$0$0$07.3Ductwork$8,675$0$5,574$0$0$14,249$1,242$0$2,324$17,816$327.4Stack$8,721$0$5,103$0$0$13,824$1,331$0$1,516$16,671$307.9Duct & Stack Foundations

$0$1,000$1,137$0$0$2,137$200$0$467$2,804$5SUBTOTAL 7.$17,397$1,000$11,814$0$0$30,211$2,773$0$4,307$37,291$68 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$51,625$0$6,866$0$0$58,491$5,606$0$6,410$70,507$1288.2Turbine Plant Auxiliaries

$347$0$744$0$0$1,091$107$0$120$1,317$28.3Condenser & Auxiliaries$6,712$0$2,288$0$0$9,000$861$0$986$10,848$208.4Steam Piping$15,895$0$7,837$0$0$23,732$1,994$0$3,859$29,585$548.9TG Foundations

$0$1,089$1,721$0$0$2,810$266$0$615$3,691$7SUBTOTAL 8.$74,579$1,089$19,456$0$0$95,124$8,833$0$11,990$115,948$211 9COOLING WATER SYSTEM9.1Cooling Towers$9,084$0$2,829$0$0$11,913$1,139$0$1,305$14,358$269.2Circulating Water Pumps$1,887$0$116$0$0$2,003$169$0$217$2,389$49.3Circ.Water System Auxiliaries

$498$0$66$0$0$565$54$0$62$680$19.4Circ.Water Piping

$0$3,950$3,828$0$0$7,779$728$0$1,276$9,783$189.5Make-up Water System

$438$0$585$0$0$1,024$98$0$168$1,290$29.6Component Cooling Water Sys

$395$0$314$0$0$709$67$0$116$892$29.9Circ.Water System Foundations& Structures

$0$2,346$3,727$0$0$6,073$575$0$1,330$7,977$15SUBTOTAL 9.$12,303$6,296$11,466$0$0$30,066$2,830$0$4,475$37,370$68 Cost and Performance Baseline for Fossil Energy Plants 406 Exhibit 4-43 Case 11 Total Plant Cost Details (Continued) AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 10ASH/SPENT SORBENT HANDLING SYS10.1Ash CoolersN/A$0N/A$0$0$0$0$0$0$0$010.2Cyclone Ash LetdownN/A$0N/A$0$0$0$0$0$0$0$010.3HGCU Ash LetdownN/A$0N/A$0$0$0$0$0$0$0$010.4High Temperature Ash PipingN/A$0N/A$0$0$0$0$0$0$0$010.5Other Ash Recovery EquipmentN/A$0N/A$0$0$0$0$0$0$0$010.6Ash Storage Silos

$590$0$1,818$0$0$2,408$236$0$264$2,909$510.7Ash Transport & Feed Equipment$3,819$0$3,912$0$0$7,731$739$0$847$9,317$1710.8Misc. Ash Handling Equipment

$0$0$0$0$0$0$0$0$0$0$010.9Ash/Spent Sorbent Foundation

$0$140$165$0$0$305$29$0$67$401$1SUBTOTAL 10.$4,409$140$5,895$0$0$10,444$1,004$0$1,178$12,627$23 11ACCESSORY ELECTRIC PLANT11.1Generator Equipment$1,598$0$260$0$0$1,858$172$0$152$2,182$411.2Station Service Equipment$2,824$0$928$0$0$3,752$351$0$308$4,410$811.3Switchgear & Motor Control $3,247$0$552$0$0$3,798$352$0$415$4,565$811.4Conduit & Cable Tray

$0$2,035$7,038$0$0$9,073$878$0$1,493$11,445$2111.5Wire & Cable

$0$3,841$7,414$0$0$11,255$948$0$1,830$14,034$2611.6Protective Equipment

$260$0$885$0$0$1,146$112$0$126$1,383$311.7Standby Equipment$1,277$0$29$0$0$1,306$120$0$143$1,568$311.8Main Power Transformers$8,335$0$172$0$0$8,507$646$0$915$10,068$1811.9Electrical Foundations

$0$311$763$0$0$1,074$103$0$235$1,412$3SUBTOTAL 11.$17,541$6,187$18,041$0$0$41,769$3,682$0$5,617$51,068$93 12INSTRUMENTATION & CONTROL12.1PC Control Equipmentw/12.7$0w/12.7$0$0$0$0$0$0$0$012.2Combustion Turbine ControlN/A$0N/A$0$0$0$0$0$0$0$012.3Steam Turbine Controlw/8.1$0w/8.1$0$0$0$0$0$0$0$012.4Other Major Component Control

$0$0$0$0$0$0$0$0$0$0$012.5Signal Processing Equipmentw/12.7$0w/12.7$0$0$0$0$0$0$0$012.6Control Boards,Panels & Racks

$450$0$270$0$0$720$68$0$118$906$212.7Distributed Control System Equipment$4,543$0$794$0$0$5,337$495$0$583$6,415$1212.8Instrument Wiring & Tubing$2,463$0$4,885$0$0$7,348$626$0$1,196$9,170$1712.9Other I & C Equipment$1,284$0$2,913$0$0$4,197$407$0$460$5,064$9SUBTOTAL 12.$8,739$0$8,862$0$0$17,601$1,596$0$2,358$21,555$39 Cost and Performance Baseline for Fossil Energy Plants 407 Exhibit 4-43 Case 11 Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 13IMPROVEMENTS TO SITE13.1Site Preparation

$0$50$998$0$0$1,048$104$0$230$1,382$313.2Site Improvements

$0$1,657$2,058$0$0$3,715$366$0$816$4,897$913.3Site Facilities$2,969$0$2,928$0$0$5,897$581$0$1,296$7,774$14SUBTOTAL 13.$2,969$1,707$5,984$0$0$10,660$1,052$0$2,342$14,054$26 14BUILDINGS & STRUCTURES14.1Boiler Building

$0$8,281$7,282$0$0$15,564$1,399$0$2,544$19,507$3514.2Turbine Building

$0$11,828$11,024$0$0$22,851$2,060$0$3,737$28,648$5214.3Administration Building

$0$586$620$0$0$1,206$109$0$197$1,513$314.4Circulation Water Pumphouse

$0$168$134$0$0$301$27$0$49$378$114.5Water Treatment Buildings

$0$566$516$0$0$1,081$97$0$177$1,356$214.6Machine Shop

$0$392$264$0$0$656$58$0$107$821$114.7Warehouse

$0$266$267$0$0$532$48$0$87$668$114.8Other Buildings & Structures

$0$217$185$0$0$402$36$0$66$504$114.9Waste Treating Building & Str.

$0$416$1,262$0$0$1,678$159$0$276$2,112$4SUBTOTAL 14.

$0$22,720$21,552$0$0$44,272$3,994$0$7,240$55,506$101TOTAL COST$444,675$44,192$250,892$0$0$739,759$69,584$0$96,558$905,901$1,647Owner's CostsPreproduction Costs6 Months All Labor$7,258$131 Month Maintenance Materials

$895$21 Month Non-fuel Consumables

$892$21 Month Waste Disposal

$235$025% of 1 Months Fuel Cost at 100% CF$1,427$32% of TPC$18,118$33Total$28,826$52Inventory Capital60 day supply of fuel and consumables at 100% CF$12,944$240.5% of TPC (spare parts)$4,530$8Total$17,474$32Initial Cost for Catalyst and Chemicals

$0$0Land$900$2Other Owner's Costs$135,885$247Financing Costs$24,459$44Total Overnight Costs (TOC)$1,113,445$2,024TASC Multiplier(IOU, low-risk, 35 year)1.134Total As-Spent Cost (TASC)$1,262,647$2,296 Cost and Performance Baseline for Fossil Energy Plants 408 Exhibit 4-44 Case 11 Initial and Annual Operating and Maintenance Costs INITIAL & ANNUAL O&M EXPENSESCost Base (Jun):

2007Case 11 - 1x550 MWnet SuperCritical PCHeat Rate-net (Btu/kWh):8,686 MWe-net: 550 Capacity Factor (%):

85OPERATING & MAINTENANCE LABOROperating Labor Operating Labor Rate(base):34.65$/hour Operating Labor Burden:30.00% of base Labor O-H Charge Rate:25.00% of laborTotal Operating Labor Requirements(O.J.)per Shift:1 unit/mod. Plant Skilled Operator2.02.0 Operator9.09.0 Foreman1.01.0 Lab Tech's, etc.2.02.0 TOTAL-O.J.'s14.014.0Annual CostAnnual Unit Cost

$$/kW-netAnnual Operating Labor Cost$5,524,319$10.044Maintenance Labor Cost$6,088,905$11.070Administrative & Support Labor$2,903,306$5.279Property Taxes and Insurance$18,118,017$32.941TOTAL FIXED OPERATING COSTS$32,634,546$59.333VARIABLE OPERATING COSTS$/kWh-netMaintenance Material Cost$9,133,357$0.00223ConsumablesConsumptionUnit Initial Fill Initial Fill /Day Cost CostWater (/1000 gallons) 03,8841.08$0$1,303,324$0.00032ChemicalsMU & WT Chem.(lbs) 018,7990.17$0$1,009,427$0.00025Limestone (ton) 0 48821.63$0$3,273,667$0.00080Carbon (Mercury Removal) (lb) 0 01.05$0$0$0.00000MEA Solvent (ton) 0 02,249.89$0$0$0.00000NaOH (tons) 0 0433.68$0$0$0.00000H2SO4 (tons) 0 0138.78$0$0$0.00000Corrosion Inhibitor 0 00.00$0$0$0.00000Activated Carbon (lb) 0 01.05$0$0$0.00000Ammonia (19% NH3) ton 0 74129.80$0$2,960,869$0.00072Subtotal Chemicals

$0$7,243,963$0.00177OtherSupplemental Fuel (MBtu) 0 00.00$0$0$0.00000SCR Catalyst (m3)w/equip.0.315,775.94$0$553,798$0.00014Emission Penalties 0 00.00$0$0$0.00000Subtotal Other

$0$553,798$0.00014Waste DisposalFly Ash (ton) 0 38116.23$0$1,919,038$0.00047Bottom Ash (ton) 0 9516.23$0$479,759$0.00012 Subtotal-Waste Disposal

$0$2,398,797$0.00059By-products & Emissions Gypsum (tons) 0 7590.00$0$0$0.00000Subtotal By-Products

$0$0$0.00000TOTAL VARIABLE OPERATING COSTS

$0$20,633,239$0.00504Fuel (ton) 04,91438.18$0$58,217,892$0.01422 Cost and Performance Baseline for Fossil Energy Plants 409 4.3.7 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 CO 2 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.

Case 12 - Supercritical PC with CO 2 Capture The process description for Case 12 is essentially the same as Case 11 with one notable exception, the addition of CO 2 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 The Case 12 modeling assumptions were presented previously in Section Case 12 Performance Results 4.3.2. The plant produces a net output of 5 50 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 CO 2 compression, accounts for approximately 58 percent of the auxiliary plant load. The CWS (CWPs and cooling tower fan) accounts for over 1 3 percent of the auxiliary load, largely due to the high cooling water demand of the CDR facili ty Cost and Performance Baseline for Fossil Energy Plants 410 Exhibit 4-45 Case 12 Block Flow Diagram, Supercritical Unit with CO 2 Capture Cost and Performance Baseline for Fossil Energy Plants 411 Exhibit 4-46 Case 12 Stream Table, Supercritical Unit with CO 2 Capture 1 2 3 4 5 6 7 8 9 10 11 12 13 14V-L Mole Fraction Ar0.00920.00920.00920.00920.00920.00920.00920.00000.00000.00870.00000.00870.00870.0000 CO 20.00030.00030.00030.00030.00030.00030.00030.00000.00000.14500.00000.14500.14500.0000 H 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 H 2 O0.00990.00990.00990.00990.00990.00990.00990.00000.00000.08700.00000.08700.08701.0000 N 20.77320.77320.77320.77320.77320.77320.77320.00000.00000.73240.00000.73240.73240.0000 O 20.20740.20740.20740.20740.20740.20740.20740.00000.00000.02470.00000.02470.02470.0000 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00210.00000.00210.00210.0000Total1.00001.00001.00001.00001.00001.00001.00000.00000.00001.00000.00001.00001.00001.0000V-L Flowrate (kgmol/hr)66,87666,8761,99020,54420,5442,8181,546 0 094,107 094,10794,1073,385V-L Flowrate (kg/hr)1,929,8521,929,85257,422592,830592,83081,32544,605 0 02,799,052 02,799,0522,799,05260,975Solids Flowrate (kg/hr) 0 0 0 0 0 0 0256,6524,97719,91019,910 0 025,966Temperature (°C) 15 19 19 15 25 25 15 15 15 169 15 169 182 15Pressure (MPa, abs)0.100.110.110.100.110.110.100.100.100.100.100.100.110.10Enthalpy (kJ/kg)

A30.2334.3634.3630.2340.7840.7830.23------327.40---308.96322.83---Density (kg/m 3)1.21.21.21.21.31.31.2------0.8---0.80.8---V-L Molecular Weight28.85728.85728.85728.85728.85728.85728.857------29.743---29.74329.743---V-L Flowrate (lbmol/hr)147,437147,4374,38745,29145,2916,2133,408 0 0207,471 0207,471207,4717,462V-L Flowrate (lb/hr)4,254,5954,254,595126,5951,306,9671,306,967179,29198,338 0 06,170,854 06,170,8546,170,854134,426Solids Flowrate (lb/hr) 0 0 0 0 0 0 0565,82010,97343,89343,893 0 057,245Temperature (°F) 59 66 66 59 78 78 59 59 59 337 59 337 360 59Pressure (psia)14.715.315.314.716.116.114.714.714.714.414.714.215.415.0Enthalpy (Btu/lb)

A13.014.814.813.017.517.513.0------140.8---132.8138.8---Density (lb/ft 3)0.0760.0780.0780.0760.0810.0810.076------0.050---0.0490.052---A - Reference conditions are 32.02 F & 0.089 PSIA Cost and Performance Baseline for Fossil Energy Plants 412 Exhibit 4-46 Case 12 Stream Table, Supercritical Unit with CO 2 Capture (Continued) 15 16 17 18 19 20 21 22 23 24 25 26 27 28V-L Mole Fraction Ar0.00000.01280.00000.00810.01080.00000.00000.00000.00000.00000.00000.00000.00000.0000 CO 20.00000.00050.00040.13500.01790.99610.99850.00000.00000.00000.00000.00000.00000.0000 H 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 H 2 O1.00000.00620.99960.15370.03830.00390.00151.00001.00001.00001.00001.00001.00001.0000 N 20.00000.75060.00000.67930.90130.00000.00000.00000.00000.00000.00000.00000.00000.0000 O 20.00000.23000.00000.02380.03160.00000.00000.00000.00000.00000.00000.00000.00000.0000 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000Total1.00001.00001.00001.00001.00001.00001.00001.00001.00001.00001.00001.00001.00001.0000V-L Flowrate (kgmol/hr)13,485 975 250102,54877,28612,51112,48144,92244,922126,511103,236103,23649,30449,304V-L Flowrate (kg/hr)242,94128,2894,4982,956,5312,177,293549,344548,802809,288809,2882,279,1331,859,8261,859,826888,227888,227Solids Flowrate (kg/hr) 0 040,138 0 0 0 0 0 0 0 0 0 0 0Temperature (°C) 15 181 58 58 32 21 35 291 151 593 354 593 38 40Pressure (MPa, abs)0.100.310.100.100.100.1615.270.510.9224.234.904.520.011.69Enthalpy (kJ/kg)

A-46.80191.58---301.4393.8619.49-211.713,045.10636.313,476.623,081.813,652.222,115.77166.72Density (kg/m 3)1,003.12.4---1.11.12.9795.92.0916.069.218.711.60.1993.2V-L Molecular Weight18.01529.029---28.83128.17243.90843.97118.01518.01518.01518.01518.01518.01518.015V-L Flowrate (lbmol/hr)29,7302,148 550226,080170,38727,58227,51699,03799,037278,909227,597227,597108,697108,697V-L Flowrate (lb/hr)535,59262,3689,9166,518,0344,800,1091,211,0961,209,9021,784,1751,784,1755,024,6284,100,2154,100,2151,958,2061,958,206Solids Flowrate (lb/hr) 0 088,488 0 0 0 0 0 0 0 0 0 0 0Temperature (°F) 59 357 136 136 89 69 95 556 3041,100 6681,100 101 103Pressure (psia)14.745.014.914.914.723.52,214.573.5133.63,514.7710.8655.81.0245.0Enthalpy (Btu/lb)

A-20.182.4---129.640.48.4-91.01,309.2273.61,494.71,324.91,570.2909.671.7Density (lb/ft 3)62.6220.149---0.0670.0700.18449.6840.12357.1844.3191.1660.7220.00462.002 Cost and Performance Baseline for Fossil Energy Plants 413 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 CO 2 Compression 44,890 Miscellaneous Balance of Plant2,3 2,000 Steam Turbine Auxiliaries 400 Condensate Pumps 560 Circulating Water Pumps 10,100 Ground Water Pumps 91 0 Cooling Tower Fans 5,230 Transformer Losses 2,290 TOTAL AUXILIARIES, kWe 112,83 0 NET POWER, kWe 5 49 , 9 7 0 Net Plant Efficiency (HHV) 28.4% Net Plant Heat Rate, kJ/kWh (Btu/kWh) 12,663 (12 , 002) CONDENSER COOLING DUTY, 10 6 kJ/h r (10 6 Btu/h r) 1,737 (1,646

) CONSUMABLES As-Received Coal Feed, kg/h r (lb/h r) 256,652 (565,820)

Limestone Sorbent Feed, kg/h r (lb/h r) 25,96 6 (57 , 245) Thermal Input, kWt 1 1,934,519 Raw Water Withdrawal, m 3/min (gpm) 38.1 (10,071

) Raw Water Consumption, m 3/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

Cost and Performance Baseline for Fossil Energy Plants 414 The environmental targets for emissions of Hg, NOx, SO 2, and PM were presented in Section Environmental Performance 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 kg/GJ (lb/10 6 Btu) Tonne/year (ton/year) 85% CF kg/MWh (lb/MWh) SO 2 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) CO 2 8.8 (20.4) 453,763 (500,188) 92 (203) CO 2 1 11 1 (2 44) 1 CO 2 emissions based on net power instead of gross power SO 2 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 SO 2 emissions are further reduced to 10 ppmv using a NaOH based polishing scrubber in the CDR facility. The remaining low concentration of SO 2 is essentially completely removed in the CDR absorber vessel resulting in very low SO 2 emissions.

NOx emissions are controlled to about 0.5 lb/10 6 Btu through the use of LNBs and OFA. An SCR unit then further reduces the NOx concentration by 86 percent to 0.07 lb/10 6 Bt u. 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 CO 2 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 CO 2 in the stack gas, carbon in the FGD product, and the captured CO 2 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)/(367,272-7 83)

100] or 90.2 percent Cost and Performance Baseline for Fossil Energy Plants 415 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 (CO 2) 355 (783) FGD Product 274 (605) FGD Reagent 2,635 (5,809)

CO 2 Product 149,685 (329,999)

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 Scrubber/HS S 126 (278) 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 Water Use Water Demand, m 3/min (gpm) Internal Recycle, m 3/min (gpm) Raw Water Withdrawal, m 3/min (gpm) Process Water Discharge, m 3/min (gpm) Raw Water Consumption, m 3/min (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)

Cost and Performance Baseline for Fossil Energy Plants 416 A heat and mass balance diagram is shown for the Case 12 PC boiler, the FGD unit, CDR system , and steam cycle in Heat and Mass Balance Diagrams 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 CO 2 compressor intercooler load is included in the Econamine process heat out stream.

Cost and Performance Baseline for Fossil Energy Plants 417 Exhibit 4-52 Case 12 Heat and Mass Balance, Supercritical PC Boiler with CO 2 Capture N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA H EAT AND M ATERIAL F LOW D IAGRAM P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Ash Slurry Synthesis Gas Sour Gas Sour Water Water Steam P AGES 1 OF 2 B ITUMINOUS B ASELINE S TUDY C ASE 12 S UPERCRITICAL P ULVERIZED C OAL B OILER AND G AS C LEANUP S YSTEMS DWG. NO.BB-HMB-CS-12-PG-1 Pulverized Coal Boiler SCR AMMONIA INFILTRATION AIR AIR AIR COAL ASH From Feedwater Heaters Single Reheat To IP Turbine Throttle Steam To HP Turbine FGD ASH FORCED DRAFT FANS PRIMARY AIR FANS STACK 565 , 820 W 77.8 T 16.1 P 17.5 H 66.4 T 15.3 P 14.8 H 5 , 024 , 628 W 1 , 100.0 T 3 , 514.7 P 1 , 494.7 H 4 , 100 , 215 W 1 , 100.0 T 655.8 P 1 , 570.6 H Single Reheat Extraction from HP Turbine 1 , 306 , 967 W 59.0 T 14.7 P 13.0 H 4 , 254 , 595 W 59.0 T 14.7 P 13.0 H 98 , 338 W 59.0 T 14.7 P 13.0 H 6 , 214 , 747 W 337.0 T 14.4 P 140.8 H 10 , 973 W 43 , 893 W 4 , 100 , 215 W 668.4 T 710.8 P 1 , 324.9 H 5 , 024 , 628 W 545.5 T 4 , 185.0 P 539.3 H 5 6 , 518 , 034 W 135.8 T 14.9 P 129.6 H 1 2 4 7 8 9 ID FANS 6 , 170 , 854 W 337.0 T 14.2 P 132.8 H Gross Plant Power

663 MWe Auxiliary Load

113 MWe Net Plant Power

550 MWe Net Plant Efficiency , HHV: 28.4%Net Plant Heat Rate

12 , 002 BTU/KWe Lime/Ash Flue Gas OXIDATION AIR MAKE-UP WATER LIMESTONE SLURRY GYPSUM 15 14 11 360.4 T 15.4 P 138.8 H 191 , 671 W 59.0 T 15.0 P 62 , 368 W 357.4 T 45.0 P 82.4 H 535 , 592 W 59.0 T 14.7 P 98 , 404 W 135.8 T 14.9 P STRIPPER ABSORBER FLUE GAS Acid Gas ECONAMINE FG

+ECONAMINE CONDENSATE 18 252 , 068 W 306.3 T 73.5 P 1 , 181.0 H 1 , 784 , 175 W 556.3 T 73.5 P 1 , 309.6 H 1 , 784 , 175 W 304.0 T 133.6 P 273.6 H ECONAMINE STEAM 1 , 209 , 902 W 95.0 T 2 , 214.5 P 1 , 211 , 096 W 69.0 T 23.5 P 8.4 H 4 , 800 , 109 W 88.8 T 14.7 P 40.4 H CO 2 COMPRESSION (INTERSTAGE COOLING)CO 2 PRODUCT Baghouse 21 22 20 3 6 10 12 13 16 17 19 23 24 25 26 DOE/NETL SC PC P LANT C ASE 12 Cost and Performance Baseline for Fossil Energy Plants 418 Exhibit 4-53 Case 12 Heat and Mass Balance, Supercritical Steam Cycle N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA H EAT AND M ATERIAL F LOW D IAGRAM P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas Sour Gas Sour Water Water Steam P AGES 2 OF 2 DWG. NO.BB-HMB-CS-12-PG-2 B ITUMINOUS B ASELINE S TUDY C ASE 12 S UPERCRITICAL P ULVERIZED C OAL P OWER B LOCK S YSTEMS LP TURBINE GENERATOR HP TURBINE IP TURBINE CONDENSER HOT WELL P-1028 P-1048 To Boiler BOILER FEED PUMP TURBINE DRIVES STEAM SEAL REGULATOR Throttle Steam Single Reheat Extraction From Boiler GLAND SEAL CONDENSER CONDENSATE PUMPS 5 , 024 , 628 W 1 , 100.0 T 3 , 514.7 P 1 , 494.7 H 2 , 900.0 P 285 , 001 W 803.0 T 211.9 P 1 , 426.1 H 612 , 527 W 665.2 T 700.8 P 1 , 323.6 H Single Reheat Extraction to Boiler 4 , 100 , 215 W 668.4 T 710.8 P 1 , 324.9 H 710.8 P 1 , 115.5 P 281 , 028 W 763.9 T 990.5 P 1 , 367.5 H 710.8 P 710.8 P 221.9 P 75.0 P 75.0 P 375 , 024 W 556.3 T 73.5 P 1 , 309.2 H 126.1 T 2.0 P 1 , 085.4 H 1 , 337 , 035 W 101.1 T 1.0 P 1 , 009.5 H 2 , 793 W 212.0 T 14.7 P 179.9 H 29.0 P 11.4 P 4.5 P 101.4 T 250.0 P 70.0 H 2 , 793 W 674.7 T 75.0 P 1 , 367.7 H 1 , 958 , 206 W 101.1 T 1.0 P 69.1 H 1 , 958 , 206 W 103.1 T 245.0 P 71.7 H 1 , 958 , 206 W 123.8 T 240.0 P 92.2 H 240 , 053 W 113.1 T 1.4 P 81.0 H 202 , 990 W 133.8 T 2.5 P 101.6 H 1 , 958 , 206 W 235.0 T 225.0 P 203.5 H 1 , 178 , 556 W 321.8 T 91.9 P 291.8 H 1 , 958 , 206 W 190.2 T 230.0 P 158.5 H 893 , 554 W 398.7 T 243.6 P 373.2 H 281 , 028 W 513.3 T 765.9 P 503.4 H 5 , 024 , 628 W 388.7 T 4 , 195.0 P 367.8 H 5 , 024 , 628 W 503.3 T 4 , 190.0 P 491.0 H DEAERATOR BOILER FEED PUMPS 5 , 024 , 628 W 545.5 T 4 , 185.0 P 539.3 H 24 4 , 100 , 215 W 1 , 100.0 T 655.8 P 1 , 570.6 H 83 , 560 W 200.2 T 11.6 P 168.0 H 155 , 189 W 161.0 T 4.9 P 128.7 H 1 , 958 , 206 W 151.0 T 235.0 P 119.3 H 103 , 690 W 595.3 T 70.0 P 1 , 328.7 H 83 , 560 W 370.1 T 25.0 P 1 , 223.5 H 71 , 629 W 216.1 T 10.4 P 1 , 153.6 H 47 , 801 W 156.0 T 4.3 P 1 , 123.0 H 37 , 063 W 128.8 T 2.2 P 1 , 054.1 H 2 , 900.0 P 3 , 731 , 302 W 556.3 T 73.5 P 1 , 309.2 H 1 , 572 , 104 W 556.3 T 73.5 P 1 , 309.2 H 2.3 P 2 , 900.0 P 311.8 T 4 , 200.0 P 289.0 H 5 , 024 , 628 W 302.9 T 70.0 P 272.3 H 3 , 301 W 674.7 T 75.0 P 1 , 367.7 H Gross Plant Power

663 MWe Auxiliary Load

113 MWe Net Plant Power

550 MWe Net Plant Efficiency , HHV: 28.4%Net Plant Heat Rate

12 , 002 BTU/KWe FWH 1 FWH 2 FWH 3 FWH 4 FWH 6 FWH 7 FWH 8 4 , 985 W 674.7 T 75.0 P 1 , 367.7 H 1 , 784 , 175 W 304.0 T 133.6 P 273.6 H ECONAMINE CONDENSATE 23 1 , 784 , 175 W 556.3 T 73.5 P 1 , 309.6 H ECONAMINE STEAM 22 25 26 28 DOE/NETL SC PC P LANT C ASE 12 Cost and Performance Baseline for Fossil Energy Plants 419 Exhibit 4-54 Case 12 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total 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)

CO 2 -116 (-110) -116 (-110) Cooling Tower Blowdown 65.8 (62.3) 65.8 (62.3)

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.

Cost and Performance Baseline for Fossil Energy Plants 420 4.3.9 Major equipment items for the SC PC plant with CO 2 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 Case 12 - Major Equipment List 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 No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Bottom Trestle Dumper and Receiving HoppersN/A181 tonne (200 ton) 2 0 2FeederBelt572 tonne/hr (630 tph) 2 0 3Conveyor No. 1Belt1,134 tonne/hr (1,250 tph) 1 0 4Transfer Tower No. 1EnclosedN/A 1 0 5Conveyor No. 2Belt1,134 tonne/hr (1,250 tph) 1 0 6As-Received Coal Sampling SystemTwo-stageN/A 1 0 7Stacker/ReclaimerTraveling, linear1,134 tonne/hr (1,250 tph) 1 0 8Reclaim HopperN/A54 tonne (60 ton) 2 1 9FeederVibratory209 tonne/hr (230 tph) 2 1 10Conveyor No. 3Belt w/ tripper426 tonne/hr (470 tph) 1 0 11Crusher TowerN/AN/A 1 0 12Coal Surge Bin w/ Vent FilterDual outlet209 tonne (230 ton) 2 0 13CrusherImpactor reduction8 cm x 0 - 3 cm x 0(3 in x 0 1/4 in x 0) 2 0 14As-Fired Coal Sampling SystemSwing hammerN/A 1 1 15Conveyor No. 4Belt w/tripper426 tonne/hr (470 tph) 1 0 16Transfer Tower No. 2EnclosedN/A 1 0 17Conveyor No. 5Belt w/ tripper426 tonne/hr (470 tph) 1 0 18Coal Silo w/ Vent Filter and Slide GatesField erected907 tonne (1,000 ton) 3 0 19Limestone Truck Unloading HopperN/A36 tonne (40 ton) 1 0 20Limestone FeederBelt109 tonne/hr (120 tph) 1 0 21Limestone Conveyor No. L1Belt109 tonne/hr (120 tph) 1 0 22Limestone Reclaim HopperN/A18 tonne (20 ton) 1 0 23Limestone Reclaim FeederBelt82 tonne/hr (90 tph) 1 0 24Limestone Conveyor No. L2Belt82 tonne/hr (90 tph) 1 0 25Limestone Day Binw/ actuator345 tonne (380 ton) 2 0 Cost and Performance Baseline for Fossil Energy Plants 421 ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Coal FeederGravimetric45 tonne/hr (50 tph) 6 0 2Coal PulverizerBall type or equivalent45 tonne/hr (50 tph) 6 0 3Limestone Weigh FeederGravimetric28 tonne/hr (31 tph) 1 1 4Limestone Ball MillRotary28 tonne/hr (31 tph) 1 1 5Limestone Mill Slurry Tank with AgitatorN/A109,777 liters (29,000 gal) 1 1 6Limestone Mill Recycle PumpsHorizontal centrifugal1,855 lpm @ 12m H2O (490 gpm @ 40 ft H2O) 1 1 7Hydroclone Classifier4 active cyclones in a 5 cyclone bank454 lpm (120 gpm) per cyclone 1 1 8Distribution Box2-wayN/A 1 1 9Limestone Slurry Storage Tank with AgitatorField erected617,022 liters (163,000 gal) 1 1 10Limestone Slurry Feed PumpsHorizontal centrifugal1,287 lpm @ 9m H2O (340 gpm @ 30 ft H2O) 1 1 Cost and Performance Baseline for Fossil Energy Plants 422 ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Demineralized Water Storage TankVertical, cylindrical, outdoor1,506,594 liters (398,000 gal) 2 0 2Condensate PumpsVertical canned16,277 lpm @ 213 m H2O (4,300 gpm @ 700 ft H2O) 1 1 3Deaerator and Storage TankHorizontal spray type2,507,005 kg/hr (5,527,000 lb/hr), 5 min. tank 1 0 4Boiler Feed Pump/TurbineBarrel type, multi-stage, centrifugal42,018 lpm @ 3,505 m H2O (11,100 gpm @ 11,500 ft H2O) 1 1 5Startup Boiler Feed Pump, Electric Motor DrivenBarrel type, multi-stage, centrifugal12,492 lpm @ 3,505 m H2O (3,300 gpm @ 11,500 ft H2O) 1 0 6LP Feedwater Heater 1A/1BHorizontal U-tube489,880 kg/hr (1,080,000 lb/hr) 2 0 7LP Feedwater Heater 2A/2BHorizontal U-tube489,880 kg/hr (1,080,000 lb/hr) 2 0 8LP Feedwater Heater 3A/3BHorizontal U-tube489,880 kg/hr (1,080,000 lb/hr) 2 0 9LP Feedwater Heater 4A/4BHorizontal U-tube489,880 kg/hr (1,080,000 lb/hr) 2 0 10HP Feedwater Heater 6Horizontal U-tube2,508,366 kg/hr (5,530,000 lb/hr) 1 0 11HP Feedwater Heater 7Horizontal U-tube2,508,366 kg/hr (5,530,000 lb/hr) 1 0 12HP Feedwater heater 8Horizontal U-tube2,508,366 kg/hr (5,530,000 lb/hr) 1 0 13Auxiliary BoilerShop fabricated, water tube18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0 14Fuel Oil SystemNo. 2 fuel oil for light off1,135,624 liter (300,000 gal) 1 0 15Service Air CompressorsFlooded Screw28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1 16Instrument Air DryersDuplex, regenerative28 m3/min (1,000 scfm) 2 1 17Closed Cycle Cooling Heat ExchangersShell and tube53 GJ/hr (50 MMBtu/hr) each 2 0 18Closed Cycle Cooling Water PumpsHorizontal centrifugal20,820 lpm @ 30 m H2O (5,500 gpm @ 100 ft H2O) 2 1 19Engine-Driven Fire PumpVertical turbine, diesel engine3,785 lpm @ 88 m H2O (1,000 gpm @ 290 ft H2O) 1 1 20Fire Service Booster PumpTwo-stage horizontal centrifugal2,650 lpm @ 64 m H2O (700 gpm @ 210 ft H2O) 1 1 21Raw Water PumpsStainless steel, single suction11,016 lpm @ 18 m H2O (2,910 gpm @ 60 ft H2O) 2 1 22Ground Water PumpsStainless steel, single suction4,429 lpm @ 268 m H2O (1,170 gpm @ 880 ft H2O) 5 1 23Filtered Water PumpsStainless steel, single suction2,725 lpm @ 49 m H2O (720 gpm @ 160 ft H2O) 2 1 24Filtered Water TankVertical, cylindrical2,619,505 liter (692,000 gal) 1 0 25Makeup Water DemineralizerMulti-media filter, cartridge filter, RO membrane assembly, electrodeionization unit984 lpm (260 gpm) 1 1 26Liquid Waste Treatment System--10 years, 24-hour storm 1 0 Cost and Performance Baseline for Fossil Energy Plants 423 ACCOUNT 4 BOILER AND ACCESSORI ES Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1BoilerSupercritical, drum, wall-fired, low NOx burners, overfire air2,508,366 kg/hr steam @ 25.5 MPa/602°C/602°C (5,530,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) 1 0 2Primary Air FanCentrifugal326,133 kg/hr, 4,449 m3/min @ 123 cm WG (719,000 lb/hr, 157,100 acfm @ 48 in. WG) 2 0 3Forced Draft FanCentrifugal1,061,406 kg/hr, 14,484 m3/min @ 47 cm WG (2,340,000 lb/hr, 511,500 acfm @ 19 in. WG) 2 0 4Induced Draft FanCentrifugal1,539,493 kg/hr, 32,491 m3/min @ 104 cm WG (3,394,000 lb/hr, 1,147,400 acfm @ 41 in. WG) 2 0 5SCR Reactor VesselSpace for spare layer3,079,892 kg/hr (6,790,000 lb/hr) 2 0 6SCR Catalyst

3 0 7Dilution Air BlowerCentrifugal184 m3/min @ 108 cm WG (6,500 acfm @ 42 in. WG) 2 1 8Ammonia StorageHorizontal tank200,627 liter (53,000 gal) 5 0 9Ammonia Feed PumpCentrifugal39 lpm @ 91 m H2O (10 gpm @ 300 ft H2O) 2 1 Cost and Performance Baseline for Fossil Energy Plants 424 ACCOUNT 5 FLUE GAS CLEANUP Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Fabric FilterSingle stage, high-ratio with pulse-jet online cleaning system1,539,493 kg/hr (3,394,000 lb/hr) 99.8% efficiency 2 0 2Absorber ModuleCounter-current open spray61,561 m3/min (2,174,000 acfm) 1 0 3Recirculation PumpsHorizontal centrifugal215,768 lpm @ 64 m H2O (57,000 gpm @ 210 ft H2O) 5 1 4Bleed PumpsHorizontal centrifugal5,565 lpm (1,470 gpm) at 20 wt% solids 2 1 5Oxidation Air BlowersCentrifugal109 m3/min @ 0.3 MPa (3,840 acfm @ 37 psia) 2 1 6AgitatorsSide entering50 hp 5 1 7Dewatering CyclonesRadial assembly, 5 units each1,401 lpm (370 gpm) per cyclone 2 0 8Vacuum Filter BeltHorizontal belt44 tonne/hr (49 tph) of 50 wt % slurry 2 1 9Filtrate Water Return PumpsHorizontal centrifugal833 lpm @ 12 m H2O (220 gpm @ 40 ft H2O) 1 1 10Filtrate Water Return Storage TankVertical, lined567,812 lpm (150,000 gal) 1 0 11Process Makeup Water PumpsHorizontal centrifugal4,467 lpm @ 21 m H2O (1,180 gpm @ 70 ft H2O) 1 1 Cost and Performance Baseline for Fossil Energy Plants 425 ACCOUNT 5C CARBON DIOXIDE RECOVERY ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES N/A ACCOUNT 7 HRSG, DUCTING & STAC K ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Econamine FG PlusAmine-based CO2 capture technology1,626,129 kg/h (3,585,000 lb/h) 20.6 wt % CO2 concentration 2 0 2Econamine Condensate PumpCentrifugal16,959 lpm @ 52 m H2O (4,480 gpm @ 170 ft H2O) 1 1 3CO2 CompressorIntegrally geared, multi-stage centrifugal301,656 kg/h @ 15.3 MPa (665,037 lb/h @ 2,215 psia) 2 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1StackReinforced concrete with FRP liner152 m (500 ft) high x5.6 m (18 ft) diameter 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Steam TurbineCommercially available advanced steam turbine698 MW24.1 MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 1 0 2Steam Turbine GeneratorHydrogen cooled, static excitation780 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0 3Surface CondenserSingle pass, divided waterbox including vacuum pumps1,910 GJ/hr (1,810 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1 0 Cost and Performance Baseline for Fossil Energy Plants 426 ACCOUNT 9 COOLING WATER SYSTEM Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Circulating Water PumpsVertical, wet pit1,014,500 lpm @ 30 m(268,000 gpm @ 100 ft) 2 1 2Cooling TowerEvaporative, mechanical draft, multi-cell11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 5655 GJ/hr (5360 MMBtu/hr) heat duty 1 0 Cost and Performance Baseline for Fossil Energy Plants 427 ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Economizer Hopper (part of boiler scope of supply)

4 0 2Bottom Ash Hopper (part of boiler scope of supply)

2 0 3Clinker Grinder

--5.4 tonne/hr (6 tph) 1 1 4Pyrites Hopper (part of pulverizer scope of supply included with boiler)

6 0 5Hydroejectors

12 6Economizer /Pyrites Transfer Tank----1 0 7Ash Sluice PumpsVertical, wet pit227 lpm @ 17 m H2O (60 gpm @ 56 ft H2O) 1 1 8Ash Seal Water PumpsVertical, wet pit7,571 lpm @ 9 m H2O (2000 gpm @ 28 ft H2O) 1 1 9Hydrobins--227 lpm (60 gpm) 1 1 10Baghouse Hopper (part of baghouse scope of supply)

24 0 11Air Heater Hopper (part of boiler scope of supply)

10 0 12Air Blower

--20 m3/min @ 0.2 MPa (710 scfm @ 24 psi) 1 1 13Fly Ash SiloReinforced concrete1,270 tonne (1,400 ton) 2 0 14Slide Gate Valves

2 0 15Unloader----1 0 16Telescoping Unloading Chute

--127 tonne/hr (140 tph) 1 0 Cost and Performance Baseline for Fossil Energy Plants 428 ACCOUNT 11 ACCESSORY ELECTRIC PLANT ACCOUNT 12 INSTRUMENTATION AND CONTROL Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1STG TransformerOil-filled24 kV/345 kV, 650 MVA, 3-ph, 60 Hz 1 0 2Auxiliary TransformerOil-filled24 kV/4.16 kV, 123 MVA, 3-ph, 60 Hz 1 1 3Low Voltage TransformerDry ventilated4.16 kV/480 V, 18 MVA, 3-ph, 60 Hz 1 1 4STG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled24 kV, 3-ph, 60 Hz 1 0 5Medium Voltage SwitchgearMetal clad4.16 kV, 3-ph, 60 Hz 1 1 6Low Voltage SwitchgearMetal enclosed480 V, 3-ph, 60 Hz 1 1 7Emergency Diesel GeneratorSized for emergency shutdown750 kW, 480 V, 3-ph, 60 Hz 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1DCS - Main ControlMonitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W)Operator stations/printers and engineering stations/printers 1 0 2DCS - ProcessorMicroprocessor with redundant input/outputN/A 1 0 3DCS - Data HighwayFiber opticFully redundant, 25% spare 1 0 Cost and Performance Baseline for Fossil Energy Plants 429 4.3.10 The cost estimating methodology was described previously in Section Case 12 - Cost Estimating Basis 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 owner's costs, TOC

, and TASC. Exhibit 4-57 shows the initial and annual O&M costs.

The estimated TOC of the SC PC boiler with CO 2 capture is $

3,570/kW. Process contingency represents 2.8 percent of the TOC and project contingency represents 10.2 percent. The COE, including CO 2 TS&M costs of 5.7 mills/kWh, is 10 6.6 mills/kWh.

Cost and Performance Baseline for Fossil Energy Plants 430 Exhibit 4-55 Case 12 Total Plant Cost Summary Client: USDOE/NETLReport Date:2010-Jan-14Project: Bituminous Baseline StudyCase: Case 12 - 1x550 MWnet Super-Critical PC w/ CO2 CapturePlant Size: 550.0MW,netEstimate Type: ConceptualCost Base (Jun) 2007($x1000)AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING$20,098$5,400$12,019$0$0$37,517$3,366$0$6,132$47,015$85 2COAL & SORBENT PREP & FEED$13,673$796$3,473$0$0$17,942$1,572$0$2,927$22,442$41 3FEEDWATER & MISC. BOP SYSTEMS$54,851$0$25,849$0$0$80,700$7,397$0$14,455$102,552$186 4PC BOILER4.1PC Boiler & Accessories$195,902$0$109,921$0$0$305,822$29,763$0$33,559$369,144$6714.2SCR (w/4.1)

$0$0$0$0$0$0$0$0$0$0$04.3Open$0$0$0$0$0$0$0$0$0$0$04.4-4.9Boiler BoP (w/ ID Fans)

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 4$195,902$0$109,921$0$0$305,822$29,763$0$33,559$369,144$671 5FLUE GAS CLEANUP$101,027$0$34,490$0$0$135,517$12,971$0$14,849$163,336$297 5BCO2 REMOVAL & COMPRESSION$235,366$0$71,742$0$0$307,108$29,363$54,181$78,130$468,782$852 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine GeneratorN/A$0N/A$0$0$0$0$0$0$0$06.2-6.9Combustion Turbine Other

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 6

$0$0$0$0$0$0$0$0$0$0$0 7HRSG, DUCTING & STACK7.1Heat Recovery Steam GeneratorN/A$0N/A$0$0$0$0$0$0$0$07.2-7.9HRSG Accessories, Ductwork and Stack$17,541$961$11,881$0$0$30,383$2,783$0$4,359$37,526$68SUBTOTAL 7$17,541$961$11,881$0$0$30,383$2,783$0$4,359$37,526$68 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$56,794$0$7,537$0$0$64,331$6,165$0$7,050$77,546$1418.2-8.9Turbine Plant Auxiliaries and Steam Piping$27,360$1,200$15,331$0$0$43,892$3,826$0$6,848$54,565$99SUBTOTAL 8$84,154$1,200$22,868$0$0$108,222$9,991$0$13,898$132,111$240 9COOLING WATER SYSTEM$20,722$9,941$18,443$0$0$49,106$4,622$0$7,236$60,965$111 10ASH/SPENT SORBENT HANDLING SYS$5,276$168$7,053$0$0$12,497$1,202$0$1,410$15,108$27 11ACCESSORY ELECTRIC PLANT$25,213$10,656$30,191$0$0$66,060$5,843$0$9,029$80,931$147 12INSTRUMENTATION & CONTROL$10,017$0$10,157$0$0$20,174$1,829$1,009$2,826$25,838$47 13IMPROVEMENTS TO SITE$3,321$1,909$6,692$0$0$11,921$1,176$0$2,620$15,717$29 14BUILDINGS & 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$2,913TOTAL PLANT COST

SUMMARY

Cost and Performance Baseline for Fossil Energy Plants 431 Exhibit 4-56 Case 12 Total Plant Cost Details AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING1.1Coal Receive & Unload$4,115$0$1,880$0$0$5,995$536$0$980$7,510$141.2Coal Stackout & Reclaim$5,318$0$1,205$0$0$6,523$571$0$1,064$8,158$151.3Coal Conveyors$4,944$0$1,192$0$0$6,137$538$0$1,001$7,676$141.4Other Coal Handling$1,294$0$276$0$0$1,569$137$0$256$1,963$41.5Sorbent Receive & Unload

$168$0$51$0$0$218$19$0$36$273$01.6Sorbent Stackout & Reclaim$2,709$0$496$0$0$3,205$279$0$523$4,007$71.7Sorbent Conveyors

$967$209$237$0$0$1,413$122$0$230$1,765$31.8Other Sorbent Handling

$584$137$306$0$0$1,027$91$0$168$1,285$21.9Coal & Sorbent Hnd.Foundations

$0$5,054$6,376$0$0$11,430$1,074$0$1,876$14,379$26SUBTOTAL 1.$20,098$5,400$12,019$0$0$37,517$3,366$0$6,132$47,015$85 2COAL & SORBENT PREP & FEED2.1Coal Crushing & Drying$2,388$0$465$0$0$2,853$249$0$465$3,567$62.2Coal Conveyor to Storage$6,113$0$1,334$0$0$7,447$651$0$1,215$9,313$172.3Coal Injection System

$0$0$0$0$0$0$0$0$0$0$02.4Misc.Coal Prep & Feed

$0$0$0$0$0$0$0$0$0$0$02.5Sorbent Prep Equipment$4,617$199$959$0$0$5,774$503$0$942$7,219$132.6Sorbent Storage & Feed

$556$0$213$0$0$769$68$0$126$963$22.7Sorbent Injection System

$0$0$0$0$0$0$0$0$0$0$02.8Booster Air Supply System

$0$0$0$0$0$0$0$0$0$0$02.9Coal & Sorbent Feed Foundation

$0$597$501$0$0$1,098$102$0$180$1,380$3SUBTOTAL 2.$13,673$796$3,473$0$0$17,942$1,572$0$2,927$22,442$41 3FEEDWATER & MISC. BOP SYSTEMS3.1Feedwater System$22,860$0$7,384$0$0$30,244$2,643$0$4,933$37,820$693.2Water Makeup & Pretreating $6,997$0$2,252$0$0$9,249$875$0$2,025$12,149$223.3Other Feedwater Subsystems$6,998$0$2,958$0$0$9,956$892$0$1,627$12,475$233.4Service Water Systems$1,372$0$746$0$0$2,118$199$0$463$2,780$53.5Other Boiler Plant Systems$8,675$0$8,565$0$0$17,240$1,638$0$2,832$21,709$393.6FO Supply Sys & Nat Gas

$276$0$345$0$0$621$59$0$102$781$13.7Waste Treatment Equipment$4,744$0$2,704$0$0$7,448$725$0$1,635$9,808$183.8Misc. Equip.(cranes,AirComp.,Comm.)$2,930$0$895$0$0$3,825$368$0$838$5,031$9SUBTOTAL 3.$54,851$0$25,849$0$0$80,700$7,397$0$14,455$102,552$186 4PC BOILER4.1PC Boiler & Accessories$195,902$0$109,921$0$0$305,822$29,763$0$33,559$369,144$6714.2SCR (w/4.1)

$0$0$0$0$0$0$0$0$0$0$04.3Open$0$0$0$0$0$0$0$0$0$0$04.4Boiler BoP (w/ ID Fans)

$0$0$0$0$0$0$0$0$0$0$04.5Primary Air Systemw/4.1$0w/4.1$0$0$0$0$0$0$0$04.6Secondary Air Systemw/4.1$0w/4.1$0$0$0$0$0$0$0$04.8Major Component Rigging

$0w/4.1w/4.1$0$0$0$0$0$0$0$04.9Boiler Foundations

$0w/14.1w/14.1$0$0$0$0$0$0$0$0SUBTOTAL 4.$195,902$0$109,921$0$0$305,822$29,763$0$33,559$369,144$671 Cost and Performance Baseline for Fossil Energy Plants 432 Exhibit 4-56 Case 12 Total Plant Cost Details (Continued) AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 5FLUE GAS CLEANUP5.1Absorber Vessels & Accessories$70,185$0$15,109$0$0$85,294$8,132$0$9,343$102,768$1875.2Other FGD$3,663$0$4,150$0$0$7,813$758$0$857$9,428$175.3Bag House & Accessories$20,190$0$12,813$0$0$33,003$3,180$0$3,618$39,801$725.4Other Particulate Removal Materials$1,366$0$1,462$0$0$2,828$274$0$310$3,413$65.5Gypsum Dewatering System$5,623$0$955$0$0$6,579$626$0$720$7,925$145.6Mercury Removal System

$0$0$0$0$0$0$0$0$0$0$05.9Open$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 5.$101,027$0$34,490$0$0$135,517$12,971$0$14,849$163,336$297 5BCO2 REMOVAL & COMPRESSION5B.1CO2 Removal System$207,807$0$63,097$0$0$270,904$25,901$54,181$70,197$421,183$7665B.2CO2 Compression & Drying$27,558$0$8,646$0$0$36,204$3,462$0$7,933$47,599$87SUBTOTAL 5.$235,366$0$71,742$0$0$307,108$29,363$54,181$78,130$468,782$852 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine GeneratorN/A$0N/A$0$0$0$0$0$0$0$06.2Open$0$0$0$0$0$0$0$0$0$0$06.3Compressed Air Piping

$0$0$0$0$0$0$0$0$0$0$06.9Combustion Turbine Foundations

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 6.

$0$0$0$0$0$0$0$0$0$0$0 7HRSG, DUCTING & STACK7.1Heat Recovery Steam GeneratorN/A$0N/A$0$0$0$0$0$0$0$07.2HRSG Accessories

$0$0$0$0$0$0$0$0$0$0$07.3Ductwork$9,165$0$5,889$0$0$15,054$1,313$0$2,455$18,822$347.4Stack$8,376$0$4,901$0$0$13,277$1,278$0$1,456$16,011$297.9Duct & Stack Foundations

$0$961$1,092$0$0$2,052$192$0$449$2,693$5SUBTOTAL 7.$17,541$961$11,881$0$0$30,383$2,783$0$4,359$37,526$68 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$56,794$0$7,537$0$0$64,331$6,165$0$7,050$77,546$1418.2Turbine Plant Auxiliaries

$382$0$819$0$0$1,202$118$0$132$1,451$38.3Condenser & Auxiliaries$5,509$0$2,030$0$0$7,540$722$0$826$9,088$178.4Steam Piping$21,469$0$10,585$0$0$32,054$2,693$0$5,212$39,959$738.9TG Foundations

$0$1,200$1,896$0$0$3,096$293$0$678$4,067$7SUBTOTAL 8.$84,154$1,200$22,868$0$0$108,222$9,991$0$13,898$132,111$240 9COOLING WATER SYSTEM9.1Cooling Towers$15,451$0$4,811$0$0$20,262$1,938$0$2,220$24,419$449.2Circulating Water Pumps$3,219$0$248$0$0$3,467$293$0$376$4,136$89.3Circ.Water System Auxiliaries

$787$0$105$0$0$892$85$0$98$1,075$29.4Circ.Water Piping

$0$6,243$6,050$0$0$12,293$1,151$0$2,017$15,460$289.5Make-up Water System

$641$0$857$0$0$1,498$144$0$246$1,888$39.6Component Cooling Water Sys

$624$0$496$0$0$1,120$106$0$184$1,410$39.9Circ.Water System Foundations & Structures

$0$3,698$5,876$0$0$9,575$906$0$2,096$12,577$23SUBTOTAL 9.$20,722$9,941$18,443$0$0$49,106$4,622$0$7,236$60,965$111 Cost and Performance Baseline for Fossil Energy Plants 433 Exhibit 4-56 Case 12 Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 10ASH/SPENT SORBENT HANDLING SYS10.1Ash CoolersN/A$0N/A$0$0$0$0$0$0$0$010.2Cyclone Ash LetdownN/A$0N/A$0$0$0$0$0$0$0$010.3HGCU Ash LetdownN/A$0N/A$0$0$0$0$0$0$0$010.4High Temperature Ash PipingN/A$0N/A$0$0$0$0$0$0$0$010.5Other Ash Recovery EquipmentN/A$0N/A$0$0$0$0$0$0$0$010.6Ash Storage Silos

$706$0$2,175$0$0$2,881$283$0$316$3,480$610.7Ash Transport & Feed Equipment$4,570$0$4,681$0$0$9,250$885$0$1,014$11,149$2010.8Misc. Ash Handling Equipment

$0$0$0$0$0$0$0$0$0$0$010.9Ash/Spent Sorbent Foundation

$0$168$198$0$0$365$34$0$80$479$1SUBTOTAL 10.$5,276$168$7,053$0$0$12,497$1,202$0$1,410$15,108$27 11ACCESSORY ELECTRIC PLANT11.1Generator Equipment$1,727$0$280$0$0$2,008$186$0$165$2,358$411.2Station Service Equipment$4,957$0$1,629$0$0$6,585$616$0$540$7,741$1411.3Switchgear & Motor Control $5,699$0$969$0$0$6,667$618$0$729$8,014$1511.4Conduit & Cable Tray

$0$3,573$12,354$0$0$15,926$1,542$0$2,620$20,089$3711.5Wire & Cable

$0$6,742$13,014$0$0$19,756$1,664$0$3,213$24,633$4511.6Protective Equipment

$261$0$888$0$0$1,149$112$0$126$1,388$311.7Standby Equipment$1,360$0$31$0$0$1,391$128$0$152$1,670$311.8Main Power Transformers$11,209$0$189$0$0$11,398$864$0$1,226$13,488$2511.9Electrical Foundations

$0$342$837$0$0$1,179$113$0$258$1,550$3SUBTOTAL 11.$25,213$10,656$30,191$0$0$66,060$5,843$0$9,029$80,931$147 12INSTRUMENTATION & CONTROL12.1PC Control Equipmentw/12.7$0w/12.7$0$0$0$0$0$0$0$012.2Combustion Turbine ControlN/A$0N/A$0$0$0$0$0$0$0$012.3Steam Turbine Controlw/8.1$0w/8.1$0$0$0$0$0$0$0$012.4Other Major Component Control

$0$0$0$0$0$0$0$0$0$0$012.5Signal Processing Equipmentw/12.7$0w/12.7$0$0$0$0$0$0$0$012.6Control Boards,Panels & Racks

$516$0$309$0$0$825$78$41$142$1,085$212.7Distributed Control System Equipment$5,207$0$910$0$0$6,117$567$306$699$7,689$1412.8Instrument Wiring & Tubing$2,823$0$5,599$0$0$8,422$718$421$1,434$10,995$2012.9Other I & C Equipment$1,471$0$3,339$0$0$4,810$466$241$552$6,069$11SUBTOTAL 12.$10,017$0$10,157$0$0$20,174$1,829$1,009$2,826$25,838$47 Cost and Performance Baseline for Fossil Energy Plants 434 Exhibit 4-56 Case 12 Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 13IMPROVEMENTS TO SITE13.1Site Preparation

$0$56$1,116$0$0$1,172$116$0$258$1,546$313.2Site Improvements

$0$1,853$2,301$0$0$4,154$410$0$913$5,477$1013.3Site Facilities$3,321$0$3,275$0$0$6,595$650$0$1,449$8,694$16SUBTOTAL 13.$3,321$1,909$6,692$0$0$11,921$1,176$0$2,620$15,717$29 14BUILDINGS & STRUCTURES14.1Boiler Building

$0$8,851$7,784$0$0$16,635$1,495$0$2,719$20,849$3814.2Turbine Building

$0$12,808$11,937$0$0$24,746$2,230$0$4,046$31,023$5614.3Administration Building

$0$643$680$0$0$1,324$120$0$217$1,660$314.4Circulation Water Pumphouse

$0$176$139$0$0$315$28$0$51$395$114.5Water Treatment Buildings

$0$887$809$0$0$1,697$153$0$277$2,127$414.6Machine Shop

$0$430$289$0$0$719$64$0$117$901$214.7Warehouse

$0$292$292$0$0$584$53$0$96$732$114.8Other Buildings & Structures

$0$238$203$0$0$441$40$0$72$553$114.9Waste Treating Building & Str.

$0$456$1,384$0$0$1,840$175$0$302$2,317$4SUBTOTAL 14.

$0$24,782$23,519$0$0$48,301$4,357$0$7,899$60,557$110TOTAL COST$787,159$55,813$388,298$0$0$1,231,270$116,235$55,190$199,329$1,602,023$2,913Owner's CostsPreproduction Costs6 Months All Labor$10,579$191 Month Maintenance Materials$1,541$31 Month Non-fuel Consumables$1,637$31 Month Waste Disposal

$325$125% of 1 Months Fuel Cost at 100% CF$1,971$42% of TPC$32,040$58Total$48,094$87Inventory Capital60 day supply of fuel and consumables at 100% CF$18,563$340.5% of TPC (spare parts)$8,010$15Total$26,573$48Initial Cost for Catalyst and Chemicals$2,496$5Land$900$2Other Owner's Costs$240,304$437Financing Costs$43,255$79Total Overnight Costs (TOC)$1,963,644$3,570TASC Multiplier(IOU, high-risk, 35 year)1.140Total As-Spent Cost (TASC)$2,238,554$4,070 Cost and Performance Baseline for Fossil Energy Plants 435 Exhibit 4-57 Case 12 Initial and Annual Operating and Maintenance Costs INITIAL & ANNUAL O&M EXPENSESCost Base (Jun):

2007Case 12 - 1x550 MWnet Super-Critical PC w/ CO2 CaptureHeat Rate-net (Btu/kWh):12,002 MWe-net: 550Capacity Factor (%):

85OPERATING & MAINTENANCE LABOROperating Labor Operating Labor Rate(base):34.65$/hour Operating Labor Burden:30.00% of base Labor O-H Charge Rate:25.00% of laborTotal Operating Labor Requirements(O.J.)per Shift:1 unit/mod. Plant Skilled Operator2.02.0 Operator11.311.3 Foreman1.01.0 Lab Tech's, etc.2.02.0 TOTAL-O.J.'s16.316.3Annual CostAnnual Unit Cost

$$/kW-netAnnual Operating Labor Cost$6,444,907$11.719Maintenance Labor Cost$10,481,104$19.058Administrative & Support Labor$4,231,503$7.694Property Taxes and Insurance$32,040,467$58.260TOTAL FIXED OPERATING COSTS$53,197,981$96.731VARIABLE OPERATING COSTS$/kWh-netMaintenance Material Cost$15,721,656$0.00384ConsumablesConsumptionUnit Initial Fill Initial Fill /Day Cost CostWater(/1000 gallons) 07,3241.08$0$2,457,806$0.00060ChemicalsMU & WT Chem.(lbs) 035,4520.17$0$1,903,577$0.00046Limestone (ton) 0 68721.63$0$4,610,586$0.00113Carbon (Mercury Removal) lb 0 01.05$0$0$0.00000MEA Solvent (ton)1,0281.462,249.89$2,312,307$1,017,164$0.00025NaOH (tons) 737.26433.68$31,484$976,789$0.00024H2SO4 (tons) 696.93138.78$9,615$298,293$0.00007Corrosion Inhibitor 0 00.00$142,156$6,769$0.00000Activated Carbon (lb) 01,7411.05$0$567,144$0.00014Ammonia (19% NH3) ton 0 102129.80$0$4,090,854$0.00100Subtotal Chemicals$2,495,562$13,471,176$0.00329OtherSupplemental Fuel (MBtu) 0 00.00$0$0$0.00000SCR Catalyst (m3)w/equip.0.435,775.94$0$765,005$0.00019Emission Penalties 0 00.00$0$0$0.00000Subtotal Other

$0$765,005$0.00019Waste DisposalFly Ash (ton) 0 52716.23$0$2,651,418$0.00065Bottom Ash (ton) 0 13216.23$0$662,855$0.00016Subtotal-Waste Disposal

$0$3,314,273$0.00081By-products & Emissions Gypsum (tons) 01,0620.00$0$0$0.00000Subtotal By-Products

$0$0$0.00000TOTAL VARIABLE OPERATING COSTS$2,495,562$35,729,917$0.00873Fuel (ton) 06,79038.18$0$80,434,598$0.01964 Cost and Performance Baseline for Fossil Energy Plants 436 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 1 Capacity factor is 85% for all PC cases 2 COE and LCOE are defined in Section 2.7. PERFORMANCE Case 9Case 10Case 11Case 12CO2 Capture 0%90%0%90%Gross Power Output (kWe)582,600672,700580,400662,800Auxiliary Power Requirement (kWe)32,580122,74030,410112,830Net Power Output (kWe)550,020549,960549,990549,970Coal Flowrate (lb/hr)437,378614,994409,528565,820Natural Gas Flowrate (lb/hr)N/AN/AN/AN/AHHV Thermal Input (kWth)1,495,3792,102,6431,400,1621,934,519Net Plant HHV Efficiency (%)36.8%26.2%39.3%28.4%Net Plant HHV Heat Rate (Btu/kWh)9,27713,0468,68712,002Raw Water Withdrawal (gpm/MWnet)10.720.49.718.3Process Water Discharge (gpm/MWnet)2.24.72.04.3Raw Water Consumption (gpm/MWnet)8.515.77.714.1 CO 2 Emissions (lb/MMBtu) 204 20 204 20 CO 2 Emissions (lb/MWhgross)1,783 2171,675 203 CO 2 Emissions (lb/MWhnet)1,888 2661,768 244 SO 2 Emissions (lb/MMBtu)0.08580.00170.08580.0016 SO 2 Emissions (lb/MWhgross)0.75150.01760.70630.0162NOx Emissions (lb/MMBtu)0.0700.0700.0700.070NOx Emissions (lb/MWhgross)0.6130.7470.5760.697PM Emissions (lb/MMBtu)0.01300.01300.01300.0130PM Emissions (lb/MWhgross)0.1140.1390.1070.129Hg Emissions (lb/TBtu)1.1431.1431.1431.143Hg Emissions (lb/MWhgross)1.00E-051.22E-059.41E-061.14E-05COSTTotal Plant Cost (2007$/kW)1,6222,9421,6472,913Total Overnight Cost (2007$/kW)1,9963,6102,0243,570 Bare Erected Cost1,3172,2551,3452,239 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 657Total Overnight Cost (2007$ x 1,000)1,098,1241,985,4321,113,4451,963,644Total As Spent Capital (2007$/kW)2,2644,1152,2964,070COE (mills/kWh, 2007$)1,259.4109.658.9106.5 CO2 TS&M Costs0.05.80.05.6 Fuel Costs15.221.314.219.6 Variable Costs5.19.25.08.7 Fixed Costs7.813.18.013.0 Capital Costs31.260.231.759.6LCOE (mills/kWh, 2007$)1,275.3139.074.7135.2Pulverized Coal BoilerPC SubcriticalPC Supercritical Cost and Performance Baseline for Fossil Energy Plants 437 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 CO 2 capture is approximately 1 percent greater than SC PC with CO 2 capture. The TOC penalty for adding CO 2 capture in the subcritical case is 81 percent and is 7 6 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 CO 2 capture cost penalty of 76 and 7 1 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 CO 2 capture cases because of the larger cooling water demand discussed previously. In addition, the gross output of the two PC plants increases by 9 0 MW (subcritical) and 8 2 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 1,9963,6102,0243,5702,2644,1152,2964,070 01,0002,0003,0004,0005,0006,000TOCTASCTOCTASCTOCTASCTOCTASCSubcritical PCSubcritical PC w/ CO2 CaptureSupercritical PCSupercritical PC w/ CO2 CaptureTOC or TASC, $/kW (2007$)TASCOwner's CostProcess ContingencyProject ContingencyHome Office ExpenseBare Erected Cost Cost and Performance Baseline for Fossil Energy Plants 438 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 CO 2 capture cases. Fuel cost is the second largest component of COE, and capital charges and fuel costs combined represent 7 4 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 TO C. In the CO 2 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

31.260.231.759.67.813.18.013.05.19.25.08.715.221.314.219.65.95.7 0 20 40 60 80 100 120 140Subcritical PCSubcritical PC w/ CO2 CaptureSupercritical PCSupercritical PC w/ CO2 CaptureCOE, mills/kWh (2007$)CO2 TS&M CostsFuel CostsVariable CostsFixed CostsCapital Costs Cost and Performance Baseline for Fossil Energy Plants 439 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 CO 2 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 CO 2 avoided was calculated, and the results for the PC CO 2 capture cases are shown in Exhibit 4-63. The cost of CO 2 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 CO 2 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 0 50 100 150 200 250 300 0 10 20 30 40 50 60 70 80 90 100COE, mills/kWh (2007$)Capacity Factor, %Subcritical w/CO2 CaptureSupercritical w/CO2 CaptureSubcritical No CaptureSupercritical No CaptureCoal price = $1.64/MMBtu Cost and Performance Baseline for Fossil Energy Plants 440 Exhibit 4-62 Sensitivity of COE to Coal Price for PC Cases Exhibit 4-63 First Year Cost of CO 2 Avoided in PC Cases 0 20 40 60 80 100 120 140 00.5 11.5 22.5 33.5 4COE, mills/kWh (2007$)Fuel Price, $/MMBtuSubcritical w/CO2 CaptureSupercritical w/CO2 CaptureSubcritical No CaptureSupercritical No CaptureCapacity Factor = 85%

68 69 75 69 0102030405060708090100Subcritical PCSupercritical PC CO 2Avoided Cost, $/tonne (2007$)Avoided Cost (Analogous Technology w/o Capture Reference)Avoided Cost (SC PC w/o Capture Reference)

Cost and Performance Baseline for Fossil Energy Plants 441 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 [

75Similar results from an EPRI study using Illinois No. 6 coal were reported as follows:[] 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.

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 CO 2 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 CO 2 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 9 0 MW in the subcritical PC case and by 8 2 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 CO 2 capture cases than non

-capture cases because of the higher efficiencies of SC PC and non

-capture PC cases.

SO 2 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 SO 2 emissions in CO 2 capture cases. The SO 2 emissions for subcritical PC are higher than SC on a mass basis and when normalized by gross output because of the lower efficiency.

Uncontrolled CO 2 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 CO 2 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 CO 2 capture cases. The amount of raw water consumption in Cost and Performance Baseline for Fossil Energy Plants 442 the CO 2 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 CO 2 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 CO 2 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

10.720.49.718.38.515.77.714.1 0 5 10 15 20 25Subcritical PCSubcritical PC w/ CO2 CaptureSupercritical PCSupercritical PC w/ CO2 CaptureWater, gpm/MWnetRaw Water WithdrawalProcess DischargeRaw Water Consumption Cost and Performance Baseline for Fossil Energy Plants 443 5. 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 CTG s, two HRSG's and one STG in a multi

-shaft 2x2x1 configuration.

NATURAL GAS COMBINED CYCLE PLANTS The NGCC cases are evaluated with and without CO 2 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/5 66°C (2400 psig/1050F/10 50F) 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 CO 2 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 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.

Natural Gas Supply System 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 The combined cycle plant is based on two CTG's. The CTG is representative of the advanced F Class turbines with an ISO base rating of 184,400 kW when firing natural gas

[Combustion Turbine 77Each 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.

]. This machine is an axial flow, single spool, constant speed unit, with variable IGV s , and dry LNB combustion system.

Cost and Performance Baseline for Fossil Energy Plants 444 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 ASSEMBLY Coupling to Generator, Dry Chemical Exhaust Bearing Fire Protection System, Insulation Blankets, Platforms, Stairs and Ladders Engine Assembly with Bedplate Variable IGV System, Compressor, Bleed System, Purge Air System, Bearing Seal Air System, Combustors, Dual Fuel Nozzles, Turbine Rotor Cooler Walk-in acoustical enclosure HVAC, Lighting, and LP CO 2 Fire Protection System MECHANICAL PACKAGE HVAC , Lighting, Air Compressor for Pneumatic System, LP CO 2 Fire Protection System Lubricating Oil System and Control Oil System Lube Oil Reservoir, Accumulators, 2x100% AC Driven Oil Pumps, DC Emergency Oil Pump with Starter, 2x100% Oil Coolers, Duplex Oil Filter, Oil Temperature and Pressure Control Valves, Oil Vapor Exhaust Fans and Demister, Oil Heaters, Oil Interconnect Piping (SS and CS), Oil System Instrumentation, Oil for Flushing and First Filling ELECTRICAL PACKAGE 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),

Control System Valves and Instrumentation Communication link for interface with plant DCS Supervisory System, Bentley Nevada Vibration Monitoring System, LP CO 2 Fire Protection System, Cable Tray and Conduit Provisions for Performance Testing including Test Ports, Thermowells, Instrumentation and DCS interface cards INLET AND EXHAUST SYSTEMS Inlet Duct Trash Screens, Inlet Duct and Silencers, Self Cleaning Filters, Hoist System For Filter Maintenance, Evaporative Cooler System, Exhaust Duct Expansion Joint, Exhaust Silencers Inlet and Exhaust Flow, Pressure and Temperature Ports and Instrumentation FUEL SYSTEMS N. Gas System Gas Valves Including Vent, Throttle and Trip Valves, Gas Filter/Separator, Gas Supply Instruments and Instrument Panel STARTING SYSTEM Enclosure, Starting Motor or Static Start System, Turning Gear and Clutch Assembly, Starting Clutch, Torque Converter GENERATOR 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 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 Generator Cooling Totally Enclosed Water-to-Air-Cooled (TEWAC) System (including circulation system, interconnecting piping and controls), or Hydrogen Cooling System (including H 2 to Glycol and Glycol to Air heat exchangers, liquid level detector circulation system, interconnecting piping and controls)

MISCELLANEOUS Interconnecting Pipe, Wire, Tubing and Cable Instrument Air System Including Air Dryer On Line and Off Line Water Wash System LP CO 2 Storage Tank Drain System Drain Tanks Coupling, Coupling Cover and Associated Hardware

Cost and Performance Baseline for Fossil Energy Plants 445 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 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.

Heat Recovery Steam Generator 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 This reference plant is designed to achieve 2.5 ppmvd NOx emissions (expressed as NO 2 and referenced to 15 percent O 2). 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 O 2) [NOx Control System 78The 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 N 2 and H 2O. 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 O 2). ]. 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 (500F) to 343°C (650F). The ammonia storage and injection system consists of the unloading facilities, bulk storage tank, vaporizers, and dilution air skid.

Cost and Performance Baseline for Fossil Energy Plants 446 5.1.5 A CDR facility is used in Case 14 to remove 90 percent of the CO 2 in the F G 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 CO

2. The CDR is comprised of FG supply, CO 2 absorption, solvent stripping and reclaiming, and CO 2 compression and drying. Carbon Dioxide Recovery Facility The CO 2 absorption/stripping/solvent reclaim process for Case 14 is based on the Fluor Econamine FG Plus SM technology as previously described in Section 4.1.7 with the exception that no SO 2 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 SO 2, 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. The function of the FG cooling and supply system is to transport FG from the HRSG to the CO 2 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. FG Cooling and Supply 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 CO 2 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 CO 2 absorber tower.

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 CO 2 compression interstage cooling. The cooling water requirements for the CDR facility in the NGCC capture case is about 594,308 lpm (1 57,000 gpm), which greatly exceeds the NGCC plant cooling water requirement of about 200,626 lpm (53,000 gpm).

Circulating Water System The cooled FG enters the bottom of the CO 2 Absorber and flows up through the tower countercurrent to a stream of lean MEA

-based solvent called Econamine. Approximately 90 percent of the CO 2 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 CO 2 from the flue gas and leaves the bottom of the absorber with the absorbed CO

2. CO 2 Absorption

Cost and Performance Baseline for Fossil Energy Plants 447 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 CO 2 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 CO 2 Absorber. The wash water level is maintained by water makeup from the Wash Water Makeup Pump.

Water Wash Section The rich solvent from the bottom of the CO 2 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 CO

2. 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 CO 2 Absorber, completing the circulating solvent circuit. Rich/Lean Amine Heat Exchange System The purpose of the Solvent Stripper is to separate the CO 2 from the rich solvent feed exiting the bottom of the CO 2 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 CO 2 from the solution. Steam is provided from the crossover pipe between the IP and LP section s 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 CO 2, 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 CO 2-rich gas is then delivered to the CO 2 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 CO 2 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 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 Solvent Stripper Reclaimer

Cost and Performance Baseline for Fossil Energy Plants 448 to the Solvent Stripper and the spent solvent is pumped via the Solvent Reclaimer Drain Pump to the Solvent Reclaimer Drain Tank.

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.

Steam Condensate A proprietary corrosion inhibitor is continuously injected into the CO 2 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 CO 2 recovery plant system. Corrosion Inhibitor System In the compression section, the CO 2 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 Gas Compression and Drying System 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 CO 2 stream is dehydrated to a dewpoint of

-40ºC (-40°F) with triethylene glycol. The virtually moisture-free SC CO 2 stream is delivered to the plant battery limit as sequestration ready. CO 2 TS&M costs were estimated and included in LCOE and COE using the methodology described in Section 2.7.

5.1.6 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.

Steam Turbine 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/5 66°C (3 60 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.

Cost and Performance Baseline for Fossil Energy Plants 449 Exhibit 5-2 CO 2 Compressor Interstage Pressures Stage Outlet Pressure, 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 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. Condensate 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.

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 1 00 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 Feedwater Cost and Performance Baseline for Fossil Energy Plants 450 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 startu p

strainers, which are utilized during initial startup and following major outages or system maintenance.

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.

Steam System 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.

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.

Circulating Water System 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.

Cost and Performance Baseline for Fossil Energy Plants 451 Structures assumed for NGCC cases can be summarized as follows:

Buildings and Structures 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 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.

Accessory Electric Plant 5.1.9 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.

Instrumentation and Control 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.

Cost and Performance Baseline for Fossil Energy Plants 452 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/1050F/10 50F) cycle. The only difference between the two plants is that Case 14 includes CO 2 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 In this section the NGCC process without CO 2 capture is described. The system description follows the BFD in Process Description 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 10 6°C (22 2°F) and passes to the plant stack

Cost and Performance Baseline for Fossil Energy Plants 453 Exhibit 5-3 Case 13 Block Flow Diagram, NGCC without CO 2 Capture Cost and Performance Baseline for Fossil Energy Plants 454 Exhibit 5-4 Case 13 Stream Table, NGCC without CO 2 Capture 1 2 3 4 5 6V-L Mole Fraction Ar0.00920.00000.00890.00890.00000.0000 CH 40.00000.93100.00000.00000.00000.0000 C 2 H 60.00000.03200.00000.00000.00000.0000 C 3 H 80.00000.00700.00000.00000.00000.0000 C 4 H100.00000.00400.00000.00000.00000.0000 CO0.00000.00000.00000.00000.00000.0000 CO 20.00030.01000.04040.04040.00000.0000 H 2 O0.00990.00000.08670.08671.00001.0000 N 20.77320.01600.74320.74320.00000.0000 O 20.20740.00000.12090.12090.00000.0000 SO 20.00000.00000.00000.00000.00000.0000Total1.00001.00001.00001.00001.00001.0000V-L Flowrate (kgmol/hr)109,3234,380113,831113,83121,58928,545V-L Flowrate (kg/hr)3,154,73575,9013,230,6363,230,636388,927514,240Solids Flowrate (kg/hr) 0 0 0 0 0 0Temperature (°C) 15 38 629 106 566 38Pressure (MPa, abs)0.103.100.110.1016.650.01Enthalpy (kJ/kg)

A30.2346.30835.81248.813,472.36160.61Density (kg/m 3)1.222.20.40.947.7992.9V-L Molecular Weight28.85717.32828.38128.38118.01518.015V-L Flowrate (lbmol/hr)241,0169,657250,954250,95447,59562,930V-L Flowrate (lb/hr)6,955,000167,3337,122,3337,122,333857,4371,133,706Solids Flowrate (lb/hr) 0 0 0 0 0 0Temperature (°F) 59 1001,163 2221,050 101Pressure (psia)14.7450.015.214.72,414.71.0Enthalpy (Btu/lb)

A13.019.9359.3107.01,492.869.1Density (lb/ft 3)0.0761.3840.0250.0572.97761.982A - Reference conditions are 32.02 F & 0.089 PSIA Cost and Performance Baseline for Fossil Energy Plants 455 5.2.2 System assumptions for Cases 13 and 14 , NGCC with and without CO 2 capture, are compiled in Key System Assumptions Exhibit 5-5. Exhibit 5-5 NGCC Plant Study Configuration Matrix Case 13 w/o CO 2 Capture Case 1 4 w/CO 2 Capture Steam Cycle , MPa/°C/°C (psig/°F/°F) 16.5/566/566 (2400/1050/10 50) 16.5/566/566 (2400/1050/10 50) Fuel Natural Gas Natural Gas Fuel Pressure at Plant Battery Limit MPa (psia) 3.1 (450) 3.1 (450) 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) SO 2 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), ppm v 10 10 Particulate Control N/A N/A Mercury Control N/A N/A CO 2 Control N/A Econamine Overall CO 2 Capture (A)

N/A 90.7% CO 2 Sequestration N/A Off-site Saline Formation A. Removal efficiencies are based on the FG content The balance of plant assumptions are common to both NGCC cases and are presented in Balance of Plant

- Cases 13 and 1 4 Exhibit 5-6.

Cost and Performance Baseline for Fossil Energy Plants 456 Exhibit 5-6 NGCC Balance of Plant Assumptions Recirculating Wet Cooling Tower Cooling System Fuel and Other Storage Natural Gas Pipeline supply at 3.1 MPa (450 psia) and 38°C (100°F) Plant Distribution Voltage Motors below 1 hp 110/220 volt Motors between 1 hp and 250 hp 480 volt Motors between 250 hp and 5,000 hp 4,160 volt 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 m 3/d (1,500 gpd) Water Discharge Most of the process wastewater is recycled to the cooling tower basin. Blowdown is treated for chloride and metals, and discharged.

5.2.3 Dual trains are used to accommodate the size of commercial GTs. There is no redundancy other than normal sparing of rotating equipment. The plant design consists of the following major subsystems:

Sparing Philosophy Two advanced F class CTGs (2 x 50%)

Two 3-pressure reheat HRSGs with self supporting stacks and SCR systems (2 x 50%)

One 3-pressure reheat, triple

-admission STG (1 x 100%)

Two trains of Econamine CO 2 capture (2 x 50%) (Case 14 only)

Cost and Performance Baseline for Fossil Energy Plants 457 5.2.4 The plant produces a net output of 5 55 MW at a net plant efficiency of 50.

2 percent (HHV basis). Case 13 Performance Results Overall plant performance is summarized in Exhibit 5-7 , which includes auxiliary power requirements.

Exhibit 5-7 Case 13 Plant Performance Summary POWER

SUMMARY

(Gross Power at Generator Terminals, kWe)

Gas Turbine Power 362,200 Steam Turbine Power 202,500 TOTAL POWER, kWe 564,700 AUXILIARY LOAD

SUMMARY

, kWe Condensate Pumps 170 Boiler Feedwater Pumps 2,720 Circulating Water Pump 2,300 Ground Water Pumps 210 Cooling Tower Fans 1,190 SCR 10 Gas Turbine Auxiliaries 700 Steam Turbine Auxiliaries 100 Miscellaneous Balance of Plant 1 500 Transformer Losses 1,720 TOTAL AUXILIARIES, kWe 9,620 NET POWER, kWe 555,080 Net Plant Efficiency (HHV) 50.2% Net Plant Efficiency (LHV) 55.7% Net Plant Heat Rate (HHV)

, kJ/kWh (Btu/kWh

) 7,172 (6,798)

Net Plant Heat Rate (LHV)

, kJ/kWh (Btu/kWh) 6,466 (6,129)

CONDENSER COOLING DUTY, 10 6 kJ/h r (10 6 Btu/h r) 1,139 (1,080)

CONSUMABLES Natural Gas Feed Flow, kg/hr (lb/hr) 75,901 (167,333)

Thermal Input (HHV), kW th 1,105,812 Thermal Input (LHV)

, kW th 997,032 Raw Water Withdrawal , m 3/min (gpm) 8.9 (2,362)

Raw Water Consumption , m 3/min (gpm) 6.9 (1,831)

1. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

Cost and Performance Baseline for Fossil Energy Plants 458 The environmental targets for emissions of NOx, SO 2 , and PM were presented in Section 2.4. A summary of the plant air emissions for Case 13 is presented in Environmental Performance Exhibit 5-8. Exhibit 5-8 Case 13 Air Emissions kg/GJ (lb/10 6 Btu) Tonne/year (ton/year) 85% CF kg/MWh (lb/MWh) SO 2 Negligible Negligible Negligible NOx 0.004 (0.009) 115 (127) 0.027 (0.060) Particulates Negligible Negligible Negligible Hg Negligible Negligible Negligible CO 2 51 (118) 1,507,427 (1,661,654) 359 (790) CO 2 1 365 (804) 1 CO 2 emissions based on net power instead of gross power The operation of the modern, state

-of-the-art GT fueled by natural gas, coupled to a HRSG, results in very low levels of NOx emissions and negligible levels of SO 2, particulate and Hg emissions. As noted in Section 2.4, if the fuel contains the maximum amount of sulfur compounds allowed in pipeline natural gas, the NGCC SO 2 emissions would be 21 tonnes/yr (23 tons/yr) at 85 percent CF, or 0.00195 lb/MMBtu.

The low level of NOx production (2.5 ppmvd at 15 percent O

2) is achieved by utilizing a dry LNB coupled with an SCR system.

CO 2 emissions are reduced relative to those produced by burning coal given the same power output because of the higher heat content of natural gas, the lower carbon intensity of gas relative to coal, and the higher overall efficiency of the NGCC plant relative to a coal

-fired plant.

The carbon balance for the plant is shown in Exhibit 5-9. The carbon input to the plant consists of carbon in the natural gas and carbon as CO 2 in the CT air. Carbon leaves the plant as CO 2 through the stack.

Exhibit 5-9 Case 13 Carbon Balance Carbon In, kg/hr (lb/hr)

Carbon Out, kg/hr (lb/hr)

Natural Gas 54,822 (120,863)

Stack Gas 55,251 (121,808)

Air (CO 2) 429 (946) Total 55,251 (121,808)

Total 55,251 (121,808)

Cost and Performance Baseline for Fossil Energy Plants 459 A sulfur balance is not included for Case 13 because the sulfur concentration of the natural gas feed is negligible. Consequently, sulfur emissions are also negligible, as shown in Exhibit 5-8 , despite the use of no sulfur control technology.

Exhibit 5-10 shows the water balance for Case 13. 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 condenser 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 5-10 Case 13 Water Balance Water Use Water Demand, m 3/min (gpm) Internal Recycle, m 3/min (gpm) Raw Water Withdrawal, m 3/min (gpm) Process Water Discharge, m 3/min (gpm) Raw Water Consumption, m 3/min (gpm)

Condenser Makeup BFW Makeup 0.1 (23) 0.1 (23) 0.0 (0) 0.1 (23) 0.1 (23) 0.0 (0) 0.1 (23) Cooling Tower BFW Blowdown 8.9 (2,362) 0.0 (0) 0.1 (23) 0.1 (23) 8.9 (2,339)

-0.1 (-23) 2.0 (531) 6.8 (1,808)

Total 9.0 (2,385) 0.1 (23) 8.9 (2,362) 2.0 (531) 6.9 (1,831)

A heat and mass balance diagram is shown for the NGCC in Heat and Mass Balance Diagrams Exhibit 5-11. An overall plant energy balance is provided in tabular form in Exhibit 5-12. The power out is the combined CT and steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 5-7) is calculated by multiplying the power out by a combined generator efficiency of 98.4 percent.

Cost and Performance Baseline for Fossil Energy Plants 460 This page intentionally left blank

Cost and Performance Baseline for Fossil Energy Plants 461 Exhibit 5-11 Case 13 Heat and Mass Balance, NGCC without CO 2 Capture N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA H EAT AND M ATERIAL F LOW D IAGRAM P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Nitrogen Natural Gas Carbon Dioxide Water Steam P AGES 1 OF 1 N ATURAL GAS COMBINED CYCLE PLANT C ASE 13 2 X ADVANCED F-CLASS GT 2400/1050/1050 DWG. NO.BB-HMB-CS-13-PG-1 Flue Gas A MBIENT A IR 1 6 , 955 , 000 W 59.0 T 14.7 P 12.9 H Gross Plant Power

565 MWe Auxiliary Load

10 MWe Net Plant Power

555 MWe Net Plant Efficiency , HHV: 50.2%Net Plant Heat Rate

6 , 798 BTU/KWe A DVANCED F C LASS G AS T URBINES COMBUSTOR N ATURAL GAS 167 , 333 W 100.0 T 450.0 P 19.9 H 2 7 , 122 , 333 W 222.4 T 14.7 P 106.9 H 7 , 122 , 333 W 1 , 163.5 T 15.2 P 359.3 H GENERATOR CONDENSATE PUMPS 8 , 801 W 1 , 302 W 101.3 T 130.0 P 69.5 H 1 , 133 , 706 W 101.1 T 1.0 P 69.1 H 1 , 400 W 581.0 T 75.0 P 1 , 321.3 H 1 , 017 , 200 W 641.4 T 75.0 P 1 , 351.1 H 1 , 110 , 400 W 632.6 T 75.0 P 1 , 346.8 H 1 , 110 , 400 W 101.1 T 1.0 P 1 , 032.6 H HOT WELL CONDENSER S TACK 4 S TEAM T URBINE MAKEUP 11 , 337 W 59.0 T 14.7 P 27.1 H AIR INLET FILTER 3 HP PUMP 1 , 133 , 706 W 253.0 T 100.0 P 221.9 H BLOWDOWN 94 , 141 W 300.1 T 95.0 P 269.4 H 173 , 467 W 300.7 T 400.0 P 270.7 H 866 , 098 W 305.3 T 2 , 540.0 P 279.3 H 11 , 337 W GLAND SEAL CONDENSER 1 , 400 W 212.0 T 14.7 P 179.9 H LP TURBINE 9 , 569 W 1 , 133 , 706 W 103.9 T 120.0 P 72.1 H Three Pressure Heat Recovery Steam Generator (HRSG)829 , 777 W 1 , 055.0 T 360.0 P 1 , 553.4 H A A 171 , 732 W 1 , 055.0 T 360.0 P 1 , 553.4 H HOT REHEAT C OLD R EHEAT 829 , 777 W 587.9 T 390.0 P 1 , 300.6 H STEAM SEAL REGULATOR 93 , 200 W 537.0 T 80.0 P 1 , 299.1 H 16 , 993 W 970.1 T 1 , 850.0 P 1 , 459.8 H HP TURBINE IP TURBINE 852 , 917 W 2 , 654 W 1 , 050.0 T 2 , 414.7 P 1 , 492.8 H 1 , 018 , 502 W MAIN STEAM 857 , 437 W 1 , 050.0 T 2 , 414.7 P 1 , 492.8 H 5 10 , 969 W 866 W IP STEAM IP PUMP LP PUMP 6 DOE/NETL SC PC P LANT C ASE 13 Cost and Performance Baseline for Fossil Energy Plants 462

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Cost and Performance Baseline for Fossil Energy Plants 463 Exhibit 5-12 Case 13 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)

Natural Gas 3,981 (3,773) 2.7 (2.5) 3,984 (3,776)

GT Air 95.4 (90.4) 95 (90) Raw Water Withdrawal 33.6 (31.9) 34 (32) Auxiliary Power 35 (33) 35 (33) Totals 3,981 (3,773) 131.6 (124.8) 35 (33) 4,147 (3,931)

Heat Out GJ/hr (MMBtu/hr)

Cooling Tower Blowdown 14.9 (14.2) 15 (14) Stack Gas 804 (762) 804 (762) Condenser 1,141 (1,082) 1,141 (1,082)

Process Losses*

154 (146) 154 (146) Power 2,033 (1,927) 2,033 (1,927)

Totals 0 (0) 2,114 (2,004) 2,033 (1,927) 4,147 (3,931)

Process Losses are calculated by difference and reflect various turbine, and other heat and work losses.

Cost and Performance Baseline for Fossil Energy Plants 464 5.2.5 Major equipment items for the NGCC plant with no CO 2 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 Case 13 - Major Equipment List 5.2.6. 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 N/A ACCOUNT 2 FUEL AND SORBENT PREPARATION AND FEED Equipment No.DescriptionTypeOperating Qty.Spares 1Gas PipelineUnderground, coated carbon steel, wrapped cathodic protection16 km (10 mile)0 2Gas Metering Station

--1 0Design Condition63 m3/min @ 3.1 MPa(2,216 acfm @ 450 psia)41 cm (16 in) standard wall pipe63 m3/min (2,216 acfm)

Cost and Performance Baseline for Fossil Energy Plants 465 ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment No.DescriptionTypeOperating Qty.Spares 1Demineralized Water Storage TankVertical, cylindrical, outdoor 2 0 2Condensate PumpsVertical canned 2 1 4Auxiliary BoilerShop fabricated, water tube 1 0 5Service Air CompressorsFlooded Screw 2 1 6Instrument Air DryersDuplex, regenerative 2 1 7Closed Cycle Cooling Heat ExchangersPlate and frame 2 0 8Closed Cycle Cooling Water PumpsHorizontal centrifugal 2 1 9Engine-Driven Fire PumpVertical turbine, diesel engine 1 1 10Fire Service Booster PumpTwo-stage horizontal centrifugal 1 1 11Raw Water PumpsStainless steel, single suction 2 1 12Filtered Water PumpsStainless steel, single suction 2 1 13Filtered Water TankVertical, cylindrical 1 0 14Makeup Water DemineralizerMulti-media filter, cartridge filter, RO membrane assembly and electro-deionization unit 1 0 15Liquid Waste Treatment System 1 0Design Condition678,767 liters (179,310 gal)4,732 lpm @ 110 m H2O(1,250 gpm @ 360 ft H2O)13 MMkJ/hr (13 MMBtu/hr) 3Boiler Feedwater PumpHorizontal, split case, multi-stage, centrifugal, with interstage bleed for IP and LP feedwater5,300 lpm @ 21 m H2O(1,400 gpm @ 70 ft H2O) 2HP water: 3,634 lpm @ 2,103 m H2O (960 gpm @ 6,900 ft H2O)IP water: 719 lpm @ 283 m H2O (190 gpm @ 930 ft H2O)18,144 kg/h, 2.8 MPa, 343°C(40,000 lb/h, 400 psig, 650°F)13 m3/min @ 0.7 MPa(450 scfm @ 100 psig)LP water: 379 lpm @ 24.4 m H2O (100 gpm @ 80 ft H2O) 1143,847 liter (38,000 gal)341 lpm (90 gpm)10 years, 24-hour storm3,785 lpm @ 107 m H2O(1,000 gpm @ 350 ft H2O)2,650 lpm @ 76 m H2O(700 gpm @ 250 ft H2O)4,921 lpm @ 18 m H2O(1,300 gpm @ 60 ft H2O)151 lpm @ 49 m H2O(40 gpm @ 160 ft H2O)13 m3/min (450 scfm)

Cost and Performance Baseline for Fossil Energy Plants 466 ACCOUNT 4 GASIFIER, BOILER AND ACCESSORIES N/A ACCOUNT 5 FLUE GAS CLEANUP N/A ACCOUNT 6 COMBUSTION TURBINE GENERATORS AND AUXILIARIES ACCOUNT 7 WASTE HEAT BOILER, DUCTING, AND STACK Equipment No.DescriptionTypeOperating Qty.Spares 1Gas TurbineAdvanced F class w/ dry low-NOx burner 2 0 2Gas Turbine GeneratorTEWAC 2 0Design Condition184 MW 200 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phaseEquipment No.DescriptionTypeOperating Qty.Spares 1StackCS plate, type 409SS liner 2 0 3SCR ReactorSpace for spare layer 2 0 4SCR Catalyst

--1 layer 0 5Dilution Air BlowersCentrifugal 2 1 6Ammonia Feed PumpCentrifugal 2 1 7Ammonia Storage TankHorizontal tank 1 0 2 0 2Heat Recovery Steam GeneratorDrum, multi-pressure with economizer section and integral deaerator Reheat steam - 249,852 kg/h, 2.4 MPa/566°C (550,830 lb/h, 345 psig/1,050°F)Design Condition46 m (150 ft) high x7.5 m (25 ft) diameterMain steam - 213,910 kg/h, 16.5 MPa/566°C (471,590 lb/h, 2,400 psig/1,050°F)1,778,084 kg/h (3,920,000 lb/h)Space available for an additional catalyst layer11 m3/min @ 107 cm WG(390 scfm @ 42 in WG)3.8 lpm @ 91 m H2O(1 gpm @ 300 ft H2O)68,138 liter (18,000 gal)

Cost and Performance Baseline for Fossil Energy Plants 467 ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES ACCOUNT 9 COOLING WATER SYSTEM

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING N/A Equipment No.DescriptionTypeOperating Qty.Spares 1Steam TurbineTandem compound, HP, IP, and two-flow LP turbines 1 0 2Steam Turbine GeneratorHydrogen cooled, static excitation 1 0 3Steam BypassOne per HRSG 2 0 4Surface CondenserSingle pass, divided waterbox including vacuum pumps 1 0Design Condition213 MW 16.5 MPa/566°C/566°C (2,400 psig/ 1050°F/1050°F)1,254 MMkJ/hr, (1,190 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F)240 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase50% steam flow @ design steam conditionsEquipment No.DescriptionTypeOperating Qty.Spares 1Circulating Water PumpsVertical, wet pit 2 1 2Cooling TowerEvaporative, mechanical draft, multi-cell 1 0Design Condition230,912 lpm @ 30.5 m(61,000 gpm @ 100 ft)11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT 1,283 MMkJ/hr (1,217 MMBtu/hr) heat load Cost and Performance Baseline for Fossil Energy Plants 468 ACCOUNT 11 ACCESSORY ELECTRIC PLANT ACCOUNT 12 INSTRUMENTATION AND CONTROL Equipment No.DescriptionTypeOperating Qty.Spares 1CTG TransformerOil-filled 2 0 3Auxiliary TransformerOil-filled 1 1 4Low Voltage TransformerDry ventilated 1 1 5CTG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled 2 0 6STG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled 1 0 7Medium Voltage SwitchgearMetal clad 1 1 8Low Voltage SwitchgearMetal enclosed 1 1 9Emergency Diesel GeneratorSized for emergency shutdown 1 0Design Condition24 kV/345 kV, 200 MVA, 3-ph, 60 Hz24 kV/345 kV, 230 MVA, 3-ph, 60 Hz24 kV, 3-ph, 60 Hz24 kV, 3-ph, 60 Hz4.16 kV, 3-ph, 60 Hz480 V, 3-ph, 60 Hz4.16 kV/480 V, 1 MVA, 3-ph, 60 Hz750 kW, 480 V, 3-ph, 60 Hz24 kV/4.16 kV, 09 MVA, 3-ph, 60 Hz 2STG TransformerOil-filled 1 0Equipment No.DescriptionTypeOperating Qty.Spares 1DCS - Main ControlMonitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) 1 0 3DCS - Data HighwayFiber optic 1 0Design ConditionOperator stations/printers and engineering stations/printers 0Fully redundant, 25% spare 1 2DCS - ProcessorMicroprocessor with redundant input/outputN/A Cost and Performance Baseline for Fossil Energy Plants 469 5.2.6 The cost estimating methodology was described previously in Section Case 13 - Cost Estimating 2.7. Exhibit 5-13 shows the total plant capital cost summary organized by cost account and Exhibi t 5-14 shows a more detailed breakdown of the capital costs. Exhibit 5-15 shows the initial and annual O&M costs.

The estimated TOC of the NGCC with no CO 2 capture is $

718/kW. No process contingency was included in this case because all elements of the technology are commercially proven. The project contingency is 8.6 percent of TOC. The COE is 58.9 mills/kWh.

Cost and Performance Baseline for Fossil Energy Plants 470 Exhibit 5-13 Case 13 Total Plant Cost Summary Client: USDOE/NETLReport Date:2010-Jan-14Project: Bituminous Baseline StudyCase: Case 13 - 1x555 MWnet 2x1 7FB NGCCPlant Size: 555.1MW,netEstimate Type: ConceptualCost Base (Jun) 2007($x1000)AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING

$0$0$0$0$0$0$0$0$0$0$0 2COAL & SORBENT PREP & FEED

$0$0$0$0$0$0$0$0$0$0$0 3FEEDWATER & MISC. BOP SYSTEMS$22,444$4,461$6,516$0$0$33,421$2,819$0$5,782$42,022$76 4GASIFIER & ACCESSORIES4.1Gasifier, Syngas Cooler & Auxiliaries

$0$0$0$0$0$0$0$0$0$0$04.2Syngas Cooling

$0$0$0$0$0$0$0$0$0$0$04.3ASU/Oxidant Compression

$0$0$0$0$0$0$0$0$0$0$04.4-4.9Other gasification Equipment

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 4

$0$0$0$0$0$0$0$0$0$0$0 5AGAS CLEANUP & PIPING

$0$0$0$0$0$0$0$0$0$0$0 5BCO2 REMOVAL & COMPRESSION

$0$0$0$0$0$0$0$0$0$0$0 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine Generator$75,294$0$4,804$0$0$80,098$6,800$0$8,690$95,589$1726.2-6.9Combustion Turbine Other

$0$719$744$0$0$1,462$122$0$317$1,901$3SUBTOTAL 6$75,294$719$5,548$0$0$81,561$6,922$0$9,007$97,490$176 7HRSG, DUCTING & STACK7.1Heat Recovery Steam Generator$32,958$0$4,279$0$0$37,237$3,170$0$4,041$44,448$807.2-7.9SCR System, Ductwork and Stack$1,243$950$1,118$0$0$3,311$282$0$583$4,176$8SUBTOTAL 7$34,200$950$5,397$0$0$40,548$3,453$0$4,624$48,624$88 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$23,774$0$3,855$0$0$27,630$2,374$0$3,000$33,005$598.2-8.9Turbine Plant Auxiliaries and Steam Piping$8,304$798$5,509$0$0$14,611$1,190$0$2,164$17,965$32SUBTOTAL 8$32,078$798$9,365$0$0$42,241$3,565$0$5,164$50,970$92 9COOLING WATER SYSTEM$5,524$4,298$3,854$0$0$13,677$1,137$0$2,106$16,920$30 10ASH/SPENT SORBENT HANDLING SYS

$0$0$0$0$0$0$0$0$0$0$0 11ACCESSORY ELECTRIC PLANT$16,639$3,671$8,860$0$0$29,170$2,237$0$3,330$34,737$63 12INSTRUMENTATION & CONTROL$5,778$593$4,801$0$0$11,173$930$0$1,387$13,490$24 13IMPROVEMENTS TO SITE$1,722$935$4,582$0$0$7,238$640$0$1,576$9,455$17 14BUILDINGS & STRUCTURES

$0$4,155$4,417$0$0$8,571$697$0$1,390$10,658$19

TOTAL COST$193,680$20,581$53,339$0$0$267,599$22,400$0$34,366$324,365$584TOTAL PLANT COST

SUMMARY

Cost and Performance Baseline for Fossil Energy Plants 471 Exhibit 5-14 Case 13 Total Plant Cost Details AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING1.1Coal Receive & Unload

$0$0$0$0$0$0$0$0$0$0$01.2Coal Stackout & Reclaim

$0$0$0$0$0$0$0$0$0$0$01.3Coal Conveyors & Yd Crush

$0$0$0$0$0$0$0$0$0$0$01.4Other Coal Handling

$0$0$0$0$0$0$0$0$0$0$01.5Sorbent Receive & Unload

$0$0$0$0$0$0$0$0$0$0$01.6Sorbent Stackout & Reclaim

$0$0$0$0$0$0$0$0$0$0$01.7Sorbent Conveyors

$0$0$0$0$0$0$0$0$0$0$01.8Other Sorbent Handling

$0$0$0$0$0$0$0$0$0$0$01.9Coal & Sorbent Hnd.Foundations

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 1.

$0$0$0$0$0$0$0$0$0$0$0 2COAL & SORBENT PREP & FEED2.1Coal Crushing & Drying

$0$0$0$0$0$0$0$0$0$0$02.2Prepared Coal Storage & Feed

$0$0$0$0$0$0$0$0$0$0$02.3Slurry Prep & Feed

$0$0$0$0$0$0$0$0$0$0$02.4Misc.Coal Prep & Feed

$0$0$0$0$0$0$0$0$0$0$02.5Sorbent Prep Equipment

$0$0$0$0$0$0$0$0$0$0$02.6Sorbent Storage & Feed

$0$0$0$0$0$0$0$0$0$0$02.7Sorbent Injection System

$0$0$0$0$0$0$0$0$0$0$02.8Booster Air Supply System

$0$0$0$0$0$0$0$0$0$0$02.9Coal & Sorbent Feed Foundation

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 2.

$0$0$0$0$0$0$0$0$0$0$0 3FEEDWATER & MISC. BOP SYSTEMS3.1Feedwater System$2,426$2,499$2,055$0$0$6,980$576$0$1,133$8,690$163.2Water Makeup & Pretreating $1,466$153$766$0$0$2,384$203$0$517$3,105$63.3Other Feedwater Subsystems$1,106$374$314$0$0$1,794$144$0$291$2,229$43.4Service Water Systems

$173$357$1,157$0$0$1,687$147$0$367$2,201$43.5Other Boiler Plant Systems$1,162$450$1,043$0$0$2,655$225$0$432$3,313$63.6Natural Gas, incl. pipeline$14,667$505$440$0$0$15,612$1,323$0$2,540$19,476$353.7Waste Treatment Equipment

$529$0$302$0$0$831$72$0$181$1,084$23.8Misc. Equip.(cranes,AirComp.,Comm.)

$915$122$439$0$0$1,477$128$0$321$1,925$3SUBTOTAL 3.$22,444$4,461$6,516$0$0$33,421$2,819$0$5,782$42,022$76 4GASIFIER & ACCESSORIES4.1Gasifier, Syngas Cooler & Auxiliaries

$0$0$0$0$0$0$0$0$0$0$04.2Syngas Cooling

$0$0$0$0$0$0$0$0$0$0$04.3ASU/Oxidant Compression

$0$0$0$0$0$0$0$0$0$0$04.4LT Heat Recovery & FG Saturation

$0$0$0$0$0$0$0$0$0$0$04.5Misc. Gasification Equipment

$0$0$0$0$0$0$0$0$0$0$04.6Other Gasification Equipment

$0$0$0$0$0$0$0$0$0$0$04.8Major Component Rigging

$0$0$0$0$0$0$0$0$0$0$04.9Gasification Foundations

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 4.

$0$0$0$0$0$0$0$0$0$0$0 Cost and Performance Baseline for Fossil Energy Plants 472 Exhibit 5-14 Case 13 Total Plant Cost Details (Continued) AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 5AGAS CLEANUP & PIPING5A.1MDEA-LT AGR

$0$0$0$0$0$0$0$0$0$0$05A.2Elemental Sulfur Plant

$0$0$0$0$0$0$0$0$0$0$05A.3Mercury Removal

$0$0$0$0$0$0$0$0$0$0$05A.4COS Hydrolysis

$0$0$0$0$0$0$0$0$0$0$05A.5Blowback Gas Systems

$0$0$0$0$0$0$0$0$0$0$05A.6Fuel Gas Piping

$0$0$0$0$0$0$0$0$0$0$05A.9HGCU Foundations

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 5.

$0$0$0$0$0$0$0$0$0$0$0 5BCO2 REMOVAL & COMPRESSION5B.1CO2 Removal System

$0$0$0$0$0$0$0$0$0$0$05B.2CO2 Compression & Drying

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 5.

$0$0$0$0$0$0$0$0$0$0$0 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine Generator$75,294$0$4,804$0$0$80,098$6,800$0$8,690$95,589$1726.2Combustion Turbine Accessories

$0$0$0$0$0$0$0$0$0$0$06.3Compressed Air Piping

$0$0$0$0$0$0$0$0$0$0$06.9Combustion Turbine Foundations

$0$719$744$0$0$1,462$122$0$317$1,901$3SUBTOTAL 6.$75,294$719$5,548$0$0$81,561$6,922$0$9,007$97,490$176 7HRSG, DUCTING & STACK7.1Heat Recovery Steam Generator$32,958$0$4,279$0$0$37,237$3,170$0$4,041$44,448$807.2SCR System$1,243$522$733$0$0$2,498$215$0$407$3,120$67.3Ductwork$0$0$0$0$0$0$0$0$0$0$07.4Stack$0$0$0$0$0$0$0$0$0$0$07.9HRSG,Duct & Stack Foundations

$0$428$385$0$0$813$68$0$176$1,057$2SUBTOTAL 7.$34,200$950$5,397$0$0$40,548$3,453$0$4,624$48,624$88 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$23,774$0$3,855$0$0$27,630$2,374$0$3,000$33,005$598.2Turbine Plant Auxiliaries

$161$0$369$0$0$530$46$0$58$634$18.3Condenser & Auxiliaries$4,108$0$1,226$0$0$5,334$457$0$579$6,370$118.4Steam Piping$4,035$0$2,653$0$0$6,688$513$0$1,080$8,281$158.9TG Foundations

$0$798$1,261$0$0$2,059$175$0$447$2,680$5SUBTOTAL 8.$32,078$798$9,365$0$0$42,241$3,565$0$5,164$50,970$92 9COOLING WATER SYSTEM9.1Cooling Towers$3,880$0$496$0$0$4,377$373$0$475$5,224$99.2Circulating Water Pumps$1,142$0$63$0$0$1,205$91$0$130$1,425$39.3Circ.Water System Auxiliaries

$93$0$12$0$0$105$9$0$11$126$09.4Circ.Water Piping

$0$2,713$657$0$0$3,370$272$0$546$4,189$89.5Make-up Water System

$229$0$305$0$0$534$46$0$87$667$19.6Component Cooling Water Sys

$180$215$143$0$0$539$45$0$88$672$19.9Circ.Water System Foundations

$0$1,370$2,177$0$0$3,547$301$0$770$4,618$8SUBTOTAL 9.$5,524$4,298$3,854$0$0$13,677$1,137$0$2,106$16,920$30 Cost and Performance Baseline for Fossil Energy Plants 473 Exhibit 5-14 Case 13 Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 10ASH/SPENT SORBENT HANDLING SYS10.1Slag Dewatering & Cooling

$0$0$0$0$0$0$0$0$0$0$010.2Gasifier Ash Depressurization

$0$0$0$0$0$0$0$0$0$0$010.3Cleanup Ash Depressurization

$0$0$0$0$0$0$0$0$0$0$010.4High Temperature Ash Piping

$0$0$0$0$0$0$0$0$0$0$010.5Other Ash Recovery Equipment

$0$0$0$0$0$0$0$0$0$0$010.6Ash Storage Silos

$0$0$0$0$0$0$0$0$0$0$010.7Ash Transport & Feed Equipment

$0$0$0$0$0$0$0$0$0$0$010.8Misc. Ash Handling Equipment

$0$0$0$0$0$0$0$0$0$0$010.9Ash/Spent Sorbent Foundation

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 10.

$0$0$0$0$0$0$0$0$0$0$0 11ACCESSORY ELECTRIC PLANT11.1Generator Equipment$4,068$0$2,444$0$0$6,513$552$0$530$7,594$1411.2Station Service Equipment$1,208$0$102$0$0$1,310$108$0$106$1,525$311.3Switchgear & Motor Control $1,489$0$253$0$0$1,742$145$0$189$2,076$411.4Conduit & Cable Tray

$0$712$2,194$0$0$2,905$251$0$474$3,630$711.5Wire & Cable

$0$2,266$1,391$0$0$3,657$236$0$584$4,477$811.6Protective Equipment

$0$563$1,916$0$0$2,480$217$0$270$2,966$511.7Standby Equipment

$103$0$94$0$0$197$17$0$21$235$011.8Main Power Transformers$9,770$0$146$0$0$9,916$673$0$1,059$11,648$2111.9Electrical Foundations

$0$130$319$0$0$449$38$0$98$585$1SUBTOTAL 11.$16,639$3,671$8,860$0$0$29,170$2,237$0$3,330$34,737$63 12INSTRUMENTATION & CONTROL12.1IGCC Control Equipmentw/4.1$0w/4.1$0$0$0$0$0$0$0$012.2Combustion Turbine Controlw/6.1$0w/6.1$0$0$0$0$0$0$0$012.3Steam Turbine Controlw/8.1$0w/8.1$0$0$0$0$0$0$0$012.4Other Major Component Control

$735$0$458$0$0$1,193$101$0$194$1,488$312.5Signal Processing Equipmentw/12.7$0w/12.7$0$0$0$0$0$0$0$012.6Control Boards,Panels & Racks

$220$0$132$0$0$351$30$0$57$438$112.7Computer & Accessories$3,514$0$105$0$0$3,619$298$0$392$4,308$812.8Instrument Wiring & Tubing

$0$593$1,134$0$0$1,727$130$0$279$2,136$412.9Other I & C Equipment$1,310$0$2,972$0$0$4,282$372$0$465$5,120$9SUBTOTAL 12.$5,778$593$4,801$0$0$11,173$930$0$1,387$13,490$24 Cost and Performance Baseline for Fossil Energy Plants 474 Exhibit 5-14 Case 13 Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 13IMPROVEMENTS TO SITE13.1Site Preparation

$0$92$1,837$0$0$1,929$172$0$420$2,520$513.2Site Improvements

$0$843$1,047$0$0$1,890$167$0$411$2,469$413.3Site Facilities$1,722$0$1,698$0$0$3,419$302$0$744$4,465$8SUBTOTAL 13.$1,722$935$4,582$0$0$7,238$640$0$1,576$9,455$17 14BUILDINGS & STRUCTURES14.1Combustion Turbine Area

$0$236$125$0$0$361$28$0$58$447$114.2Steam Turbine Building

$0$1,972$2,626$0$0$4,598$378$0$746$5,722$1014.3Administration Building

$0$455$308$0$0$763$61$0$124$947$214.4Circulation Water Pumphouse

$0$152$75$0$0$227$18$0$37$281$114.5Water Treatment Buildings

$0$316$288$0$0$605$49$0$98$752$114.6Machine Shop

$0$394$252$0$0$647$51$0$105$803$114.7Warehouse

$0$255$154$0$0$408$32$0$66$507$114.8Other Buildings & Structures

$0$76$56$0$0$132$11$0$21$164$014.9Waste Treating Building & Str.

$0$298$533$0$0$831$69$0$135$1,036$2SUBTOTAL 14.

$0$4,155$4,417$0$0$8,571$697$0$1,390$10,658$19TOTAL COST$193,680$20,581$53,339$0$0$267,599$22,400$0$34,366$324,365$584Owner's CostsPreproduction Costs6 Months All Labor$2,880$51 Month Maintenance Materials

$388$11 Month Non-fuel Consumables

$146$01 Month Waste Disposal

$0$025% of 1 Months Fuel Cost at 100% CF$4,509$82% of TPC$6,487$12Total$14,410$26Inventory Capital60 day supply of consumables at 100% CF

$180$00.5% of TPC (spare parts)$1,622$3Total$1,802$3Initial Cost for Catalyst and Chemicals

$0$0Land$300$1Other Owner's Costs$48,655$88Financing Costs$8,758$16Total Overnight Costs (TOC)$398,290$718TASC Multiplier(IOU, low-risk, 33 year)1.075Total As-Spent Cost (TASC)$428,162$771 Cost and Performance Baseline for Fossil Energy Plants 475 Exhibit 5-15 Case 13 Initial and Annual Operating and Maintenance Cost Summary INITIAL & ANNUAL O&M EXPENSESCost Base (Jun):

2007Case 13 - 1x555 MWnet 2x1 7FB NGCCHeat Rate-net (Btu/kWh):6,798 MWe-net: 555 Capacity Factor (%):

85OPERATING & MAINTENANCE LABOROperating Labor Operating Labor Rate(base):34.65$/hour Operating Labor Burden:30.00% of base Labor O-H Charge Rate:25.00% of laborTotal Operating Labor Requirements(O.J.)per Shift:1 unit/mod. Plant Skilled Operator1.01.0 Operator2.02.0 Foreman1.01.0 Lab Tech's, etc.1.01.0 TOTAL-O.J.'s5.05.0Annual CostAnnual Unit Cost

$$/kW-netAnnual Operating Labor Cost$1,972,971$3.554Maintenance Labor Cost$2,635,374$4.748Administrative & Support Labor$1,152,086$2.076Property Taxes and Insurance$6,487,309$11.687TOTAL FIXED OPERATING COSTS$12,247,740$22.065VARIABLE OPERATING COSTS$/kWh-netMaintenance Material Cost$3,953,061$0.00096ConsumablesConsumptionUnit Initial Fill Initial Fill /Day Cost CostWater (/1000 gallons)0.001700.641.08$0$570,718$0.00014ChemicalsMU & WT Chem. (lbs)0.0010131.920.17$0$544,027$0.00013MEA Solvent (ton)0.000.002249.89$0$0$0.00000Activated Carbon (lb)0.000.001.05$0$0$0.00000Corrosion Inhibitor0.000.000.00$0$0$0.00000SCR Catalyst (m3)w/equip.0.075775.94$0$129,612$0.00003Ammonia (19% NH3) ton0.006.06129.80$0$244,142$0.00006Subtotal Chemicals

$0$917,781$0.00022OtherSupplemental Fuel (MBtu)0.000.000.00$0$0$0.00000Gases, N2 etc.(/100scf)0.000.000.00$0$0$0.00000L.P. Steam (/1000 pounds)0.000.000.00$0$0$0.00000Subtotal Other

$0$0$0.00000Waste DisposalFlyash (ton)0.000.000.00$0$0$0.00000Bottom Ash (ton)0.000.000.00$0$0$0.00000Subtotal Waste Disposal

$0$0$0.00000By-productsSulfur (tons)0.000.000.00$0$0$0.00000Subtotal By-products

$0$0$0.00000TOTAL VARIABLE OPERATING COSTS

$0$5,441,560$0.00132Fuel (MMBtu) 090,5626.55$0$183,973,460$0.04451 Cost and Performance Baseline for Fossil Energy Plants 476 5.2.7 The plant configuration for Case 14 is the same as Case 13 with the exception that the Econamine CDR technology was added for CO 2 capture. The nominal net output decreases to 4 74 MW because, like the IGCC cases, the CT fixes the output and the CDR facility significantly increases the auxiliary power load and reduces the steam turbine output

. Case 14 - NGCC with CO 2 Capture The process description for Case 14 is essentially the same as Case 13 with one notable exception, the addition of CO 2 capture. A BFD and stream tables for Case 14 are shown in Exhibit 5-16 and Exhibit 5-17, respectively. Since the CDR facility process description was provided in Section 5.1.5, it is not repeated here.

5.2.8 The Case 14 modeling assumptions were presented previously in Section Case 14 Performance Results 5.2.2. The plant produces a net output of 4 74 MW at a net plant efficiency of 42.8 percent (HHV basis). Overall plant performance is summarized in Exhibit 5-18 , which includes auxiliary power requirements. The CDR facility, including CO 2 compression, accounts for over 6 6 percent of the auxiliary plant load. The CWS (CWPs and cooling tower fan) accounts for nearly 18 percent of the auxiliary load, largely due to the high cooling water demand of the CDR facility.

Cost and Performance Baseline for Fossil Energy Plants 477 Exhibit 5-16 Case 14 Block Flow Diagram, NGCC with CO 2 Capture Cost and Performance Baseline for Fossil Energy Plants 478 Exhibit 5-17 Case 14 Stream Table, NGCC with CO 2 Capture 1 2 3 4 5 6 7 8 9 10 11V-L Mole Fraction Ar0.00920.00000.00890.00890.00980.00000.00000.00000.00000.00000.0000 CH 40.00000.93100.00000.00000.00000.00000.00000.00000.00000.00000.0000 C 2 H 60.00000.03200.00000.00000.00000.00000.00000.00000.00000.00000.0000 C 3 H 80.00000.00700.00000.00000.00000.00000.00000.00000.00000.00000.0000 C 4 H100.00000.00400.00000.00000.00000.00000.00000.00000.00000.00000.0000 CO0.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 CO 20.00030.01000.04040.04040.00450.98931.00000.00000.00000.00000.0000 H 2 O0.00990.00000.08670.08670.03390.01070.00001.00001.00001.00001.0000 N 20.77320.01600.74320.74320.81870.00000.00000.00000.00000.00000.0000 O 20.20740.00000.12090.12090.13320.00000.00000.00000.00000.00000.0000 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000Total1.00001.00001.00001.00001.00001.00001.00001.00001.00001.00001.0000V-L Flowrate (kgmol/hr)109,3234,380113,831113,831103,3334,1854,14017,88717,88721,58913,482V-L Flowrate (kg/hr)3,154,73575,9013,230,6363,230,6362,933,892183,013182,203322,243322,243388,927242,889Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0 0 0Temperature (°C) 15 38 629 143 30 21 51 152 151 566 38Pressure (MPa, abs)0.103.100.110.100.100.1615.270.510.4916.650.01Enthalpy (kJ/kg)

A30.2346.30835.81288.6183.9626.65-164.902,746.79635.723,472.36160.61Density (kg/m 3)1.222.20.40.81.12.9653.52.7915.847.7992.9V-L Molecular Weight28.85717.32828.38128.38128.39343.73144.01018.01518.01518.01518.015V-L Flowrate (lbmol/hr)241,0169,657250,954250,954227,8099,2269,12739,43539,43547,59529,724V-L Flowrate (lb/hr)6,955,000167,3337,122,3337,122,3336,468,125403,474401,689710,425710,425857,437535,480Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0 0 0Temperature (°F) 59 1001,163 290 85 69 124 306 3041,050 101Pressure (psia)14.7450.015.214.714.723.52,214.773.571.02,414.71.0Enthalpy (Btu/lb)

A13.019.9359.3124.136.111.5-70.91,180.9273.31,492.869.1Density (lb/ft 3)0.0761.3840.0250.0520.0710.18340.8000.16957.1722.97761.982A - Reference conditions are 32.02 F & 0.089 PSIA Cost and Performance Baseline for Fossil Energy Plants 479 Exhibit 5-18 Case 14 Plant Performance Summary POWER

SUMMARY

(Gross Power at Generator Terminals, kWe)

Gas Turbine Power 362,200 Steam Turbine Power 148,800 TOTAL POWER, kWe 511,000 AUXILIARY LOAD

SUMMARY

, kWe Condensate Pumps 80 Boiler Feedwater Pumps 2,710 Amine System Auxiliaries 9,600 CO 2 Compression 15,200 Circulating Water Pump 4,360 Ground Water Pumps 360 Cooling Tower Fans 2,250 SCR 10 Gas Turbine Auxiliaries 700 Steam Turbine Auxiliaries 100 Miscellaneous Balance of Plant 1 500 Transformer Losses 1,560 TOTAL AUXILIARIES, kWe 37,430 NET POWER, kWe 473,570 Net Plant Efficiency (HHV) 42.8% Net Plant Efficiency (LHV) 47.5% Net Plant Heat Rate (HHV), kJ/kWh (Btu/kWh

) 8,406 (7,968)

Net Plant Heat Rate (LHV), kJ/kWh (Btu/kWh

) 7,579 (7,184)

CONDENSER COOLING DUTY, 10 6 kJ/h r (10 6 Btu/h r) 528 (500) CONSUMABLES Natural Gas Feed Flow, kg/hr (lb/hr) 75,901 (167,333)

Thermal Input (HHV), kW th 1,105,812 Thermal Input (LHV) , kW th 997,032 Raw Water Withdrawal, m 3/min (gpm) 15.1 (3,980)

Raw Water Consumption, m 3/min (gpm) 11.3 (2,985)

1. Includes plant control systems, lighting, HVAC

, and miscellaneous low voltage loads

Cost and Performance Baseline for Fossil Energy Plants 480 The environmental targets for emissions of NOx, SO 2 , and PM were presented in Section 2.4. A summary of the plant air emissions for Case 14 is presented in Environmental Performance Exhibit 5-19. Exhibit 5-19 Case 14 Air Emissions kg/GJ (lb/10 6 Btu) Tonne/year (ton/year) 85% CF kg/MWh (lb/MWh) SO 2 Negligible Negligible Negligible NOx 0.004 (0.00

8) 105 (115) 0.027 (0.061) Particulates Negligible Negligible Negligible Hg Negligible Negligible Negligible CO 2 5.1 (11.8) 150,743 (166,165) 40 (87) CO 2 1 4 3 (94) 1 CO 2 emissions based on net power instead of gross power The operation of the modern, state

-of-the-art GT fueled by natural gas, coupled to a HRSG, results in very low levels of NOx emissions and negligible levels of SO 2, particulate

, and Hg emissions. As noted in Section 2.4, if the fuel contains the maximum amount of sulfur compounds allowed in pipeline natural gas, the NGCC SO 2 emissions would be 21 tonnes/yr (23 tons/yr) at 85 percent CF, or 0.00195 lb/MMBtu.

The low level of NOx production (2.5 ppmvd at 15 percent O

2) is achieved by utilizing a dry LNB coupled with an SCR system.

Ninety percent of the CO 2 in the FG is removed in CDR facility.

The carbon balance for the plant is shown in Exhibit 5-20. The carbon input to the plant consists of carbon in the natural gas in addition to carbon in the CT air. Carbon leaves the plant as CO 2 in the stack gas and the captured CO 2 product. The CO 2 capture efficiency is defined by the following fraction:

(CO 2 Product Carbon)/(Natural Gas Carbon)*100 or (109,628)/(120,863)

100 or 90.7 percent Exhibit 5-20 Case 14 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Natural Gas 54,822 (120,863)

Stack Gas 5,525 (12,181)

Air (CO 2) 429 (946) CO 2 Product 49,726 (109,628)

Total 55,251 (121,808)

Cost and Performance Baseline for Fossil Energy Plants 481 A sulfur balance is not included for Case 14 because the sulfur concentration of natural gas is negligible.

Consequently, sulfur emissions are also negligible, as shown in Exhibit 5-19, despite the use of no sulfur control technology.

Exhibit 5-21 shows the overall water balance for the plant. The exhibit is presented in an identical manner as was for Case 13.

Exhibit 5-21 Case 14 Water Balance Water Use Water Demand, m 3/min (gpm) Internal Recycle, m 3/min (gpm) Raw Water Withdrawal, m 3/min (gpm) Process Water Discharge, m 3/min (gpm) Raw Water Consumption, m 3/min (gpm)

Econamine 0.04 (12) 0.0 (0) 0.04 (12) 0.0 (0) 0.04 (12) Condenser Makeup BFW Makeup 0.1 (23) 0.1 (23) 0.0 (0) 0.1 (23) 0.1 (23) 0.0 (0) 0.1 (23) Cooling Tower BFW Blowdown

Flue Gas Condensate 17.0 (4,477) 2.0 (520) 0.1 (23) 1.9 (497) 15.0 (3,958)

-0.1 (-23) -1.9 (-497) 3.8 (1,007) 11.2 (2,951)

CO 2 Product Condensate 0.03 (8) -0.0 3 (-8) Total 17.1 (4,5 12) 2.0 (52 8) 15.1 (3,9 92) 3.8 (1,007) 11.3 (2,985)

A heat and mass balance diagram is shown for the NGCC in Heat and Mass Balance Diagrams Exhibit 5-22. An overall plant energy balance is provided in tabular form in Exhibit 5-23. The power out is the combined CT and steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 5-18) is calculated by multiplying the power out by a combined generator efficiency of 98.3 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 CO 2 compressor intercooler load is included in the Econamine process heat out stream.

Cost and Performance Baseline for Fossil Energy Plants 482 This page intentionally left blank

Cost and Performance Baseline for Fossil Energy Plants 483 Exhibit 5-22 Case 14 Heat and Mass Balance, NGCC with CO 2 Capture N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA H EAT AND M ATERIAL F LOW D IAGRAM P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Nitrogen Natural Gas Carbon Dioxide Water Steam P AGES 1 OF 1 N ATURAL GAS COMBINED CYCLE PLANT C ASE 14 2 X ADVANCED F-CLASS GT 2400/1050/1050 DWG. NO.BB-HMB-CS-14-PG-1 Flue Gas 401 , 689 W 123.8 T 2 , 214.7 P CO 2 PRODUCT A MBIENT A IR 1 6 , 955 , 000 W 59.0 T 14.7 P 12.9 H CO 2 COMPRESSION (INTERSTAGE COOLING) & DRYING 403 , 474 W 69.0 T 23.5 P 11.5 H KNOCKOUT WATER 248 , 601 W 85.1 T 14.7 P 8.6 H Gross Plant Power

511 MWe Auxiliary Load

37 MWe Net Plant Power

474 MWe Net Plant Efficiency , HHV: 42.8%Net Plant Heat Rate

7 , 968 BTU/KWe A DVANCED F C LASS G AS T URBINES COMBUSTOR N ATURAL GAS 167 , 333 W 100.0 T 450.0 P 19.9 H 2 6 , 468 , 125 W 85.1 T 14.7 P 36.0 H 7 , 122 , 333 W 289.7 T 14.7 P 124.0 H 7 , 122 , 333 W 1 , 163.5 T 15.2 P 359.3 H GENERATOR CONDENSATE PUMPS 8 , 801 W 1 , 302 W 101.3 T 130.0 P 69.5 H 535 , 480 W 101.1 T 1.0 P 69.1 H 5 1 , 400 W 581.0 T 75.0 P 1 , 321.3 H 1 , 017 , 200 W 641.4 T 75.0 P 1 , 351.1 H 512 , 174 W 622.2 T 75.0 P 1 , 341.7 H 512 , 174 W 101.1 T 1.0 P 1 , 029.8 H HOT WELL CONDENSER S TACK 4 REBOILER CONDENSATE CONDENSATE PUMPS S TEAM T URBINE MAKEUP 11 , 337 W 59.0 T 14.7 P 27.1 H AIR INLET FILTER 3 HP PUMP 535 , 480 W 253.0 T 100.0 P 221.9 H BLOWDOWN 94 , 141 W 300.1 T 95.0 P 269.4 H 173 , 467 W 300.7 T 400.0 P 270.7 H 866 , 098 W 305.3 T 2 , 540.0 P 279.3 H 11 , 337 W STRIPPER ABSORBER FLUE GAS ACID GAS ECONAMINE FG

+BLOWER 598 , 226 W 641.4 T 75.0 P 1 , 351.1 H WATER 1 , 785 W 100.0 T 14.7 P GLAND SEAL CONDENSER 1 , 400 W 212.0 T 14.7 P 179.9 H LP TURBINE S TEAM TO REBOILER 710 , 425 W 306.2 T 73.5 P 1 , 180.9 H 9 , 569 W 535 , 480 W 106.8 T 120.0 P 75.0 H Three Pressure Heat Recovery Steam Generator (HRSG)829 , 777 W 1 , 055.0 T 360.0 P 1 , 553.4 H A A 171 , 732 W 1 , 055.0 T 360.0 P 1 , 553.4 H HOT REHEAT C OLD R EHEAT 829 , 777 W 587.9 T 390.0 P 1 , 300.6 H STEAM SEAL REGULATOR 93 , 200 W 537.0 T 80.0 P 1 , 299.1 H 16 , 993 W 970.1 T 1 , 850.0 P 1 , 459.8 H HP TURBINE IP TURBINE 852 , 917 W 2 , 654 W 1 , 050.0 T 2 , 414.7 P 1 , 492.8 H 1 , 018 , 502 W MAIN STEAM 857 , 437 W 1 , 050.0 T 2 , 414.7 P 1 , 492.8 H 6 7 8 9 10 10 , 969 W 866 W IP STEAM 598 , 226 W 303.9 T 73.5 P 273.3 H IP PUMP LP PUMP 710 , 425 W 303.9 T 71.0 P 273.3 H DOE/NETL SC PC P LANT C ASE 14 11 Cost and Performance Baseline for Fossil Energy Plants 484 This page intentionally left blank

Cost and Performance Baseline for Fossil Energy Plants 485 Exhibit 5-23 Case 14 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)

Natural Gas 3,981 (3,773) 2.7 (2.5) 3,984 (3,776)

GT Air 95.4 (90.4) 95 (90) Raw Water Withdrawal 56.7 (53.7) 57 (54) Auxiliary Power 0.0 (0.0) 135 (128) 135 (128) Totals 3,981 (3,773) 154.7 (146.6) 135 (128) 4,270 (4,048)

Heat Out GJ/hr (MMBtu/hr)

CO 2 -30.0 (-28.5) -30 (-28) Cooling Tower Blowdown 28.3 (26.8) 28 (27) Econamine Losses 1,010 (957) 1,010 (957)

CO 2 Compression Intercooling 84.9 (80.5) 85 (81) Stack Gas 246 (233) 246 (233) Condenser 532 (504) 532 (504) Process Losses*

560 (530) 560 (530) Power 1,840 (1,744) 1,840 (1,744)

Totals 0 (0) 2,431 (2,304) 1,840 (1,744) 4,270 (4,048)

Process Losses are calculated by difference and reflect various boiler, turbine, and other heat and work losses. Aspen flowsheet balance is within 0.5 percent.

Cost and Performance Baseline for Fossil Energy Plants 486 5.2.9 Major equipment items for the NGCC plant with CO 2 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 Case 14 Major Equipment List 5.2.10. 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 COAL AND SORBENT HANDLING N/A ACCOUNT 2 FUEL AND SORBENT PREPARATION AND FEED Equipment No.DescriptionTypeOperating Qty.Spares 1Gas PipelineUnderground, coated carbon steel, wrapped cathodic protection16 km (10 mile)0 2Gas Metering Station

--1 0Design Condition63 m3/min @ 3.1 MPa(2,216 acfm @ 450 psia)41 cm (16 in) standard wall pipe63 m3/min (2,216 acfm)

Cost and Performance Baseline for Fossil Energy Plants 487 ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment No.DescriptionTypeOperating Qty.Spares 1Demineralized Water Storage TankVertical, cylindrical, outdoor 2 0 2Condensate PumpsVertical canned 2 1 4Auxiliary BoilerShop fabricated, water tube 1 0 5Service Air CompressorsFlooded Screw 2 1 6Instrument Air DryersDuplex, regenerative 2 1 7Closed Cycle Cooling Heat ExchangersPlate and frame 2 0 8Closed Cycle Cooling Water PumpsHorizontal centrifugal 2 1 9Engine-Driven Fire PumpVertical turbine, diesel engine 1 1 10Fire Service Booster PumpTwo-stage horizontal centrifugal 1 1 11Raw Water PumpsStainless steel, single suction 2 1 12Filtered Water PumpsStainless steel, single suction 2 1 13Filtered Water TankVertical, cylindrical 1 0 14Makeup Water DemineralizerMulti-media filter, cartridge filter, RO membrane assembly and electro-deionization unit 1 0 15Liquid Waste Treatment System 1 0 1143,847 liter (38,000 gal)341 lpm (90 gpm)10 years, 24-hour storm3,785 lpm @ 107 m H2O(1,000 gpm @ 350 ft H2O)2,650 lpm @ 76 m H2O(700 gpm @ 250 ft H2O)8,328 lpm @ 18 m H2O(2,200 gpm @ 60 ft H2O)151 lpm @ 49 m H2O(40 gpm @ 160 ft H2O)13 m3/min (450 scfm) 2HP water: 3,634 lpm @ 2,103 m H2O (960 gpm @ 6,900 ft H2O)IP water: 719 lpm @ 283 m H2O (190 gpm @ 930 ft H2O)18,144 kg/h, 2.8 MPa, 343°C(40,000 lb/h, 400 psig, 650°F)13 m3/min @ 0.7 MPa(450 scfm @ 100 psig)LP water: 379 lpm @ 24.4 m H2O (100 gpm @ 80 ft H2O) 3Boiler Feedwater PumpHorizontal, split case, multi-stage, centrifugal, with interstage bleed for IP and LP feedwaterDesign Condition677,594 liters (179,000 gal)2,233 lpm @ 110 m H2O(590 gpm @ 360 ft H2O)13 MMkJ/hr (13 MMBtu/hr)5,300 lpm @ 21 m H2O(1,400 gpm @ 70 ft H2O)

Cost and Performance Baseline for Fossil Energy Plants 488 ACCOUNT 4 GASIFIER, BOILER AND ACCESSORIES N/A ACCOUNT 5B CARBON DIOXIDE RECOVERY ACCOUNT 6 COMBUSTION TURBINE GENERATORS AND AUXILIARIES Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Econamine FG PlusAmine-based CO2 capture technology1,776,723 kg/hr (3,917,000 lb/hr) 6.3 wt % CO2 concentration 2 0 2CO2 CompressorIntegrally geared, multi 100,244 kg/hr @ 15.3 MPa (221,000 lb/hr @ 2,215 psia) 2 0Equipment No.DescriptionTypeOperating Qty.Spares 1Gas TurbineAdvanced F class w/ dry low-NOx burner 2 0 2Gas Turbine GeneratorTEWAC 2 0Design Condition180 MW 200 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase Cost and Performance Baseline for Fossil Energy Plants 489 ACCOUNT 7 WASTE HEAT BOILER, DUCTING, AND STACK Equipment No.DescriptionTypeOperating Qty.Spares 1StackCS plate, type 409SS liner 2 0 3SCR ReactorSpace for spare layer 2 0 4SCR Catalyst

--1 layer 0 5Dilution Air BlowersCentrifugal 2 1 6Ammonia Feed PumpCentrifugal 2 1 7Ammonia Storage TankHorizontal tank 1 0 2 0 2Heat Recovery Steam GeneratorDrum, multi-pressure with economizer section and integral deaerator Reheat steam - 249,852 kg/h, 2.4 MPa/566°C (550,830 lb/h, 345 psig/1,050°F)Design Condition46 m (150 ft) high x6.4 m (21 ft) diameterMain steam - 213,910 kg/h, 16.5 MPa/566°C (471,590 lb/h, 2,400 psig/1,050°F)1,614,791 kg/h (3,560,000 lb/h)Space available for an additional catalyst layer11 m3/min @ 107 cm WG(390 scfm @ 42 in WG)3.8 lpm @ 91 m H2O(1 gpm @ 300 ft H2O)68,138 liter (18,000 gal)

Cost and Performance Baseline for Fossil Energy Plants 490 ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES ACCOUNT 9 COOLING WATER SYSTEM ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING N/A Equipment No.DescriptionTypeOperating Qty.Spares 1Steam TurbineTandem compound, HP, IP, and two-flow LP turbines 1 0 2Steam Turbine GeneratorHydrogen cooled, static excitation 1 0 3Steam BypassOne per HRSG 2 0 4Surface CondenserSingle pass, divided waterbox including vacuum pumps 1 0Design Condition157 MW 16.5 MPa/566°C/566°C (2,400 psig/ 1050°F/1050°F)580 MMkJ/hr, (550 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F)170 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase50% steam flow @ design steam conditionsEquipment No.DescriptionTypeOperating Qty.Spares 1Circulating Water PumpsVertical, wet pit 2 1 2Cooling TowerEvaporative, mechanical draft, multi-cell 1 0Design Condition435,326 lpm @ 30.5 m(115,000 gpm @ 100 ft)11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT 613 MMkJ/hr (582 MMBtu/hr) heat load Cost and Performance Baseline for Fossil Energy Plants 491 ACCOUNT 11 ACCESSORY ELECTRIC PLANT ACCOUNT 12 INSTRUMENTATION AND CONTROL Equipment No.DescriptionTypeOperating Qty.Spares 1CTG TransformerOil-filled 2 0 2STG TransformerOil-filled 1 0 3High Voltage Auxiliary TransformerOil-filled 2 0 4Medium Voltage TransformerOil-filled 1 1 5Low Voltage TransformerDry ventilated 1 1 6CTG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled 2 0 7STG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled 1 0 8Medium Voltage SwitchgearMetal clad 1 1 9Low Voltage SwitchgearMetal enclosed 1 1 10Emergency Diesel GeneratorSized for emergency shutdown 1 0Design Condition24 kV/345 kV, 200 MVA, 3-ph, 60 Hz345 kV/13.8 kV, 8 MVA, 3-ph, 60 Hz24 kV/345 kV, 150 MVA, 3-ph, 60 Hz24 kV, 3-ph, 60 Hz24 kV, 3-ph, 60 Hz4.16 kV, 3-ph, 60 Hz480 V, 3-ph, 60 Hz4.16 kV/480 V, 3 MVA, 3-ph, 60 Hz750 kW, 480 V, 3-ph, 60 Hz24 kV/4.16 kV, 23 MVA, 3-ph, 60 HzEquipment No.DescriptionTypeOperating Qty.Spares 1DCS - Main ControlMonitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) 1 0 3DCS - Data HighwayFiber optic 1 0 1 0Fully redundant, 25% spareDesign ConditionOperator stations/printers and engineering stations/printers 2DCS - ProcessorMicroprocessor with redundant input/outputN/A Cost and Performance Baseline for Fossil Energy Plants 492 5.2.10 The cost estimating methodology was described previously in Section Case 14 - Cost Estimating 2.7. Exhibit 5-24 shows the total plant capital cost summary organized by cost account and Exhibit 5-25 shows a more detailed breakdown of the capital costs. Exhibit 5-26 shows the initial and annual O&M costs. The estimated TOC of the NGCC with CO 2 capture is $1, 497/kW. Process contingency represents 4.0 percent of the TOC and project contingency represents 10.8 percent. The COE, including CO 2 TS&M costs of 3.2 mills/kWh, is 85.9 mills/kWh.

Cost and Performance Baseline for Fossil Energy Plants 493 Exhibit 5-24 Case 14 Total Plant Cost Summary Client: USDOE/NETLReport Date:2010-Jan-14Project: Bituminous Baseline StudyCase: Case 14 - 1x475 MWnet 2x1 7FB NGCC w/ CO2 CapturePlant Size: 473.6MW,netEstimate Type: ConceptualCost Base (Jun) 2007($x1000)AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING

$0$0$0$0$0$0$0$0$0$0$0 2COAL & SORBENT PREP & FEED

$0$0$0$0$0$0$0$0$0$0$0 3FEEDWATER & MISC. BOP SYSTEMS$23,934$4,864$7,962$0$0$36,760$3,106$0$6,447$46,312$98 4GASIFIER & ACCESSORIES4.1Gasifier, Syngas Cooler & Auxiliaries

$0$0$0$0$0$0$0$0$0$0$04.2Syngas Cooling

$0$0$0$0$0$0$0$0$0$0$04.3ASU/Oxidant Compression

$0$0$0$0$0$0$0$0$0$0$04.4-4.9Other gasification Equipment

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 4

$0$0$0$0$0$0$0$0$0$0$0 5AGAS CLEANUP & PIPING

$0$0$0$0$0$0$0$0$0$0$0 5BCO2 REMOVAL & COMPRESSION$121,638$0$37,053$0$0$158,691$13,593$27,994$40,056$240,334$507 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine Generator$75,294$0$4,804$0$0$80,098$6,800$0$8,690$95,589$2026.2-6.9Combustion Turbine Other

$0$719$744$0$0$1,462$122$0$317$1,901$4SUBTOTAL 6$75,294$719$5,548$0$0$81,561$6,922$0$9,007$97,490$206 7HRSG, DUCTING & STACK7.1Heat Recovery Steam Generator$32,958$0$4,279$0$0$37,237$3,170$0$4,041$44,448$947.2-7.9SCR System, Ductwork and Stack$1,243$950$1,118$0$0$3,311$282$0$583$4,176$9SUBTOTAL 7$34,201$950$5,397$0$0$40,548$3,453$0$4,624$48,624$103 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$19,229$0$3,465$0$0$22,694$1,951$0$2,465$27,110$578.2-8.9Turbine Plant Auxiliaries and Steam Piping$6,570$637$4,691$0$0$11,898$958$0$1,824$14,680$31SUBTOTAL 8$25,799$637$8,156$0$0$34,592$2,909$0$4,289$41,791$88 9COOLING WATER SYSTEM$8,569$6,296$5,689$0$0$20,554$1,708$0$3,140$25,403$54 10ASH/SPENT SORBENT HANDLING SYS

$0$0$0$0$0$0$0$0$0$0$0 11ACCESSORY ELECTRIC PLANT$20,769$5,564$12,124$0$0$38,458$2,957$0$4,473$45,888$97 12INSTRUMENTATION & CONTROL$6,272$644$5,211$0$0$12,127$1,010$606$1,575$15,318$32 13IMPROVEMENTS TO SITE$1,724$936$4,588$0$0$7,248$641$0$1,578$9,467$20 14BUILDINGS & STRUCTURES

$0$3,982$4,121$0$0$8,103$658$0$1,314$10,075$21

TOTAL COST$318,200$24,594$95,849$0$0$438,642$36,957$28,600$76,502$580,701$1,226TOTAL PLANT COST

SUMMARY

Cost and Performance Baseline for Fossil Energy Plants 494 Exhibit 5-25 Case 14 Total Plant Cost Details AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING1.1Coal Receive & Unload

$0$0$0$0$0$0$0$0$0$0$01.2Coal Stackout & Reclaim

$0$0$0$0$0$0$0$0$0$0$01.3Coal Conveyors & Yd Crush

$0$0$0$0$0$0$0$0$0$0$01.4Other Coal Handling

$0$0$0$0$0$0$0$0$0$0$01.5Sorbent Receive & Unload

$0$0$0$0$0$0$0$0$0$0$01.6Sorbent Stackout & Reclaim

$0$0$0$0$0$0$0$0$0$0$01.7Sorbent Conveyors

$0$0$0$0$0$0$0$0$0$0$01.8Other Sorbent Handling

$0$0$0$0$0$0$0$0$0$0$01.9Coal & Sorbent Hnd.Foundations

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 1.

$0$0$0$0$0$0$0$0$0$0$0 2COAL & SORBENT PREP & FEED2.1Coal Crushing & Drying

$0$0$0$0$0$0$0$0$0$0$02.2Prepared Coal Storage & Feed

$0$0$0$0$0$0$0$0$0$0$02.3Slurry Prep & Feed

$0$0$0$0$0$0$0$0$0$0$02.4Misc.Coal Prep & Feed

$0$0$0$0$0$0$0$0$0$0$02.5Sorbent Prep Equipment

$0$0$0$0$0$0$0$0$0$0$02.6Sorbent Storage & Feed

$0$0$0$0$0$0$0$0$0$0$02.7Sorbent Injection System

$0$0$0$0$0$0$0$0$0$0$02.8Booster Air Supply System

$0$0$0$0$0$0$0$0$0$0$02.9Coal & Sorbent Feed Foundation

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 2.

$0$0$0$0$0$0$0$0$0$0$0 3FEEDWATER & MISC. BOP SYSTEMS3.1Feedwater System$2,426$2,499$2,055$0$0$6,980$576$0$1,133$8,690$183.2Water Makeup & Pretreating $2,123$222$1,109$0$0$3,453$294$0$750$4,497$93.3Other Feedwater Subsystems$1,106$374$314$0$0$1,794$144$0$291$2,229$53.4Service Water Systems

$251$517$1,676$0$0$2,444$213$0$531$3,188$73.5Other Boiler Plant Systems$1,683$652$1,511$0$0$3,846$326$0$626$4,798$103.6Natural Gas, incl. pipeline$14,652$476$415$0$0$15,543$1,317$0$2,529$19,389$413.7Waste Treatment Equipment

$766$0$437$0$0$1,203$105$0$262$1,569$33.8Misc. Equip.(cranes,AirComp.,Comm.)

$927$124$445$0$0$1,496$129$0$325$1,951$4SUBTOTAL 3.$23,934$4,864$7,962$0$0$36,760$3,106$0$6,447$46,312$98 4GASIFIER & ACCESSORIES4.1Gasifier, Syngas Cooler & Auxiliaries

$0$0$0$0$0$0$0$0$0$0$04.2Syngas Cooling

$0$0$0$0$0$0$0$0$0$0$04.3ASU/Oxidant Compression

$0$0$0$0$0$0$0$0$0$0$04.4LT Heat Recovery & FG Saturation

$0$0$0$0$0$0$0$0$0$0$04.5Misc. Gasification Equipment

$0$0$0$0$0$0$0$0$0$0$04.6Other Gasification Equipment

$0$0$0$0$0$0$0$0$0$0$04.8Major Component Rigging

$0$0$0$0$0$0$0$0$0$0$04.9Gasification Foundations

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 4.

$0$0$0$0$0$0$0$0$0$0$0 Cost and Performance Baseline for Fossil Energy Plants 495 Exhibit 5-25 Case 14 Total Plant Cost Details (Continued) AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 5AGAS CLEANUP & PIPING5A.1MDEA-LT AGR

$0$0$0$0$0$0$0$0$0$0$05A.2Elemental Sulfur Plant

$0$0$0$0$0$0$0$0$0$0$05A.3Mercury Removal

$0$0$0$0$0$0$0$0$0$0$05A.4COS Hydrolysis

$0$0$0$0$0$0$0$0$0$0$05A.5Blowback Gas Systems

$0$0$0$0$0$0$0$0$0$0$05A.6Fuel Gas Piping

$0$0$0$0$0$0$0$0$0$0$05A.9HGCU Foundations

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 5.

$0$0$0$0$0$0$0$0$0$0$0 5BCO2 REMOVAL & COMPRESSION5B.1CO2 Removal System$107,387$0$32,583$0$0$139,970$11,989$27,994$35,991$215,943$4565B.2CO2 Compression & Drying$14,251$0$4,471$0$0$18,721$1,604$0$4,065$24,390$52SUBTOTAL 5.$121,638$0$37,053$0$0$158,691$13,593$27,994$40,056$240,334$507 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine Generator$75,294$0$4,804$0$0$80,098$6,800$0$8,690$95,589$2026.2Combustion Turbine Accessories

$0$0$0$0$0$0$0$0$0$0$06.3Compressed Air Piping

$0$0$0$0$0$0$0$0$0$0$06.9Combustion Turbine Foundations

$0$719$744$0$0$1,462$122$0$317$1,901$4SUBTOTAL 6.$75,294$719$5,548$0$0$81,561$6,922$0$9,007$97,490$206 7HRSG, DUCTING & STACK7.1Heat Recovery Steam Generator$32,958$0$4,279$0$0$37,237$3,170$0$4,041$44,448$947.2SCR System$1,243$522$733$0$0$2,498$215$0$407$3,120$77.3Ductwork$0$0$0$0$0$0$0$0$0$0$07.4Stack$0$0$0$0$0$0$0$0$0$0$07.9HRSG,Duct & Stack Foundations

$0$428$385$0$0$813$68$0$176$1,057$2SUBTOTAL 7.$34,201$950$5,397$0$0$40,548$3,453$0$4,624$48,624$103 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$19,229$0$3,465$0$0$22,694$1,951$0$2,465$27,110$578.2Turbine Plant Auxiliaries

$141$0$317$0$0$458$40$0$50$548$18.3Condenser & Auxiliaries$2,393$0$714$0$0$3,107$266$0$337$3,711$88.4Steam Piping$4,035$0$2,653$0$0$6,688$513$0$1,080$8,281$178.9TG Foundations

$0$637$1,007$0$0$1,644$139$0$357$2,140$5SUBTOTAL 8.$25,799$637$8,156$0$0$34,592$2,909$0$4,289$41,791$88 9COOLING WATER SYSTEM9.1Cooling Towers$6,077$0$777$0$0$6,854$584$0$744$8,182$179.2Circulating Water Pumps$1,780$0$106$0$0$1,887$142$0$203$2,232$59.3Circ.Water System Auxiliaries

$136$0$18$0$0$154$13$0$17$184$09.4Circ.Water Piping

$0$3,968$962$0$0$4,930$399$0$799$6,128$139.5Make-up Water System

$313$0$418$0$0$730$63$0$119$912$29.6Component Cooling Water Sys

$264$315$210$0$0$788$66$0$128$983$29.9Circ.Water System Foundations

$0$2,013$3,198$0$0$5,211$442$0$1,130$6,783$14SUBTOTAL 9.$8,569$6,296$5,689$0$0$20,554$1,708$0$3,140$25,403$54 Cost and Performance Baseline for Fossil Energy Plants 496 Exhibit 5-25 Case 14 Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 10ASH/SPENT SORBENT HANDLING SYS10.1Slag Dewatering & Cooling

$0$0$0$0$0$0$0$0$0$0$010.2Gasifier Ash Depressurization

$0$0$0$0$0$0$0$0$0$0$010.3Cleanup Ash Depressurization

$0$0$0$0$0$0$0$0$0$0$010.4High Temperature Ash Piping

$0$0$0$0$0$0$0$0$0$0$010.5Other Ash Recovery Equipment

$0$0$0$0$0$0$0$0$0$0$010.6Ash Storage Silos

$0$0$0$0$0$0$0$0$0$0$010.7Ash Transport & Feed Equipment

$0$0$0$0$0$0$0$0$0$0$010.8Misc. Ash Handling Equipment

$0$0$0$0$0$0$0$0$0$0$010.9Ash/Spent Sorbent Foundation

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 10.

$0$0$0$0$0$0$0$0$0$0$0 11ACCESSORY ELECTRIC PLANT11.1Generator Equipment$5,372$0$3,228$0$0$8,600$728$0$700$10,028$2111.2Station Service Equipment$1,980$0$167$0$0$2,147$177$0$174$2,498$511.3Switchgear & Motor Control $2,440$0$415$0$0$2,855$237$0$309$3,402$711.4Conduit & Cable Tray

$0$1,166$3,595$0$0$4,761$412$0$776$5,949$1311.5Wire & Cable

$0$3,713$2,280$0$0$5,993$386$0$957$7,337$1511.6Protective Equipment

$0$563$1,916$0$0$2,480$217$0$270$2,966$611.7Standby Equipment

$98$0$90$0$0$188$16$0$20$224$011.8Main Power Transformers$10,878$0$136$0$0$11,014$747$0$1,176$12,937$2711.9Electrical Foundations

$0$121$298$0$0$419$36$0$91$546$1SUBTOTAL 11.$20,769$5,564$12,124$0$0$38,458$2,957$0$4,473$45,888$97 12INSTRUMENTATION & CONTROL12.1IGCC Control Equipmentw/4.1$0 w/4.1

$0$0$0$0$0$0$0$012.2Combustion Turbine Controlw/6.1$0w/6.1$0$0$0$0$0$0$0$012.3Steam Turbine Controlw/8.1$0w/8.1$0$0$0$0$0$0$0$012.4Other Major Component Control

$797$0$498$0$0$1,295$110$65$220$1,690$412.5Signal Processing Equipment w/12.7

$0 w/12.7

$0$0$0$0$0$0$0$012.6Control Boards,Panels & Racks

$238$0$143$0$0$381$32$19$65$497$112.7Computer & Accessories$3,814$0$114$0$0$3,928$323$196$445$4,892$1012.8Instrument Wiring & Tubing

$0$644$1,230$0$0$1,874$141$94$316$2,426$512.9Other I & C Equipment$1,422$0$3,226$0$0$4,648$404$232$528$5,813$12SUBTOTAL 12.$6,272$644$5,211$0$0$12,127$1,010$606$1,575$15,318$32 Cost and Performance Baseline for Fossil Energy Plants 497 Exhibit 5-25 Case 14 Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 13IMPROVEMENTS TO SITE13.1Site Preparation

$0$92$1,839$0$0$1,931$172$0$421$2,524$513.2Site Improvements

$0$844$1,049$0$0$1,893$167$0$412$2,472$513.3Site Facilities$1,724$0$1,700$0$0$3,424$302$0$745$4,471$9SUBTOTAL 13.$1,724$936$4,588$0$0$7,248$641$0$1,578$9,467$20 14BUILDINGS & STRUCTURES14.1Combustion Turbine Area

$0$236$125$0$0$361$28$0$58$447$114.2Steam Turbine Building

$0$1,639$2,183$0$0$3,822$314$0$620$4,756$1014.3Administration Building

$0$462$313$0$0$775$62$0$125$962$214.4Circulation Water Pumphouse

$0$147$73$0$0$220$17$0$36$272$114.5Water Treatment Buildings

$0$458$418$0$0$876$71$0$142$1,089$214.6Machine Shop

$0$401$256$0$0$657$52$0$106$815$214.7Warehouse

$0$259$156$0$0$415$33$0$67$515$114.8Other Buildings & Structures

$0$77$56$0$0$134$11$0$22$166$014.9Waste Treating Building & Str.

$0$303$541$0$0$845$70$0$137$1,052$2SUBTOTAL 14.

$0$3,982$4,121$0$0$8,103$658$0$1,314$10,075$21TOTAL COST$318,200$24,594$95,849$0$0$438,642$36,957$28,600$76,502$580,701$1,226Owner's CostsPreproduction Costs6 Months All Labor$4,163$91 Month Maintenance Materials

$612$11 Month Non-fuel Consumables

$273$11 Month Waste Disposal

$0$025% of 1 Months Fuel Cost at 100% CF$4,509$102% of TPC$11,614$25Total$21,170$45Inventory Capital60 day supply of consumables at 100% CF

$357$10.5% of TPC (spare parts)$2,904$6Total$3,260$7Initial Cost for Catalyst and Chemicals

$823$2Land$300$1Other Owner's Costs$87,105$184Financing Costs$15,679$33Total Overnight Costs (TOC)$709,039$1,497TASC Multiplier(IOU, high-risk, 33 year)1.078Total As-Spent Cost (TASC)$764,344$1,614 Cost and Performance Baseline for Fossil Energy Plants 498 Exhibit 5-26 Case 14 Initial and Annual Operating and Maintenance Cost Summary INITIAL & ANNUAL O&M EXPENSESCost Base (Jun):

2007Case 14 - 1x475 MWnet 2x1 7FB NGCC w/ CO2 CaptureHeat Rate-net (Btu/kWh):7,968 MWe-net: 474 Capacity Factor (%):

85OPERATING & MAINTENANCE LABOROperating Labor Operating Labor Rate(base):34.65$/hour Operating Labor Burden:30.00% of base Labor O-H Charge Rate:25.00% of laborTotal Operating Labor Requirements(O.J.)per Shift:1 unit/mod. Plant Skilled Operator1.01.0 Operator3.33.3 Foreman1.01.0 Lab Tech's, etc.1.01.0 TOTAL-O.J.'s6.36.3Annual CostAnnual Unit Cost

$$/kW-netAnnual Operating Labor Cost$2,497,781$5.274Maintenance Labor Cost$4,162,295$8.789Administrative & Support Labor$1,665,019$3.516Property Taxes and Insurance$11,614,024$24.524TOTAL FIXED OPERATING COSTS$19,939,120$42.104VARIABLE OPERATING COSTS$/kWh-netMaintenance Material Cost$6,243,443$0.00177ConsumablesConsumptionUnit Initial Fill Initial Fill /Day Cost CostWater (/1000 gallons)0.002,865.601.08$0$961,666$0.00027ChemicalsMU & WT Chem.(lbs)0.0017,072.410.17$0$916,693$0.00026MEA Solvent (ton)344.710.482,249.89$775,561$337,908$0.00010Activated Carbon (lb)0.00578.271.05$0$188,408$0.00005Corrosion Inhibitor0.000.000.00$47,225$2,249$0.00000SCR Catalyst (m3)w/equip.0.075,775.94$0$129,612$0.00004Ammonia (19% NH3) (ton)0.006.06129.80$0$244,142$0.00007Subtotal Chemicals$822,786$1,819,011$0.00052OtherSupplemental Fuel (MBtu)0.000.000.00$0$0$0.00000Gases,N2 etc. (/100scf)0.000.000.00$0$0$0.00000L.P. Steam (/1000 pounds)0.000.000.00$0$0$0.00000Subtotal Other

$0$0$0.00000Waste DisposalFlyash (ton)0.000.000.00$0$0$0.00000Bottom Ash (ton)0.000.000.00$0$0$0.00000Subtotal Waste Disposal

$0$0$0.00000By-productsSulfur (tons)0.000.000.00$0$0$0.00000Subtotal By-products

$0$0$0.00000TOTAL VARIABLE OPERATING COSTS$822,786$9,024,121$0.00256Fuel (MMBtu) 090,5626.55$0$183,972,091$0.05217 Cost and Performance Baseline for Fossil Energy Plants 499 5.3 NGCC CASE

SUMMARY

The performance results of the two NGCC plant configurations modeled in this study are summarized in Exhibit 5-27. Exhibit 5-27 Estimated Performance and Cost Results for NGCC Cases 1 Capacity factor is 85% for all NGCC cases 2 COE and LCOE are defined in Section 2.7. PERFORMANCECase 13Case 14CO2 Capture 0%90%Gross Power Output (kWe)564,700511,000Auxiliary Power Requirement (kWe)9,62037,430Net Power Output (kWe)555,080473,570Coal Flowrate (lb/hr)N/AN/ANatural Gas Flowrate (lb/hr)167,333167,333HHV Thermal Input (kWth)1,105,8121,105,812Net Plant HHV Efficiency (%)50.2%42.8%Net Plant HHV Heat Rate (Btu/kWh)6,7987,968Raw Water Withdrawal (gpm/MWnet)4.38.4Process Water Discharge (gpm/MWnet)1.02.1Raw Water Consumption (gpm/MWnet)3.36.3 CO 2 Emissions (lb/MMBtu) 118 12 CO 2 Emissions (lb/MWhgross)790 87 CO 2 Emissions (lb/MWhnet)804 94 SO 2 Emissions (lb/MMBtu)NegligibleNegligible SO 2 Emissions (lb/MWhgross)NegligibleNegligibleNOx Emissions (lb/MMBtu)0.0090.008NOx Emissions (lb/MWhgross)0.0600.061PM Emissions (lb/MMBtu)NegligibleNegligiblePM Emissions (lb/MWhgross)NegligibleNegligibleHg Emissions (lb/TBtu)NegligibleNegligibleHg Emissions (lb/MWhgross)NegligibleNegligibleCOSTTotal Plant Cost (2007$/kW) 5841,226Total Overnight Cost (2007$/kW) 7181,497 Bare Erected Cost 482 926 Home Office Expenses 40 78 Project Contingency 62 162 Process Contingency 0 60 Owner's Costs 133 271Total Overnight Cost (2007$ x 1,000)398,290709,039Total As Spent Capital (2007$/kW) 7711,614COE (mills/kWh, 2007$)1,258.985.9 CO2 TS&M Costs0.03.2 Fuel Costs44.552.2 Variable Costs1.32.6 Fixed Costs3.05.7 Capital Costs10.122.3LCOE (mills/kWh, 2007$)1,274.7108.9NGCC Advanced F Class Cost and Performance Baseline for Fossil Energy Plants 500 The components of TOC and overall TASC are shown for the two NGCC cases in Exhibit 5-28. The TOC of the non

-capture case, $

718/kW, is the lowest of all technologies studied by at least 5 0 percent. Addition of CO 2 capture more than doubles the TOC cost, but NGCC with capture is still the least capital intensive of all the capture technologies by at least 5 5 percent. The process contingency included for the Econamine process totals $

59/kW, which represents approximately 4 percent of the TO C. The COE for NGCC cases is heavily dependent on the price of natural gas as shown in Exhibit 5-29. The fuel component of COE represents 7 6 percent of the total in the non-capture case and 61 percent of the total in the CO 2 capture case. Because COE has a small capital component, it is less sensitive to CF than the more capital intensive PC and IGCC cases. The decrease in net kilowatt

-hours (kWh) produced is nearly offset by a corresponding decrease in fuel cost. The CO 2 TS&M component of COE is only 4 percent of the total in the CO 2 capture case. Exhibit 5-28 Plant Capital Cost for NGCC Cases 7181,497 7711,614 0 200 400 600 8001,0001,2001,4001,6001,8002,000TOCTASCTOCTASCNGCCNGCC w/ CO2 CaptureTOC or TASC, $/kW (2007$)TASCOwner's CostProcess ContingencyProject ContingencyHome Office ExpenseBare Erected Cost Cost and Performance Baseline for Fossil Energy Plants 501 Exhibit 5-29 COE of NGCC Cases The sensitivity of NGCC to CF is shown in Exhibit 5-30. Unlike the PC and IGCC case, NGCC is relatively insensitive to CF but highly sensitive to fuel cost as shown in Exhibit 5-31. A 33 percent increase in natural gas price (from $6 to $8/MMBtu) results in a COE increase of 25 percent in the non

-capture case and 20 percent in the CO 2 capture case. Because of the higher capital cost in the CO 2 capture case, the impact of fuel price changes is slightly diminished.

As presented in Section 2.4 the first year cost of CO 2 avoided cost was calculated. In the NGCC capture case the cost of CO 2 avoided using NGCC without CO 2 capture as the reference is $69.5/tonne ($6 3/ton). The high cost relative to PC and IGCC technologies is mainly due to the much smaller amount of CO 2 generated by NGCC and therefore captured in the Econamine process. The cost of CO 2 avoided is $35.3/tonne ($3 2/ton) when using SC PC without capture as the reference. This is due to the smaller difference in COE and larger difference in CO 2 emissions between the SC PC non-capture and NGCC capture cases

. 10.122.33.05.71.32.644.552.23.2 020406080100120140160NGCCNGCC w/ CO2 CaptureCOE, mills/kWh (2007$)CO2 TS&M CostsFuel CostsVariable CostsFixed CostsCapital Costs Cost and Performance Baseline for Fossil Energy Plants 502 Exhibit 5-30 Sensitivity of COE to Capacity Factor in NGCC Cases Exhibit 5-31 Sensitivity of COE to Fuel Price in NGCC Cases 0 20 40 60 80 100 120 140 160 0 10 20 30 40 50 60 70 80 90 100COE, mills/kWh (2007$)Capacity Factor, %NGCC w/CO2 CaptureNGCC No CaptureNatural gas price = $6.55/MMBtu 0 20 40 60 80 100 120 140 0 2 4 6 8 10 12 14COE, mills/kWh (2007$)Natural Gas Price, $/MMBtuNGCC No CaptureNGCC w/CO2 CaptureCapacity factor = 85%

Cost and Performance Baseline for Fossil Energy Plants 503 The following observations can be made regarding plant performance with reference to Exhibit 5-27: The efficiency of the NGCC case with no CO 2 capture is 50.2 percent (HHV basis). Gas Turbine World provides estimated performance for an advanced F class turbine operated on natural gas in a combined cycle mode, and the reported efficiency is 57.5 percent (LHV basis)

[79 The efficiency penalty to add CO 2 capture in the NGCC case is 14.7 relative percent. The efficiency reduction is caused primarily by the auxiliary loads of the Econamine system and CO 2 compression as well as the significantly increased cooling water requirement, which increases the auxiliary load of the CWPs and the cooling tower fan. CO 2 capture results in a 28 MW increase in auxiliary load compared to the non

-capture case. ]. Adjusting the result from this study to an LHV basis results in an efficiency of 55.7 percent.

The energy penalty for NGCC is less than PC (14.7 relative percent for NGCC compared to 28.9 and 27.6 relative percent for subcritical and SC PC respectively

) and IGCC (21.4 relative percent) mainly because natural gas has a lower carbon intensity than coal and NGCC has a higher efficiency than PC or IGCC. In the PC cases, about 589,670 kg/h r (1.3 million lb/h r) of CO 2 must be captured and compressed while in the NGCC case only about 181,437 kg/h r (400,000 lb/h r) is captured and compressed.

A study assumption is that the natural gas contains no PM or Hg, resulting in negligible emissions of both.

This study also assumes that the natural gas contains no sulfur compounds, resulting in negligible emissions of SO

2. As noted previously in the report, if the natural gas contained the maximum allowable amount of sulfur per EPA's pipeline natural gas specification, the resulting SO 2 emissions would be 21 tonnes/yr (23 tons/yr), or 0.00195 lb/MMBtu.

NOx emissions are nearly identical for the two NGCC cases on a heat input and mass basis. This is a result of the fixed output from the GT (25 ppmv at 15 percent O

2) and the fixed efficiency of the SCR (90 percent).

The normalized water withdrawal , process discharge and raw water consumption are shown in Exhibit 5-32 for the NGCC cases. The following observations can be made:

Normalized water withdrawal increases 95 percent and normalized raw water consumption 91 percent in the CO 2 capture case. The high cooling water demand of the Econamine process results in a large increase in cooling tower makeup requirements.

Cooling tower makeup comprises approximately 99 percent of the raw water consumption in both NGCC cases. The only internal recycle stream in the non

-capture case is the BFW blowdown, which is recycled to the cooling tower. In the CO 2 capture case condensate is recovered from the FG as it is cooled to the absorber temperature of 32°C (89°F) and is also recycled to the cooling tower.

Cost and Performance Baseline for Fossil Energy Plants 504 Exhibit 5-32 Raw Water Withdrawal and Consumption in NGCC Cases 4.38.43.36.3 0 1 2 3 4 5 6 7 8 9NGCCNGCC w/ CO2 CaptureWater, gpm/MWnetRaw Water WithdrawalProcess DischargeRaw Water Consumption Cost and Performance Baseline for Fossil Energy Plants 505 6. This supplementary chapter presents sensitivities of the economic performance to higher natural gas prices and dispatch

-based CF s. Sections EFFECT OF HIGHER NATURAL GAS PRICES AND DISPATCH-BASED CAPACITY FACTORS 6.1 through 6.3 discuss the sensitivity to higher natural gas prices (at a constant CF)10 6.4 while Sections through 6.8 examine dispatch-based CF s. 6.1 INCREASING NATURAL GAS PRIC ES An investigation was conducted because of the potential for natural gas prices to increase over the long-term. Regulations limiting the emissions of CO 2 may cause natural gas to become an increasingly attractive fuel source for power generation. Natural gas is preferred in many cases because of its lower carbon intensity relative to coal: burning natural gas emits less CO 2 than an equivalent amount of coal. When compared to the average IGCC and PC non

-capture cases in this study, NGCC emits 52 percent and 56 percent less CO 2 on a lb/net

-MWh basis, respectively. As demand increases the natural gas supply has the potential to become constrained. Gas resources within the U.S. are mature and much of the low

-cost gas has already been produced. Drilling and exploration will need to be done to find alternative sources of natural gas. Producers will have to drill higher cost wells with lower deliverability requiring high

-cost technology to meet increased demand. Additional pipelines will have to be built as this gas will come from increasingly remote areas. The recently accessible Marcellus shale formation still must overcome environmental obstacles to be viable. The cost to produce the same volume of gas will increase causing the consumer to pay more for natural gas.

As domestic production costs increase, an alternative source for natural gas is imported liquefied natural gas (LNG). LNG is increasingly becoming a worldwide commodity as the supply and availability increase. As of 2009, there are only seven import terminals in the U.S. If imported LNG is to become a viable fuel source for the U.S., more terminal facilities will have to be built to keep up with the increasing demand. There is significant lag time between planning, permit acquisition, and construction of these large

-scale facilities. This lag time

, along with competition for LNG resources between other nations as the U

.S. enters the market

, will further limit the supply to the U.

S. 6.2 PRICE METHODOLOGY The baseline natural gas price used in this report is $6.55/MMBtu (June 2007 dollars). Two other natural gas prices are evaluated in this chapter to judge the sensitivity of the results to higher gas prices. The first is the EIA's AEO 2008 "High Price" projection for 2010. The "High Price" is $7.54/MMBtu in 2007 dollars11 10 It is acknowledged that changes in fuel pricing will likely have an i mpact on capacity factor. However fo r the purposes of this example, capacity factor is assumed to remain constant at a relatively high value of 85 percent in the face of changing fuel prices.

. 11 The AEO 2008 "High Price" is reported as $7.31/MMBtu in 2006 dollars. This value was escalated to $7.54/MMBtu in 2007 dollars by using the GDP chain

-type price index from AEO 2008.

Cost and Performance Baseline for Fossil Energy Plants 506 The second natural gas cost is derived from applying the historical correlation between natural gas and West Texas Intermediate (WTI) crude oil

[80NG Price ($/MMBtu) =

-0.4744 + 0.1543 x (Oil Price WTI ($/bbl))

]. The AEO "High Price" projection cost for imported crude oil in 2010 is $71.33/bbl in 2007 dollars12 6.3 COST OF ELECTRICITY

. Using the "High Price" in the correlation equation results in a natural gas price of $10.53/MMBtu. Using the Oil Correlation again, a $51.94/bbl price would be needed to have a $7.54/MMBtu price for natural gas.

The COE results are shown in Exhibit 6-1 with the capital costs, fixed operating cost, variable operating cost, and fuel cost shown separately. In capture cases the CO 2 TS&M costs are also shown as a separate bar segment. Fuel cost is the dominant component of COE in all NGCC cases and therefore fuel price increases have a significant impact. The following conclusions can be drawn: In non-capture cases, the NGCC "High Price" case still has a lower COE (65.6 mills/kWh) than any of the IGCC cases (average 77.2 mills/kWh), but the NGCC Oil Correlation Price cost (86.0 mills/kWh) represents the highest COE of all the non

-capture cases. In capture cases, the NGCC baseline cost (8 5.9 mills/kWh) is the lowest capture case cost in the initial study, and the NGCC "High Price" cost (93.8 mills/kWh) is still the lowest COE. When the natural gas price increases to $10.53/MMBtu in the Oil Correlation case, NGCC becomes the most expensive technology with CO 2 capture. This differs from the baseline results where NGCC with capture was the lowest cost.

For the three NGCC cases without CO 2 capture, the fuel component of COE ranges from 76 percent to 83 percent. For capture cases, the fuel component of COE ranges from 61 percent to 71 percent.

For the NGCC non

-capture cases, an increase in the natural gas price of 15.1 percent for "High Price" and 60.8 percent for the Oil Correlation price cause an increase of 11 percent and 46 percent in the COE, respectively. The COE in the NGCC CO 2 capture cases increases by 9 percent and 37 percent, respectively.

First year CO 2 avoided costs are shown in Exhibit 6-7 and are calculated using both analogous technologies and non

-capture SC PC as references. The IGCC and PC cases were averaged to emphasize the NGCC cases at different natural gas prices. The following conclusions can be drawn: For NGCC cases, the first year CO 2 avoided costs increase with the price of natural gas. This is consistent with the COE trend as NGCC cases are predominately affected by fuel price.

12 The AEO "High Price" is reported as $69.19/bbl in 2006 dollars. This value was escalated to $71.33 in 2007 dollars by using the GDP chain

-type price index from AEO 2008.

Cost and Performance Baseline for Fossil Energy Plants 507 At the baseline natural gas price of $6.55/MMBtu, the NGCC cases have a higher first year CO 2 avoided cost per ton than PC or IGCC when compared to the analogous non

-capture technology

. However, NGCC has the lowest first year avoided cost relative to a non-capture SC PC plant except at the highest natural gas price case.

Cost and Performance Baseline for Fossil Energy Plants 508 Exhibit 6-1 COE By Cost Component 44.463.331.260.231.759.610.122.310.122.310.122.311.515.77.813.18.013.03.05.73.05.73.05.77.49.75.19.25.08.71.32.61.32.61.32.613.917.715.221.314.219.644.552.251.360.171.683.95.55.95.73.23.23.277.2111.859.4109.758.9106.658.985.965.693.886.0117.7 0 20 40 60 80 100 120 140IGCC AverageIGCC Average w/ CO2 CaptureSubcritical PCSubcritical PC w/ CO2 CaptureSupercritical PCSupercritical PC w/ CO2 CaptureNGCCNGCC w/ CO2 CaptureNGCC High PriceNGCC High Price w/ CO2 CaptureNGCC Oil CorrelationNGCC Oil Correlation w/ CO2 CaptureCOE, mills/kWh (2007$)CO2 TS&M CostsFuel CostsVariable CostsFixed CostsCapital Costs Cost and Performance Baseline for Fossil Energy Plants 509 Exhibit 6-2 First Year CO 2 Avoided Costs 52698488987572364677 0 20 40 60 80 100 120IGCC AveragePC AverageNGCC BaselineNGCC "High Price"NGCC Petroleum CorrelationFirst Year CO2 Avoided Cost, $/tonne (2007$)FY Avoided Cost (Analogous Technology w/o Capture Reference)FY Avoided Cost (SC PC w/o Capture Reference)

Cost and Performance Baseline for Fossil Energy Plants 5 10 Exhibit 6-3 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 costs 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. The vertical lines represent the natural gas prices highlighted in this section.

At the AEO "High Price" of $7.54/MMBtu NGCC has a lower COE than all IGCC cases at any of the coal prices. At this natural gas price for non

-capture cases PC is the most cost effective method for producing electricity. For IGCC cases to compete with NGCC cases at the highest studied coal price, the cost of natural gas would have to be $9.

75/MMBtu. Fuel cost sensitivity is presented for the CO 2 capture cases in Exhibit 6-4. Even at the lowest coal cost shown ($1.23/MMBtu), the COE of NGCC at the "High Price" is lower than both the IGCC cases and PC cases. At a natural gas price 52 percent higher than the baseline price of $6.55/MMBtu, the NGCC case is statistically equal to the PC cases at a coal cost of 25 percent more than the baseline price ($2.05/MMBtu).

Exhibit 6-3 COE Sensitivity to Fuel Costs in Non-Capture Cases 40 50 60 70 80 90 100 3 4 5 6 7 8 9 10 11 12 13COE, mills/kWh (2007$)Natural Gas Price, $/MMBtuNGCCPC w/ coal at $1.23/MMBtuPC w/ coal at $1.64/MMBtuPC w/ coal at $2.05/MMBtuIGCC w/ coal at $1.23/MMBtuIGCC w/ coal at $1.64/MMBtuIGCC w/ coal at $2.05/MMBtuBaseline Study Price

-$6.55/MMBtuAEO "High Price"-$7.54/MMBtuPetroleum Correlation Price-$10.53/MMBtu Cost and Performance Baseline for Fossil Energy Plants 511 Exhibit 6-4 COE Sensitivity to Fuel Costs in CO 2 Capture Cases The sensitivity of COE to CF is shown for all non capture technologies in Exhibi t 6-5 and for all capture technologies in Exhibit 6-6. The baseline PC and IGCC cases for non

-capture and capture were averaged to highlight the comparison with the NGCC cases. The average PC plant with capture and the average IGCC plant with 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 6-5 and Exhibit 6-6 for 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.

40 50 60 70 80 90 100 110 120 130 140 3 4 5 6 7 8 9 10 11 12 13COE, mills/kWh (2007$)Natural Gas Price, $/MMBtuNGCCPC w/ coal at $1.23/MMBtuPC w/ coal at $1.64/MMBtuPC w/ coal at $2.05/MMBtuIGCC w/ coal at $1.23/MMBtuIGCC w/ coal at $1.64/MMBtuIGCC w/ coal at $2.05/MMBtuBaseline Study Price

-$6.55/MMBtuAEO "High Price"-$7.54/MMBtuPetroleum Correlation Price

-$10.53/MMBtu Cost and Performance Baseline for Fossil Energy Plants 512 Exhibit 6-5 COE Sensitivity to Capacity Factor in Non-Capture Cases 40 60 80 100 120 140 160 180 200 20 30 40 50 60 70 80 90 100COE, mills/kWh (2007$)Capacity Factor, %Avg. IGCC no captureAvg. PC no captureNGCC no capture Petroleum CorrelationNGCC no capture "High Price"NGCC no captureCoal = $1.64/MMBtuNatural Gas = $6.55/MMBtu Cost and Performance Baseline for Fossil Energy Plants 513 Exhibit 6-6 COE Sensitivity to Capacity Factor in Capture Cases The NGCC curves are flatter than the coal curves because for NGCC the fuel cost, rather than the capital cost, is the dominant component of COE, even at baseline natural gas prices. Conclusions that can be drawn from Exhibit 6-5 and Exhibit 6-6 include: At high CFs, coal based technologies with and without CO 2 capture can be competitive with NGCC depending on the price of natural gas. As the CF falls among the non

-capture technologies, IGCC becomes less competitive first, followed by PC. IGCC and PC with CO 2 capture become less competitive together as the CF decreases.

At low CFs, the coal based IGCC and PC technologies are affected to a greater extent than NGCC. At a CF less than 45 percent, NGCC is the most economic option at each natural gas price examined.

6.4 DISPATCH-BASED CAPACITY FACTO RS The baseline assumption in this report was that all technologies would always be dispatched when available

, making CF and availability factor equivalent. In reality the marginal production cost would determine dispatch order and hence CF. The balance of this chapter examines the determination and impact of a dispatch

-based CF. Estimates are provided for th e plant dispatch expected in cases without CO 2 capture, if these units were to compete for electric sales with the other 1,706 generators that would provide the generation to supply the demand of the PJM Interconnection (PJM) control region in 2010. The 40 60 80 100 120 140 160 180 200 220 240 260 280 300 20 30 40 50 60 70 80 90 100COE, mills/kWh (2007$)Capacity Factor, %Avg. IGCC w/CO2 captureAvg. PC w/CO2 captureNGCC w/ CO2 capture Petroleum CorrelationNGCC w/ CO2 capture "High Price"NGCC w/CO2 captureCoal = $1.64/MMBtuNatural Gas = $6.55/MMBtu Cost and Performance Baseline for Fossil Energy Plants 514 basis for projecting the expected CF of each of the units without CO 2 capture is provided, along with the financial implications of that dispatch.

The estimated year 2010 CFs earned in the PJM operating region for the units examined are listed in Exhibit 6-7. The bases for these estimates are discussed later in this chapter.

Exhibit 6-7 Dispatch Based Capacity Factors for Cases without CO 2 Capture Case Year 2010 Capacity Factor Case 1 - GE IGCC 51.5% Case 3 - CoP IGCC 54.1% Case 5 - Shell IGCC 62.0% Case 9 - Subcritical PC 73.4% Case 11 - SC PC 85.0% Case 13 - NGCC 16.5% The annual CF of an electric generating unit is the ratio of its actual generation (that is, the unit's annual kWh) to the kWh it would generate if, hypothetically, it could operate a t full capacity for every hour of the year without interruption. The CF is a measure of how much the unit is used , and is an important measure for assessing the potential for profitable financial return from the investment in the purchase of the generating equipment.

About Capacity Factor No generating unit can run all of the time; thus, the CF of a unit is always less than 1.00. Reasons for the unit not running all of the time include:

The unit is removed from service for planned maintenance.

The unit is forced to temporarily decrease output due to a partial equipment failure that limits output, which requires unplanned maintenance that can be accomplished with the unit running at partial load.

The unit is forced to be completely removed from service due to equipment failures and subsequent required unplanned maintenance.

The unit runs only at part load because of grid variations in the demand for power. The ability of the unit to follow the demand makes this unit the most economical to turndown compared to the other units running at the same time.

The unit costs more to operate than competing units, therefore it is displaced by units that are either more efficient or use less costly fuel. Since the unit's production costs are higher than competing units that could meet the system power demand at a given period Cost and Performance Baseline for Fossil Energy Plants 515 of time, the unit is dropped for periods of time from the dispatch order since it is not needed. Units that have lower production costs then meet the demand, and the unit remains idle until once again the system demand rises high enough so that the unit rejoins the dispatch order as the most cost effective unit available for service at that given level of demand.

A unit cannot have a CF greater than its equivalent availability (defined as the fraction of time that the unit is available accounting only for planned maintenance and forced outages

). The equivalent availability thus forms the upper bound on the CF. Of course, the unit may have a lower CF when there are periods of time where competing units with lower production costs can win the competitive bidding to meet demand, forcing the less economical unit to be idle.

For the most part, a generating unit can only provide a financial return to its investors when it is running. While a unit can earn revenue even if it is not providing output, selling ancillary

services, such as providing reserve power and other standby services, overwhelmingly, the investment in the unit is made with anticipation of revenue from unit operations; the more hours the unit runs

-that is, the higher its CF- the greater potential return from its operations.

Financial Implications of Capacity Factor An electric generating unit's CF has a dramatic impact on the annual fixed operating costs. These costs must be paid whether or not the unit is operating and earning revenue. These fixed costs include property tax, paying off the capital investment to the investment bankers, salaries for the operations staff who need to be there whether the plant is running or not, and others. The greater the CF (the number of hours that a unit operates, and thus earns revenue), the greater the period over which these fixed operating costs can be amortized, and the lower the percentage impact on the total annual costs of production for the unit.

PJM Interconnection is a regional transmission organization (RTO) that coordinates the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia , and the District of Columbia.

As an Independent System Operator, in 2006, PJM dispatche d the generation of 1,706 sources for meeting demand. It is an excellent choice for modeling the dispatch prospects of the units modeled in this study, since: Unit Dispatch in the PJM Control Region PJM is the largest control region in the world, eclipsing Japan, and of France, the next larger regions.

PJM dispatches a diverse mix of generation.

PJM is a model for competitive electric power dispatch operations

more than 70 nations have sent delegates to PJM to learn about its market model and its operation of the electric grid.

Cost and Performance Baseline for Fossil Energy Plants 516 This analysis of unit dispatch within PJM for the cases in this study was performed with consideration for the following:

Method Used to Estimate Unit Dispatch in PJM in Year 2010 Hour-by-hour forecast of expected electric demand within the control region in 2010. Forecast of fuel costs for the units competing for electric sales within the region in 2010. Assessment of the seasonal availability of the competing fleet of generating units.

Estimate s for each of the generating units competing for electric sales within the control region: Variable operating costs for each. Fuel and other production costs for each. Forecast the hour

-by-hour unit dispatch that would result in the most competitive mix of units for each hour of operation throughout the target study year 2010. To update the examined cases, dispatched based CFs were determined for the six cases without CO 2 capture through modeling the dispatch of the units in the P JM ISO. The remainder of this chapter provides:

Dispatch-Based Capacity Factor

- What is Discussed The modeling results of the six non-capture cases within this regio

n. A description of the PJM ISO

. A review of the modeling method and assumptions that were used to develop these estimates.

A listing of the case economics at the anticipated CF levels estimated in this chapter. 6.5 DISPATCH MODELING RESULTS WITHIN PJM Year 2010 unit dispatch modeling in the PJM control region was performed under two scenarios:

Natural gas price fixed at the EIA

-predicted value for 2010 of $6.55/MMBtu.

Varying the natural gas price over the range of $0 to $20/MMBtu.

The generating unit dispatch stack, including a list of generating units ordered by production costs, for the fixed natural gas price case is shown in Exhibit 6-8 and illustrates the increase in production cost with increase d cumulative production from the system. Additionally, this plot shows the fuel type of the plants within the stack. As expected, the fuel price dominates the stacking order with the technologies using the lower cost (or no cost) fuels being dispatched first, then coal, then natural gas; those with the most expensive fuel, No. 2 oil, are dispatched last.

Cost and Performance Baseline for Fossil Energy Plants 517 Exhibit 6-8 Estimated Stacking Order in PJM for Year 2010 Based on First Year Production Costs The stack curve in Exhibit 6-8 would change with variations in the natural gas price. For example, as the price of natural gas decreases, the production cost of the natural gas

-fired units would decrease. This could eventually lead to a drop below the bituminous coal

-fired unit

's production costs. In this case, the natural gas units would shift to the left of the bituminous coal-fired units and be dispatched first.

Based on the uncertainty of natural gas prices in 2010, the initial dispatch modeling was performed as a scan of the natural gas price ranging from $0 to $20/MMBtu. At low natural gas prices, $2.50/MMBtu

, the natural gas units in the PJM fleet are dispatched prior to the coal-fired units. The most efficient coal unit, SC PC, achieves the lowest production cost and therefore is the first to be dispatched with increasing natural gas prices. This results in the SC PC unit having the highest CF, as shown in Exhibit 6-9. Exhibit 6-9 further shows that the dispatch of the units is not significantly impacted by natural gas prices in the range of $6

-$10/MMBtu. When the price of natural gas is above $12.50/MMBtu, the production cost of the NGCC unit is above that of the oil-fired units in the fleet, so the CF continues to drop.

050100150200250300 020000400006000080000100000120000140000160000Production Cost ($/MWh)Cumulative Production (MW)Natural GasWindLandfill GasHydroCoalNo 2 OilBlack LiquorMSWOther GasWood SolidsNo. 6 OilNuclearNaturalGas Price = $6.55/MMBtuCoal Price = $1.64/MMBtu Cost and Performance Baseline for Fossil Energy Plants 518 Exhibit 6-9 Capacity Factors of Replacement Units Dispatched into PJM The fuel cost s used in this study (coal at $1.64/MMBtu and natural gas at $6.55/MMBtu) lead to the CFs listed in Exhibit 6-10. Exhibit 6-10 Dispatch Based Capacity Factors Assuming No CO 2 Capture Case CF Case 1 - GE IGCC 51.5% Case 3 - CoP IGCC 54.1% Case 5 - Shell IGCC 62.0% Case 9 - Subcritical PC 73.4% Case 11 - SC PC 85.0% Case 13 - NGCC 16.5% Exhibit 6-11 illustrates the desired unit dispatch factor, which ignores availability and is therefore the percentage of time that a unit would be dispatched if it is 100 percent available, as a function of the production cost of the entire PJM fleet. For the coal

-based cases, there is a high sensitivity of the dispatch factor on the production cost; that is if the production cost changes a 0 20 40 60 80 100$0$5$10$15$20Capacity Factor (%)NG Price ($/MMBtu)PC SupercriticalPC SubcriticalIGCC -ShellIGCC -CoPIGCC -GENGCC -F Class Cost and Performance Baseline for Fossil Energy Plants 519 small amount the dispatch factor changes significantly. Additionally, the high efficiency of the SC PC leads to this unit being very competitive compared to the existing PJM portfolio.

Exhibit 6-11 Summary of Prospective Facility Parameters for Modeling The dispatch based CFs were used to revise the economic analyses for the cases without CO 2 capture. The impact o f dispatch based CFs on the LCOE are summarized in Exhibit 6-12 and Exhibit 6-13. These exhibits compare the "must run" LCOEs ("initial") determined with the CF s initially assumed in this report to the LCOEs determined with the dispatch

-based CF ("calculated") for 2010 operations in PJM. In the comparison, it is important to note that variable costs (fuel and variable O&M) are the same while the fixed costs (capital charges and fixed O&M) vary.

Cost and Performance Baseline for Fossil Energy Plants 520 Exhibit 6-12 Comparison of COE as a Function of Capacity Factor Breakdown of COE ($/MWh)

COE $/MWh CF Capital Costs Fixed O&M Variable O&M Fuel Case 1 GE IGCC Initial 80.0% $43.39 $11.28 $7.30 $14.36 $76.32 Calculated 51.5% $67.40 $17.52 $7.30 $14.36 $106.57 Case 3 CoP IGCC Initial 80.0% $41.68 $11.08 $7.20 $14.08 $74.05 Calculated 54.1% $61.64 $16.39 $7.20 $14.08 $99.31 Case 5 Shell IGCC Initial 80.0% $48.16 $12.16 $7.75 $13.28 $81.35 Calculated 62.0% $62.14 $15.69 $7.75 $13.28 $98.86 Case 9 Subcritical PC Initial 85.0% $33.31 $7.83 $5.15 $15.21 $61.50 Calculated 73.4% $38.57 $9.07 $5.15 $15.21 $68.00 Case 11 SC PC Initial 85.0% $33.78 $7.97 $5.04 $14.25 $61.03 Calculated 85.0% $33.78 $7.97 $5.04 $14.25 $61.03 Case 13 NGCC Initial 85.0% $10.11 $2.96 $1.32 $44.53 $58.92 Calculated 16.5% $52.08 $15.27 $1.32 $44.53 $113.20 Cost and Performance Baseline for Fossil Energy Plants 521 Exhibit 6-13 Impact of Dispatched Based Capacity Factors on the Cost of Electricity

$0$25$50$75$100$125$150Cost of Electricity ($/MWh)Capital CostsFixed O&MVariable O&MFuelnatural gascoalGEE IGCCConocoPhilips IGCCShell IGCCSubcritical PCSupercritical PCNGCCCF = 80%CF = 52%CF =

80%CF =

85%CF =

73%CF =

85%CF =

62%CF =

80%CF =

54%CF = 17%CF = 85%Left Collumn

-Assumed Capacity FactorRight Collumn

-Dispatch Calculation Based Capacity Factor Cost and Performance Baseline for Fossil Energy Plants 522 6.6 PJM INDEPENDENT SYSTEM OPERATOR PJM was formed in 1927 in order to share the resources of three utilities, Philadelphia Electric Company (PECO), Pennsylvania Power & Light Company (PP&L), and Public Service Electric & Gas Company (PSE&G), thus allowing them to increase operational efficiencies. This became the world's first power pool. PJM became the first fully functioning Independent System Operator in 1998, responsible for both the safety and reliability of the transmission system and overseeing the administration of a competitive wholesale electric power market.

The scope of the PJM East and PJM West operations includes:

51 million people served 144,644 MW of peak load 164,905 MW of generation capacity 729,000 GWh (gigawatt

-hour) of energy per year 1,706 generation sources of diverse types 56,250 miles of transmission lines 450+ members

$71 billion in energy and energy service trades since 1997 PJM is a limited liability company that operates on a profit neutral basis. PJM's Operating Agreement and Tariff provide that it can recoup its operating expenses from its member companies. Debt service is included in the operating expenses that PJM bills to members on a monthly basis. It is a non

-stock corporation owned by its members and governed by the Federal Energy Regulatory Commission (FERC) in cooperation with the state regulatory boards in which it operates. Other income comes from studies and interconnection fees, membership dues, and interest.

Today, PJM has evolved to become more of a process than a specific region, though its physical region is expanding rapidly

, as well. The recent issues in wholesale trading and stalled unregulated retail initiatives have demonstrated the need to provide a uniform set of operating principles that allow s the forces of supply and demand to work freely in a transparent manner while encouraging participation by new, non

-utility participants. PJM has shown it has the technology (notably a suite of Internet scheduling and trading tools) and organizational structure to accomplish this while maintaining system reliability. PJM's operating territory as of February 2008 is shown in Exhibit 6-14 [81].

Cost and Performance Baseline for Fossil Energy Plants 523 Exhibit 6-14 The PJM Operating Territor y 6.6.1 PJM is its region's RTO with responsibility to act in several roles, including:

PJM Roles and Responsibilities Control area operator Transmission provider Market administrator Regional transmission planner NERC security coordinator PJM is responsible for the region's electric integrity, unit dispatch and reliability, and administering the pricing mechanisms for delivery of all power. With the implementation of the PJM Open Access Transmission Tariff in 1997, PJM began operating the nation's first regional bid-based energy market, and now operates six competitive markets selling energy, capacity and ancillary services. PJM enables participants to buy and sell energy, schedule bilateral electric sale transactions, and reserve transmission service. PJM provides the accounting and billing services for these transactions.

Each day, PJM forecasts how much electricity will be needed and receives offers to supply electricity from producers and other suppliers of electricity. PJM decides what offers to accept Cost and Performance Baseline for Fossil Energy Plants 524 by selecting which plants will make electricity over the next period. PJM bases its decisions on the overall least cost for the whole region, considering the pattern of demand and availability of supply. PJM directs the operation of the generation plants by agreements with their owners. The electricity actually flows through transmission lines (high tower, high voltage lines) to local utilities' distribution station and from there is sent on local electric lines to homes, factories and businesses. PJM also anticipates electricity needs years ahead and makes plans to ensure that enough electricity will be there as the region grows [82 6.6.2 ]. Generation capacity in PJM is currently 187,172 MW based on the stacking order compiled in January 2008 for the year 2006. The mix of fuels in PJM as indicated in the stacking order is shown in Exhibit 6-15. Generation Mix Exhibit 6-15 PJM Installed Capacity by Fuel Type 6.6.3 PJM is dedicated to making all facets of electric generation service that are practicable available on a competitive market basis, thus providing accurate pricing signals and access to these products for all participants in a deregulated electricity environment. PJM's spot and ancillary markets offer market flexibility in that they support bilateral transactions by providing liquidity and risk management instruments, allowing self-scheduling of supply, and providing spot market access. Based on the short but significant history of this effort, it would appear that PJM has PJM Markets Coal , 38.8Natural Gas, 27.4Nuclear, 16.5Distilate/Residual Fuel Oil and Oil Based Fuels, 7.7Hydro, 3.3Biomass and Municipal Waste, 1.1Wind, 1.6Other, 3.7 Cost and Performance Baseline for Fossil Energy Plants 525 succeeded in creating rational markets with the ability to adapt as market power or reliability issues arise. PJM currently operates six markets:

Day-ahead energy market Real-time energy market Daily capacity market Monthly/multi

-monthly (interval) capacity market Regulation market Monthly FTR auction market 6.6.4 Generation owners in PJM can sell the output from their units in three ways: bid into the PJM day-ahead market, self

-schedule their output to serve their own load, or sell their output directly (bilaterally) to another party. PJM Energy Markets PJM was a net exporter of energy on a monthly basis for every month in 200 6, and exported an average of 1.5 million MW h. Imports into the region and exports out of the region respond to market prices. As detailed in the PJM Interconnection State of the Market Report

- 200 6, this activity supports the view that the PJM energy market is liquid, and exists in the context of a much broader energy marketplace.

All anticipated generation and load in PJM must be scheduled through PJM at least the day before. Generators are contacted the day before and advised as to which (if any) of their bids were accepted, the hours they must run, and the amounts that they will be required to provide each hour. If a generator fails to supply the generation when required, it must replace that energy by purchasing it

- either bilaterally or from the real

-time energy market.

PJM runs two energy markets: the day

-ahead market and the real

-time market. All transactions made in the day

-ahead market are financially binding, with adjustments for actual generation and usage made using the real

-time market.

6.6.5 This study assumes that the units modeled in this study would be selling their output to the PJM day-ahead market.

The day-ahead energy market is a financial market and is used to provide a hedge against price fluctuations (primarily congestion charges) in the real

-time market. Based on load schedules submitted by all load

-serving entities (LSEs) at least the day before the Operating Day, PJM calculates the expected energy needed at various locations (major busses) throughout the system, and accepts both sell and buy bids for the total amount needed each hour plus reserves. Then PJM stacks the sell bids in low

-to-high price (or economic) order and assigns a price for electricity for each hour at each location for the following day in dollars per megawatt ($/MW). The price for one megawatt of power during each hour the next operating day in the day

-ahead market will be the lowest price bid satisfying the anticipated load requirement for that hour, plus any congestion charges expected to occur at that location. This hourly price is known as the Locational Marginal Price, or LMP. All successful bidders for that hour receive the price accepted, regardless of the price they bid.

Day-Ahead Market PJM defines LMP as the "cost of supplying the next MW of load at a specific location, considering generation marginal cost, cost of transmission congestion, and losses." LMP values Cost and Performance Baseline for Fossil Energy Plants 526 are the result of security

-constrained economic dispatch operations, a method system operators have used to manage congestion for years. A least

-cost security constrained dispatch algorithm determines the least expensive way to serve load while respecting transmission limits.

During periods of low demand, the LMP is generally the same at all locations. That is, none of the transmission capability is constrained. During periods of high demand, equipment problems, or system irregularities, the LMP can vary significantly from one location to another. This is especially so during peak system days.

Day-Ahead Energy Market Timeline Up to 12 noon

- PJM receives bids and offers for energy for next Operating Day.

12 noon to 4 pm

- Day-ahead market is closed for evaluation by PJM.

4 pm - PJM posts day

-ahead and hourly schedules.

4 pm to 6 pm - Re-bidding period. Re

-bidding period is for generation not selected for day-ahead market and lets them re

-bid for regulation, operating, and spinning reserves. PJM desires to give preference to uncommitted capacity first.

PJM continually re

-evaluates and sends out individual generation schedule updates as required throughout the Operating Day. The maximum and minimum day ahead electricity prices for the PJM ISO region for the year 2006 are shown in Exhibit 6-16. Exhibit 6-16 PJM East Day

-Ahead LMP for 2006

$0$50$100$150$200$250$300$350$400Jan-06Feb-06Mar-06Apr-06May-06Jun-06Jul-06Aug-06Sep-06Oct-06Nov-06Dec-06Day Ahead LMP ($/MWh)DA LMP MinimumDA LMP Maximum Cost and Performance Baseline for Fossil Energy Plants 527 6.6.6 There is a strong correlation between price and demand in the PJM markets. Exhibit 6-17 illustrates day-ahead high and low prices, and daily high and low loads for the year 2006.

Prices and Demand Exhibit 6-17 PJM Load and Day

-Ahead LMP for 2006 Exhibit 6-18 and Exhibit 6-19 show the correlation between price and demand over a one

-year period. They also show a rational association between the two, supporting the viewpoint that PJM has been effective at creating competitive energy markets.

$0$100$200$300$400$500$600 0 25 50 75 100 125 150 Jan-06Feb-06Mar-06Apr-06May-06Jun-06Jul-06Aug-06Sep-06Oct-06Nov-06Dec-06DA -LMP ($/MWh)Demand (GW)PJM Demand

-MinimumPJM Demand

-MaximumDA LMP MinimumDA LMP Maximum Cost and Performance Baseline for Fossil Energy Plants 528 Exhibit 6-18 PJM Day-Ahead LMP vs. Demand for 2006 Exhibit 6-19 PJM Price/Load Distribution for 2006

Cost and Performance Baseline for Fossil Energy Plants 529

6.7 DESCRIPTION

OF THE PJM REGIONAL MODELING The analysis tools used to predict economic dispatch are a series of databases and calculations designed to model future dispatching of power generation facilities taking into account:

Fuel Cost Additional new generation Changes in demand Changes in legislation The se procedures emulate the competitive dispatch of units. Outputs from the modeling include:

CFs for competing units Individual and fleet wide emissions The analysis method is based on modeling the current conditions in a power generation network and then projecting the operation of the system into the future. Modeling of a current generation system requires

The demand of the generation system on an hourly basis The selling price of electricity within the generation system on an hourly basis Identifying power generation units in the system with their operating parameters including:

Nameplate capacity Fuel type Heat rate Emission intensities Variable operating and maintenance costs Delivered fuel costs To project the existing system into the future, the existing conditions are modified by projections of future:

Fuel Prices Demand Change in generation unit portfolio Changes in legislation This data above is acquired through a variety of publicly available databases and internal modeling methods.

The dispatch of prospective units is determined through

Determining the dispatch order of the existing plants in a system based on the production costs of the individual units. These electricity production costs are determined from the fuel costs, plant efficiency, the variable operating and maintenance costs, and penalties that are related to the generation of electricity such as for CO 2 emissions. In the case of modeling the PJM region, 1,706 units are characterized. The list of plants and their Cost and Performance Baseline for Fossil Energy Plants 530 information, ordered by production cost, is referred to as the "stack

". The units are then inserted into this mix of generating units, and ordered based upon their specific production costs.

Identifying the marginal production cost of the last

-dispatched unit for a given hour through comparing the hourly demand for the generation system to the cumulative generation in the stack. The last facility dispatched to meet the demand sets the production cost for that hour.

Determining if a prospective unit is dispatched in an hour by comparing the plant production cost to the production cost of the last plant dispatched. If the prospective unit's production cost is less, then the unit is dispatched.

Sum the hourly results for the prospective power plants to determine the CF for each unit during the year.

o For the non

-capture technologies, the CFs of the facilities, listed earlier in Exhibit 6-7 , were determined through dispatch modeling of these units into the PJM ISO. 6.8 WPLANET MODEL INPUTS The inputs for the model were obtained from standard databases containing generation information for the year 2006. Exhibit 6-20 provides a summary of the sources used to obtain the required information for 2006.

Exhibit 6-20 Data Sources for Electricity Generation in the PJM Region in Year 2006 Generation System Parameter for 2006 Data Source Comments Hourly System

-Wide Demand PJM website database Electricity Selling Price (D A-LMP 1) PJM website database Not required for current calculations Contributing Power Generation Unit Names PJM website database Generation Unit Parameters 2006 UDI Database 2 Fuel Type 2006 UDI Database Nameplate Capacity 2006 UDI Database Heat rate 2006 eGrid Database Emission Intensities 2006 eGrid Database Not required for current calculations Variable O&M Costs Power plant operations models Delivered Fuel Costs 2006 FERC Form 423 1 DA-LMP is Day Ahead Locational Marginal Price 2 UDI World Electric Power Plants Database 2006, available from www.platts.com

Cost and Performance Baseline for Fossil Energy Plants 531 This data is cast into the future for projections of the fuel prices, generation demand, and additions to the generation facility portfolio. The assumptions for the projections and the data sources used are summarized in Exhibit 6-21. Exhibit 6-21 Assumptions for Projecting PJM Year 2006 into 2010 Fuel Prices Natural Gas EAO 2007 - $6.55/MMBtu Bituminous Coal EAO 2007 -$1.64/MMBtu Subbituminous Coal Scaled Bituminous Coal Price Diesel Fuel Oil 2006 delivered fuel costs scaled to 2010 by futures market prices.

Other Fuels Fixed at previous study prices.

Demand Forecast 1.44 % increase per year based on 2006 EIA

-411 projected demand growth for RFC Reliability Region.

Changes in Generation Facility Portfolio Data from future power generation studies on PJM website. Summarized in Exhibit 6-22 The additional facilities that are planned or under construction and expected to be in service in 2010 amount to an additional 10,000 MW of generating capability. The breakdown of these technologies by fuel type is shown in Exhibit 6-22. Exhibit 6-22 Breakdown of Additional Generation in the PJM ISO by Fuel Type Coal, 51.4Coal IGCC, 10.5Natural Gas, 10.5Wind, 24.6Other (Biomass, Solar, Refuse, Wood), 3 Cost and Performance Baseline for Fossil Energy Plants 532 The characteristics of the non

-carbon capture units are listed in Exhibit 6-23. These costs are based on the AEO 2008 projections of the 2007 natural gas and coal prices, $6.55/MMBtu and $1.64/MMBtu respectively. The SC PC facility has the lowest production costs (fuel and variable O&M costs) from the high efficiency and the low fuel cost. In spite of the greater efficiency and lower O&M cost of the natural gas-fired combined cycle system, the natural gas-fired unit has the greatest operating cost by a factor of two because of the greater fuel cost.

Exhibit 6-23 Summary of Prospective Facility Parameters Bituminous Baseline Facility Types Fuel Type Fuel Cos t ($/MMBtu) O&M (mills/kWh) Production Costs (mills/kWh) Heat Rate (Btu/kWh) Nameplate Capacity Case 1 IGCC GEE Bit Coal $1.64 $7.30 $21.66 8,756 622 Case 3 IGCC CoP Bit Coal $1.64 $7.20 $21.28 8,585 625 Case 5 IGCC Shell Bit Coal $1.64 $7.75 $21.03 8,099 629 Case 9 PC Sub Bit Coal $1.64 $5.15 $20.36 9,276 550 Case 11 PC Super Bit Coal $1.64 $5.04 $19.28 8,686 550 Case 13 NGCC F-Class NG $6.55 $1.32 $45.84 6,798 555

Cost and Performance Baseline for Fossil Energy Plants 533 7. This supplementary chapter examines the impact of dry and parallel cooling systems on the cost and performance of six plant configurations:

DRY AND PARALLEL COOLING IGCC (CoP) without CO 2 capture IGCC (CoP) with CO 2 capture SC PC without CO 2 capture SC PC with CO 2 capture NGCC without CO 2 capture NGCC with CO 2 capture Parallel and dry cooling systems don't have universal definitions. In this study the systems are defined as follows:

Parallel Cooling: Steam exiting the LP turbine is divided equally between a conventional condenser using cooling water as the cooling medium and an air

-cooled condenser using ambient air as the cooling medium. Additional cooling loads use cooling water

, which rejects heat to an evaporative cooling tower.

Dry Cooling:The cooling system definition results in significant load on an evaporative cooling tower in PC and NGCC cases with CO 2 capture even in the dry cooling scenarios because of the large Econamine cooling water requirement. Since the cooling water temperature achieved in an air

-cooled cooler would be significantly higher than in an evaporative cooling tower, the Econamine performance would also be affected. The quote basis for the Econamine process is for 16°C (60°F) cooling water and no data were available to estimate performance characteristics at higher temperatures. Hence the decision to maintain an evaporative cooling tower for non

-condenser loads even in the dry cooling cases.

Steam exiting the LP condenser is condensed entirely in an air

-cooled condenser. Additional miscellaneous cooling loads use cooling water that rejects heat to an evaporative cooling tower.

The study ambient design conditions are the same as ISO conditions and were presented previously in Exhibit 2-1. The ambient conditions and additional study assumptions result in the following design basis:

Coal feed rate was maintained constant relative to the baseline case for both the parallel and dry cooling scenarios, which resulted in constant gross output but different net output for each case (different auxiliary loads for an air

-cooled condenser).

The condenser approach temperature in the baseline study was 12°C (21°F). Th e approach temperature for the air

-cooled condenser was assumed to be 23°C (42°F)[

83], which maintained a constant condenser temperature and pressure of 38°C (101°F) and 0.0068 MPa (0.9823 psia) for all cases.

Cost and Performance Baseline for Fossil Energy Plants 534 The power requirement for the air

-cooled condenser fans is 3.5 times greater than for evaporative cooling tower fans when the air

-cooled condenser and cooling tower have equivalent heat duty

[84 The baseline study accounted for cooling loads that were modeled such as the steam turbine condenser; the CO 2 capture process; compressor intercoolers; low temperature syngas cooling and sour water stripper condenser (IGCC cases); and an allowance for miscellaneous loads. The miscellaneous loads assigned to each technology were 100 MMBtu/hr for PC and 25 MMBtu/hr for IGCC and NGCC. These loads were maintained at the same values for the parallel and dry cooling cases and were assigned to the evaporative cooling tower.

]. The cost accounts affected by the change in cooling system are shown in Exhibit 7-1 along with the process parameter used for cost scaling and the scaling exponent.

Exhibit 7-1 Cost Accounts Affected by Change in Cooling System Cost Account Scaling Parameter Scaling Exponent Account 3.2:

Water Makeup and Pretreating Raw water makeup 0.71 Account 3.4:

Service Water Systems Raw water makeup 0.71 Account 3.7:

Waste Treatment Equipment Raw water makeup 0.71 Account 8.3a:

Condenser and Auxiliaries Condenser duty 0.67 Account 8.3b:

Air-Cooled Condenser Air-cooled condenser duty 0.70 Account 9.1:

Cooling Towers Cooling tower duty 0.70 Account 9.2

CWP s Circulating water flow rate 0.86 Account 9.3:

CWS Auxiliaries Circulating water flow rate 0.65 Account 9.4:

Circulating Water Piping Circulating water flow rate 0.65 Account 9.5:

Makeup Water System Raw water makeup 0.60 Account 9.6:

Component Cooling Water System Circulating water flow rate 0.65 Account 9.9:

CWS Foundations and Structures Circulating water flow rate 0.60 Account 14.4:

Circulation Water Pumphouse Circulating water flow rate 0.60 Account 14.5:

Water Treatment Buildings Raw water makeup 0.66 Account 14.9:

Waste Treatment Building and Structures Raw water makeup 0.07 Cost and Performance Baseline for Fossil Energy Plants 535 7.1 STUDY RESULTS Dry and parallel cooling systems result in decreased water consumption at the expense of increased cost and reduced efficiency. There is a net increase in capital cost because of the addition of the air

-cooled condenser, which is greater than the reductions realized from the reduced cooling water flow rate and cooling tower duty. The O&M costs change minimally because an increase in fixed O&M costs (maintenance labor and materials) is approximately offset by a decrease in variable O&M costs (raw water and water treatment chemicals).

The normalized raw water withdrawal for the baseline, parallel , and dry cases is shown in Exhibit 7-2. In each case the raw water withdrawal (in gpm) is normalized by the net unit output (in MWs). In Exhibit 7-3 the absolute net reduction in raw water withdrawal (in gpm) for the parallel and dry cooling systems is shown. The raw water source continues to be 50 percent from groundwater and 50 percent from a municipal water supply. The following conclusions can be drawn: The greatest impact on raw water withdrawal is for PC and NGCC non

-capture cases using dry cooling. The steam turbine condenser duty represents over 95 percent of the cooling duty in those cases, and the use of an air

-cooled condenser leaves very little remaining load for the cooling tower. Water demand for FGD in the PC case and for BFW makeup in the PC and NGCC cases is relatively small, resulting in low normalized water withdrawal. The impact is not quite as dramatic in the IGCC non

-capture case because there are additional cooling loads besides the steam turbine condenser, namely low temperature syngas cooling, the ASU Main Air Compressor (MAC) intercoolers, the AGR process, and the SWS condenser.

The smallest impact of dry and parallel cooling on water withdrawal is for PC and NGCC CO 2 capture cases. The Econamine process requires significantly more cooling water than the two

-stage Selexol process used in IGCC cases, and the capture process cooling load is assigned to an evaporative cooling tower. Therefore, the cases using the Econamine process continue to have significant evaporative and blowdown losses from the cooling tower

, which diminishes the water savings of the parallel and dry systems.

NGCC has the lowest normalized raw water withdrawal for CO 2 capture cases using conventional wet cooling. The same is true using a parallel cooling system. However, when using a dry cooling system, the IGCC capture plant has the lowest normalized raw water withdrawal primarily due to the higher steam turbine output of the IGCC plant (240 MW) compared to the NGCC plant (149 MW) and the associated cooling duty.

In all cases the use of parallel and dry cooling has a significant impact on water withdrawal. The absolute water savings ranges from 537 gpm for NGCC with CO 2 capture using parallel cooling to 4,649 gpm for SC PC without capture using dry cooling.

The reduction in water withdrawal comes with a performance and cost penalty. The net plant output decreases slightly because the increase in auxiliary load due to the air

-cooled condenser fan is greater than the decrease due to a reduction in the cooling tower fan and CWP loads.

Cost and Performance Baseline for Fossil Energy Plants 536 Exhibit 7-2 Normalized Raw Water Withdrawal for Baseline, Parallel and Dry Cooling Cases 7.04.72.411.18.45.69.85.61.418.315.111.94.32.20.18.47.36.1 0 2 4 6 8 10 12 14 16 18 20WetHybridDryWetHybridDryWetHybridDryWetHybridDryWetHybridDryWetHybridDryIGCC No CaptureIGCC w/CaptureSCPC No CaptureSCPC w/CaptureNGCC No CaptureNGCC w/CaptureNormalized Raw Water Withdrawal, gpm/net

-MW Cost and Performance Baseline for Fossil Energy Plants 537 Exhibit 7-3 Absolute Decrease in Raw Water Withdrawal for Parallel and Dry Cooling Cases 0 5001,0001,5002,0002,5003,0003,5004,0004,5005,000WetHybridDryWetHybridDryWetHybridDryWetHybridDryWetHybridDryWetHybridDryIGCC No CaptureIGCC w/CaptureSCPC No CaptureSCPC w/CaptureNGCC No CaptureNGCC w/Capture1,4322,8631,4242,8482,3244,6491,7533,5101,1542,3095371,075Water Withdrawal Reduction, gpm Cost and Performance Baseline for Fossil Energy Plants 538 The impact on net plant output relative to the baseline (wet cooling) cases is shown in Exhibit 7-4. The plant de

-rate is greatest for the dry cooling cases because the air

-cooled condenser load increases faster than the cooling tower fan/CWP load decreases. The de

-rate ranges from 100 kW for NGCC with CO 2 capture using parallel cooling to 1,059 kW for SC PC without CO 2 capture using dry cooling. The impact on net plant efficiency is relatively small with the largest decrease less than 0.3 percentage points when going from wet to dry cooling for the SC PC without CO 2 capture case.

Exhibit 7-4 Net Output Reduction Relative to the Baseline (Wet Cooling) Case Technology/Cooling System Net Output Reduction, kW (No CO 2 Capture) Net Plant Efficiency, % Net Output Reduction, kW (With CO 2 Capture) Net Plant Efficiency, % IGCC/Wet N/A 39.75 N/A 31.02 IGCC/Parallel -290 39.73 -280 31.01 IGCC/Dry -690 39.70 -670 30.98 SC PC/Wet N/A 39.28 N/A 28.67 SC PC/Parallel -500 39.25 -300 28.40 SC PC/Dry -1,059 39.21 -630 28.40 NGCC/Wet N/A 50.20 N/A 42.83 NGCC/Parallel -270 50.17 -100 42.82 NGCC/Dry -497 50.15 -200 42.81 The cost impact is more significant than the performance impact. The capital cost of the air

-cooled condenser is only partially offset by the reduction in cost of the cooling tower, CWS, and other water systems impacted by the reduction in water usage. Because there are always miscellaneous cooling loads assigned to the evaporative cooling tower, the cooling tower and CWSs are never eliminated, even in the dry cooling cases. The TOC for each case is shown in Exhibit 7-5. The increase in TOC ranges from $46/kW for NGCC with CO 2 capture using parallel cooling to $109/kW for SC PC with CO 2 capture using dry cooling. The TOC delta between parallel and dry cooling cases is smallest for SC PC with no capture. The increase in cost of the air

-cooled condenser is more nearly offset by reductions in other water related accounts because of the very large decrease in water withdrawal, which decreases from 3,080 gpm in the parall el cooling case to 770 gpm in the dry cooling case.

Cost and Performance Baseline for Fossil Energy Plants 539 The O&M costs stay approximately constant for all cases as discussed at the beginning of Section 7.1. The TOC and O&M costs were used to calculate a COE for each of the cases.

The impact on the COE is shown in Exhibit 7-6. The range of COE increase is from 0.83 mills/kWh (NGCC with capture using parallel cooling) to 2.16 mills/kWh (IGCC with CO 2 capture using dry cooling). The COE actually shows a slight decrease when going from parallel to dry coolin g for the SC PC no capture case for several reasons:

The TOC increase is small because of the large reduction in water requirements as discussed above.

The decrease in variable operating cost is more significant because of the large decrease in water withdrawal.

Cost and Performance Baseline for Fossil Energy Plants 540 Exhibit 7-5 Total Overnight Cost for Baseline, Parallel and Dry Cooling Cases 0 5001,0001,5002,0002,5003,0003,5004,000WetHybridDryWetHybridDryWetHybridDryWetHybridDryWetHybridDryWetHybridDryIGCC No CaptureIGCC w/CaptureSCPC No CaptureSCPC w/CaptureNGCC No CaptureNGCC w/Capture2,3512,3512,3513,4663,4663,4662,0242,0242,0243,5703,5703,570 718 718 7181,4971,4971,497 57 77 72 103 82 92 65 109 56 73 46 66TOC, $/kW (2007$)TOC Baseline, $/kWTOC Increase, $/kW Cost and Performance Baseline for Fossil Energy Plants 541 Exhibit 7-6 COE for Baseline, Parallel and Dry Cooling Systems 0 20 40 60 80 100 120 140WetHybridDryWetHybridDryWetHybridDryWetHybridDryWetHybridDryWetHybridDryIGCC No CaptureIGCC w/CaptureSCPC No CaptureSCPC w/CaptureNGCC No CaptureNGCC w/Capture74.074.074.0110.4110.4110.458.958.958.9106.6106.6106.658.958.958.985.985.985.91.251.601.562.161.411.381.081.820.941.140.831.14COE, mills/kWh (2007$)Baseline COE (Wet Cooling)Incremental COE (Hybrid/Parallel Cooling)

Cost and Performance Baseline for Fossil Energy Plants 542 7.2 SENSITIVITY CASE The assumptions made in this study resulted in a constant fuel feed rate and constant condenser operating condition for all cases. The constant condenser temperature and pressure are the result

of assuming ISO ambient conditions. In reality fossil energy plants are designed for summer and winter temperature extremes. The SC PC case without CO 2 capture was used to examine the effect on a dry and wet cooling system of designing for a high ambient summer temperature.

The ambient design conditions used for the sensitivity study are shown in Exhibit 7-7 and are representative of summertime at Chicago's O'Hare Airport [85 83]. For the dry cooling case a 50°F approach to the dry bulb temperature was assumed

[], which results in a condenser temperature of 138°F. For the wet cooling case the following assumptions result in a condenser temperature of 118°F:

Circulating water is cooled to within 5°F of the WB temperature The cooling water temperature range is 20°F The condenser temperature approach is 20°F Exhibit 7-7 Design Ambient Conditions for SC PC Sensitivity Case Elevation, m (ft) 0 Barometric Pressure, MPa (psia) 0.10 (14.696)

Design Ambient Temperature, Dry Bulb, °C (°F) 31 (88) Design Ambient Temperature, WB, °C (°F) 23 (73) Design Ambient Relative Humidity, %

47 In both cases the net output was maintained at approximately 550 MW, which required an increase in coal feed rate relative to the baseline SC PC cases. The results, presented below, show that the cost and performance penalties of a dry cooling system are greater than when using ISO design conditions.

The normalized water usage for the wet system at high ambient temperature design conditions is 10.3 gpm/MW(net) and for the dry system is 1.4 gpm/MW(net), or a reduction of 86 percent.

The performance penalty is 1.45 percentage points (38.23 to 36.78 percent). The dry cooling case requires an increase in coal feed rate of 3.9 percent to maintain the same net power output as the wet cooling case.

The cost penalty is also greater than in the ISO ambient condition case. The TOC increases by

$145/kW in the dry cooling case compared to $92/kW for dry cooling at ISO conditions. The high ambient temperature case results in cost increases for all cost accounts (rather than just water based accounts) because of the increase in coal feed rate. The COE increases by 3.05 mills/kWh in the dry cooling case at high ambient temperature compared to only 1.38 mills/kWh at ISO conditions. The increase in COE represents a 5.1 percent increase over the wet cooling Cost and Performance Baseline for Fossil Energy Plants 543 case at high ambient temperature. The COE includes the increased fuel cost to maintain a nominal 550 MW net output.

7.3 CONCLUSION

S Parallel and dry cooling have a significant impact on water consumption for all fossil energy technologies examined. The amount of water saved relative to a conventional wet cooling system ranges from 240

- 2,077 million gallons per year. The cost and performance penalty for dry and parallel cooling systems at ISO conditions is less than at a higher summer ambient design temperature that would represent a typical power plant design point. The performance penalty (net plant efficiency) at ISO conditions ranges from 0.006 to 0.270 percentage points and is 1.45 percentage points at the high temperature ambient condition. The cost penalty is primarily capital cost and ranges from 0.83 to 2.16 mills/kWh at ISO conditions and is 3.05 mills/kWh at high ambient temperature using SC PC with no capture and a dry cooling system.

Cost and Performance Baseline for Fossil Energy Plants 544 This page intentionally left blank

Cost and Performance Baseline for Fossil Energy Plants 545 8. GEE offers three design configurations for their gasification system

[GEE IGCC IN QUENCH

-ONLY CONFIGURATION WITH CO 2 CAPTURE 86 Quench: In this configuration, the hot syngas exiting the gasifier passes through a pool of water to quench the temperature to approximately 288°C (550°F) before entering the syngas scrubber. It is the simplest and lowest capital cost design, but also the least efficient.

]: Radiant Only: In this configuration, the hot syngas exiting the gasifier passes through a radiant syngas cooler where it is cooled from about 1

,316°C (2 ,400°F) to 677°C

(1 ,250°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 net power output, higher efficiency, improved reliability/availability relative to the radiant

-convective configuration described below, 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 1

,316°C (2 ,400°F) to 677°C (1 ,250°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 Electric's Polk Power Station.

Chapter 0 of this report examined the radiant only version of the GEE gasifier in both non

-

capture and capture configurations (Cases 1 and 2). This supplementary chapter examines the performance of the GEE gasifier operated in the quench only mode with carbon capture (Case 2A). The balance of this chapter is organized analogously to Section 3.2 of the original report (GEE IGCC Cases), and more specifically Section 3.2.8 , which covers the GEE IGCC with CO 2 capture. However, only deviations from the original chapter are presented here to avoid needless repetitio n: Process and System Description provides an overview of the technology operation as applied to the GE IGCC operated in quench only mode. The systems that are common to all gasifiers were covered in Section 3.1 and features unchanged from the radiant only operation were covered in Section 3.2.8. Only features that are unique to quench only operation are discussed further in this section.

Key Assumptions is a summary of study and modeling assumptions relevant to the GEE IGCC cases.

Sparing Philosophy is unchanged from the radiant only cases and not repeated here.

Performance Results provides the main modeling results from quench only configuration, including the performance summary, environmental performance, carbon balance, sulfur Cost and Performance Baseline for Fossil Energy Plants 546 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 2A.

8.1 CASE 2 A - GEE IGCC IN QUENCH ONLY MODE WITH CO 2 CAPTURE Case 2A is configured to produce electric power with CO 2 capture. The plant configuration is the same as the GEE IGCC Case 2 with the exception that the gasifier is operated in quench only mode. The gross power output from the plant is constrained by the capacity of the two CTs, and since the CO 2 capture process increases the auxiliary load on the plant, the net output is significantly reduced relative to Case 1.

The process description for Case 2A is similar to Case 2 with exception of the gasifier operating mode. A BFD and stream tables for Case 2A are shown in Exhibit 8-1 and Exhibit 8-2 , respectively. Instead of repeating the entire process description, only differences from Case 2 are reported here.

The gasification process is the same as Case 2 with the exception that the syngas exiting the gasifier passes through a water quench where the temperature is reduced fro m 1 ,316°C (2 ,400°F) to 288°C (550°F). The total coal feed to the two gasifiers is 5,301 tonnes/day (5,844 TPD)

(stream 6) and the ASU provides 4,343 tonnes/day (4,787 TPD) of 95 percent oxygen to the gasifier and Claus plant (streams 3 and 5).

Gasification Particulate is largely removed in the quench tank and no additional heat recovery occurs prior to the syngas scrubber.

Raw Gas Cooling/Particulate Removal The outlet temperature from the syngas scrubber is 227°C (440°F) (stream 10). Syngas Scrubber/Sour Water Stripper The SGS process is the same as described for Case 2 with a 97 percent overall conversion of the CO to CO 2. The warm syngas from the second stage of SGS (stream 12) is cooled to 244°C (471°F) by heating the syngas entering the first shift reactor. The syngas is then cooled to 193°C (380°F) by producing IP steam that is sent to the RH in the HRSG. 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. Sour Gas Shift (SGS)

Cost and Performance Baseline for Fossil Energy Plants 547 Exhibit 8-1 Case 2A Block Flow Diagram, GEE Quench Only IGCC with CO 2 Capture Cost and Performance Baseline for Fossil Energy Plants 548 Exhibit 8-2 Case 2A Stream Table, GEE Quench Only IGCC with CO 2 Capture 1 2 3 4 5 6 7 8 9 10 11 12V-L Mole Fraction Ar0.00920.01650.03180.00230.03180.00000.00000.00000.00860.00530.00000.0053 CH 40.00000.00000.00000.00000.00000.00000.00000.00000.00110.00070.00000.0007 CO0.00000.00000.00000.00000.00000.00000.00000.00000.35760.21970.00000.0061 CO 20.00030.00540.00000.00000.00000.00000.00000.00000.13800.08480.00000.2985COS0.00000.00000.00000.00000.00000.00000.00000.00000.00020.00010.00000.0000 H 20.00000.00000.00000.00000.00000.00000.00000.00000.34060.20930.00000.4229 H 2 O0.00990.13550.00000.00030.00000.00000.99970.00000.13690.47001.00000.2562 HCl0.00000.00000.00000.00000.00000.00000.00000.00000.00080.00010.00000.0001 H 2 S0.00000.00000.00000.00000.00000.00000.00000.00000.00730.00450.00000.0046 N 20.77320.70770.01780.99200.01780.00000.00000.00000.00700.00430.00000.0043 NH 30.00000.00000.00000.00000.00000.00000.00030.00000.00190.00130.00000.0013 O 20.20740.13490.95040.00540.95040.00000.00000.00000.00000.00000.00000.0000 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000Total1.00001.00001.00001.00001.00000.00001.00000.00001.00001.00001.00001.0000V-L Flowrate (kgmol/hr)27,3671,660 9720,0455,526 05,037 023,12137,625 037,625V-L Flowrate (kg/hr)789,73145,6073,132562,472177,815 090,741 0465,209726,195 0726,195Solids Flowrate (kg/hr) 0 0 0 0 0220,888 024,235 0 0 0 0Temperature (°C) 15 18 32 93 32 15 1461,3161,316 227 288 250Pressure (MPa, abs)0.100.110.862.650.860.105.795.625.625.585.525.45Enthalpy (kJ/kg)

A30.2335.6226.6792.5026.67---0.00---2,631.861,479.522,918.181,017.26Density (kg/m 3)1.21.511.024.411.0---867.1---8.525.925.624.5V-L Molecular Weight28.85727.47932.18128.06032.181---18.015---20.12119.30118.01519.301V-L Flowrate (lbmol/hr)60,3343,659 21544,19312,182 011,105 050,97282,948 082,948V-L Flowrate (lb/hr)1,741,060100,5456,9061,240,039392,015 0200,050 01,025,6111,600,986 01,600,986Solids Flowrate (lb/hr) 0 0 0 0 0486,976 053,430 0 0 0 0Temperature (°F) 59 65 90 199 90 59 2952,4002,400 440 550 481Pressure (psia)14.716.4125.0384.0125.014.7840.0815.0815.0810.0800.0790.0Enthalpy (Btu/lb)

A13.015.311.539.811.5------1,131.5636.11,254.6437.3Density (lb/ft 3)0.0760.0910.6871.5210.687---54.131---0.5301.6191.5971.529A - Reference conditions are 32.02 F & 0.089 PSIA Cost and Performance Baseline for Fossil Energy Plants 549 Exhibit 8-2 Case 2A Stream Table, GEE Quench Only IGCC with CO 2 Capture (Continued) 13 14 15 16 17 18 19 20 21 22 23 24V-L Mole Fraction Ar0.00710.00710.01150.01150.00020.00180.00000.01030.00920.00910.00910.0000 CH 40.00090.00090.00150.00150.00000.00040.00000.00000.00000.00000.00000.0000 CO0.00820.00810.01300.01300.00020.00230.00000.00610.00000.00000.00000.0000 CO 20.40170.40530.05010.05010.99480.52180.00000.66060.00030.00830.00830.0000COS0.00000.00000.00000.00000.00000.00020.00000.00000.00000.00000.00000.0000 H 20.56900.56470.91330.91330.00480.10290.00000.25960.00000.00000.00000.0000 H 2 O0.00120.00120.00010.00010.00000.02250.00000.00170.00990.12220.12221.0000 HCl0.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 H 2 S0.00610.00610.00000.00000.00000.34720.00000.00430.00000.00000.00000.0000 N 20.00580.00650.01050.01050.00000.00080.00000.05740.77320.75410.75410.0000 NH 30.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 O 20.00000.00000.00000.00000.00000.00000.00000.00000.20740.10640.10640.0000 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000Total1.00001.00001.00001.00001.00001.00000.00001.00001.00001.00001.00001.0000V-L Flowrate (kgmol/hr)27,96328,35717,42417,42410,414 496 0 394110,253139,653139,65320,010V-L Flowrate (kg/hr)552,101564,70590,45590,455456,19017,654 012,6043,181,5573,834,4853,834,485360,491Solids Flowrate (kg/hr) 0 0 0 0 0 05,523 0 0 0 0 0Temperature (°C) 35 35 35 195 51 48 178 38 15 562 132 534Pressure (MPa, abs)5.175.15.1373.17215.2700.1630.1195.5120.1010.1050.10512.512Enthalpy (kJ/kg)

A36.9436.2194.9241,117.278-162.29274.702---5.84230.227834.643343.5003,432.968Density (kg/m 3)41.041.210.24.2641.82.25,280.677.31.20.40.936.7V-L Molecular Weight19.744 205.1915.19143.80435.590---31.96628.85727.45727.45718.015V-L Flowrate (lbmol/hr)61,64762,51638,41438,41422,9601,094 0 869243,066307,881307,88144,115V-L Flowrate (lb/hr)1,217,1741,244,961199,419199,4191,005,72838,921 027,7867,014,1338,453,5938,453,593794,747Solids Flowrate (lb/hr) 0 0 0 0 0 012,177 0 0 0 0 0Temperature (°F) 95 95 95 383 124 119 352 100 591,044 270 994Pressure (psia)750.0745.0745.0460.02,214.723.717.3799.514.715.215.21,814.7Enthalpy (Btu/lb)

A15.915.683.8480.3-69.832.1---2.513.0358.8147.71,475.9Density (lb/ft 3)2.562 30.6360.26140.0650.137329.6554.8230.0760.0260.0532.293 Cost and Performance Baseline for Fossil Energy Plants 550 Mercury removal and the AGR process are the same as in Case 2.

Mercury Removal and Acid Gas Removal The AGR process in Case 2A is a two stage Selexol process where H 2S is removed in the first stage and CO 2 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 CO 2-rich stream and an acid gas feed to the Claus plant. The acid gas (stream 18) contains 35 percent H 2S and 52 percent CO 2 with the balance primarily H

2. The CO 2 compression and dehydration scheme is the same as for Case 2.

CO 2 Compression and Dehydration The Claus plant is the same as Case 2 with the following exceptions:

Claus Unit 5,523 kg/h r (12,177 lb/h r) of sulfur (stream 19) are produced The waste heat boiler generates 12,957 kg/h r (28,564 lb/h r) of 3.0 MPa (430 psia) steam.

Clean syngas from the AGR plant is heated to 241°C (465°F) using first hot water from the syngas scrubber followed by 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 (1

,044°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 nominal 12.4 MPa/538°C/538°C (1800 psig/1000°F/1000°F) steam cycle.

Power Block The same elevated pressure ASU is used in Case 2A and produces 4,343 tonnes/day (4,787 TPD) of 95 mol% oxygen and 14,595 tonnes/day (16,087 TPD) of nitrogen. There is no integration between the ASU and the CT. Air Separation Unit 8.1.1 System assumptions for Case 2A are shown in Key System Assumptions Exhibit 8-3.

Cost and Performance Baseline for Fossil Energy Plants 551 Exhibit 8-3 GEE IGCC Plant Study Configuration Matrix Case 2 A Gasifier Pressure, MPa (psia) 5.6 (815) O 2:Coal Ratio, kg O 2/kg dry coal 0.9 1 Carbon Conversion, %

98 Syngas HHV at Gasifier Outlet, kJ/Nm 3 (Btu/scf) 8, 655 (2 32) Steam Cycle, MPa/°C/°C (psig/ F/ F) 12.4/53 4/53 4 (1800/994/994) Condenser Pressure, mm Hg (in Hg) 51 (2.0) CT 2x Advanced F Class (232 MW output each)

Gasifier Technology GEE Quench Only Oxidant 95 vol% Oxygen Coal Illinois No. 6 Coal Slurry Solids Con tent, % 63 COS Hydrolysis Occurs in SGS SGS Yes H 2S Separation Selexol 1 st Stage Sulfur Removal, %

99.8 Sulfur Recovery Claus Plant with Tail Gas Recycle to Selexol/ Elemental Sulfur Particulate Control Water Quench, Scrubber, and AGR Absorber Mercury Control Carbon Bed NOx Control MNQC (LNB) and N 2 Dilution CO 2 Separation Selexol 2nd Stage CO2 Capture 90.2% CO 2 Sequestration Off-site Saline Formation

Cost and Performance Baseline for Fossil Energy Plants 552 8.1.2 The plant produces a net output of 494 MW at a net plant efficiency of 29.7 percent (HHV basis). Overall performance for the entire plant is summarized in Case 2 A Performance Results Exhibit 8-4 , which includes auxiliary power requirements. The ASU accounts for 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 CO 2 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 about 5 percent of the load, leaving 9 percent of the auxiliary load for all other systems.

Cost and Performance Baseline for Fossil Energy Plants 553 Exhibit 8-4 Case 2A Plant Performance Summary POWER

SUMMARY

(Gross Power at Generator Terminals, kWe)

Case 2 Case 2A Gas Turbine Power 464,000 464,000 Sweet Gas Expander Power 6,500 6,600 Steam Turbine Power 263,500 213,600 TOTAL POWER, kWe 734,000 684,200 AUXILIARY LOAD

SUMMARY

, kWe Coal Handling 470 470 Coal Milling 2,270 2,270 Sour Water Recycle Slurry Pump 190 200 Slag Handling 1,160 1,160 Air Separation Unit Auxiliaries 1,000 1,000 Air Separation Unit Main Air Compressor 67,330 67,350 Oxygen Compressor 10,640 10,640 Nitrogen Compressors 35,640 35,630 CO 2 Compressor 31,160 31,130 Boiler Feedwater Pumps 4,180 2,620 Condensate Pump 280 230 Quench Water Pump 540 1,270 Circulating Water Pump 4,620 4,810 Ground Water Pumps 530 550 Cooling Tower Fans 2,390 2,490 Scrubber Pumps 230 480 Acid Gas Removal 19,230 19,210 Gas Turbine Auxiliaries 1,000 1,000 Steam Turbine Auxiliaries 100 100 Claus Plant/TGTU Auxiliaries 250 250 Claus Plant TG Recycle Compressor 1,780 1,800 Miscellaneous Balance of Plant 2 3,000 3,000 Transformer Losses 2,760 2,600 TOTAL AUXILIARIES, kWe 190,750 190,260 NET POWER, kWe 543,250 493,940 Net Plant Efficiency, % (HHV) 32.6 29.7 Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,034 (10,458) 12,135 (11,502)

CONDENSER COOLING DUTY 10 6 kJ/h r (10 6 Btu/h r) 1,509 (1,430) 1,467 (1,390)

CONSUMABLES As-Received Coal Feed, kg/h r (lb/h r) 220,904 (487,011) 220,888 (486,976)

Thermal Input, kWt 1 1,665,074 1,664,954 Raw Water Withdrawal, m 3/min (gpm) 22.0 (5,815) 23.2 (6,117)

Raw Water Consumption, m 3/min (gpm) 17.9 (4,739) 18.9 (4,993) 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

Cost and Performance Baseline for Fossil Energy Plants 554 The environmental targets for emissions of Hg, NOx, SO 2, and PM were presented in Section Environmental Performance 2.4. A summary of the plant air emissions for Case 2A is presented in Exhibit 8-5. Exhibit 8-5 Case 2A Air Emissions kg/GJ (lb/10 6 Btu) Tonne/year (tons/year) @

80% CF kg/MWh (lb/MWh) SO 2 0.001 (0.002) 39 (43) 0.008 (.018)

NOx 0.021 (0.049) 878 (968) 0.183 (.404)

Particulates 0.003 (0.0071) 128 (141) 0.027 (.059)

Hg 2.46E-7 (5.71E-7) 0.010 (0.011) 2.15E-6 (4.74E-6) CO 2 8.5 (19.8) 358,390 (395,058) 75 (165) CO 2 1 104 (228) 1 CO 2 emissions based on net power instead of gross power The low level of SO 2 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 CO 2 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 less tha n 1 ppmv. The H 2 S-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 H 2S and then recycled back to the Selexol process, thereby eliminating the need for a tail gas treatment unit.

NO x emissions are limited by nitrogen dilution to 15 ppmvd (as NO 2 @15 percent O 2). Ammonia in the syngas is removed with process condensate prior to the low

-temperature AGR process. This helps lower NO x 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 percent of the CO 2 from the syngas is captured in the AGR system and compressed for sequestration.

The carbon balance for the plant is shown in Exhibit 8-6. 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 CO 2 in the stack gas, ASU vent gas, and the captured CO 2 product. The CO 2 capture efficiency is defined as the amount of carbon in the CO 2 product stream relative to the amount of carbon in the coal less carbon contained in the slag, represented by the following fraction:

Cost and Performance Baseline for Fossil Energy Plants 555 (Carbon in CO 2 Product)/[(Carbon in the Coal)

-(Carbon in Slag)] or 274,397/(310,421-6,208)

100 or 90.2 percent Exhibit 8-6 Case 2A Carbon Balance Carbon In, kg/hr (lb/hr)

Carbon Out, kg/h r (lb/hr) Coal 140,805 (310,421)

Slag 2,816 (6,208)

Air (CO 2) 540 (1,191)

Stack Gas 13,957 (30,770)

ASU Vent 107 (237) CO 2 Product 124,464 (274,397)

Total 141,345 (311,612)

Exhibit 8-7 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 co-sequestered with the CO 2 product, and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible.

Exhibit 8-7 Case 2A Sulfur Balance Sulfur In, kg/hr (lb/hr)

Sulfur Out, kg/h r (lb/hr) Coal 5,536 (12,206) Elemental Sulfur 5,523 (12,177)

Stack Gas 3 (6) CO 2 Product 10 (23) Total 5,536 (12,206)

Total 5,536 (12,206)

Exhibit 8-8 shows the overall water balance for the plant. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent). 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 that water is re

-used as internal recycle. Raw water withdrawal is the difference between water demand and internal recycle.

Some process water is returned to the source via cooling tower and sour water stripper blowdown. The difference between raw water withdrawal and process water discharge is raw water consumption, or the net impact on the water source.

Cost and Performance Baseline for Fossil Energy Plants 556 Exhibit 8-8 Case 2A Water Balance Water Use Water Demand m 3/min (gpm) Internal Recycle m 3/min (gpm) Raw Water Withdrawal m 3/min (gpm) Process Water Discharge m 3/min (gpm) Raw Water Consumption m 3/min (gpm) Slag Handling 0.53 (139) 0.53 (139) 0.0 (0) 0.0 (0) 0.0 (0) Slurry Water 1.5 (400) 1.5 (400) 0.0 (0) 0.0 (0) 0.0 (0) Quench Water 6.7 (1,759) 1.9 (493) 4.8 (1,267) 0.0 (0) 4.8 (1,267)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.04 (10) -0.04 (-10) Condenser Makeup Gasifier Steam Shift Steam BFW Makeup 0.15 (40)

0.15 (40) 0.0 (0) 0.15 (40)

0.15 (40) 0.0 (0) 0.15 (40) Cooling Tower Makeup BFW Blowdown SWS Blowdown SWS Excess 18.8 (4,954) 0.54 (143) 0.15 (40) 0.39 (103) 18.2 (4,811)

-0.15 (-40) -0.39 (-103) 4.2 (1,114) 14.0 (3,697) Total 27.6 (7,292) 4.4 (1,174) 23.2 (6,117) 4.3 (1,124) 18.9 (4,993)

A plant heat and material balance is presented in Energy Balance Exhibit 8-9 through Exhibit 8-11 with a n overall plant energy balance presented in tabular form in Exhibit 8-12.

Cost and Performance Baseline for Fossil Energy Plants 557 Exhibit 8-9 Case 2A Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA DOE/NETL D UAL T RAIN IGCC P LANT C ASE 2 A H EAT AND M ATERIAL F LOW D IAGRAM B ITUMINOUS BASELINE S TUDY C ASE 2 A GEE G ASIFIER (Q UENCH O NLY)ASU AND G ASIFICATION DWG. NO.BB-HMB-CS-2 A-PG-1 P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas P AGES 1 OF 3 Ambient Air Four Stage Air Compressor Elevated Pressure ASU Four Stage N 2 Compressor Four Stage O 2 Compressor ASU Vent Water Steam Gross Plant Power

684 MWe Auxiliary Load

190 MWe Net Plant Power

494 MWe Net Plant Efficiency , HHV: 29.7%Net Plant Heat Rate

11 , 502 BTU/KWe N 2 to GT Combustor 1 , 741 , 060 W 59.0 T 14.7 P 13.0 H 392 , 015 W 90.0 T 125.0 P 11.5 H 392 , 015 W 241.2 T 940.0 P 40.8 H To Claus Plant 6 , 906 W 90.0 T 125.0 P 11.5 H 100 , 545 W 64.7 T 16.4 P 15.3 H 1 , 083 , 228 W 90.0 T 56.4 P 14.2 H 156 , 811 W 50.0 T 182.0 P 2.9 H 5 1 3 2 Slurry Mix Tank Milled Coal Slag 486 , 976 W 59.0 T 14.7 P 200 , 050 W 295.0 T 840.0 P 240.4 H 53 , 430 W 2 , 400.0 T 815.0 P 677 , 288 W 385.0 T 384.0 P 87.2 H 687 , 025 W 159.8 T 840.0 P 2 , 952.8 H 100.0 T 189.5 P 18.0 H 6 677 , 288 W 199.0 T 384.0 P 39.8 H N 2 to GT Combustor N 2 Boost Compressor 562 , 752 W 199.0 T 384.0 P 39.8 H 562 , 752 W 385.0 T 469.0 P 87.0 H Black Water Flash Tank Knockout Drum Vent To Claus Unit Raw Fuel Gas CWS CWR Fines Process Water From Sour Water Stripper Syngas Scrubber Slag Quench Section Drag Conveyor 4 1 , 025 , 611 W 2 , 400.0 T 815.0 P 1 , 131.5 H 1 , 600 , 986 W 440.0 T 810.0 P 636.1 H Syngas Quench 1 , 905 , 234 W 550.0 T 815.0 P 761.0 H 8 9 10 Sour Water 7 HP BFW Saturated Steam To HRSG HP Superheater Radiant Syngas Cooler Cost and Performance Baseline for Fossil Energy Plants 558 Exhibit 8-10 Case 2A Syngas Cleanup Heat and Mass Balance Schematic Mercury Removal Knock Out Drum Syngas Preheater Sour Drum Process Condensate to Syngas Scrubber Makeup Water Claus Plant Tail Gas Furnace Catalytic Reactor Beds Sulfur Knock Out From ASU Syngas Coolers Sour Stripper 1 , 600 , 986 W 440.0 T 810.0 P 636.1 H 1 , 244 , 961 W 94.6 T 745.0 P 15.6 H 38 , 921 W 119.0 T 23.7 P 199 , 419 W 383.2 T 460.0 P 480.3 H 12 , 177 W 36 , 693 W 450.0 T 12.3 P 467.0 H 3 , 043 W 246.5 T 65.0 P 500.1 H 6 , 906 W 90.0 T 125.0 P 11.5 H N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA DOE/NETL D UAL T RAIN IGCC P LANT C ASE 2 A H EAT AND M ATERIAL F LOW D IAGRAM B ITUMINOUS BASELINE S TUDY C ASE 2 A GEE G ASIFIER (Q UENCH O NLY)G AS CLEANUP SYSTEM DWG. NO.BB-HMB-CS-2 A-PG-2 P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas P AGES 2 OF 3 Sour Gas Sour Water Water Steam Gross Plant Power

684 MWe Auxiliary Load

190 MWe Net Plant Power

494 MWe Net Plant Efficiency , HHV: 29.7%Net Plant Heat Rate

11 , 502 BTU/KWe 19 13 20 CO 2 Tailgas 30 , 265 W 120.0 T 10.6 P 112.7 H 1 , 217 , 174 W 94.9 T 750.0 P 15.9 H 8 , 907 W 114.5 T 10.6 P 40.3 H 3 27 , 786 W 100.0 T 799.5 P Raw Syngas 15 199 , 419 W 94.6 T 745.0 P 83.8 H Claus Oxygen Preheater 6 , 906 W 450.0 T 124.5 P 91.9 H 18 Fuel Gas Expander Fuel Gas To GT 16 199 , 419 W 465.0 T 740.0 P 595.4 H High Temperature Shift #1 Low Temperature Shift #2 Shift Steam 12 11 COS Hydrolysis Preheater 1 , 600 , 986 W 450.0 T 805.0 P 621.4 H 0 W 1 , 600 , 986 W 449.7 T 800.0 P 621.4 H 781.7 T 800.0 P 606.0 H 425.0 T 800.0 P 440.0 H 1 , 600 , 986 W 481.4 T 790.0 P 437.3 H 1 , 600 , 986 W 471.1 T 785.0 P 432.6 H Two-Stage Selexol Clean Gas CO 2 Acid Gas Multistage Intercooled CO 2 Compressor Interstage Knockout CO 2 Product 17 10 14 1 , 005 , 728 W 123.8 T 2 , 214.7 P Tail Gas Recycle Compressor Hydrogenation and Tail Gas Cooling Cost and Performance Baseline for Fossil Energy Plants 559 Exhibit 8-11 Case 2A Combined Cycle Power Generation Heat and Mass Balance Schematic HRSG HP Turbine IP Turbine Nitrogen Diluent Intake Ambient Air Steam Seal Regulator Ip Extraction Steam To 250 PSIA Header LP Process Header Blowdown Flash To WWT Gland Steam Condenser Condensate to Gasification Island HP BFW to Radiant Syngas Cooler HP Saturated Steam to HRSG Superheater LP Turbine Stack Expander Compressor Fuel Gas Deaerator IP BFW Generator Generator Condensate Pump HP Pump Steam Turbine LP Pump Advanced F

-Class Gas Turbine MP Flash Bottoms LP Flash Tops 7 , 014 , 133 W 59.0 T 14.7 P 13.0 H 1 , 523 , 839 W 101.1 T 1.0 P 69.1 H 8 , 453 , 593 W 269.6 T 15.2 P 147.7 H 199 , 419 W 383.2 T 460.0 P 480.3 H 8 , 453 , 593 W 1 , 043.8 T 15.2 P 358.8 H From Gasifier Island Preheating To Claus LP BFW 794 , 747 W 993.8 T 1 , 814.7 P 1 , 475.9 H 6 , 774 W 298.0 T 65.0 P 1 , 179.0 H 813 , 698 W 278.8 T 2 , 250.7 P 252.3 H 18 , 959 W 585.0 T 2 , 000.7 P 593.3 H 1 , 491 , 866 W 441.1 T 65.0 P 1 , 252.8 H 1 , 523 , 839 W 103.2 T 120.0 P 71.4 H 1 , 523 , 839 W 235.0 T 105.0 P 203.7 H 1 , 400 W 614.9 T 65.0 P 1 , 338.7 H 1 , 400 W 212.0 T 14.7 P 179.9 H IP Pump N OTES: 1. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA DOE/NETL D UAL T RAIN IGCC P LANT C ASE 2 A H EAT AND M ATERIAL F LOW D IAGRAM B ITUMINOUS BASELINE S TUDY C ASE 2 A GEE G ASIFIER (Q UENCH O NLY)P OWER B LOCK S YSTEM DWG. NO.BB-HMB-CS-2 A-PG-3 P LANT P ERFORMANCE S UMMARY L EGEND P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M/HR H E NTHALPY , BTU/LB M MW E P OWER , M EGAWATTS E LECTRICAL Air Oxygen Nitrogen Coal/Char/Slurry/Slag Synthesis Gas P AGES 3 OF 3 Sour Gas Sour Water Water Steam Gross Plant Power

684 MWe Auxiliary Load

190 MWe Net Plant Power

494 MWe Net Plant Efficiency , HHV: 29.7%Net Plant Heat Rate

11 , 502 BTU/KWe 21 22 24 16 23 Flue Gas HOT WELL CONDENSER Make-up 19 , 812 W 59.0 T 14.7 P 27.1 H 9 , 025 W 660.6 T 501.4 P 1 , 334.6 H 9 , 761 W 614.9 T 65.0 P 1 , 338.7 H 33 , 608 W 851.8 T 280.0 P 1 , 448.6 H 798 W 993.8 T 1 , 814.7 P 1 , 475.9 H 1 , 337 W 504.7 T 65.0 P 1 , 284.4 H Cost and Performance Baseline for Fossil Energy Plants 560 This page intentionally left blank

Cost and Performance Baseline for Fossil Energy Plants 561 Exhibit 8-12 Case 2A Overall Energy Balance HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)

Coal 5,994 (5,681) 5.0 (4.7) 5,999 (5,686)

ASU Air 23.9 (22.6) 24 (23) GT Air 96.2 (91.2) 96 (91) Water 87.1 (82.5) 87 (83) Auxiliary Power 685 (649) 685 (649) TOTAL 5,994 (5,681) 212.1 (201.1) 685 (649) 6,891 (6,531)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 1.6 (1.5) 2 (2) Slag 92 (88) 37.8 (35.9) 130 (123) Sulfur 51 (49) 0.6 (0.6) 52 (49) CO 2 -74.0 (-70.2) -74 (-70) Cooling Tower Blowdown 31.3 (29.7) 31 (30) HRSG Flue Gas 1,317 (1,248) 1,317 (1,248)

Condenser 1,452 (1,377) 1,452 (1,377)

Non-Condenser Cooling Tower Loads 1 794 (753) 794 (753) Process Losses 2 723 (686) 723 (686) Power 2,463 (2,335) 2,463 (2,335)

TOTAL 144 (136) 4,284 (4,061) 2,463 (2,335) 6,891 (6,531) 1 Includes ASU compressor intercoolers, CO 2 compressor intercoolers, sour water stripper condenser, and syngas cooler (low level heat rejection) 2 Calculated by difference to close the energy balance 8.1.3 Major equipment items for the GEE quench only gasifier with CO 2 capture are shown in the following tables. 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.

Case 2 A - Major Equipment List

Cost and Performance Baseline for Fossil Energy Plants 562 ACCOUNT 1 COAL HANDLING Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Bottom Trestle Dumper and Receiving HoppersN/A181 tonne (200 ton) 2 0 2FeederBelt572 tonne/hr (630 tph) 2 0 3Conveyor No. 1Belt1,134 tonne/hr (1,250 tph) 1 0 4Transfer Tower No. 1EnclosedN/A 1 0 5Conveyor No. 2Belt1,134 tonne/hr (1,250 tph) 1 0 6As-Received Coal Sampling SystemTwo-stageN/A 1 0 7Stacker/ReclaimerTraveling, linear1,134 tonne/hr (1,250 tph) 1 0 8Reclaim HopperN/A45 tonne (50 ton) 2 1 9FeederVibratory181 tonne/hr (200 tph) 2 1 10Conveyor No. 3Belt w/ tripper363 tonne/hr (400 tph) 1 0 11Crusher TowerN/AN/A 1 0 12Coal Surge Bin w/ Vent FilterDual outlet181 tonne (200 ton) 2 0 13CrusherImpactor reduction8 cm x 0 - 3 cm x 0(3" x 0 1/4" x 0) 2 0 14As-Fired Coal Sampling SystemSwing hammerN/A 1 1 15Conveyor No. 4Belt w/tripper363 tonne/hr (400 tph) 1 0 16Transfer Tower No. 2EnclosedN/A 1 0 17Conveyor No. 5Belt w/ tripper363 tonne/hr (400 tph) 1 0 18Coal Silo w/ Vent Filter and Slide GatesField erected816 tonne (900 ton) 3 0 Cost and Performance Baseline for Fossil Energy Plants 563 ACCOUNT 2 COAL PREPARATION AND FEED Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1FeederVibratory82 tonne/h (90 tph) 3 0 2Conveyor No. 6Belt w/tripper245 tonne/h (270 tph) 1 0 3Rod Mill Feed HopperDual Outlet490 tonne (540 ton) 1 0 4Weigh FeederBelt118 tonne/h (130 tph) 2 0 5Rod MillRotary118 tonne/h (130 tph) 2 0 6Slurry Water Storage Tank with AgitatorField erected299,883 liters (79,220 gal) 2 0 7Slurry Water PumpsCentrifugal833 lpm (220 gpm) 2 1 8Trommel ScreenCoarse172 tonne/h (190 tph) 2 0 9Rod Mill Discharge Tank with AgitatorField erected392,285 liters (103,630 gal) 2 0 10Rod Mill Product PumpsCentrifugal3,407 lpm (900 gpm) 2 2 11Slurry Storage Tank with AgitatorField erected1,176,894 liters (310,900 gal) 2 0 12Slurry Recycle PumpsCentrifugal6,435 lpm (1,700 gpm) 2 2 13Slurry Product PumpsPositive displacement3,407 lpm (900 gpm) 2 2 Cost and Performance Baseline for Fossil Energy Plants 564 ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Demineralized Water Storage TankVertical, cylindrical, outdoor810,078 liters (214,000 gal) 2 0 2Condensate PumpsVertical canned6,397 lpm @ 91 m H2O(1,690 gpm @ 300 ft H2O) 2 1 3Deaerator (integral w/ HRSG)Horizontal spray type464,932 kg/hr (1,025,000 lb/hr) 2 0 4Intermediate Pressure Feedwater PumpHorizontal centrifugal, single stage6,587 lpm @ 27 m H2O(1,740 gpm @ 90 ft H2O) 2 1 5High Pressure Feedwater Pump No. 1Barrel type, multi-stage, centrifugalHP water: 3,520 lpm @ 1,859 m H2O (930 gpm @ 6,100 ft H2O)2 1 6High Pressure Feedwater Pump No. 2Barrel type, multi-stage, centrifugalIP water: 1,590 lpm @ 223 m H2O (420 gpm @ 730 ft H2O) 2 1 7Auxiliary BoilerShop fabricated, water tube18,144 kg/hr, 2.8 MPa, 343°C(40,000 lb/hr, 400 psig, 650°F) 1 0 8Service Air CompressorsFlooded Screw28 m3/min @ 0.7 MPa(1,000 scfm @ 100 psig) 2 1 9Instrument Air DryersDuplex, regenerative28 m3/min (1,000 scfm) 2 1 10Closed Cylce Cooling Heat ExchangersPlate and frame451 GJ/hr (428 MMBtu/hr) each 2 0 11Closed Cycle Cooling Water PumpsHorizontal centrifugal162,016 lpm @ 21 m H2O(42,800 gpm @ 70 ft H2O) 2 1 12Engine-Driven Fire PumpVertical turbine, diesel engine3,785 lpm @ 107 m H2O(1,000 gpm @ 350 ft H2O) 1 1 13Fire Service Booster PumpTwo-stage horizontal centrifugal2,650 lpm @ 76 m H2O(700 gpm @ 250 ft H2O) 1 1 14Raw Water PumpsStainless steel, single suction5,867 lpm @ 18 m H2O(1,550 gpm @ 60 ft H2O) 2 1 15Ground Water PumpsStainless steel, single suction2,915 lpm @ 268 m H2O (770 gpm @ 880 ft H2O) 4 1 16Filtered Water PumpsStainless steel, single suction3,899 lpm @ 49 m H2O(1,030 gpm @ 160 ft H2O) 2 1 17Filtered Water TankVertical, cylindrical1,862,423 liter (492,000 gal) 2 0 18Makeup Water DemineralizerAnion, cation, and mixed bed227 lpm (60 gpm) 2 0 19Liquid Waste Treatment System10 years, 24-hour storm 1 0 Cost and Performance Baseline for Fossil Energy Plants 565 ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1GasifierPressurized slurry-feed, entrained bed2,903 tonne/day, 5.6 MPa(3,200 tpd, 814.96 psia) 2 0 2Synthesis Gas QuenchPressurized quench tank255,826 kg/hr (564,000 lb/hr) 2 0 3Syngas Scrubber Including Sour Water StripperVertical upflow475,365 kg/hr (1,048,000 lb/hr) 2 0 4Raw Gas CoolersShell and tube with condensate drain399,615 kg/hr (881,000 lb/hr) 8 0 5Raw Gas Knockout DrumVertical with mist eliminator304,360 kg/hr, 35°C, 5.2 MPa(671,000 lb/hr, 95°F, 755 psia) 2 0 6Synthesis Gas ReheaterShell and tube49,895 kg/hr (110,000 lb/hr) 2 0 7Flare StackSelf-supporting, carbon steel, stainless steel top, pilot ignition475,365 kg/hr (1,048,000 lb/hr) syngas 2 0 8ASU Main Air CompressorCentrifugal, multi-stage5,947 m3/min @ 1.3 MPa(210,000 scfm @ 190 psia) 2 0 9Cold BoxVendor design2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2 0 10Oxygen CompressorCentrifugal, multi-stage1,189 m3/min (42,000 scfm)Suction - 0.9 MPa (130 psia)Discharge - 6.5 MPa (940 psia) 2 0 11Primary Nitrogen CompressorCentrifugal, multi-stage3,794 m3/min (134,000 scfm)Suction - 0.4 MPa (60 psia)Discharge - 2.7 MPa (390 psia) 2 0 12Secondary Nitrogen CompressorCentrifugal, single-stage538 m3/min (19,000 scfm)Suction - 1.2 MPa (180 psia)Discharge - 2.7 MPa (390 psia) 2 0 13Syngas Dilution Nitrogen Boost CompressorCentrifugal, single-stage1,982 m3/min (70,000 scfm)Suction - 2.6 MPa (380 psia)Discharge - 3.2 MPa (470 psia) 2 0 Cost and Performance Baseline for Fossil Energy Plants 566 ACCOUNT 5 SYNGAS CLEANUP ACCOUNT 5B CO 2 COMPRESSION ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Mercury AdsorberSulfated carbon bed303,453 kg/hr (669,000 lb/hr) 35°C (95°F) 5.2 MPa (750 psia) 2 0 2Sulfur PlantClaus type146 tonne/day (161 tpd) 1 0 3Water Gas Shift ReactorsFixed bed, catalytic399,615 kg/hr (881,000 lb/hr) 232°C (450°F) 5.5 MPa (800 psia) 4 0 4Shift Reactor Heat Recovery ExchangersShell and TubeExchanger 1: 154 GJ/hr (146 MMBtu/hr) Exchanger 2: 4 GJ/hr (4 MMBtu/hr) 4 0 5Acid Gas Removal PlantTwo-stage Selexol310,711 kg/hr (685,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 2 0 6Hydrogenation ReactorFixed bed, catalytic18,308 kg/hr (40,363 lb/hr)232°C (450°F) 0.1 MPa (12.3 psia) 1 0 7Tail Gas Recycle CompressorCentrifugal13,878 kg/hr (30,597 lb/hr) 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1CO2 CompressorIntegrally geared, multi-stage centrifugal1,130 m3/min @ 15.3 MPa (39,900 scfm @ 2,215 psia) 4 1Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Gas TurbineAdvanced F class230 MW 2 0 2Gas Turbine GeneratorTEWAC260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0 3Syngas Expansion Turbine/GeneratorTurbo Expander49,759 kg/h (109,700 lb/h)5.1 MPa (740 psia) Inlet3.2 MPa (460 psia) Outlet 2 0 Cost and Performance Baseline for Fossil Energy Plants 567 ACCOUNT 7 HRSG, DUCTING AND STACK ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES ACCOUNT 9 COOLING WATER SYSTEM Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1StackCS plate, type 409SS liner76 m (250 ft) high x8.5 m (28 ft) diameter 1 0 2Heat Recovery Steam GeneratorDrum, multi-pressure with economizer section and integral deaeratorMain steam - 198,270 kg/hr, 12.4 MPa/534°C (437,111 lb/hr, 1,800 psig/994°F) Reheat steam - 265,278 kg/hr, 3.1 MPa/534°C (584,838 lb/hr, 452 psig/994°F) 2 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Steam TurbineCommercially available advanced steam turbine225 MW 12.4 MPa/534°C/534°C (1800 psig/ 994°F/994°F) 1 0 2Steam Turbine GeneratorHydrogen cooled, static excitiation250 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0 3Steam BypassOne per HRSG50% steam flow @ design steam conditions 2 0 4Surface CondenserSingle pass, divided waterbox including vacuum pumps1,593 GJ/hr (1,510 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F)1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Circulating Water PumpsVertical, wet pit484,533 lpm @ 30 m(128,000 gpm @ 100 ft) 2 1 2Cooling TowerEvaporative, mechanical draft, multi-cell11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2690 GJ/hr (2550 MMBtu/hr) heat duty 1 0 Cost and Performance Baseline for Fossil Energy Plants 568 ACCOUNT 10 SLAG RECOVERY AND HANDLING Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1Slag Quench TankWater bath253,623 liters (67,000 gal) 2 0 2Slag CrusherRoll14 tonne/hr (15 tph) 2 0 3Slag DepressurizerLock Hopper14 tonne/hr (15 tph) 2 0 4Slag Receiving TankHorizontal, weir151,416 liters (40,000 gal) 2 0 5Black Water Overflow TankShop fabricated68,137 liters (18,000 gal) 2 6Slag ConveyorDrag chain14 tonne/hr (15 tph) 2 0 7Slag Separation ScreenVibrating14 tonne/hr (15 tph) 2 0 8Coarse Slag ConveyorBelt/bucket14 tonne/hr (15 tph) 2 0 9Fine Ash Settling TankVertical, gravity215,768 liters (57,000 gal) 2 0 10Fine Ash Recycle PumpsHorizontal centrifugal38 lpm @ 14 m H2O(10 gpm @ 46 ft H2O) 2 2 11Grey Water Storage TankField erected68,137 liters (18,000 gal) 2 0 12Grey Water PumpsCentrifugal227 lpm @ 564 m H2O(60 gpm @ 1,850 ft H2O) 2 2 13Slag Storage BinVertical, field erected998 tonne (1,100 tons) 2 0 14Unloading EquipmentTelescoping chute109 tonne/hr (120 tph) 1 0 Cost and Performance Baseline for Fossil Energy Plants 569 ACCOUNT 11 ACCESSORY ELECTRIC PLANT ACCOUNT 12 INSTRUMENTATION AND CONTROLS Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1CTG Step-up TransformerOil-filled24 kV/345 kV, 260 MVA, 3-ph, 60 Hz 2 0 2STG Step-up TransformerOil-filled24 kV/345 kV, 250 MVA, 3-ph, 60 Hz 1 0 3High Voltage Auxiliary TransformerOil-filled345 kV/13.8 kV, 80 MVA, 3-ph, 60 Hz 2 0 4Medium Voltage Auxiliary TransformerOil-filled24 kV/4.16 kV, 48 MVA, 3-ph, 60 Hz 1 1 5Low Voltage TransformerDry ventilated4.16 kV/480 V, 7 MVA, 3-ph, 60 Hz 1 1 6CTG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled24 kV, 3-ph, 60 Hz 2 0 7STG Isolated Phase Bus Duct and Tap BusAluminum, self-cooled24 kV, 3-ph, 60 Hz 1 0 8Medium Voltage SwitchgearMetal clad4.16 kV, 3-ph, 60 Hz 1 1 9Low Voltage SwitchgearMetal enclosed480 V, 3-ph, 60 Hz 1 1 10Emergency Diesel GeneratorSized for emergency shutdown750 kW, 480 V, 3-ph, 60 Hz 1 0Equipment No.DescriptionTypeDesign ConditionOperating Qty.Spares 1DCS - Main ControlMonitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W)Operator stations/printers and engineering stations/printers 1 0 2DCS - ProcessorMicroprocessor with redundant input/outputN/A 1 0 3DCS - Data HighwayFiber opticFully redundant, 25% spare 1 0 Cost and Performance Baseline for Fossil Energy Plants 570 8.1.4 The cost estimating methodology was described previously in Section Case 2 A - Cost Estimating 2.7. Exhibit 8-13 shows the TPC summary organized by cost account and Exhibit 8-14 shows a more detailed breakdown of the capital costs. Exhibit 8-15 shows the initial and annual O&M costs. The estimated TOC of the GEE gasifier with CO 2 capture in quench

-only configuration is $3,375/kW. Process contingency represents 3.4 percent of the TOC and project contingency represents 11.0 percent. The COE, including CO 2 TS&M costs of 5.8 mills/kWh, is 1 08.5 mills/kWh. For comparison, the TOC and COE for Case 2, GEE in radiant

-only configuration with CO 2 capture are $3,334/kW and 1 05.7 mills/kWh.

Cost and Performance Baseline for Fossil Energy Plants 571 Exhibit 8-13 Case 2A Total Plant Cost Summary Case: Case 2A - GEE Quench 495 MWnet IGCC w/ CO2Plant Size: 493.9MW,netEstimate Type: ConceptualCost Base (Jun) 2007($x1000)AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING$14,279$2,654$11,074$0$0$28,007$2,542$0$6,110$36,659$74 2COAL & SORBENT PREP & FEED$21,755$4,448$17,256$0$0$43,459$3,959$1,577$9,799$58,794$119 3FEEDWATER & MISC. BOP SYSTEMS$8,849$6,224$9,449$0$0$24,521$2,324$0$6,359$33,204$67 4GASIFIER & ACCESSORIES4.1Quench Gasifier System$66,598$0$57,069$0$0$123,667$11,556$16,201$23,572$174,996$3544.2Syngas Scrubber Sys.w/4.1$0w/ 4.1$0$0$0$0$0$0$0$04.3ASU/Oxidant Compression$193,046$0w/equip.$0$0$193,046$18,712$0$21,176$232,934$4724.4-4.9Other Gasification Equipment$7,097$2,671$2,230$0$0$11,999$1,125$0$2,892$16,016$32SUBTOTAL 4$266,741$2,671$59,299$0$0$328,712$31,392$16,201$47,640$423,945$858 5AGAS CLEANUP & PIPING$97,698$3,331$82,513$0$0$183,542$17,795$27,526$45,888$274,751$556 5BCO2 COMPRESSION$18,242$0$11,182$0$0$29,424$2,834$0$6,452$38,709$78 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine Generator$92,026$0$6,583$0$0$98,609$9,348$9,861$11,782$129,599$2626.2-6.9Combustion Turbine Other$5,547$887$1,748$0$0$8,182$775$0$1,650$10,607$21SUBTOTAL 6$97,573$887$8,331$0$0$106,791$10,123$9,861$13,432$140,206$284 7HRSG, DUCTING & STACK7.1Heat Recovery Steam Generator$33,631$0$4,782$0$0$38,413$3,652$0$4,206$46,271$947.2-7.9SCR System, Ductwork and Stack$3,375$2,406$3,152$0$0$8,933$828$0$1,588$11,350$23SUBTOTAL 7$37,006$2,406$7,934$0$0$47,346$4,480$0$5,795$57,621$117 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$24,314$0$4,162$0$0$28,476$2,732$0$3,121$34,329$698.2-8.9Turbine Plant Auxiliaries and Steam Piping$8,443$830$5,626$0$0$14,898$1,367$0$3,064$19,330$39SUBTOTAL 8$32,756$830$9,788$0$0$43,374$4,099$0$6,185$53,659$109 9COOLING WATER SYSTEM$10,625$10,049$8,616$0$0$29,290$2,720$0$6,524$38,535$78 10ASH/SPENT SORBENT HANDLING SYS$14,733$8,238$14,937$0$0$37,909$3,652$0$4,476$46,037$93 11ACCESSORY ELECTRIC PLANT$31,380$12,503$24,392$0$0$68,275$5,874$0$14,086$88,234$179 12INSTRUMENTATION & CONTROL$10,977$2,019$7,072$0$0$20,068$1,819$1,003$3,814$26,704$54 13IMPROVEMENTS TO SITE$3,371$1,987$8,317$0$0$13,675$1,350$0$4,508$19,533$40 14BUILDINGS & STRUCTURES

$0$6,539$7,369$0$0$13,909$1,265$0$2,492$17,666$36

TOTAL COST$665,985$64,787$287,529$0$0$1,018,301$96,229$56,168$183,558$1,354,257$2,742 Cost and Performance Baseline for Fossil Energy Plants 572 Exhibit 8-14 Case 2A Total Plant Cost Details AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING1.1Coal Receive & Unload$3,750$0$1,832$0$0$5,582$500$0$1,216$7,299$151.2Coal Stackout & Reclaim$4,846$0$1,175$0$0$6,020$528$0$1,310$7,858$161.3Coal Conveyors & Yd Crush$4,505$0$1,162$0$0$5,668$498$0$1,233$7,398$151.4Other Coal Handling$1,179$0$269$0$0$1,448$127$0$315$1,889$41.5Sorbent Receive & Unload

$0$0$0$0$0$0$0$0$0$0$01.6Sorbent Stackout & Reclaim

$0$0$0$0$0$0$0$0$0$0$01.7Sorbent Conveyors

$0$0$0$0$0$0$0$0$0$0$01.8Other Sorbent Handling

$0$0$0$0$0$0$0$0$0$0$01.9Coal & Sorbent Hnd.Foundations

$0$2,654$6,635$0$0$9,289$890$0$2,036$12,215$25SUBTOTAL 1.$14,279$2,654$11,074$0$0$28,007$2,542$0$6,110$36,659$74 2COAL & SORBENT PREP & FEED2.1Coal Crushing & Dryingw/2.3$0w/2.3$0$0$0$0$0$0$0$02.2Prepared Coal Storage & Feed$1,602$383$251$0$0$2,236$191$0$485$2,913$62.3Slurry Prep & Feed$19,273$0$12,273$0$0$31,546$2,874$1,577$7,199$43,196$872.4Misc.Coal Prep & Feed

$881$641$1,922$0$0$3,443$316$0$752$4,512$92.5Sorbent Prep Equipment

$0$0$0$0$0$0$0$0$0$0$02.6Sorbent Storage & Feed

$0$0$0$0$0$0$0$0$0$0$02.7Sorbent Injection System

$0$0$0$0$0$0$0$0$0$0$02.8Booster Air Supply System

$0$0$0$0$0$0$0$0$0$0$02.9Coal & Sorbent Feed Foundation

$0$3,423$2,811$0$0$6,234$577$0$1,362$8,174$17SUBTOTAL 2.$21,755$4,448$17,256$0$0$43,459$3,959$1,577$9,799$58,794$119 3FEEDWATER & MISC. BOP SYSTEMS3.1Feedwater System$1,916$3,291$1,737$0$0$6,944$643$0$1,517$9,105$183.2Water Makeup & Pretreating

$744$78$416$0$0$1,237$118$0$406$1,761$43.3Other Feedwater Subsystems$1,048$354$319$0$0$1,722$155$0$375$2,252$53.4Service Water Systems

$426$876$3,042$0$0$4,343$424$0$1,430$6,197$133.5Other Boiler Plant Systems$2,284$885$2,193$0$0$5,362$509$0$1,174$7,045$143.6FO Supply Sys & Nat Gas

$315$596$556$0$0$1,467$141$0$322$1,930$43.7Waste Treatment Equipment$1,040$0$634$0$0$1,674$163$0$551$2,388$53.8Misc. Power Plant Equipment$1,076$144$552$0$0$1,772$171$0$583$2,527$5SUBTOTAL 3.$8,849$6,224$9,449$0$0$24,521$2,324$0$6,359$33,204$67 4GASIFIER & ACCESSORIES4.1Quench Gasifier System$66,598$0$57,069$0$0$123,667$11,556$16,201$23,572$174,996$3544.2Syngas Scrubber Sys.w/4.1$0w/ 4.1$0$0$0$0$0$0$0$04.3ASU/Oxidant Compression$193,046$0w/equip.$0$0$193,046$18,712$0$21,176$232,934$4724.4Low Temperature Cooling$7,097$0$0$0$0$7,097$671$0$1,554$9,321$194.5Black Water & Sour Gas Sectionw/4.1$0w/4.1$0$0$0$0$0$0$0$04.6Flare Stack System

$0$0$0$0$0$0$0$0$0$0$04.8Major Component Riggingw/4.1&4.2$0w/4.1&4.2$0$0$0$0$0$0$0$04.9Gasification Foundations

$0$2,671$2,230$0$0$4,902$454$0$1,339$6,695$14SUBTOTAL 4.$266,741$2,671$59,299$0$0$328,712$31,392$16,201$47,640$423,945$858 Cost and Performance Baseline for Fossil Energy Plants 573 Exhibit 8-14 Case 2A Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 5AGAS CLEANUP & PIPING5A.1Double Stage Selexol$74,127$0$62,899$0$0$137,026$13,252$27,405$35,537$213,219$4325A.2Elemental Sulfur Plant$10,328$2,058$13,325$0$0$25,712$2,498$0$5,642$33,851$695A.3Mercury Removal$1,372$0$1,044$0$0$2,417$233$121$554$3,325$75A.4Shift Reactors$10,045$0$4,044$0$0$14,089$1,351$0$3,088$18,527$385A.5Particulate Removal

$0$0$0$0$0$0$0$0$0$0$05A.6Blowback Gas Systems$1,826$0$346$0$0$2,172$265$0$487$2,924$65A.7Fuel Gas Piping

$0$632$443$0$0$1,075$100$0$235$1,410$35A.9HGCU Foundations

$0$640$413$0$0$1,053$97$0$345$1,495$3SUBTOTAL 5A.$97,698$3,331$82,513$0$0$183,542$17,795$27,526$45,888$274,751$556 5BCO2 COMPRESSION5B.1CO2 Removal System

$0$0$0$0$0$0$0$0$0$0$05B.2CO2 Compression & Drying$18,242$0$11,182$0$0$29,424$2,834$0$6,452$38,709$78SUBTOTAL 5B.$18,242$0$11,182$0$0$29,424$2,834$0$6,452$38,709$78 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine Generator$92,026$0$6,583$0$0$98,609$9,348$9,861$11,782$129,599$2626.2Syngas Expander$5,547$0$766$0$0$6,313$600$0$1,037$7,951$166.3Compressed Air Piping

$0$0$0$0$0$0$0$0$0$0$06.9Combustion Turbine Foundations

$0$887$982$0$0$1,868$175$0$613$2,656$5SUBTOTAL 6.$97,573$887$8,331$0$0$106,791$10,123$9,861$13,432$140,206$284 7HRSG, DUCTING & STACK7.1Heat Recovery Steam Generator$33,631$0$4,782$0$0$38,413$3,652$0$4,206$46,271$947.2Open$0$0$0$0$0$0$0$0$0$0$07.3Ductwork$0$1,730$1,234$0$0$2,964$260$0$645$3,869$87.4Stack$3,375$0$1,268$0$0$4,643$445$0$509$5,597$117.9HRSG, Duct & Stack Foundations

$0$676$649$0$0$1,326$123$0$435$1,884$4SUBTOTAL 7.$37,006$2,406$7,934$0$0$47,346$4,480$0$5,795$57,621$117 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$24,314$0$4,162$0$0$28,476$2,732$0$3,121$34,329$698.2Turbine Plant Auxiliaries

$171$0$393$0$0$564$55$0$62$681$18.3Condenser & Auxiliaries$4,853$0$1,425$0$0$6,277$600$0$688$7,565$158.4Steam Piping$3,419$0$2,405$0$0$5,825$500$0$1,581$7,906$168.9TG Foundations

$0$830$1,403$0$0$2,233$212$0$733$3,178$6SUBTOTAL 8.$32,756$830$9,788$0$0$43,374$4,099$0$6,185$53,659$109 Cost and Performance Baseline for Fossil Energy Plants 574 Exhibit 8-14 Case 2A Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 9COOLING WATER SYSTEM9.1Cooling Towers$7,359$0$1,339$0$0$8,697$828$0$1,429$10,954$229.2Circulating Water Pumps$1,919$0$141$0$0$2,060$174$0$335$2,569$59.3Circ.Water System Auxiliaries

$160$0$23$0$0$183$17$0$30$230$09.4Circ.Water Piping

$0$6,671$1,729$0$0$8,400$759$0$1,832$10,991$229.5Make-up Water System

$400$0$572$0$0$972$93$0$213$1,278$39.6Component Cooling Water Sys

$787$942$670$0$0$2,399$225$0$525$3,149$69.9Circ.Water System Foundations

$0$2,437$4,143$0$0$6,579$624$0$2,161$9,364$19SUBTOTAL 9.$10,625$10,049$8,616$0$0$29,290$2,720$0$6,524$38,535$78 10ASH/SPENT SORBENT HANDLING SYS10.1Slag Dewatering & Cooling$12,136$6,692$13,595$0$0$32,423$3,129$0$3,555$39,107$7910.2Gasifier Ash Depressurizationw/10.1w/10.1w/10.1$0$0$0$0$0$0$0$010.3Cleanup Ash Depressurizationw/10.1w/10.1w/10.1$0$0$0$0$0$0$0$010.4High Temperature Ash Piping

$0$0$0$0$0$0$0$0$0$0$010.5Slag Handling System

$0$0$0$0$0$0$0$0$0$0$010.6Ash Storage Silos

$589$0$641$0$0$1,229$119$0$202$1,551$310.7Ash Transport & Feed Equipment

$790$0$190$0$0$980$91$0$161$1,232$210.8Misc. Ash Handling Equipment$1,219$1,494$446$0$0$3,160$301$0$519$3,980$810.9Ash/Spent Sorbent Foundation

$0$52$65$0$0$117$11$0$39$167$0SUBTOTAL 10.$14,733$8,238$14,937$0$0$37,909$3,652$0$4,476$46,037$93 11ACCESSORY ELECTRIC PLANT11.1Generator Equipment

$909$0$899$0$0$1,809$173$0$198$2,179$411.2Station Service Equipment$4,668$0$421$0$0$5,089$469$0$556$6,114$1211.3Switchgear & Motor Control $8,630$0$1,570$0$0$10,199$946$0$1,672$12,817$2611.4Conduit & Cable Tray

$0$4,009$13,225$0$0$17,234$1,667$0$4,725$23,626$4811.5Wire & Cable

$0$7,660$5,033$0$0$12,693$922$0$3,404$17,018$3411.6Protective Equipment

$0$686$2,496$0$0$3,182$311$0$524$4,017$811.7Standby Equipment

$226$0$221$0$0$446$43$0$73$562$111.8Main Power Transformers$16,946$0$137$0$0$17,084$1,292$0$2,756$21,132$4311.9Electrical Foundations

$0$149$391$0$0$540$52$0$177$769$2SUBTOTAL 11.$31,380$12,503$24,392$0$0$68,275$5,874$0$14,086$88,234$179 12INSTRUMENTATION & CONTROL12.1IGCC Control Equipmentw/4.1$0w/4.1$0$0$0$0$0$0$0$012.2Combustion Turbine Controlw/6.1$0w/6.1$0$0$0$0$0$0$0$012.3Steam Turbine Controlw/8.1$0w/8.1$0$0$0$0$0$0$0$012.4Other Major Component Control$1,084$0$724$0$0$1,807$171$90$310$2,379$512.5Signal Processing Equipmentw/12.7$0 w/12.7$0$0$0$0$0$0$0$012.6Control Boards,Panels & Racks

$249$0$160$0$0$409$39$20$94$561$112.7Computer & Accessories$5,780$0$185$0$0$5,965$548$298$681$7,492$1512.8Instrument Wiring & Tubing

$0$2,019$4,128$0$0$6,147$521$307$1,744$8,720$1812.9Other I & C Equipment$3,864$0$1,876$0$0$5,740$540$287$985$7,552$15SUBTOTAL 12.$10,977$2,019$7,072$0$0$20,068$1,819$1,003$3,814$26,704$54 Cost and Performance Baseline for Fossil Energy Plants 575 Exhibit 8-14 Case 2A Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 13IMPROVEMENTS TO SITE13.1Site Preparation

$0$106$2,261$0$0$2,366$235$0$780$3,382$713.2Site Improvements

$0$1,881$2,500$0$0$4,381$432$0$1,444$6,257$1313.3Site Facilities$3,371$0$3,557$0$0$6,928$683$0$2,283$9,894$20SUBTOTAL 13.$3,371$1,987$8,317$0$0$13,675$1,350$0$4,508$19,533$40 14BUILDINGS & STRUCTURES14.1Combustion Turbine Area

$0$265$150$0$0$414$36$0$90$541$114.2Steam Turbine Building

$0$2,096$2,986$0$0$5,081$468$0$832$6,381$1314.3Administration Building

$0$862$625$0$0$1,487$132$0$243$1,863$414.4Circulation Water Pumphouse

$0$162$86$0$0$247$22$0$40$310$114.5Water Treatment Buildings

$0$622$606$0$0$1,228$111$0$201$1,540$314.6Machine Shop

$0$441$302$0$0$743$66$0$121$930$214.7Warehouse

$0$712$460$0$0$1,172$104$0$191$1,467$314.8Other Buildings & Structures

$0$427$332$0$0$759$68$0$165$992$214.9Waste Treating Building & Str.

$0$954$1,823$0$0$2,776$259$0$607$3,642$7SUBTOTAL 14.

$0$6,539$7,369$0$0$13,909$1,265$0$2,492$17,666$36TOTAL COST$665,985$64,787$287,529$0$0$1,018,301$96,229$56,168$183,558$1,354,257$2,742Owner's CostsPreproduction Costs6 Months All Labor$12,023$241 Month Maintenance Materials$2,632$51 Month Non-fuel Consumables

$400$11 Month Waste Disposal

$318$125% of 1 Months Fuel Cost at 100% CF$1,697$32% of TPC$27,085$55Total$44,154$89Inventory Capital60 day supply of fuel and consumables at 100% CF$14,085$290.5% of TPC (spare parts)$6,771$14Total$20,856$42Initial Cost for Catalyst and Chemicals$7,292$15Land$900$2Other Owner's Costs$203,139$411Financing Costs$36,565$74Total Overnight Costs (TOC)$1,667,163$3,375TASC Multiplier(IOU, high-risk, 35 year)1.140Total As-Spent Cost (TASC)$1,900,566$3,848 Cost and Performance Baseline for Fossil Energy Plants 576 Exhibit 8-15 Case 2A Initial and Annual Operating and Maintenance Costs INITIAL & ANNUAL O&M EXPENSESCost Base (Jun):

2007Case 2A - GEE Quench 495 MWnet IGCC w/ CO2Heat Rate-net (Btu/kWh):11,502 MWe-net: 494 Capacity Factor (%):

80OPERATING & MAINTENANCE LABOROperating Labor Operating Labor Rate(base):34.65$/hour Operating Labor Burden:30.00% of base Labor O-H Charge Rate:25.00% of laborTotal Skilled Operator2.02.0 Operator10.010.0 Foreman1.01.0 Lab Tech's, etc.3.03.0 TOTAL-O.J.'s16.016.0Annual CostAnnual Unit Cost

$$/kW-netAnnual Operating Labor Cost$6,313,507$12.782Maintenance Labor Cost$12,922,767$26.163Administrative & Support Labor$4,809,068$9.736Property Taxes and Insurance$27,085,142$54.835 TOTAL FIXED OPERATING COSTS

$51,130,484

$103.516VARIABLE OPERATING COSTS$/kWh-netMaintenance Material Cost$25,263,935$0.00730ConsumablesConsumptionUnit Initial Fill Initial Fill /Day Cost CostWater (/1000 gallons) 04,4041.08$0$1,391,076$0.00040ChemicalsMU & WT Chem. (lbs) 026,2390.17$0$1,326,020$0.00038Carbon (Mercury Removal) (lb)79,1951081.05$83,168$33,267$0.00001COS Catalyst (m3) 0 02,397.36$0$0$0.00000Water Gas Shift Catalyst (ft3)6,4434.41498.83$3,213,847$642,769$0.00019Selexol Solution (gal)298,200 9513.40$3,995,355$371,115$0.00011SCR Catalyst (m3) 0 00.00$0$0$0.00000Ammonia (19% NH3) (ton) 0 00.00$0$0$0.00000Claus Catalyst (ft3)w/equip2.01131.27$0$77,204$0.00002Subtotal-Chemicals$7,292,370$2,450,376$0.00071OtherSupplemental Fuel (MBtu) 0 00.00$0$0$0.00000Gases, N2 etc. (/100scf) 0 00.00$0$0$0.00000L.P. Steam (/1000 pounds) 0 00.00$0$0$0.00000Subtotal-Other$0$0$0.00000Waste DisposalSpent Mercury Catalyst (lb.)

01080.42$0$13,212$0.00000Flyash (ton) 0 00.00$0$0$0.00000Slag (ton) 0 64116.23$0$3,037,649$0.00088Subtotal Waste Disposal$0$3,050,861$0.00088By-products & EmissionsSulfur (ton) 01460.00$0$0$0.00000Subtotal By-products$0$0$0.00000TOTAL VARIABLE OPERATING COSTS$7,292,370$32,156,247$0.00929Fuel (ton) 05,84438.18$0$65,156,652$0.01882 Cost and Performance Baseline for Fossil Energy Plants 577 9. Studies of PC plants with post combustion capture of CO 2 for the 2009 NETL Bituminous and Low Rank Baselines Studies are based on a performance and cost estimate for an Econamine CO 2 capture system provided by Fluor in 2005

[SENSITIVITY TO MEA SYSTEM PERFORMANCE AND COST BITUMINOUS BASELINE CASE 12A 87]. A recent Fluor publication [

88The Fluor publication [] indicates that Fluor has improved the Econamine system. According to Fluor, the improved system is able to achieve a reboiler steam requirement of 1,270 Btu/lb CO 2 as compared to the 1,530 Btu/lb CO 2 used in the baseline studies. Fluor also indicated concurrent reductions in auxiliary electrical power requirements and capital costs.

88] indicates the improvements in performance and cost are enabled by an improved solvent formulation with an MEA concentration greater than 30 percent and improved corrosion inhibitors. Fluor states that the improved solvent results in increased reaction rates enabling less absorber packing and lower capital cost. Also, the higher solvent carrying capacity results in lower solvent circulation rates, lower steam requirements, and lower capital cost of solvent circulation equipment.

Cost and performance data on the improved system were unavailable directly from Fluor. Using a commercial AGR software package, the CO 2 removal process was simulated using higher MEA concentrations, but the confiden ce in the generated results and any associated equipment sizing or costing changes were not adequate for use in this analysis. Therefore, a sensitivity analysis was performed using published data from Fluor and best engineering judgment to estimate the impact of an improved MEA CO 2 capture system on the performance and cost of a SC boiler firing bituminous coal with back

-end CO 2 capture. 9.1 BASIS FOR SENSITIVITY ANALYSIS The sensitivity analysis was performed on Case 12 of the Bituminous Baseline Study. This case used a SC PC plant burning bituminous (Illinois #6) coal at ISO conditions. The sensitivity case was labeled Case 12A.

It was assumed, based on qualitative statements by Fluor, that the improved performance and reduced cost were achieved by increasing the MEA concentration from 30 wt% to 36 wt%. It was further assumed that Econamine reboiler steam requirements, power requirements and capital cost were inversely proportional to the increase in MEA concentration. The reboiler steam requirement and electrical auxiliary requirements were reduced by the ratio o f 30/36 = 0.83. The Econamine plant capital cost was scaled using two factors

- the first based on the amount of CO 2 capture d to the 0.6 power and the second based on the ratio of the increased solvent concentration to the 0.7 power

. The Aspen model for Case 12 was modified for the reduced reboiler steam requirement and calculations were adjusted for the reduced auxiliary power requirement. Performance and cost estimates for Case 12A as compared to Case 12 are included in the following sections.

9.2 PERFORMANCE

The BFD, Stream Tables and Performance Summary for Case 12A are shown in Exhibit 9-1 , Exhibit 9-2, and Exhibit 9-3. The Performance Summary from Case 12 is also included in Cost and Performance Baseline for Fossil Energy Plants 578 Exhibit 9-3 for comparison. The net plant efficiency for Case 12A is 29.8 percent compared to 28.4 percent for Case 12.

The auxiliary power for Case 12A is 104 MW compared to 113 MW for Case 12. Gross output was reduced for Case 12A by 9 MW to maintain a 550 MW net output for both cases. The reduction in auxiliary power results primarily from reductions in the Econamine and CO 2 compressor auxiliaries with minor reductions in most other auxiliary loads resulting from a slightly smaller gross plant size.

Cost and Performance Baseline for Fossil Energy Plants 579 Exhibit 9-1 Case 12A Block Flow Diagram, Supercritical Unit with CO 2 Capture (MEA Sensitivity)

Cost and Performance Baseline for Fossil Energy Plants 580 Exhibit 9-2 Case 12A Stream Table, Supercritical Unit with CO 2 Capture 1 2 3 4 5 6 7 8 9 10 11 12 13 14V-L Mole Fraction Ar0.00920.00920.00920.00920.00920.00920.00920.00000.00000.00870.00000.00870.00870.0000 CO 20.00030.00030.00030.00030.00030.00030.00030.00000.00000.14500.00000.14500.14500.0000 H 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 H 2 O0.00990.00990.00990.00990.00990.00990.00990.00000.00000.08700.00000.08700.08701.0000 N 20.77320.77320.77320.77320.77320.77320.77320.00000.00000.73240.00000.73240.73240.0000 O 20.20740.20740.20740.20740.20740.20740.20740.00000.00000.02470.00000.02470.02470.0000 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00210.00000.00210.00210.0000Total1.00001.00001.00001.00001.00001.00001.00000.00000.00001.00000.00001.00001.00001.0000V-L Flowrate (kgmol/hr)63,82463,8241,89919,60619,6062,6901,475 0 089,812 089,81289,8123,349V-L Flowrate (kg/hr)1,841,7671,841,76754,801565,772565,77277,61342,569 0 02,671,294 02,671,2942,671,29460,334Solids Flowrate (kg/hr) 0 0 0 0 0 0 0244,9384,75019,00119,001 0 024,719Temperature (°C) 15 19 19 15 25 25 15 15 15 169 15 169 182 15Pressure (MPa, abs)0.100.110.110.100.110.110.100.100.100.100.100.100.110.10Enthalpy (kJ/kg)

A30.2334.3634.3630.2340.7840.7830.23------327.40---308.96322.83---Density (kg/m 3)1.21.21.21.21.31.31.2------0.8---0.80.8---V-L Molecular Weight28.85728.85728.85728.85728.85728.85728.857------29.743---29.74329.743---V-L Flowrate (lbmol/hr)140,708140,7084,18743,22443,2245,9303,252 0 0198,001 0198,001198,0017,383V-L Flowrate (lb/hr)4,060,4014,060,401120,8161,247,3131,247,313171,10893,850 0 05,889,196 05,889,1965,889,196133,014Solids Flowrate (lb/hr) 0 0 0 0 0 0 0539,99510,47241,89041,890 0 054,497Temperature (°F) 59 66 66 59 78 78 59 59 59 337 59 337 360 59Pressure (psia)14.715.315.314.716.116.114.714.714.714.414.714.215.415.0Enthalpy (Btu/lb)

A13.014.814.813.017.517.513.0------140.8---132.8138.8---Density (lb/ft 3)0.0760.0780.0780.0760.0810.0810.076------0.050---0.0490.052---A - Reference conditions are 32.02 F & 0.089 PSIA Cost and Performance Baseline for Fossil Energy Plants 581 Exhibit 9-2 Case 12A Stream Table, Supercritical Unit with CO 2 Capture (Continued) 15 16 17 18 19 20 21 22 23 24 25 26 27 28V-L Mole Fraction Ar0.00000.01280.00000.00810.01080.00000.00000.00000.00000.00000.00000.00000.00000.0000 CO 20.00000.00050.00040.13510.01790.99610.99850.00000.00000.00000.00000.00000.00000.0000 H 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000 H 2 O1.00000.00620.99960.15370.03830.00390.00151.00001.00001.00001.00001.00001.00001.0000 N 20.00000.75060.00000.67930.90130.00000.00000.00000.00000.00000.00000.00000.00000.0000 O 20.00000.23000.00000.02380.03160.00000.00000.00000.00000.00000.00000.00000.00000.0000 SO 20.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.00000.0000Total1.00001.00001.00001.00001.00001.00001.00001.00001.00001.00001.00001.00001.00001.0000V-L Flowrate (kgmol/hr)12,734 913 23697,84873,74111,94011,91135,62135,621120,75098,49998,49953,85653,856V-L Flowrate (kg/hr)229,41126,5104,2602,821,0442,077,415524,270523,755641,731641,7312,175,3441,774,4951,774,495970,240970,240Solids Flowrate (kg/hr) 0 038,244 0 0 0 0 0 0 0 0 0 0 0Temperature (°C) 15 181 58 58 32 21 35 291 151 593 354 593 38 39Pressure (MPa, abs)0.100.310.100.100.100.1615.270.510.9224.234.904.520.011.69Enthalpy (kJ/kg)

A-46.80191.58---301.4293.8619.49-211.713,045.10636.313,476.623,081.963,652.222,111.17166.38Density (kg/m 3)1,003.12.4---1.11.12.9795.92.0916.069.218.711.60.1993.2V-L Molecular Weight18.01529.029---28.83128.17243.90843.97118.01518.01518.01518.01518.01518.01518.015V-L Flowrate (lbmol/hr)28,0742,013 521215,717162,57126,32326,26078,53278,532266,208217,154217,154118,733118,733V-L Flowrate (lb/hr)505,76658,4459,3926,219,3374,579,9171,155,8181,154,6821,414,7741,414,7744,795,8123,912,0913,912,0912,139,0122,139,012Solids Flowrate (lb/hr) 0 084,314 0 0 0 0 0 0 0 0 0 0 0Temperature (°F) 59 357 136 136 89 69 95 556 3041,100 6691,100 101 103Pressure (psia)14.745.014.914.914.723.52,214.573.5133.63,514.7710.8655.81.0245.0Enthalpy (Btu/lb)

A-20.182.4---129.640.48.4-91.01,309.2273.61,494.71,325.01,570.2907.671.5Density (lb/ft 3)62.6220.149---0.0670.0700.18449.6850.12357.1844.3191.1650.7220.00462.004 Cost and Performance Baseline for Fossil Energy Plants 582 Exhibit 9-3 Case 12A Plant Performance Summary POWER

SUMMARY

(Gross Power at Generator Terminals, kWe)

Bituminous Baseline Case 12 12A Steam Turbine Power 662,800 654,200 TOTAL (STEAM TURBINE) POWER, kWe 662,800 654,200 AUXILIARY LOAD

SUMMARY

, kWe Coal Handling and Conveying 510 500 Pulverizers 3,850 3,670 Sorbent Handling & Reagent Preparation 1,250 1,190 Ash Handling 740 700 Primary Air Fans 1,800 1,720 Forced Draft Fans 2,300 2,190 Induced Draft Fans 11,120 10,610 SCR 70 60 Baghouse 100 90 Wet FGD 4,110 3,920 Econamine FG Plus Auxiliaries 20,600 16,400 CO 2 Compression 44,890 42,840 Miscellaneous Balance of Plant2,3 2,000 2,000 Steam Turbine Auxiliaries 400 400 Condensate Pumps 560 610 Circulating Water Pumps 10,100 9,390 Ground Water Pumps 920 850 Cooling Tower Fans 5,230 4,860 Transformer Losses 2,290 2,240 TOTAL AUXILIARIES, kWe 112,840 104,240 NET POWER, kWe 549,96 0 549 ,96 0 Net Plant Efficiency (HHV) 28.4% 2 9.8% Net Plant Heat Rate, kJ/kWh (Btu/kWh) 12,663 (12

, 002) 12,085 (11,455)

CONDENSER COOLING DUTY, 10 6 kJ/h r (10 6 Btu/h r) 1,737 (1,646) 1,893 (1,794)

CONSUMABLES As-Received Coal Feed, kg/h r (lb/h r) 256,652 (565,820) 244,938 (539,995) Limestone Sorbent Feed, kg/h r (lb/h r) 25,966 (57,245) 24, 720 (54,497) Thermal Input, kWt 1 1,934,519 1,846,224 Raw Water Withdrawal, m 3/min (gpm) 38.1 (10,071

) 35.4 (9,350)

Raw Water Consumption, m 3/min (gpm) 29.3 (7,733

) 27.2 (7,177)

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

Cost and Performance Baseline for Fossil Energy Plants 583 9.3 COST ESTIMATING The cost estimating methodology was described in Section 2.7 of this report. Exhibit 9-4 shows the TPC summary organized by cost account and Exhibit 9-5 shows a more detailed breakdown of the capital costs including the TOC and TASC. Exhibit 9-6 shows the initial and annual O&M costs.

The TPC was estimated using a factored cost method with Case 12 as the reference. Account 5B.1 was scaled based on CO 2 captured to the 0.6 power and additionally reduced by 12 percent as discussed previously to account for capital cost reductions resulting from the reduced solvent circulation rate

. The estimated TOC for Case 12A is $3,364/kW. This represents a reduction from Case 12 of 6

percent. Process contingency represents 2.6 percent of the TOC and project contingency represents 10.0 percent. The COE, including CO 2 TS&M cost s of 5.3 mills/kWh, is 1 00.8 mills/kWh. This COE is 5

.5 percent less than the Baseline Case 12 COE of 10 6.6 mills/kWh.

Cost and Performance Baseline for Fossil Energy Plants 584 Exhibit 9-4 Case 12A Total Plant Cost Summary Client: USDOE/NETLReport Date:2010-Jan-14Project: Bituminous Baseline StudyCase: Case 12A - 1x550 MWnet Super-Critical PC w/ CO2 Capture (MEA Sensitivity)Plant Size: 550.0MW,netEstimate Type: ConceptualCost Base (Jun) 2007($x1000)AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING$19,514$5,244$11,671$0$0$36,429$3,268$0$5,955$45,652$83 2COAL & SORBENT PREP & FEED$13,252$772$3,366$0$0$17,391$1,524$0$2,837$21,753$40 3FEEDWATER & MISC. BOP SYSTEMS$52,950$0$24,940$0$0$77,890$7,138$0$13,939$98,967$180 4PC BOILER4.1PC Boiler & Accessories$189,629$0$106,401$0$0$296,030$28,810$0$32,484$357,324$6504.2SCR (w/4.1)

$0$0$0$0$0$0$0$0$0$0$04.3Open$0$0$0$0$0$0$0$0$0$0$04.4-4.9Boiler BoP (w/ ID Fans)

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 4$189,629$0$106,401$0$0$296,030$28,810$0$32,484$357,324$650 5FLUE GAS CLEANUP$97,431$0$33,251$0$0$130,682$12,508$0$14,319$157,509$286 5B CO 2 REMOVAL & COMPRESSION$204,675$0$62,416$0$0$267,091$25,537$46,378$67,801$406,807$740 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine GeneratorN/A$0N/A$0$0$0$0$0$0$0$06.2-6.9Combustion Turbine Other

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 6

$0$0$0$0$0$0$0$0$0$0$0 7HRSG, DUCTING & STACK7.1Heat Recovery Steam GeneratorN/A$0N/A$0$0$0$0$0$0$0$07.2-7.9HRSG Accessories, Ductwork and Stack$17,413$958$11,797$0$0$30,168$2,764$0$4,326$37,258$68SUBTOTAL 7$17,413$958$11,797$0$0$30,168$2,764$0$4,326$37,258$68 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$56,268$0$7,467$0$0$63,735$6,108$0$6,984$76,827$1408.2-8.9Turbine Plant Auxiliaries and Steam Piping$26,997$1,189$15,089$0$0$43,276$3,779$0$6,723$53,778$98SUBTOTAL 8$83,265$1,189$22,556$0$0$107,010$9,887$0$13,707$130,605$237 9COOLING WATER SYSTEM$19,662$9,537$17,647$0$0$46,846$4,410$0$6,916$58,171$106 10ASH/SPENT SORBENT HANDLING SYS$5,135$163$6,865$0$0$12,163$1,169$0$1,372$14,705$27 11ACCESSORY ELECTRIC PLANT$24,767$10,309$29,247$0$0$64,322$5,686$0$8,780$78,788$143 12INSTRUMENTATION & CONTROL$9,915$0$10,054$0$0$19,969$1,811$998$2,798$25,575$47 13IMPROVEMENTS TO SITE$3,281$1,886$6,612$0$0$11,779$1,162$0$2,588$15,529$28 14BUILDINGS & STRUCTURES

$0$24,540$23,290$0$0$47,830$4,315$0$7,822$59,967$109

TOTAL COST$740,888$54,598$370,114$0$0$1,165,600$109,989$47,376$185,644$1,508,610$2,743TOTAL PLANT COST

SUMMARY

Cost and Performance Baseline for Fossil Energy Plants 585 Exhibit 9-5 Case 12A Total Plant Cost Details AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 1COAL & SORBENT HANDLING1.1Coal Receive & Unload$3,998$0$1,826$0$0$5,823$520$0$952$7,295$131.2Coal Stackout & Reclaim$5,166$0$1,171$0$0$6,337$554$0$1,034$7,925$141.3Coal Conveyors$4,803$0$1,158$0$0$5,961$522$0$973$7,456$141.4Other Coal Handling$1,257$0$268$0$0$1,525$133$0$249$1,907$31.5Sorbent Receive & Unload

$163$0$49$0$0$212$19$0$35$265$01.6Sorbent Stackout & Reclaim$2,625$0$481$0$0$3,106$270$0$506$3,883$71.7Sorbent Conveyors

$937$203$230$0$0$1,369$118$0$223$1,710$31.8Other Sorbent Handling

$566$133$297$0$0$995$88$0$162$1,245$21.9Coal & Sorbent Hnd.Foundations

$0$4,909$6,192$0$0$11,101$1,043$0$1,822$13,966$25SUBTOTAL 1.$19,514$5,244$11,671$0$0$36,429$3,268$0$5,955$45,652$83 2COAL & SORBENT PREP & FEED2.1Coal Crushing & Drying$2,315$0$451$0$0$2,766$241$0$451$3,458$62.2Coal Conveyor to Storage$5,927$0$1,294$0$0$7,221$631$0$1,178$9,030$162.3Coal Injection System

$0$0$0$0$0$0$0$0$0$0$02.4Misc.Coal Prep & Feed

$0$0$0$0$0$0$0$0$0$0$02.5Sorbent Prep Equipment$4,471$193$929$0$0$5,593$487$0$912$6,991$132.6Sorbent Storage & Feed

$539$0$206$0$0$745$66$0$122$933$22.7Sorbent Injection System

$0$0$0$0$0$0$0$0$0$0$02.8Booster Air Supply System

$0$0$0$0$0$0$0$0$0$0$02.9Coal & Sorbent Feed Foundation

$0$579$486$0$0$1,066$99$0$175$1,339$2SUBTOTAL 2.$13,252$772$3,366$0$0$17,391$1,524$0$2,837$21,753$40 3FEEDWATER & MISC. BOP SYSTEMS3.1FeedwaterSystem$22,174$0$7,163$0$0$29,337$2,564$0$4,785$36,686$673.2Water Makeup & Pretreating $6,639$0$2,137$0$0$8,776$830$0$1,921$11,526$213.3Other Feedwater Subsystems$6,789$0$2,869$0$0$9,658$865$0$1,578$12,101$223.4Service Water Systems$1,301$0$708$0$0$2,009$189$0$440$2,638$53.5Other Boiler Plant Systems$8,379$0$8,272$0$0$16,651$1,582$0$2,735$20,968$383.6FO Supply Sys & Nat Gas

$273$0$341$0$0$613$58$0$101$772$13.7Waste Treatment Equipment$4,501$0$2,566$0$0$7,066$688$0$1,551$9,305$173.8Misc. Equip.(cranes,AirComp.,Comm.)$2,894$0$884$0$0$3,779$363$0$828$4,970$9SUBTOTAL 3.$52,950$0$24,940$0$0$77,890$7,138$0$13,939$98,967$180 4PC BOILER4.1PC Boiler & Accessories$189,629$0$106,401$0$0$296,030$28,810$0$32,484$357,324$6504.2SCR (w/4.1)

$0$0$0$0$0$0$0$0$0$0$04.3Open$0$0$0$0$0$0$0$0$0$0$04.4Boiler BoP (w/ ID Fans)

$0$0$0$0$0$0$0$0$0$0$04.5Primary Air Systemw/4.1$0w/4.1$0$0$0$0$0$0$0$04.6Secondary Air Systemw/4.1$0w/4.1$0$0$0$0$0$0$0$04.8Major Component Rigging

$0w/4.1w/4.1$0$0$0$0$0$0$0$04.9Boiler Foundations

$0w/14.1w/14.1$0$0$0$0$0$0$0$0SUBTOTAL 4.$189,629$0$106,401$0$0$296,030$28,810$0$32,484$357,324$650 Cost and Performance Baseline for Fossil Energy Plants 586 Exhibit 9-5 Case 12A Total Plant Cost Details (Continued) AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 5FLUE GAS CLEANUP5.1Absorber Vessels & Accessories$67,660$0$14,566$0$0$82,226$7,839$0$9,006$99,071$1805.2Other FGD$3,531$0$4,001$0$0$7,532$731$0$826$9,089$175.3Bag House & Accessories$19,454$0$12,346$0$0$31,801$3,065$0$3,487$38,352$705.4Other Particulate Removal Materials$1,317$0$1,409$0$0$2,725$264$0$299$3,289$65.5Gypsum Dewatering System$5,469$0$929$0$0$6,398$609$0$701$7,708$145.6Mercury Removal System

$0$0$0$0$0$0$0$0$0$0$05.9Open$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 5.$97,431$0$33,251$0$0$130,682$12,508$0$14,319$157,509$286 5B CO 2 REMOVAL & COMPRESSION5B.1 CO 2 Removal System$177,879$0$54,009$0$0$231,888$22,171$46,378$60,087$360,524$6565B.2 CO 2 Compression & Drying$26,796$0$8,406$0$0$35,202$3,367$0$7,714$46,283$84SUBTOTAL 5B.$204,675$0$62,416$0$0$267,091$25,537$46,378$67,801$406,807$740 6COMBUSTION TURBINE/ACCESSORIES6.1Combustion Turbine GeneratorN/A$0N/A$0$0$0$0$0$0$0$06.2Open$0$0$0$0$0$0$0$0$0$0$06.3Compressed Air Piping

$0$0$0$0$0$0$0$0$0$0$06.9Combustion Turbine Foundations

$0$0$0$0$0$0$0$0$0$0$0SUBTOTAL 6.

$0$0$0$0$0$0$0$0$0$0$0 7HRSG, DUCTING & STACK7.1Heat Recovery Steam GeneratorN/A$0N/A$0$0$0$0$0$0$0$07.2HRSG Accessories

$0$0$0$0$0$0$0$0$0$0$07.3Ductwork$9,063$0$5,823$0$0$14,886$1,298$0$2,428$18,611$347.4Stack$8,350$0$4,886$0$0$13,236$1,274$0$1,451$15,962$297.9Duct & Stack Foundations

$0$958$1,088$0$0$2,046$192$0$448$2,685$5SUBTOTAL 7.$17,413$958$11,797$0$0$30,168$2,764$0$4,326$37,258$68 8STEAM TURBINE GENERATOR 8.1Steam TG & Accessories$56,268$0$7,467$0$0$63,735$6,108$0$6,984$76,827$1408.2Turbine Plant Auxiliaries

$379$0$812$0$0$1,191$116$0$131$1,438$38.3Condenser & Auxiliaries$5,837$0$2,151$0$0$7,988$765$0$875$9,629$188.4Steam Piping$20,781$0$10,247$0$0$31,028$2,607$0$5,045$38,680$708.9TG Foundations

$0$1,189$1,879$0$0$3,069$290$0$672$4,031$7SUBTOTAL 8.$83,265$1,189$22,556$0$0$107,010$9,887$0$13,707$130,605$237 Cost and Performance Baseline for Fossil Energy Plants 587 Exhibit 9-5 Case 12A Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 9COOLING WATER SYSTEM9.1Cooling Towers$14,675$0$4,570$0$0$19,245$1,840$0$2,109$23,194$429.2Circulating Water Pumps$3,023$0$233$0$0$3,255$275$0$353$3,884$79.3Circ.Water System Auxiliaries

$754$0$100$0$0$854$81$0$94$1,029$29.4Circ.Water Piping

$0$5,974$5,789$0$0$11,763$1,101$0$1,930$14,794$279.5Make-up Water System

$613$0$819$0$0$1,433$137$0$235$1,805$39.6Component Cooling Water Sys

$597$0$475$0$0$1,072$102$0$176$1,350$29.9Circ.Water System Foundations& Structures

$0$3,563$5,661$0$0$9,224$873$0$2,019$12,116$22SUBTOTAL 9.$19,662$9,537$17,647$0$0$46,846$4,410$0$6,916$58,171$106 10ASH/SPENT SORBENT HANDLING SYS10.1Ash CoolersN/A$0N/A$0$0$0$0$0$0$0$010.2Cyclone Ash LetdownN/A$0N/A$0$0$0$0$0$0$0$010.3HGCU Ash LetdownN/A$0N/A$0$0$0$0$0$0$0$010.4High Temperature Ash PipingN/A$0N/A$0$0$0$0$0$0$0$010.5Other Ash Recovery EquipmentN/A$0N/A$0$0$0$0$0$0$0$010.6Ash Storage Silos

$687$0$2,117$0$0$2,804$275$0$308$3,387$610.7Ash Transport & Feed Equipment$4,448$0$4,556$0$0$9,004$861$0$986$10,851$2010.8Misc. Ash Handling Equipment

$0$0$0$0$0$0$0$0$0$0$010.9Ash/Spent Sorbent Foundation

$0$163$192$0$0$356$33$0$78$467$1SUBTOTAL 10.$5,135$163$6,865$0$0$12,163$1,169$0$1,372$14,705$27 11ACCESSORY ELECTRIC PLANT11.1Generator Equipment$1,714$0$278$0$0$1,993$185$0$163$2,341$411.2Station Service Equipment$4,791$0$1,574$0$0$6,366$595$0$522$7,483$1411.3Switchgear & Motor Control $5,508$0$936$0$0$6,445$597$0$704$7,746$1411.4Conduit & Cable Tray

$0$3,454$11,941$0$0$15,395$1,490$0$2,533$19,418$3511.5Wire & Cable

$0$6,517$12,580$0$0$19,097$1,609$0$3,106$23,811$4311.6Protective Equipment

$261$0$888$0$0$1,149$112$0$126$1,388$311.7Standby Equipment$1,352$0$31$0$0$1,383$127$0$151$1,660$311.8Main Power Transformers$11,140$0$187$0$0$11,327$859$0$1,219$13,405$2411.9Electrical Foundations

$0$339$830$0$0$1,168$112$0$256$1,536$3SUBTOTAL 11.$24,767$10,309$29,247$0$0$64,322$5,686$0$8,780$78,788$143 12INSTRUMENTATION & CONTROL12.1PC Control Equipmentw/12.7$0w/12.7$0$0$0$0$0$0$0$012.2Combustion Turbine ControlN/A$0N/A$0$0$0$0$0$0$0$012.3Steam Turbine Controlw/8.1$0w/8.1$0$0$0$0$0$0$0$012.4Other Major Component Control

$0$0$0$0$0$0$0$0$0$0$012.5Signal Processing Equipmentw/12.7$0w/12.7$0$0$0$0$0$0$0$012.6Control Boards,Panels & Racks

$511$0$306$0$0$816$77$41$140$1,074$212.7Distributed Control System Equipment$5,154$0$901$0$0$6,055$561$303$692$7,611$1412.8Instrument Wiring & Tubing$2,794$0$5,542$0$0$8,336$710$417$1,420$10,883$2012.9Other I & C Equipment$1,456$0$3,305$0$0$4,761$462$238$546$6,007$11SUBTOTAL 12.$9,915$0$10,054$0$0$19,969$1,811$998$2,798$25,575$47 Cost and Performance Baseline for Fossil Energy Plants 588 Exhibit 9-5 Case 12A Total Plant Cost Details (Continued)

AcctEquipmentMaterialLaborSalesBare ErectedEng'g CMContingenciesTOTAL PLANT COSTNo.Item/DescriptionCostCostDirectIndirectTaxCost $H.O.& FeeProcessProject$$/kW 13IMPROVEMENTS TO SITE13.1Site Preparation

$0$55$1,103$0$0$1,158$115$0$255$1,528$313.2Site Improvements

$0$1,831$2,274$0$0$4,105$405$0$902$5,411$1013.3Site Facilities$3,281$0$3,235$0$0$6,516$642$0$1,432$8,590$16SUBTOTAL 13.$3,281$1,886$6,612$0$0$11,779$1,162$0$2,588$15,529$28 14BUILDINGS & STRUCTURES14.1Boiler Building

$0$8,791$7,731$0$0$16,522$1,485$0$2,701$20,708$3814.2Turbine Building

$0$12,699$11,836$0$0$24,535$2,211$0$4,012$30,758$5614.3Administration Building

$0$637$673$0$0$1,310$119$0$214$1,644$314.4Circulation Water Pumphouse

$0$168$134$0$0$302$27$0$49$378$114.5Water Treatment Buildings

$0$842$768$0$0$1,610$145$0$263$2,018$414.6Machine Shop

$0$426$286$0$0$712$63$0$116$892$214.7Warehouse

$0$289$290$0$0$578$52$0$95$725$114.8Other Buildings & Structures

$0$236$201$0$0$437$39$0$71$547$114.9Waste Treating Building & Str.

$0$452$1,372$0$0$1,825$173$0$300$2,298$4SUBTOTAL 14.

$0$24,540$23,290$0$0$47,830$4,315$0$7,822$59,967$109TOTAL COST$740,888$54,598$370,114$0$0$1,165,600$109,989$47,376$185,644$1,508,610$2,743BEC, Categories 1-12$1,105,992Owner's CostsPreproduction Costs6 Months All Labor$10,153$181 Month Maintenance Materials$1,457$31 Month Non-fuel Consumables$1,478$31 Month Waste Disposal

$309$125% of 1 Months Fuel Cost at 100% CF$1,882$32% of TPC$30,172$55Total$45,451$83Inventory Capital60 day supply of fuel and consumables at 100% CF$18,151$330.5% of TPC (spare parts)$7,543$14Total$25,694$47Initial Cost for Catalyst and Chemicals$2,383$4Land$900$2Other Owner's Costs$226,291$411Financing Costs$40,732$74Total Overnight Costs (TOC)$1,850,062$3,364TASC Multiplier(IOU, low risk, 35 year)1.140Total As-Spent Cost (TASC)$2,109,071$3,835 Cost and Performance Baseline for Fossil Energy Plants 589 Exhibit 9-6 Case 12A Initial and Annual Operating and Maintenance Costs INITIAL & ANNUAL O&M EXPENSESCost Base (Jun):

2007Case 12A - 1x550 MWnet Super-Critical PC w/ CO2 Capture (MEA Sensitivity)Heat Rate-net (Btu/kWh):11,455 MWe-net: 550Capacity Factor (%):

85OPERATING & MAINTENANCE LABOROperating Labor Operating Labor Rate(base):34.65$/hour Operating Labor Burden:30.00% of base Labor O-H Charge Rate:25.00% of laborTotal Operating Labor Requirements(O.J.)per Shift:1 unit/mod. Plant Skilled Operator2.02.0 Operator11.311.3 Foreman1.01.0 Lab Tech's, etc.2.02.0 TOTAL-O.J.'s16.316.3Annual CostAnnual Unit Cost

$$/kW-netAnnual Operating Labor Cost$6,444,907$11.719Maintenance Labor Cost$9,800,561$17.820Administrative & Support Labor$4,061,367$7.385Property Taxes and Insurance$30,172,197$54.863 TOTAL FIXED OPERATING COSTS

$50,479,031

$91.787VARIABLE OPERATING COSTS$/kWh-netMaintenance Material Cost$14,863,811$0.00363ConsumablesConsumptionUnitInitial Initial /Day Cost Cost Water(/1000 gallons) 06,8011.08$0$2,282,387$0.00056 Chemicals MU & WT Chem.(lb) 032,9220.17$0$1,767,714$0.00043 Limestone (ton) 0 65421.63$0$4,389,274$0.00107 Carbon (Mercury Removal) (lb) 0 01.05$0$0$0.00000 MEA Solvent (ton) 9811.392,249.89$2,208,132$971,338$0.00024 NaOH (tons) 696.93433.68$30,065$932,782$0.00023 H2SO4 (tons) 666.62138.78$9,181$284,854$0.00007 Corrosion Inhibitor 0 00.00$135,751$0$0.00000 Activated Carbon(lb) 01,6621.05$0$541,593$0.00013 Ammonia (28% NH3) ton 0 97129.80$0$3,904,140$0.00095Subtotal Chemicals$2,383,130$12,791,695$0.00312 OtherSupplemental Fuel (MBtu) 0 00.00$0$0$0.00000SCR Catalyst (m3)w/equip.0.415,775.94$0$730,089$0.00018Emission Penalties 0 00.00$0$0$0.00000Subtotal Other$0$730,089$0.00018 Waste DisposalFly Ash (ton) 0 50216.23$0$2,524,978$0.00062Bottom Ash (ton) 012516.23$0$628,224$0.00015 Subtotal-Waste Disposal$0$3,153,202$0.00077 By-products & Emissions Gypsum (tons) 01,0130.00$0$0$0.00000Subtotal By-Products$0$0$0.00000TOTAL VARIABLE OPERATING COSTS$2,383,130$33,821,185$0.00826 Fuel(ton) 06,48038.18$0$76,766,172$0.01875 Cost and Performance Baseline for Fossil Energy Plants 590 This page intentionally left blank

Cost and Performance Baseline for Fossil Energy Plants 591 10. The initial issue of this report was published on May 15, 2007. Subsequent to the issue date, updates have been made to various report sections. These additions were made for clarification and aesthetic purposes and to correct an error made in determining the Econamine cooling water requirement in the PC and NGCC CO 2 capture cases. The water balances and water consumption comparison exhibits were updated accordingly. In addition, the PC and NGCC energy balance tables contained errors

, which have been corrected in this version of the report. None of the changes affect the conclusions in version 1 of the report

. REVISION CONTROL Th is second revision to this report includes more extensive changes. In the two years since the first version was released, improved modeling algorithms were developed, additional vendor information became available and numerous minor errors were identified.

Several studies were initiated that build on the baseline results generated here. Th e studies include: Impact of parallel and dry cooling systems Performance of a GE IGCC with CO 2 capture operated in a quench only mode COE sensitivity to Econamine cost and reboiler steam requirements Natural gas price sensitivity analysis Impact of dispatch

-based CF s All of these studies are reported as supplemental chapters to the original report. Because they were not part of the original study, they are not addressed in the Executive Summary or elsewhere throughout the report.

Exhibit 10-1 contains information added, changed or deleted in successive revisions.

Exhibit 10-1 Record of Revisions Revision Number Revision Date Description of Change Comments 1 8/23/07 Added disclaimer to Executive Summary and Introduction Disclaimer involves clarification on extent of participation of technology vendors.

Removed reference to Cases 7 and 8 in Exhibits

ES-1 and 1-1. SNG cases moved to Volume 2 of this report as explained in the Executive Summary and Section 1.

Added Section 2.8 Explains differences in IGCC TPC estimates in this study versus costs reported by other sources.

Cost and Performance Baseline for Fossil Energy Plants 592 Revision Number Revision Date Description of Change Comments Added Exhibit ES

-14 Mercury emissions are now shown in a separate exhibit from SO 2, NOx and PM because of the different y

-axis scale.

Corrected PC and NGCC

CO 2 capture case water balances The Econamine process cooling water requirement for the PC and NGCC CO 2 capture cases was overstated and has been revised. Replaced Exhibits ES

-4, 3-121, 4-52 and 5-30 The old water usage figures were in gpm (absolute) and in the new figures the water numbers are normalized by net plant output.

Updated Selexol process description Text was added to Section 3.1.5 to describe how H 2 slip was handled in the models.

Revised PC and NGCC

CO 2 capture case energy balances (Exhibits 4

-21, 4-42 and 5-21) The earlier version of the energy balances improperly accounted for the Econamine process heat losses. The heat removed from the Econamine process is rejected to the cooling tower.

Corrected Exhibit 5-12 and Exhibit 5-23. Sensible heat for combustion air in the two NGCC cases was for only one of the two

combustion turbines

- corrected to account for both turbines 2 10/27/10 Updated circulating water flow rate values in Section

4.1.7. Revision 1 changes to Econamine cooling water flow rate were not made in the text in Section 4.1.7 (Circulating Water System).

Added Supplmental Chapter 6 "Effect of Higher Natural Gas Prices and Dispatch

-Based Capacity Factors"

Cost and Performance Baseline for Fossil Energy Plants 593 Revision Number Revision Date Description of Change Comments Added Supplemental Chapter 7 "Dry and Parallel Cooling" Added Supplemental Chapter 8 "GEE IGCC in Quench-Only Configuration with CO 2 Capture" Added Supplemental Chapter 9 "Sensitivity to MEA System Performance and Cost Bituminous Baseline Case

12A" Updated Aspen models Major Aspen model updates included:

Converting FORTRAN code based steam cycles to Aspen blocks Using the Peng

-Robinson property method in the Aspen gasifier section Modifying the AGR used in the IGCC cases to more closely represent commercially available technology Increasing the capture efficiency of the CoP plant with capture to achieve 90 percent Correcting a steam condition error in the supercritical PC cases with capture Updated case performance results Major updates included:

Revising the water balances to include withdrawal and consumption CAD-based HMB diagrams were replaced with Visio versions Cost and Performance Baseline for Fossil Energy Plants 594 Revision Number Revision Date Description of Change Comments Completed updating case economic results Major updates included:

Adding owner's costs to the total plant costs to generate total overnight cost Updating fuel costs Revising the TS&M methodology to include the July, 2007 Handy

-Whitman Index, pore space acquisition costs, and liability costs R e-costing of cases based on the updated performance results Switching to COE as the primary cost metric (as opposed to levelized COE)

Updated report tables, figures and text to reflect the revision 2 changes

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, Gupta, Neeraj, Sass, Bruce M. and Bubenik, Thomas A., "Engineering and Economic Assessment of Carbon Dioxide Sequestration in Saline Formations ," Battelle Memorial Institute, 2001 28 Ciferno, Jared P. and McIlvried, Howard, "CO 2 Flow Modeling and Pipe Diameter Determination," February, 2003 29 Economic Evaluation of CO 2 Storage and Sink Enhancement Options, Tennessee Valley Authority, NETL and EPRI, December 2002 30 Parker, N., "Using Natural Gas Transmission Pipeline Costs to Estimate Hydrogen Pipeline Costs,"

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11 th Meeting of the International Post

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- 21, 2008, Vienna, Austria

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