# Cost and Performance Baseline for Fossil Energy Plants Volume 3c: Natural Gas Combined Cycle at Elevation

March 2011

DOE/NETL

- 2010 / 1396

# Disclaimer

This report was prepared as an account of work sponsored by an agency of the United States Gove rnment. 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, app aratus, 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 necessaril y 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 PLANT S VOLUME 3 c : NATURAL GAS COMBINED CYCLE AT ELEVATION

DOE/NETL

- 20 1 0 / 1396

Final Report March 2011

NETL Contact:

James B. Black Office of Program Planning & Analysis, Performance Divi sion

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” emiss ions), 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. E ver 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 pro gress 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 effi ciency of energy

use while at the same time significantly reducin g 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 conc ept 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 t he progress of the Fossil Energy RD&D portfolio. This report documents an accurate, independent assessment of the cost and performance for Natural Gas Combined Cycle (NGCC) plants with and without carbon dioxide (CO 2 

### ) capture and sequestration at two site elevations in Montana and North Dakota

. The NGCC cases are a subset of a study that also includes Integrated Gasification Combined Cycle (IGCC) and combustion cases. 

## Approach The power plant configurations analyzed in this study were modeled using the AS PEN 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 judg ment. 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. O peration and maintenanc e (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, th e report was updated both in terms of technical content and revised costs. 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 w hich to measure the progress of RD&D achievements.Cost and Performance Baseline

- Volume 3c (NGCC Cases)

I 

# T able of Contents

TABLE OF CONTENTS

................................ ................................ ................................ .............. I LIST OF EXHIBITS

................................ ................................ ................................ ................... III PREPARED BY

................................ ................................ ................................ ............................ V ACKNOWLEDGMENTS

................................ ................................ ................................ .......... VI LIST OF ACRONYMS AND ABBREVIATIONS

................................ ................................ . VII EXECUTIVE SUMMARY

................................ ................................ ................................ ........... 1 Energy Efficiency

................................ ................................ ................................ ..................... 4 Cost Results

................................ ................................ ................................ .............................. 5 Cost of Electricity

................................ ................................ ................................ .................... 6 First Year Cost of CO 2 

### Avoided

................................ ................................ ............................... 9 1. INTRODUCTION

................................ ................................ ................................ ................ 11 2. GENERAL EVALUATION B ASIS

................................ ................................ ................... 13 2.1 S ITE 

### C HARACTERISTICS



### ................................ ................................ ................................ .. 13 2.2 N ATURAL 

### G AS 

### C HARACTERISTICS



### ................................ ................................ .................. 15 2.3 E NVIRONMENTAL 

### T ARGETS



### ................................ ................................ ............................ 16 2.4 C APACITY 

### F ACTOR



### ................................ ................................ ................................ ......... 17 2.5 R AW 

### W ATER 

### W ITHDRAWAL AND 

### C ONSUMPTION



### ................................ ........................... 17 2.6 C OST 

### E STIMATING 

### M ETHODOLOGY



### ................................ ................................ ................ 18 2.6.1 Capital Costs

................................ ................................ ................................ .............. 19 2.6.2 Operations and M aintenance Costs

................................ ................................ ........... 27 2.6.3 CO 2 

### Transport, Storage and Monitoring

................................ ................................ ... 28 2.6.4 Finance Structure, Discounted Cash Flow Analysis, and COE

................................ 32 3. NGCC POWER PLANT PRO CESS DESCRIPTIONS

................................ ................... 41 3.1 NGCC C OMMON 

### P ROCESS 

### A REAS



### ................................ ................................ .................. 41 3.1.1 Natural Gas Supply System

................................ ................................ ........................ 41 3.1.2 Combustion Turbine

................................ ................................ ................................ ... 41 3.1.3 Heat Recovery Steam Generator

................................ ................................ ............... 43 3.1.4 NOx Control System

................................ ................................ ................................ ... 44 3.1.5 Carbon Dioxide Recovery Facility

................................ ................................ ............ 44 3.1.6 Steam Turbine

................................ ................................ ................................ ............ 49 3.1.7 Water and Steam Systems

................................ ................................ .......................... 50 3.1.8 Buildings and Structures

................................ ................................ ............................ 5 1 3.1.9 Accessor y Electric Plant

................................ ................................ ............................ 52 3.1.10 Instrumentation and Control

................................ ................................ .................. 52 3.2 NGCC P ROCESS 

### D ESCRIPTION



### ................................ ................................ ....................... 52 3.2.1 Key System Assumptions

................................ ................................ ............................ 53 3.2.2 Sparing Philosophy

................................ ................................ ................................ .... 54 3.3 C ASES 

### S31A AND 

### L31A P ROCESS 

### D ESCRIPTION



### ................................ ............................ 55 3.3.1 Case S31A

– Performance Results

................................ ................................ ............. 57 3.3.2 Case S31A

– Major Equipment List

................................ ................................ ........... 64 3.3.3 Case S31A

– Cost Estimating

................................ ................................ .................... 70 3.3.4 Case L31A

– Performance Results

................................ ................................ ............ 77 3.3.5 Case L31A

– Major Equipment List

................................ ................................ .......... 84Cost and Performance Baseline

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II 

### 3.3.6 Case L31A

– Cost Estimating

................................ ................................ .................... 89 3.4 C ASES 

### S31B AND 

### L31B P ROCESS 

### D ESCRIPTION



### ................................ ............................. 96 3.4 .1 Case S31B

– Performance Results

................................ ................................ ............. 97 3.4.2 Case S31B

– Major Equipment List

................................ ................................ ......... 106 3.4.3 Case S31B

– Cost Estimating

................................ ................................ .................. 112 3.4.4 Case L31B

– Performance Results

................................ ................................ .......... 119 3.4.5 Case L31B

– Major Equipment List

................................ ................................ ........ 128 3.4 .6 Case L31B

– Cost Estimating

................................ ................................ .................. 133 4. SUMMARY

................................ ................................ ................................ ........................ 141 5. REFERENCES

................................ ................................ ................................ ................... 149Cost and Performance Baseline

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III 

# List of Exhibits

Exhibit ES

- 1 Case Descriptions

................................ ................................ ................................ ..... 2 Exhibit ES

- 2 Cost and Performance Summary and Environmental Profile for NGCC Cases

...... 3 Exhibit ES

- 3 Net Plant Efficiency (HHV Basis)

................................ ................................ ........... 4 Exhibit ES

- 4 Total Overnight Cost

................................ ................................ ................................ 6 Exhibit ES

- 5 Economic Parameters Used to Calculate COE

................................ ........................ 7 Exhibit ES

- 6 COE by Cost Component

................................ ................................ ......................... 8 Exhibit ES

- 7 COE Sensitivity to Fuel Costs

................................ ................................ .................. 9 Exhibit ES

- 8 COE Sensitivity to CF

................................ ................................ ............................ 10 Exhibit ES

- 9 CO 2 

### Avoided Costs

................................ ................................ ................................ 10 Exhibit 2

- 1 Montana Site Ambient Conditions

................................ ................................ ........... 13 Exhibit 2

- 2 North Dakota Site Ambient Conditions

................................ ................................ .... 13 Exhibit 2

- 3 Site Characteristics

................................ ................................ ................................ ... 14 Exhibit 2

- 4 Natural Gas Composition

................................ ................................ .......................... 15 Exhibit 2

- 5 Environmental Targets for NGCC Cases

................................ ................................ .. 16 Exhibit 2

- 6 Capital Cost Levels and their Elements

................................ ................................ .... 19 Exhibit 2

- 7 Features of an AACE Class 4 Cost Estimate

................................ ............................ 20 Exhibit 2

- 8 AACE Guidelines for Process Contingency

................................ ............................. 24 Exhibit 2

- 9 Owner’s Costs Included in TOC

................................ ................................ ................ 25 Exhibit 2

- 10 TASC/TOC Factors

................................ ................................ ................................ 27 Exhibit 2

- 11 CO 2 

### Pipeline Specification

................................ ................................ ..................... 29 Exhibit 2

- 12 Deep Saline Aquifer Specification

................................ ................................ ......... 29 Exhibit 2

- 13 Global Economic Assumptions

................................ ................................ .............. 33 Exhibit 2

- 14 Financial Structure for Investor Owned Utility High and Low Risk Projects

........ 34 Exhibit 2

- 15 Illustration of COE Solutions using DCF Analysis

................................ ................ 36 Exhibit 2

- 16 PC with CCS in Current 2007 Dollars

................................ ................................ .... 37 Exhibit 2

- 17 Capital Charge Factors for COE Equation

................................ ............................. 38 Exhibit 2

- 18 COE and LCOE Summary

................................ ................................ ...................... 39 Exhibit 2

- 19 Baseline SC PC Results fo r CO 2 

### Cost Calculation

................................ ................. 39 Exhibit 3

- 1 Combustion Turbine Typical Scope of Supply

................................ ......................... 42 Exhibit 3

- 2 Fluor Econamine FG Plus Typical Flow Diagram

................................ ................... 46 Exhibit 3

- 3 CO 2 

### Compressor Interstage Pressures

................................ ................................ ...... 49 Exhibit 3

- 4 NGCC Plant Study Configuration Matrix

................................ ................................ 53 Exhibit 3

- 5 NGCC Balance of Plant Assumptions

................................ ................................ ...... 54 Exhibit 3

- 6 Cases S31A and L31A Process Flow Diagram, NGCC without CO 2 

### Capture

......... 56 Exhibit 3

- 7 Case S31A Stream Table, NGCC without CO 2 

### Capture

................................ .......... 57 Exhibit 3

- 8 Case S31A Plant Performance Summary

................................ ................................ . 58 Exhibit 3

- 9 Case S31A Air Emissions

................................ ................................ ......................... 59 Exhibit 3

- 10 Cases S31A Carbon Balance

................................ ................................ .................. 60 Exhibit 3

- 11 Case S31A Water Balance

................................ ................................ ...................... 60 Exhibit 3

- 12 Case S31A Heat and Mass Balance, NGCC without CO 2 

### Capture

........................ 61 Exhibit 3

- 13 Case S31A Overall Energy Bal ance (0°C [32°F] Reference)

................................ 63 Exhibit 3

- 14 Case S31A Total Plant Cost Summary

................................ ................................ ... 71 Exhibit 3

- 15 Case S31A Total Plant Cost Details

................................ ................................ ....... 72Cost and Performance Baseline

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IV 

### Exhibit 3

- 16 Case S31A Owner’s Costs

................................ ................................ ...................... 75 Exhibit 3

- 17 Case S31A Initial and Annual Operating and Maintenance Cost Summary

.......... 76 Exhibit 3

- 18 Case L31A Stream Table, NGCC without CO 2 

### Capture

................................ ......... 77 Exhibit 3

- 19 Case L31A Plant Performance Summary

................................ ................................ 78 Exhibit 3

- 20 Case L31A Air Emissions

................................ ................................ ....................... 79 Exhibit 3

- 21 Cases L31A Carbon Balance

................................ ................................ .................. 80 Exhibit 3

- 22 Case L31A Water Balance

................................ ................................ ...................... 80 Exhibit 3

- 23 Case L31A Heat and Mass Balance, NGCC without CO 2 

### Capture

........................ 81 Exhibit 3

- 24 Case L31A Overall Energy Balance (0°C [32°F] Reference)

................................ 83 Exhibit 3

- 25 Case L31A Total Plant Cost Summary

................................ ................................ ... 90 Exhibit 3

- 26 Case L31A Total Plant Cost Details

................................ ................................ ....... 91 Exhibit 3

- 27 Case L31A Owner’s Costs

................................ ................................ ...................... 94 Exhibit 3

- 28 Case L31A Initial and Annual Operating and Maintenance Cost Summary

.......... 95 Exhibit 3

- 29 Cases S31B and L31B Process Flow Diagram, NGCC with CO 2 

### Capture

............ 96 Exhibit 3

- 30 Case S31B Stream Table, NGCC with C O 2 

### Capture

................................ ............. 98 Exhibit 3

- 31 Case S31B Plant Performance Summary

................................ ................................ 99 Exhibit 3

- 32 Case S31B Air Emissions

................................ ................................ ..................... 100 Exhibit 3

- 33 Cases S31B Carbon Balance

................................ ................................ ................. 101 Exhibit 3

- 34 Case S31B Water Balance

................................ ................................ .................... 101 Exhibit 3

- 35 Case S31B Heat and Mass Balance, NGCC with CO 2 

### Capture

........................... 103 Exhibit 3

- 36 Case S31B Overall Energy Balance (0°C [32°F] Reference)

............................... 105 Exhibit 3

- 37 Case S31B Total Plant Cost Summary

................................ ................................ . 113 Exhibit 3

- 38 Case S31B Total Plant Cost Details

................................ ................................ ..... 114 Exhibit 3

- 39 Case S31B Own er’s Costs

................................ ................................ .................... 117 Exhibit 3

- 40 Case S31B Initial and Annual Operating and Maintenance Cost Summary

........ 118 Exhibit 3

- 41 Case L31B Stream Ta ble, NGCC without CO 2 

### Capture

................................ ...... 120 Exhibit 3

- 42 Case L31B Plant Performance Summary

................................ ............................. 121 Exhibit 3

- 43 Case L31B Air Emissions

................................ ................................ ..................... 122 Exhibit 3

- 44 Case L31B Carbon Balance

................................ ................................ .................. 123 Exhibit 3

- 45 Case L31B Water Balance

................................ ................................ .................... 123 Exhibit 3

- 46 Case L31B Heat and Mass Balance, NGCC without CO 2 

### Capture

...................... 125 Exhibit 3

- 47 Case L31B Overall Energy Balance (0°C [32°F] Reference)

.............................. 127 Exhibit 3

- 48 Case L31B Total Plant Cost Summary

................................ ................................ . 134 Exhibit 3

- 49 Case L31B Total Plant Cost Details

................................ ................................ ..... 135 Exhi bit 3

- 50 Case L31B Owner’s Costs

................................ ................................ .................... 138 Exhibit 3

- 51 Case L31B Initial and Annual Operating and Maintenance Cost Summary

........ 139 Exhibit 4

- 1 Performance and Cost Results for NGCC Cases

................................ .................... 141 Exhibit 4

- 2 Total Overnight Costs

................................ ................................ ............................. 142 Exhibit 4

- 3 COE of NGCC Cases

................................ ................................ .............................. 143 Exhibit 4

- 4 Sensitivity of COE to Capacity Factor in NGCC Cases

................................ ......... 144 Exhibit 4

- 5 Sensitivity of COE to Fuel Price in NGCC Cases

................................ .................. 144 Exhibit 4

- 6 CO 2 

### Avoided Costs

................................ ................................ ................................ . 146 Exhibit 4

- 7 Water Usage in NGCC Costs

................................ ................................ .................. 147Cost and Performance Baseline

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V 

## PREPARED BY

Research and Develo pment Solutions, LLC (RDS) :

UPDATED BY Energy Sector Planning and Analysis (ESPA) :

Vincent H. Chou Booz Allen Hamilton John L. Haslbeck Booz Allen Hamilton Allison Kyle Booz Allen Hamilton Eric Lewis Booz Allen Hamilton

Lora L. Pinkerton

WorleyParsons

Vas ant Shah Booz Allen Hamilton Elsy Varghese WorleyParsons Mark C. Woods Booz Allen Hamilton

DOE Contract # DE

- FE0004001Cost and Performance Baseline

- Volume 3c (NGCC Cases)

VI 

# 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

- 401.01.14A. The report was updated by Booz Allen Hamilton Inc. under DOE NETL Contract Number DE

- FE0004001, Energy Sector Plann ing and Analysis.
The authors wish to acknowledge the excellent guidance, contributions, and cooperation of the NETL staff, particularly:
John Wimer, Director of Office of Program Planning & Analysis
Wally Shelton

James Black

Jeff Hoffmann

Robert JamesCost and Performance Baseline

- Volume 3c (NGCC Cases)

VII 

### AACE Association for the Advancement of Cost Engineering L IS T OF A CRONYMS AND A BBREVIATIONS

AC Alternating current

a cfm Actual cubic feet per minute AEO Annual Energy Outlook Al Aluminum ANSI American National Standards Institute Aspen Aspen Plus ® BACT Best a vailable control technology BEC Bare erected cost BFD Block flow diagram BFW Boiler feed water BLS Bureau of Labor Statistics Btu British thermal unit Btu /h r British thermal unit per hour Btu/kWh British thermal unit per kilowatt hour Btu/lb British therma l unit per pound Btu/scf British thermal unit per standard cubic foot CCF Capital c harge f actor CDR Carbon dioxide r ecovery CF Capacity factor CFB Circulating f luidized b ed CL Closed

- loop

cm Centimeter CO 2 

### Carbon dioxide COE Cost of electricity CS Carbon s teel CWP Circulating water pump CT Combustion turbine CTG Combustion t urbine

- g enerator CWT Cold water temperature DC Direct current DCS Distributed control system DI De

- ionized Dia. Diameter DLN D ry low NOx DOE Department of Energy EAF Equivalent availabil ity factor EIA Energy Information Administration EPA Environmental Protection Agency EPC Engineer/ p rocure/ c onstruct EPCM Engineering/ p rocurement/ c onstruction m anagementCost and Performance Baseline

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VIII 

### FEED Front

- End Engineering Design FW Feedwater FOAK First

- of

- a

- kind ft Foot, f eet gal G allon GCV G ross calorific value GDP Gross domestic product GJ Gigajoule GJ/hr Gigajoule per hour gpm Gallons per minute gr/100 scf grains per one hundred standard cubic feet h, hr Hour H 2 

### Hydrogen Hg Mercury HHV Higher heating value hp Horsepower HP High p ressure HRSG Heat recovery steam generator HSS Heat stable salts HVAC Heating, ventilating, and air conditioning HWT Hot water temperature Hz Hertz IEA International Energy Agency IGCC Integrated gasification combined cycle in Inches IOU Investor

- owned uti lity IP Intermediate pressure ISO International Standards Organization kg/GJ Kilogram per gigajoule kg /hr Kilogram per hour kJ Kilojoules kJ/kg Kilojoules per kilogram km K ilometers kV Kilovolt kW Kilowatt kWe Kilowatts electric kWt Kilowatts thermal LAER Lowest Achievable Emission Rate CH 4 

### Methane lb Pound lb /h r Pounds per hour lb/MMBtu Pounds per million British thermal units lb/MWh Pounds per megawatt hourCost and Performance Baseline

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### LCOE Levelized cost of electricity LHV Lower heating value LNB Low NOx burner LP Low pressure lpm L iters per minute

m Meters

m 3 

### /min Cubic meter per minute md Millidarcy (a measure of permeability) MEA M onoethanolamine Mills/kWh Ten ths of a cent per kilowatt

- hour MJ/Nm 3 

### Megajoule per normal cubic meter MJ/scm Megajoule per standard cubic meter MMBtu Mill ion 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 MPa Megapascals MVA Mega vol t

- amps MW Megawatts MWh Megawatt

- hour N/A Not applicable NAAQS National Ambient Air Quality Standards NEMA National Electrical Manufacturers Association NERC North American Electric Reliability Council NETL National Energy Technology Laboratory NGCC Natura l gas combined cycle NH 3 

### Ammonia Nm 3 

### Normal cubic meter NO 2 

### N itrogen oxide NOAK N th



### - of

- a

- kind NOx Oxides of nitrogen NSPS New Source Performance Standards NSR New Source Review NDL site North Dakota Lignite Site O 2 

### Oxygen O&M Operation and maintenance OC Fn 

### Category n fixed operating cost for the initial year of operation OC Vn 

### Category n variable operating cost for the initial year of operation OSAP Office of Systems, Analyses and Planning PC Pulverized c oal PM Particulate matter POTW Publicly Owned Treatmen t Works PO Purchase orderCost and Performance Baseline

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### ppmv Parts per million volume ppmvd Parts per million volume dry PRB Powder River Basin coal region PSD Preventi on of Significant Deterioration p sia Pounds per square inch absolute psig Pounds per square inch gage Qty Quantity RD S Research and Development Solutions, LLC RH Reheater S Sulfur SC Supercritical scfm Standard cubic feet per minute SCR Selective catalytic reduction process or equipment SO 2 

### Sulfur dioxide SOx Oxides of sulfur SS Stainless steel STG Steam turbine generato r TCR Total capital requirement TASC T otal as

- spent cost TEWAC Totally Enclosed Water

- to

- Air Cooled TiO 2 

### T itanium dioxide t onne Metric Ton (1000 kg) TOC Total overnight cost TPC Total plant cost TPD Tons per day tph Tons per hour TS&M Transport, storage and monitoring U.S. United States USC U ltra

- supercritical yr Year V 2 

### O 5 

### V anadium pentoxide vol% Volume percent WB Wet bulb WO 3 

### T ungsten trioxide wt% Weight percent $/MMBtu Dollars per million British thermal units $/MMkJ Dollars per million kilojoule $/MW h D ollars per megawatt hour % PercentCost and Performance Baseline

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### This page intentionally left blankCost and Performance Baseline

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1 

### The objective of this report is to present an accurate, independent assessment of the cost and performance of electricity production from natural gas combined cycle ( NGCC ) power systems using a consistent technical and economic approach that accurately reflects current market conditions for plants using commercially available technology

. This document is Volume 3c of the Low Rank Coal Baseline Reports, which a re part of a four volume series consist ing 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

T he cost and performance of the various fossil fuel

- based technologies will most likely determine which combination of technologies will be utilized to meet the demands of the power market. Selection of new generation technologies will depend on many factors, including:

**•** Capital and operating costs

**•** Overall energy efficiency

**•** Fuel prices

**•** Cost of electricity (COE)

**•** Availability
, reliability , and environmental performance

**•** Current and potential regulation of air , water, and solid waste discharges from fossil

fueled power plants

.

**•** Market penetration of c lean coal technologies that have matured and improved as a result of recent commercial

- scale demonstrations under the Department of Energy’s ( DOE ) Clean Coal Progra ms F our NGCC plant configurations were analyzed as listed in Exhibit ES

- 1

. Two plants were located in Montana (with and without CO 2 

### capture) and two in North Dakota (with and without CO 2 

### capture). The plant locat ions are the same that were used to evaluate gasification and combustion based systems in Volumes 3a and 3b of this study. T he Montana site corresponds to cases that used Pow d er River Basin (PRB ) coal in the gasification and combustion reports while the N orth Dakota s ite corresponds to the cases that used lignite coal

. While the cases in this report all use natural gas, references to PRB and lignite coals are used to distinguish between the two plant locations with the primary difference being elevation

. The Montana site elevation is 1,036 meters (m) (3,400 feet [ft]) and the North Dakota site is 579 m (1,900 ft).
The methodology included performing steady

- state simulations of the various technologies using the Aspen Plus ® (Aspen) modeling program. The r esulting mass and energy balance data from 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,Cost and Performance Baseline

- Volume 3c (NGCC Cases)

2 

### information obtained fro m vendors and users of the technology, performance data from design/build utility projects, and/or best engineering judgment . Capital and operating costs were estimated based on simulation results and through a combination of vendor quotes, scaled estimat es from previous design/build projects, or a combination of the two. Baseline fuel costs for this analysis were determined using data from the E nergy Information Administration’s (EIA) 200 8 Annual Energy Outlook (AEO) . The 2007 cost used for natural gas is $6. 76 / m illion kilojoules ( MMkJ ) ($ 7

. 13 / m illion British thermal units [ MMBtu ] ) on a higher heating value (HHV) basis and in June 2007 United States ( U.S. ) dollars.
Exhibit ES

- 1 Case Descriptions

Case Unit Cycle Steam Cyc le, psig/ **°** F / 

### ° F Boiler Technology Location CO 2 

### Separation

S31A NGCC 2400/1050/1050 HRSG Montana

- S31B NGCC 2400/1050/1050 HRSG Montana Amine Absorber
L31A NGCC 2400/1050/1050 HRSG North Dakota

- L31B NGCC 2400/1050/1050 HRSG North Dakota Amine Absorber
All plant configurations were evaluated based on installation at a greenfield site (Montana or North Dakota )

. To compare the plants on an equivalent basis, it was assumed that these plants would be dispatch ed any time they are available. T he study capa city factor (CF) , 85 percent , was chosen to reflect the maximum availability for NGCC plants. Since variations in fuel costs and other factors can influence dispatch order and CF , sensitivity of levelized COE to CF was evaluated and is presented later in this Executive Summary ( Exhibit ES

- 8 )

. The nominal net plant output for this study was set to approximately 5 0 0 megawatts ( MW ) to satisfy combustion turbine (CT) constraint as CTs are available in discrete sizes. The actual net output varies by site and carbon capture requirement

. T he heat recovery boilers and steam turbines in all cases are readily available in a wide range of capacities.

Exhibit ES

- 2 shows the cost, perf ormance , and environmental profile summary for all cases which are discussed below

.Cost and Performance Baseline

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3 

### Exhibit ES

- 2 Cost and Performance Summary and Environmental Profile for NGCC Cases

PERFORMANCE Case S31A Case L31A Case S31B Case L31B CO 2 Capture 0% 0% 90% 90% Gross Power Output (kW e ) 522,100 557,000 470,000 501,600 Auxiliary Power Requirement (kW e ) 9,690 10,020 34,940 36,960 Net Power Output (kW e ) 512,410 546,980 435,060 464,640 Natural Gas Flowrate (lb/hr) 153,559 163,560 153,559 163,560 HHV Thermal Input (kW th ) 1,014,787 1,080,880 1,014,787 1,080,880 Net Plant HHV Efficiency (%) 50.5% 50.6% 42.9% 43.0% Net Plant HHV Heat Rate (Btu/kWh) 6,757 6,743 7,959 7,938 Raw Water Withdrawal (gpm/MW net ) 2.1 2.1 7.1 7.1 Process Water Discharge (gpm/MW net ) 0.5 0.5 1.8 1.8 Raw Water Consumption (gpm/MW net ) 1.6 1.6 5.3 5.3 CO 2 Emissions (lb/MMBtu) 118 118 12 12 CO 2 Emissions (lb/MWh gross ) 784 783 87 87 CO 2 Emissions (lb/MWh net ) 799 797 94 94 SO 2 Emissions (lb/MMBtu) Negligible Negligible Negligible Negligible SO 2 Emissions (lb/MWh gross ) Negligible Negligible Negligible Negligible NOx Emissions (lb/MMBtu) 0.009 0.009 0.009 0.009 NOx Emissions (lb/MWh gross ) 0.060 0.060 0.067 0.066 PM Emissions (lb/MMBtu) Negligible Negligible Negligible Negligible PM Emissions (lb/MWh gross ) Negligible Negligible Negligible Negligible Hg Emissions (lb/TBtu) Negligible Negligible Negligible Negligible Hg Emissions (lb/MWh gross ) Negligible Negligible Negligible Negligible COST Total Plant Cost (2007$/kW) 666 637 1,315 1,267 Total Overnight Cost (2007$/kW) 817 782 1,607 1,548 **Bare Erected Cost** 546 521 994 957 **Home Office Expenses** 46 44 84 81 **Project Contingency** 74 71 174 168 **Process Contingency** 0 0 62 61 **Owner's Costs** 151 145 291 281 Total Overnight Cost (2007$ x 1,000) 418,817 427,473 698,949 719,155 Total As Spent Capital (2007$/kW) 879 840 1,732 1,668 COE (mills/kWh, 2007$) 1 64.4 63.6 92.9 91.4 **CO 2**  **TS&M Costs** 0.0 0.0 3.4 3.3 **Fuel Costs** 48.2 48.1 56.7 56.6 **Variable Costs** 1.4 1.3 2.7 2.6 **Fixed Costs** 3.4 3.2 6.1 5.9 **Capital Costs** 11.5 11.0 24.0 23.1 LCOE (mills/kWh, 2007$) 1 81.7 80.6 117.8 115.8 NGCC with Advanced F Class

1 COE and Levelized COE are defined in Section 2.6Cost and Performance Baseline

- Volume 3c (NGCC Cases)

4 

### The net plant e fficiency (HHV basis) for all four cases is shown in Energy Efficiency

Exhibit ES

- 3 . The primary conclusion s that can be drawn are :

**•** The CO 2 

### capture result s in an efficiency penalty of 7. 6 absolute percent, relative to the

non

- capture case at both locations.

**•** The increase in elevation, going from the NDL to the Montana site, has minimal impact on efficiency but does cause a derate in the gas turbine compressor, reducing the net plant output by six percent for both CO 2 

### capture and non

- capture cases.

Exhibit ES

- 3 Net Plant Efficiency (HHV Basis)

50.5%

42.9% 50.6%

43.0%

0% 10% 20% 30% 40% 50% 60% 70%

NGCC PRB NGCC PRB w/ Capture NGCC Lig NGCC Lig w/ CaptureEfficieny, % (HHV Basis) Montana Site Elevation: 3,400 ft North Dakota Site Elevation: 1,900 ftCost and Performance Baseline

- Volume 3c (NGCC Cases)

5 

### The Total Plant Cost (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 con tingencies (process and project). Owner’s costs, including preproduction costs, inventory capital, initial cost for catalyst and chemicals, land, financing costs and other owner’s costs were added to TPC to generate total overnight cost (TOC). Property t axes and insurance were included in the fixed operating costs as an additional owner’s cost. 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). Cost Results

The cost est imates carry an accuracy of

- 15/+ 30 % , consistent with a “feasibility study ” level of design engineering applied to the various cases in this study. The value of the study lies not in the absolute accuracy of the individual case results
, but in the fact th at all cases were evaluated under the same set of technical and economic assumptions. This consistency of approach allows meaningful relative comparisons among the cases evaluated. Project contingencies were added to the Engineering/Procurement/Construc tion 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 exp erience. The cost accounts that received a process contingency include:

**•** Fluor’s Econam ine FG Plus SM 

### ( Econamine ) CO 2 

### Removal System

– 20 percent on both CO 2 

### capture cases

- unproven technology at commercial scale.

**•** Instrumentation and Controls

– five percen t on all accounts for CO 2 

### capture cases

. The normalized components of TOC and overall TASC are shown for each plant configuration i n Exhibit ES

- 4 . The following conclusions can be drawn:

**•** Adding CO 2 

### capture increas es the normalized TOC by approximately 9 7 percent. The Econamine unit and CO 2 

### compression train add significant capital cost
, as well as project and process contingency.

**•** The normalized TOC for the plants located at the NDL site are 4 percent lower than th e plants located at the Montana site. This trend is primarily because of the lower net output at the higher elevation of the Montana site.

**•** Adding Owner’s Costs to the TPC increases the cost of the non

- capture plants by approximately 23 percent and the CO 2 

### capture plants by 22 percent.Cost and Performance Baseline

- Volume 3c (NGCC Cases)

6 

### Exhibit ES

- 4 Total Overnight Cost

817 1,607

782 1,548

879 1,732

840 1,668

0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000

TOC TASC TOC TASC TOC TASC TOC TASC

NGCC NGCC w/ CO2 Capture NGCC NGCC w/ CO2 CaptureTOC and TASC ($/kW) TASC Owner's Cost Process Contingency Project Contingency Home Office Expense Bare Erected Cost North Dakota Site Elevation: 1,900 ft Montana Site Elevation: 3,400 ft



### 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 plan t’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 Po wer Systems Financial Model ( PSFM ) [ Cost of Electricity

1 ] was used to determine a “base

- year” (2007) COE that, when escalated at an assumed nominal annual general inflation rate of 3 percent 1



### Exhibit ES

- 5 , 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 simplifie d equation as detailed in Section 2.6.4

.

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 date s 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

- Volume 3c (NGCC Cases)

7 

### The project financial structure varies depending on the type of project (high risk or low risk). All cases were assumed to be undertaken at investor owned utilities (IOUs). High risk p rojects are those in which commercial scale operating experience is limited. Cases with CO 2 

### capture were considered to be high risk. All NGCC cases were assumed to have a 3 year capital expenditure period. The current

- dollar, 30

- year levelized cost of e lectricity (LCOE) was also calculated and was shown in Exhibit ES

- 2 , 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 2.6 of the report.
Exhibit ES

- 5 Economic Parameters Used to Calculate COE
High Risk (3 year capital

expenditure period) Low Risk (3 year capital

expenditure period)

First Year Capital Charge Factor 0.1 111 0 .1 048

Commod ity 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 Chemic al 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 expe cted to be representative of January 2010 costs.

The COE results are shown in Exhibit ES

- 6 with the capital cost, fixed operating cost, variable operating cost, and fuel cost shown separately. In the capture cases
, the CO 2 

### T ransport, S torage and M onitoring (TS&M) costs are also shown as a separate bar segment. The following conclusions can be drawn:

**•** The COE is dominated by fuel costs in all cases. The fuel cost component of COE comprises approximately 7 5 percent in both non

- capture cases and 62 percent in both capture cases

.

**•** The capital cost component is relatively minor in all cases, representing approximately 18 percent of the COE costs in the non

- capture cases and 25 percent in the CO 2 

### capture
cases.

**•** Adding CO 2 

### removal more than doubles the capital cost component and increa ses the COE by approximately 4 4 percent for each location.

**•** The TS&M component of COE in the CO 2 

### capture cases is about 4 percent for both capture cases

.Cost and Performance Baseline

- Volume 3c (NGCC Cases)

8 

### Exhibit ES

- 6 COE by Cost Component

11.5 24.0

11.0 23.1 3.4 6.1

3.2 5.9

1.4 2.7

1.3 2.6 48.2 56.7

48.1 56.6 3.4 3.3

64.4 92.9

63.6 91.4

0 20 40 60 80 100 120

NGCC PRB NGCC PRB w/Capture NGCC Lig NGCC Lig w/CaptureCOE (2007 mills/kWh) CO2 TS&M Cost Fuel Cost
Variable O&M Cost
Fixed O&M Cost Capital Cost Montana Site Elevation: 3,400 ft North Dakota Site Elevation: 1,900 ft



### Exhibit ES

- 7 shows the COE sensitivity to fuel cost. The top set of line s show the C OE sensitivity of capture cases , and t he bottom set of line s show the sensitivity of non

- captu re cases. As expected, a ll cases show a linear increase in CO E with the increase in natural gas prices

. The sensitivity of COE to CF is shown in Exhibit ES

- 8 . The top set of lines is the COE of the capture case s. The bottom set of lines is the non

- capture cases. All cases show a n expected decrease in CO E with the increase in CF

.Cost and Performance Baseline

- Volume 3c (NGCC Cases)

9 

### Exhibit ES

- 7 COE Sensitivity to Fuel Costs

0 20 40 60 80 100 120 140 160

0 2 4 6 8 10 12 14COE (2007 mills/kWh)

Natural Gas Price, $/MMBtu NGCC w/CO2 Capture Montana Site
NGCC w/CO2 Capture North Dakota Site
NGCC No Capture Montana Site
NGCC No Capture North Dakota Site

Capacity Factor = 85% for all cases Study Natural Gas Cost: $7.13/MMBtu



### The CO 2 

### emissions per m egawatt hour ( MWh ) in the non

- capture cases are about the same for both sites. The first year cost of CO 2 

### avoided was calculated as follows. First Year Cost of CO 2 

### Avoided

MWh tons Emissions CO Emissions CO MWh COE COE Cost Avoided

removal with removal o w removal with 

### / } { / $ } {

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

- 9 for both sites. The avoided costs are calculated for the CO 2 

### capture (B) case compared to results from each analogous non

- capture plant (A) and c ompared to a baseline SC PC non

- capture plant (SC PC A)

. The cost of CO 2 

### avoided averages $88 .0 /ton ne ($79.9/ton) compared to the analogous non

- capture (A) design and $38.4/ton ne ($34.8/ton) compared to the baseline SC PC non

- capture (SC PC A) design.Cost and Performance Baseline

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10 

### Exh ibit ES

- 8 COE Sensitivity to CF

0 20 40 60 80 100 120 140 160 180

0 10 20 30 40 50 60 70 80 90 100COE (2007 mills/kWh)

Capacity Factor, % NGCC w/CO2 Capture Montana Site

NGCC w/CO2 Capture North Dakota Site NGCC No Capture Montana Site

NGCC No Capture North Dakota Site Study Capacity Factor is 85% for all cases



### Exhibit ES

- 9 CO 2 

### Avoided Costs

89.1 87.0

43.0

33.8

0 10 20 30 40 50 60 70 80 90 100 110

NGCC PRB w/Capture NGCC Lig w/CaptureFirst YEar CO2Avoided Cost, (2007$/Tonne) Avoided Cost (Analogous Technology w/o Capture Reference Avoided Cost (SC PC w/o Capture Reference)

Montana Site Elevation: 3,400 ft North Dakota Site Elevation: 1,900 ftCost and Performance Baseline

- Volume 3c (NGCC Cases)

11 

### 1.
The objective of this report is to present an accurate, independent assessment of the cost and performance of e lectricity production from natural gas combined cycle ( NGCC ) power systems in a consistent technical and economic manner that accurately reflects current market conditions for plants using commercially available technology

. This document is Volume 3c of t he Low Rank Coal Baseline Reports, which are part of a four volume series consist ing 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 Co al and Natural Gas to Electricity

**•** Volume 4: Bituminous Coal to Liquid Fuels with Carbon Capture

Four NGCC power plant configurations were analyzed as listed in Exhibit ES

- 1 . The list includes two locations corresp onding to the Montana Powder River Basin ( PRB ) s ite and two locations corresponding to the North Dakota Lignite (NDL) s ite

. The plant locations are the same that were used to evaluate gasification and combustion based systems in Volumes 3a and 3b of this study. T he Montana site corresponds to cases that used Powder River Basin (PRB ) coal in the gasification and combustion reports while the North Dakota s ite corresponds to the cases that used lignite coal

. While the cases in this report all use natural ga s, references to PRB and lignite coals are used to distinguish between the two plant locations with the primary difference being elevation. The Montana site elevation is 1,036 meters (m) (3,400 feet [ft]) and the North Dakota site is 579 m (1,900 ft). Bo th sites include cases with and without CO 2 

### capture. The naming convention for the cases covered in this report is as follows:

**•** First letter represents location: S = PRB Montana ; L = NDL location

**•** Two digit number represents technology type: 31 = NGCC

**•** Fi nal letter indicates CO 2 

### capture: A = no capture; B = capture Volume 3c covers the four NGCC cases at the Montana and North Dakota sites : Case S31 A

– This case is based on n atural g as feed where the plant is located at the Montana PRB site

. Case S31 B

– Th is case is the same as S31 A except it includes CO 2 

### capture. Case L31 A

– This case is based on n atural g as feed where the plant is located at the NDL site

. Case L31 B

– This case is the same as L31 A except it includes CO 2 

### capture. Generating Unit Configurat ions The nominal net plant output for this study is set to approximately 500 MW to satisfy CT constraint as CTs are available in discrete sizes. The actual net output varies by site and CO 2 

### capture requirement. The heat recovery boilers and steam turbine s in all cases are readily available in a wide range of capacities.Cost and Performance Baseline

- Volume 3c (NGCC Cases)

12 

### The balance of this report is organized as follows:

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

**•** Chapter 3 describes the NGCC technologies modeled and presents the results for the four NGCC cases.

**•** Chapter 4 contains a summary of results

.

**•** Chapter 5 contains the reference list

.Cost and Performance Baseline

- Volume 3c (NGCC Cases)

13 

### 2. G ENERAL E VALUATION B ASIS
For each of the plant configurations in this study an Aspen model was developed and used to gene rate material and energy balances, which provide d the 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 lim its 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 and scaled estimates from previous design/buil d projects. Ultimately
, a COE was calculated for each of the cases and is reported as the economic figure

- of

- merit.
The balance of this chapter documents the design basis, environmental targets
, and cost assumptions used in the study.

2.1 SITE CHARACTERISTICS
The plants are located at two different generic plant sites
, Montana PRB site and NDL site. The ambient conditions for the two sites are shown in Exhibit 2

- 1 and Exhibit 2

- 2

. Exhibit 2

- 1 Montana Site Ambient Conditions Elevation, m (ft) 1,036 (3,400) Barometric Pressure, MPa (psia) 0.09 (13.0) Design Ambient Temperature, Dry Bulb, °C ( **°** F) 5.6 (42) Design Ambient Temperature, Wet Bulb, °C ( **°** F) 2.8 (37) Design Ambient Relative Humidity, % 62

Exhibit 2

- 2 North Dakota Site Ambient Conditions

El evation, m (ft) 579 (1,900) Barometric Pressure, MPa (psia) 0.10 (13.8) Design Ambient Temperature, Dry Bulb, °C ( **°** F) 4.4 (40) Design Ambient Temperature, Wet Bulb, °C ( **°** F) 2.2 (36) Design Ambient Relative Humidity, % 68

The site characteristics are assumed to be the same for both plant location s , as shown in Exhibit 2

- 3

.Cost and Performance Baseline

- Volume 3c (NGCC Cases)

14 

### Exhibit 2

- 3 Site Characteristics

Location Greenfield, Montana PRB site or NDL site
Topography Level
Size , acres 1 00 Transportation Rail Ash/Slag Disposal N/A
Water Municipal (50%) / Groundwater (50%)
Access Land locked , having access by rail and highway

CO 2 

### Storage Compressed to 15.3 MPa (2,215 psia), transported 80 kilometers (km) (50 miles)
, and sequ estered in a saline formation at a depth of 1,239 m (4,055 ft)

It was assumed that the plant proper occupies 10 acres providing a 0.15 mile buffer to the plant fence line for a total area of 100 acres

. In all cases it was assumed that buildings house the steam turbine and boiler. 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

**•** Fire protection

**•** Local code height requirements

**•** Noise regulations

– Impact on site and surrounding areaCost and Performance Baseline

- Volume 3c (NGCC Cases)

15 

### 2.2 NATURAL GAS CHARACTE RISTICS
Natural gas compos ition for all c ases with and without CO 2 

### capture is presented in Exhibit 2

- 4

. The f uel composition is normalized and heating values are calculated

. Exhibit 2

- 4 Natural Gas Composit ion

Component Vol %
Methane CH 4 

### 93. 1 Ethane C 2 

### H 6 

### 3.2 Propane C 3 

### H 8 

### 0.7

n

- Butane C 4 

### H 10 

### 0.4 Carbon Dioxide CO 2 

### 1.0 Nitrogen N 2 

### 1.6
Total 100 .0
LHV HHV kJ/kg 47, 454 52, 581 MJ/scm 34.71 38.46 Btu/lb 20,410 22, 600
B tu/scf 932 1,032

The Power Systems Financial Model (PSFM) was used to derive the capital charge factors and levelization factors for this study. 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 first year cost of natural gas used in this study is $6.76/MMkJ ($7.13/MMBtu) (2007 cost of natural gas in 2007 dollars). The cost was determined using the fol lowing information from the EIA’s 2008 AEO:

**•** The 2007 M ountain region delivered cost of natural gas to electric utilities in 2006 dollars, $252/1000 m 3 

### ($7.14/1000 ft 3 

### ), was obtained from the AEO 2008 reference case Table 108 and converted to an energy basi s, $6.56/MMkJ ($6.92/MMBtu) [ 2

**•** The 2007 cost was escalated to 2007 dollars using the GDP chain

- type price index from AEO 2008, resulting in a delivered 2007 price in 2007 dollars of $6.76/MMkJ ($7.13/MMBtu) [ ]

.

3 ]

.Cost and Performance Baseline

- Volume 3c (NGCC Cases)

16 

### 2.3 ENVIRONMENTAL TARGET S

The environmental ta rgets 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, and the status of current best available con trol technology (BACT).
Natural Gas Combustion Design Targets 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 techno logies employed and are presented in Exhibit 2

- 5

. Exhibit 2

- 5 Environmental Targets for NGCC Cases

Pollutant Environmental Target 40 CFR Part 60, Subpart KKKK Limits Control Techno logy

NOx 2.5 ppmv @ 15% O 2 

### 15 ppmv @ 15% O 2 

### Low NOx burners and SCR

SO 2 

### Negligible 0.9 lb/MWh (0.135 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 6,690 Btu/kWh.



### Publ ished vendor literature indicates that 25 ppmv NOx at 15 percent oxygen ( O 2 

### ) is achievable using natural gas and dry low NOx (DLN) technology [ 4
, 5

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 perc ent CH 4 

### by volume or having a gross calorific value (GCV ) of between 35.4 and 40.9 megajoule per normal cubic meter ( MJ/Nm 3 

### ) (950 and 1,100 Btu/scf) and having a total sulfur content of less than 13.7 milligrams per normal meter cubed ( mg /Nm 3 

### ) (0.6 gr/100 scf [ grains per one hundred standard cubic feet ] ) [ ]

. The application of SCR with 90 percent efficiency further reduces NOx emissions to 2.5 ppmv, which was sel ected as the environmental target.

6

The pipeline natural gas was assumed to contain no 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 non

- capture NGCC cases in this study would be 9.7 metric ton (1000 kg) (ton n es) / year ( yr ) ( 1 0.7 tons/yr) at 85 percent CF or 0.000 73 kilogram per gigajoule ( kg /GJ ) (0. 00 17 lb /MMBtu). Thus
, for the purpose of this study, SO 2 

### emissions were considered negligible.Cost and Performance Baseline

- Volume 3c (NGCC Cases)

17 

### Carbon Dioxide
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. CO 2 

### emissi ons are reported on both a pound ( lb ) /(gross) MWh and lb/(net) MWh basis in each capture case emissions table.

For the cases in this report volume that have CO 2 

### capture, the basis is a nominal post

- combustion 90 percent removal based on carbon input from t he natural gas

. It is assumed that all of the fuel carbon becomes CO 2 

### in the CT flue gas.

The cost of CO 2 

### capture was calculated as a first year avoided cost as illustrated in the equation below. Analogous non

- capture technologies and SC non

- capture PC w ere chosen as separate reference cases. The COE in the CO 2 

### capture cases includes TS&M as well as capture and compression.



## MWh tons Emissions CO Emissions CO MWh COE COE Cost Avoided

removal with reference reference removal with 

## / } { / $ } {

2 2 

## − **−**

**=**

2.4 CAPACITY FACTOR
This study assumes that each new plant would be dispatched any time it is available and wou ld be capable of generating maximum capacity when online ; t herefore
, CF and availability are equal

. The availability for NGCC cases was determined using the Generating Availability Data System (GADS) from the North American Electric Reliability Council (N ERC) [ 7

NERC defines an equivalent availability factor (EAF) as 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 ma tches this study’s definition of 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. T he EAF was rounded up to 85 percent and that value was also used as the NGCC plant CF

. Th e addition of CO 2 

### capture was assumed not to impact the CF even without redundant pipelines, wells or subsurface infrastructure

. This assumption was made to enable a comparison based on the impact of capital and variable operating costs only. Any reducti on in assumed CF would further increase the COE.

2.5 RAW WATER WITHDRAWAL AND CONSU MPTION
A water balance was performed on the major water consumers in the process for each case. The total water demand for each major subsystem was determined. The internal re cycle waterCost and Performance Baseline

- Volume 3c (NGCC Cases)

18 

### available from various sources was used to offset the water demand and determine the total water withdrawal. Discharge water stream quantities were estimated and subtracted from the water withdrawal to determine the water consumption from the environment required for the plant.
Fifty percent of the raw water withdrawal was assumed to be provided by a publicly owned treatment works (POTW) and 50 percent was provided from groundwater. Raw water withdrawal is defined as the water metered from a r aw water source and used in the plant processes for any and all purposes, such as cooling tower makeup and boiler feedwater (BFW) makeup.
The largest consumer of raw water in all cases is cooling tower makeup. Since plants located in the Western U.S. need to consider limited water supplies, a parallel wet/dry cooling tower was chosen for all plant configurations similar to the system installed at Xcel Energy’s Comanche 3 PC plant. In a parallel cooling system half of the turbine exhaust steam is condensed in an air

cooled condenser and half in a water

- cooled condenser. The cooling water is provided by a mechanical draft, evaporative cooling tower, and all process blowdown streams were assumed to be treated and recycled to the cooling tower. The cooling t ower blowdown was assumed to be treated and 90 percent returned to the water source with the balance sent to a pond for evaporation. The design ambient wet bulb temperature of 3°C (37°F) at the Montana site and 2°C (36°F) at the NDL site ( Exhibit 2

- 1 and Exhibit 2

- 2 ) was used to achieve a cooling water temperature of 9°C (48°F) and 8°C (47°F), respectively at the two sites using an approach of 6°C (11°F). The cooling water range was assumed to be 11°C (2 0°F). The cooling tower makeup rate was determined using the following [ 8

**•** Evaporative losses = 0.8 percent of the circulating water flow rate per 10°F of range ]:

**•** Drift losses = 0.001 percent of the circulating water flow rate

**•** Blowdown losses = Evaporative Losses / (Cycles of Concentration

- 1) Where cycles of concentration are a measure of water quality, and a mid

- range value of 4 was chosen for this study. Typical design conditions for air

- cooled condensers include an initial temperature difference (ITD ) of 40

- 55°F [ 9 ]. The ITD is the temperature difference between saturated steam at the steam turbine generator (STG) exhaust and the inlet dry bulb cooling air temperature

. The ITDs at the two locations in this study are 48 and 50°F. The fan power require ment is estimated at 3.5 times the power required for a wet cooling tower with equivalent heat duty [ 10
The water balances presented in subsequent sections include the water demand of the major water consumers within the process, the amount provided by in ternal 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. ]

.

2.6 COST ESTIMATING METH ODOLOGY
The estimating methodology for capital costs, operations an d 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.Cost and Performance Baseline

- Volume 3c (NGCC Cases)

19 

### 2.6.1
As illustrated in Capital Costs
Exhibit 2

- 6 , 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” dolla rs. The base year is the first year of capital expenditure, which for this study is assumed to be 2007. TASC is expressed in mixed

- year, current

- year dollars over the entire capital expenditure period, which is assumed to last three years for natural gas plants (2007 to 20 10 )

.

Exhibit 2

- 6 Capital Cost Levels and their Elements



### process equipment supporting facilities direct and indirect labor 

## BEC

TPC

TOC
TASC EPC contractor services process contingency project contingency

preproduction costs inventory capital financing costs other owner’s costs

escalation during capital expenditure period interest on debt during capital expenditure period 

## Bare Erected Cost Total Plant Cost Total Overnight Cost Total As

- Spent Cost

BEC, 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.



### The BEC

The comprises the cost of process equipment, on

- site facilities and infrastructure that support the plant (e.g., shops, of fices, 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.

TPC comprises the BEC plus the cost of services provided by the engineering, procurement and construction (EPC) contractor and project and process contingencies. EPC services include: detailed design, contractor permitting (i.e., those permits that individual contract ors 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.Cost and Performance Baseline

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20 

### The TOC

The 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.
TASC

Cost Estimate Basis and Classification is the sum o f all capital expenditures as they are incurred during the capital expenditure period including their escalation. TASC also includes interest during construction. Accordingly, TASC is expressed in mixed, current

- year dollars over the capital expenditure period.

The TPC and Operation and Maintenance (O&M) costs for each of the cases in the study were estimated by WorleyParsons us ing 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 a s applied in Engineering, Procurement and Construction for the process industries [ 11
Most techno

- economic studies completed by NETL feature cost estimates intended for the purpose of a “Feasibility Study” (AACE Class 4). ]

.

Exhibit 2

- 7 describes the characteristics of an AACE Class 4 Cost Estimate. Cost estimates in this study have an expected accuracy range of

- 15%/+30%.
Exhibit 2

- 7 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% t o

- 30% on the low side, and +20% to +50% on the high side

The capital costs for each cost account were reviewed by comparing individual accounts across all cases to ensure an accurate representation of the relative cost differences between the cases and a ccounts. All capital costs are presented as “overnight costs” expressed in June 2007 dollars. The dollar values have been held at June 2007 to allow direct comparison with earlier results. Significant pricing fluctuations have occurred between June 2007 and March 2009. A retrospective look suggests that pricing for these commodities peaked in mid 2008 and generally declined during the latter parts of 2008 into 2009. While some pricing is still currently declining, based on published information, pricin g at the end of 2008 remains higher than June 2007 values.
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 allocabl e components ofCost and Performance Baseline

- Volume 3c (NGCC Cases)

21 

### a system or process, so they are included within 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
Non

- capture NGCC cases ar e based on commercial offerings for a mature technology n th



### - of

- a

kind (NOAK) cost. Thus, each of these cases reflects the expected cost for the next commercial sale of each of this technolog y

. CO 2 

### Removal Plant Maturity While the post

- combustion technolo gy used for the NGC C plants has been practiced at smaller scale, it has never been practiced at a scale equivalent to that required in this study. There wer e domestic amine

- based CO 2 

### capture systems operating on natural gas

- derived flue gas at scales up t o 1,200 tons per day ( TPD ) [ 12

Contracting Strategy ]

. The plants in this study will capture a n average 4
, 6 00 TPD of CO 2 

### . Consequently the CO 2 

### capture cases will be treated as FOAK.

The estimates are based on an EPCM approach utilizing multiple subcontra cts. 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, t he Contractor assumes all risk for performance, schedule, and cost. As a result of current market conditions, EPC contractors appear more reluctant to assume that overall level of risk. The current trend appears to be a modified EPC approach where much o f 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, c an 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 and absorbs higher p roject management costs, 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 defin ed as the total plant facility within the “fence line” including the 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 separate ly 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 respect ive 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 processCost and Performance Baseline

- Volume 3c (NGCC Cases)

22 

### projects. A reference bottoms

- up estimate for each major component provides the basi s for the estimating models. This provides a basis for subsequent comparisons and easy modification when comparing between specific case

- by

- case variations.
Other key estimate considerations include the following:

**•** Labor costs are based on Midwest, Merit S hop using factors from PAS, Inc [ 13

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

. PAS presents information for eight separate regions. Volume 1 of this study used a generic Midwestern site, typical of Region 5 (IL, IN, MI, MN, OH, and WI). The weighted average rate for Region 8 (CO, MT, ND, SD, UT
, and WY) is within less than one

- half of one percent of that for Region 5. The difference is inconsequential so the same rates used in Volume 1 were maintained in this study. Costs would need to be re

- evaluated for projects employing union labor.

**•** 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 t o 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 spr ead 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 wi th the excep tion of costs included for TS&M, which are treated as an addition to COE.

**•** Engineering and Construction Management were estimated as a 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 ad justed 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 conceptualCost and Performance Baseline

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23 

### estimating models. The more recent economic down turn has resulted in a reduction of commodity prices such that many price indices ha ve 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 di fferences in costs are often more important than the absolute level of TPC. This requires cross

- account comparison between technologies to review the consistency of the direction of the costs

. Exclusions The capital cost estimate includes all anticipate d 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

- 1 0s

**•** 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 enginee ring. 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 uncertaint ies 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)
Pr oject 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 wasCost and Performance Baseline

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24 

### used as a general guideline, but some project contingen cy values outside of this range occur based on WorleyParsons’ in

- house experience.
Process Contingency Process contingency is intended to compensate for uncertainty in cost estimates caused by performance uncertainties associated with the development sta tus of a technology. Process contingencies are applied to each plant section based on its current technology status.
As shown in Exhibit 2

- 8 , AACE International Recommended Practice 16R

- 90 provides guidelines for estimating proce ss contingency based on EPRI philosophy [ 14
Process contingencies have been applied to the estimates in this study as follows: ]

.

**•** CO 2 

### Removal System (Econamine)

– 20 percent on all CO 2 

### capture cases

- unproven technology at commercial scale in NGC C service.

**•** Instrumentation and Controls

– five percent on all accounts for CO 2 

### capture cases. Exhibit 2

- 8 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.
All contingencies included in the TPC, both project and process, represent costs that are expected to be spent in the developmen t and execution of the project.

Owner’s Costs

Exhibit 2

- 9 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 [ 14 ] . 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

.Cost and Performance Baseline

- Volume 3c (NGCC Cases)

25 

### Exhibit 2

- 9 Owner’s Costs Included in TOC
Owner’s Cost Estimate Basis

Prepaid Royalties Any technology royalties are assu med 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, n o 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 cat alysts) 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.

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% ofCost and Performance Baseline

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26 

### Owner’s Cost Estimate Basis 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 De sign (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 eq uipment 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 Proc urement Construction Management approach utilizing multiple subcontracts, in which the owner assumes project risks for performance, schedule and cost)

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

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

- Unusual site improvements: normal costs associated with improvements to the plant site are included in the bare erected cost, assuming that t he 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, sei smic design, buildings/enclosures, fire protection, local code height requirements, noise regulations.
Initial Cost for Catalysts and

Chemicals **•** All initial fills not included in BEC

Taxes & Insurance **•** 2% of TPC (Fixed O&M Cost)Cost and Performance Baseline

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27 

### Interest during constru ction 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

- 10

. Exhibit 2

- 10 TASC/TOC Factors

F inance Structure IOU High Risk IOU Low Risk

TASC/TOC 1.0 78 1. 075

2.6.2
The production costs or operating costs and related maintenance expenses (O&M) pertain to those charges associated with O&M the power plants over their exp ected life. These costs include: Operations and Maintenance Costs

**•** Operating labor

**•** Maintenance

– material and labor

**•** Administrative and support labor

**•** Consumables

**•** Fuel

**•** Waste disposal 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 the number of operators required for each specific case. The average base labor rate used to determine annual cost is $34.65/ hour ( hr ) . The

assoc iated 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 mainten ance 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.Cost and Performance Baseline

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28 

### Administrative and Support Labor Labor administration and overhead charges are ass essed at a 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 operatin g hours.
Quantities for major consumables such as fuel 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 (such as reactor catalyst), which are included with the equipment pricing in the capital cost. Waste Disposal No wastes are generated in NGCC cases that require disposal

. Co

- Products and By

- Products (Other than CO 2 

### )
No co

- products or by

- products (other than CO 2 

### in the capture cases) are generated in NGCC

cases.

2.6.3

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

- 11 [ 15

**•** The CO 2 

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

. A glycol dryer located near the mid

- point of the com pression train is used to meet the moisture specification.Cost and Performance Baseline

- Volume 3c (NGCC Cases)

29 

### Exhibit 2

- 11 CO 2 

### Pipe line 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 2 

### O Concentration ppmv < 150

**•** The CO 2 

### is transported and injected as a SC fluid in order to avoid two

- phase flow and achieve maximum efficiency [ 16 ]

. The pipeline is assumed to have an outlet pressure (above the SC pressure) of 8

. 3 MPa (1, 200 psia) with no re compression 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 ( 1,0 00 psi) over an 80 km (50 mile) pipeline length [ 17

**•** The saline formation is at a depth of 1,23 6 m (4,055 ft) and has a per meability of 22 millidarcy (md) (22 μm2) 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 com pression 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.

15 ]

. 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 [ 15 ]

. The assumed aquifer characteristics are tabulated in Exhibit 2

- 12

. Exhibit 2

- 12 Deep Saline Aquifer Specification

Parameter U nits Base Case
Pressure MPa (psi) 8.4 (1,220) Thickness m (ft) 161 (530) Depth m (ft) 1,236 (4,055) Permeability md (μm 2 

### ) 22 (22) Pipeline Distance Km (miles) 80 (50) Injection Rate per Well Tonne (ton) CO 2 

### /day 9,360 (10,320) The cost metrics utilized in this study provide a best estimate of T S&M costs for a “typical” sequestration project, and may vary significan tly 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 metricsCost and Performance Baseline

- Volume 3c (NGCC Cases)

30 

### 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 cost s and the acquisition of underground pore volume, analogous existing policies were used for representative cost scenarios.
The following sub sections describe the sources and methodology used for each metric.
TS&M Capital Costs
TS&M capital costs include bo th 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 establis hed 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.
Pipel ine 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 b uilding a CO 2 

### pipeline, as noted in various studies [ 15
, 16
, 18

18 ]

. 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 pipeli ne length and diameter [ ]

. These cost curves were escalated to the June 2007 year dollars used in this stud y. Related capital expenditures were based on the findings of a previous study funded by DOE/NETL, Carbon Dioxide Sequestration in Saline Formations

– Engi neering and Economic Assessment [ 16 ]

. This study utilized a similar ba sis 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 

### Stora ge and Sink Enhancement Options [ 15 ]

. 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 co sts, 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 [ 15 ]

. These costs include a ll of the costsCost and Performance Baseline

- Volume 3c (NGCC Cases)

31 

### 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 as sociated 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 [ 19

Liabi lity Protection ]

. 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 prop erty for a period of up 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 y ear rent scenario.

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 e s have been suggested for CO 2 

### stora ge, 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 [ 20 ]

. However, at pres ent, 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 un til 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) [ 21
, 22
, 23

Liability costs assume that a bond must be purchased before injection operations are permitted in order to establish the ability and good will of an injector to address damages where they are deemed liable. A figure of five million dollars was used for the bond based on the Louisiana fund level. This b ond level may be conservative ly 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 oper ations. The b ond 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 [ 24 ]

. 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, gravityCost and Performance Baseline

- Volume 3c (NGCC Cases)

32 

### survey, and periodic seismic survey ; EM and gravity surveys are ongoing while seismic survey occurs in years 1, 2, 5, 10, 15, 20, 25, and 30 during the operational period, then in years 40, 50, 60, 70, and 80 after injection ceases.

2.6.4 The global economic assumptions are listed in Financ e Structure, Discounted Cash Flow Analysis, and COE
Exhibit 2

- 13

. Finance structures were chosen based on the assumed type of developer/owner (investor

- owned utility (I OU) 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. The NGCC non

- capture plants are categorized as low risk and the CO 2 

### capture cases are categorized as high risk

. Exhibit 2

- 14 describes the low

- risk IOU and high

- risk IOU finance structures that were assumed for this study. These finance structures were recommended in a 2008 NETL report b ased on interviews with project developers/owners, financial organizations and law firms [ 25 

### ]

.Cost and Performance Baseline

- Volume 3c (NGCC Cases)

33 

### Exhibit 2

- 13 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 performan ce, 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 Coal Plants: 5 Years Operational Period 30 years Economic Analysis Period (used for IRROE) 35 Years (capital expenditure period plus operational period) TREATMENT OF CAPITAL COSTS Capital Cost Escalation During Capital Expen diture Period (nominal annual rate) 3.6% 2 

### Distribution of Total Overnight Capital over the Capital Expenditure Period (before escalation) 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 COE (revenue), O&M Costs, and Fuel Costs (nominal annual rate) 3.0 % 3 

### COE, O&M, Fuel

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 equi valent 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

- Volume 3c (NGCC Cases)

34 

### Exhibit 2

- 14 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 T ax 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 5 

### Exhibit 2

- 15 in two ways: a COE and a levelized COE (LCOE)

. To illustrate how the two are related, COE solutions are shown i n 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 t he 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 6

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

### , 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

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 D ecember 2003 and the Producer Price Index is considered the “headline” index for all of the various Producer Price Indices.Cost and Performance Baseline

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### Exhibit 2

- 15 for a PC power plant and a NGCC po wer 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

- ye ar (2007) dollars.

**•** 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 7



### Exhibit 2

- 15 . “Thi rty

- years” refers to the length of the operational period assumed for the economic analysis. To calculate the LCOE, the PSFM was used to calculate a base

- year COE that, when escalated at a nominal annual rate of 0 percent , provided the stipulated return o n equity over the entire economic analysis period. For the example PC and NGCC power plant cases, the LCOE solutions are shown as dashed lines in the upper portion of

. Exhibit 2

- 15 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

- 15
, the capital expendi ture 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 a nalysis 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 do llars.
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.

7 For this current

- dollar analysis, the LCOE is uniform in current dollars over the analysis period. In contrast, a constant

- dolla r analysis would yield an LCOE that is uniform in constant dollars over the analysis period.Cost and Performance Baseline

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### Exhibit 2

- 15 Illustration of COE Solutions using DCF Analysis

Consistent with our nominal

- dollar discounted cash flow methodology, the COEs shown on Exhibit 2

- 15 are expressed in current dollars. However, th ey can also be expressed in constant, base year dollars (June 2007) as shown in Exhibit 2

- 16 by adjusting them with the assumed nominal annual general inflation rate (3 percent ).

Exhibit 2

- 16 illustrates the same information as in Exhibit 2

- 15 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 dec reases at a rate of 3 percent per year.Cost and Performance Baseline

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### Exhibit 2

- 16 PC with CCS in Current 2007 Dollars

Estimating COE with Capital Charge Factors For scenarios that adhere to the global economic assumptions listed in Exhibit 2

- 13 and utilize one of the finance structures listed in Exhibit 2

- 14 , the following simplified equation can be used to estimate COE as a function of TOC 8



### Exhibit 2

- 17 , 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

- 13 , 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 (alo ng with other factors related to the recovery of capital costs).Cost and Performance Baseline

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### Exhibit 2

- 17 Capital Charge Factors for COE Equation
Capital Expenditure Period Three Years

Finance Struct ure High Risk IOU Low Risk IOU
Capital Char g e Factor (CCF) 0.111 0.105
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

- 13 , all factors (COE, O&M and fuel) are assumed to escalate at a nominal annual general inflation rate of 3.0 percent . Accordingly, all first

- year costs (COE and O&M) are equivalent to base

- year costs when expressed in ba se

- 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

annua l 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

- 17 that matches the applicab le finance structure and capital expenditure period
TOC = total overnight capital, expressed in base

- year dollars
OC FIX 

### = the sum of all fixed annual operating costs, expressed in base

- year dollars
OC VAR 

### = the sum of all variable annual operating costs, i ncluding 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 The primary cost metric in this study is the COE, which is the base

- year cost presented in base

year dollars. Exhibit 2

- 18 presents this cost metric along with the COE escalated to the first year of operation using the average annual inflation r ate of 3 percent. Similarly, the LCOE isCost and Performance Baseline

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39 

### 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

- 18 COE and LCOE Summary

Case COE (mills/kWh) LCOE (mills/kWh)

Base

- Year First Operational Year Base

- Year First Operational Year
2007$ 201 0 $ 2007$ 201 0 $
S 31 A 64

. 42 74

. 58 81

. 66 8 9

. 24 S 31 B 92

. 91 1 07

. 55 1 17

. 7 7 1 28

. 69 L 31 A 6 3

. 58 7 3

. 6 0 80

. 59 88 .0 7 L 31 B 91 .36 1 05

. 76 1 15

. 8 1 1 26

. 54

First Year CO 2 

### Avoided Cost with S upercritical PC Reference

The cost of CO 2 

### removal was calculated in two ways : the cost of CO 2 

### avoided compared to the analogous non

- capture design and the cost of CO 2 

### avoided c ompared to a baseline supercritical (SC) PC plant at the same site location as the NGCC plant
, using the equation below

. The baseline SC PC plant is a 550 MW (net) plant with the results presented in Exhibit 2

- 19 , and in Volume 3 b of this study

. The cost of electricity in the CO 2 

### capture cases includes TS&M as well as capture and compression.
Exhibit 2

- 19 Baseline SC PC Results for CO 2 

### Cost Calculation

Montana

(S12A) North Dakota (L12A) Net Output (MW) 550 550 COE ( 2007 mills/kWh) 57.8 0 62.2 0 Emissions (lb/ M Wh net 

### ) 1
, 89 2 1
, 99 6

MWh tons Emissions CO Emissions CO MWh COE COE Cost Avoided

removal with reference reference removal with 

### / } { / $ } {

2 2 

### − **−**

**=**Cost and Performance Baseline

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### This page intentionally left blankCost and Performance Baseline

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41 

### 3. NGCC P OWER PLANT PROCESS DESCRIPTIONS
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 ava ilable

. Each design consists of two advanced F class combustion turbine generators (CTG), two HRSG s and one STG in a multi

- shaft 2x 2x1 configuration

. The NGCC cases are evaluated with and without carbon capture on a common thermal input basis for each site condition . The NGCC designs that include carbon dioxide recovery ( CDR ) have a smaller plant net output resulting from the addit ional CDR facility auxiliary loads. Like in 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/1050 **°** F/ 10 50 **°** F) steam cycle.

3.1 NGCC COMMON PROCESS AREAS

The four NGCC cases are nearly identical in confi guration . W ith the exception of c ase s S31B and L31B , which include a CDR facility, the following process descriptions are common to all

cases

.

3.1.1 Natural Gas Supply System
It was assumed that a natural gas main with adequate capacity is in close proximity (within 16 km [10 miles]) to the site fence line and that a suitable right o f way is available to install a branch line to the site. For the purposes of this study it was also assumed that the gas will be delivered to the plant custody transfer point at 3.0 MPa (435 psig) and 38°C (100oF), which matches the advanced F Class fuel system requirements. Hence, neither a pressure reducing station with gas preheating (to prevent moisture and hydrocarbon condensation), nor a fuel booster compressor are required.
A new gas metering station is assumed to be added on the site, adjacent t o the new CT . The

m eter 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 consumpt ion is provided.

3.1.2 Combustion Turbine
The combined cy cle plant is based on two CTGs. The CTG is representative of the advanced F Class turbines with an ISO base rating of 184,400 kW when firing natural gas at International Standards Organization ( ISO ) cond itions [ 26 ]

. As elevation increases, the output is reduced due to the lower air density, resulting in less mass flow through the turbine for a given volumetric flow or rotational velocity. This machine is an axial flow, single spool, constant speed unit, with variable inlet guide vanes and dry LNB combustion system.Cost and Performance Baseline

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### Each CTG is provided with inlet air filtration systems; inlet silencers; lube and control oil systems including cooling; electric motor starting systems; acoustical enclosures including heating and ventilation; control systems including supervisory, fire protection, and fuel systems. No back up fuel was envisioned for this project.
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 3

- 1

. Exhibit 3

- 1 Combustion Turbine Typical Scope of Supply System System Scope

ENGINE ASSEMBLY Couplin g to Generator, Dry Chemical Exhaust Bearing Fire Protection System, Insulation Blankets, Platforms, Stairs and Ladders
Engine Assembly with Bedplate Variable Inlet Guide Vane System, Compressor, Bleed System, Purge Air System, Bearing Seal Air System, Co mbustors, Dual Fuel Nozzles, Turbine Rotor Cooler Walk

- in acoustical enclosure Heating, ventilating, and air conditioning (HVAC), Lighting, and Low Pressure (LP) CO 2 

### Fire Protection System MECHANICAL PACKAGE HVAC and Lighting, Air Compressor for Pneumati c System, LP CO 2 

### Fire Protection System

Lubricating Oil System and Control Oil System Lube Oil Reservoir, Accumulators, 2x100% alternating current ( AC ) Driven Oil Pumps, direct current ( DC ) Emergency Oil Pump with Starter, 2x100% Oil Coolers, Duplex Oil F ilter, 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 and 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 Distributed control system ( 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 cardsCost and Performance Baseline

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### System System Scope

INLET AND EXHAUST SYSTEMS Inlet Duct Trash Screens, Inlet Duct and Silencers, Self Cleaning Filters, Hoist System For Filter Maintenance, Evapora tive Cooler System, Exhaust Duct Expansion Joint, Exhaust Silencers Inlet and Exhaust Flow, Pressure and Temperature Ports and Instrumentation N. GAS FUEL SYSTEMS Gas Valves Including Vent, Throttle and Trip Valves, Gas Filter/Separator, Gas Supply Instru ments 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 syst em), 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 O il 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 ( H 2) 

### 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

The gene rators would typically be provided with the CT package. The generators are assumed to be 24 kilovolt ( kV ) , 3

- phase, 60 hertz (hz) , constructed to meet American National Standards Institute (ANSI) and National Electrical Manufacturers Association (NEMA) st andards for turbine

- driven synchronous generators. The generator is TEWAC, complete with excitation system, cooling, and protective relaying.

3.1.3 Heat Recovery Steam Generator

The h eat recovery steam generator ( HRSG ) is configured with high pressure (HP ), int ermediate pressure ( IP ) , and LP steam drums, and superheater, reheater (RH), and economizer sections. The HP drum is supplied with feedwater (FW) by the HP boiler feed pump to generate HP steam, which passes to the superheater section for heating to 566°C (1
, 050°F). The IP drum is suppliedCost and Performance Baseline

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### with FW from an interstage bleed on the HP boiler feed pump. The IP steam from the drum is superheated to 566 °C ( 1
, 050 °F) and mixed with hot reheat steam fro m the reheat section at 566°C (1
, 0 50oF). The combined flows are admitted into the IP section of the steam turbine. The LP drum provides steam to the integral deaerator, and also to the LP turbine.

The economizer sections heat condensate and FW (in separate tube bundles). The HRSG tubes are typically comprised of bare surface and/or finned tubing or pipe material. The high

temperature portions are type P91 or P22 ferritic alloy material; the low

- temperature portions (< 399°C [750°F]) are carbon steel (CS) . Each HRSG exhausts directly to the stack, which is fabric ated from CS plate materials and lined with Type 409 stainless steel (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.

3.1.4 NOx Control System
This reference plant is designed to achieve 2 .5 p arts per million volume dry ( ppmvd ) NOx emissions (expressed as nitrogen oxide ( NO 2 

### ) and referenced to 15 percent O 2 

### ). Two measures are taken to reduce the NOx. The first is a dry LNB in the CTG. The dry LNB burners are a low NOx design and reduce the e missions to about 25 ppmvd (referenced to 15 percent O 2 

### ) [ 27
The second measure taken to reduce the NOx emissions was the installation of a SCR system. SCR uses ammonia (NH 3 

### ) and a catalyst to reduce NOx to N 2 

### and H 2 

### O. The SCR system consists of reactor , and (NH 3 

### ) 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 react or is located in the flue gas 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 installa tion 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 flue gas 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 (TiO 2 

### ), vanadium pentoxide (V 2 

### O 5 

### ), and tungsten trioxide (WO 3 

### ). The optimum in let flue gas temperature range for the catalyst is 260°C (500 **°** F) to 343°C (650 **°** F).
The ammonia storage and injection system consists of the unloading facilities, bulk storage tank, vaporizers, and dilution air skid.

3.1.5 Carbon Dioxide Recovery Facility

A CDR facility is used in Case s S31B and L31B to remove 90 percent of the CO 2 

### in the flue gas exiting the HRSG, dry it, and compress it to a SC con dition. It is assumed that all of the carbonCost and Performance Baseline

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45 

### in the natural gas is converted to CO 2 

### . The CDR is comprised of flue gas supply, CO 2 

### absorption, solvent stripping and reclaiming, and CO 2 

### compression and drying.

The CO 2 

### absorption/stripping/solvent reclaim p rocess for the CO 2 

### capture cases is based on the Fluor Econamine FG Plus SM 

### technology [ 28
, 29 Exhibit 3

- 2 ] . A typical flowsheet is shown in

. The Econamine FG Plus process uses a formulation of monoethanolamine (MEA) and a proprieta ry 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 O 2 

### , such as flue gas from coal

- fired power plants, gas turbine exhaust gas, and other waste gases. The Econamine pro cess used in this study differs from previous studies, including the 200 3 IEA study [ 30

**•** 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 eliminated The above are achieved at the expense of a slightly higher steam requirement in the stripper (3,6 93 kJ/kg [1,5 89 Btu/lb] versus 3,242 kJ/kg [1,395 Btu/lb] used in the IEA study) [ 31 ]

.Cost and Performance Baseline

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### Exhibit 3

- 2 Fluor Econamine FG Plus Typical Flow Diagram

PC Flue Gas to Ambient

Absorber Section Makeup Wash Water

Cooling Water

Flue Gas

Excess Water CWS LP Steam

Condensate

Waste to Disposal Stripper Cooling Water

Cooling Water

Soda Ash Injection

Solvent Storage Tank Make Up Solvent Lean Solvent Lean Solvent

Solvent Cross Heat Exchanger

Reboiler Reclaimer

Rich Solvent Rich Solvent

Direct Contact Cooler ( DCC ) and Polishing

Scrubber Wash Water Filter

DCC Circulating Water Filter Blower Condenser Product CO 2

Overhead Accumulator

Cooling Water Semi

- Rich Solvent

Water Wash

Section

CWR

Corrosion InhibitorCost and Performance Baseline

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### Flue Gas Cooling and Supply The function of the flue gas cooling and supply system is to transport flue gases from the HRSG to the CO 2 

### absorption tower, and condition flue gas pressure, temperat ure , and moisture content so it meets the requirements of the Econamine process. Temperature and hence moisture content of the flue gas exiting the HRSG is reduced in the Direct Contact Flue Gas Cooler, where flue gas is cooled using cooling water.

The water condensed from the flue gas is collected in the bottom of the Direct Contact Flue Gas Cooler section and re

- circulated to the top of the Direct Contact Flue Gas Cooler section via the Flue Gas Circulation Water Cooler, which rejects heat to the plant circulating water system. Level in the Direct Contact Flue Gas Cooler is controlled by directing the excess water to the cooling water return line. In the Direct Contact Flue Gas Cooler, flue gas is cooled beyond the CO 2 

### absorption process requirements to 33°C (91°F) to account for the subsequent flue gas temperature increase of 14°C ( 25 °F) in the flue gas blower. Downstream from the Direct Contact Flue Gas Cooler
, flue gas pressure is boosted in the flue gas blowers by approximately 0.01 4 MPa (2 pound per square inch [ psi ] ) to overcome pressure drop in the CO 2 

### absorber tower.

Circulating Water System Cooling water is provided from the NGCC plant circulating water system and returned to the NGCC plant cooling tower. The CDR facility requires a significa nt amount of cooling water for flue gas cooling, water wash cooling, absorber intercooling, reflux condenser duty, reclaimer cooling, lean solvent cooler, and CO 2 

### compression interstage cooling.

CO 2 

### Absorption 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, absorbs the CO 2 

### from the flue gases
, and leaves the bottom of the absorber with the absorbed CO 2 

### . The FG Plus process also includes solvent intercooling. The semi

- rich so lvent 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.

W ater Wash Section The purpose of the Water Wash section is to minimize solvent losses due to mechanical entrainment and evaporation. The flue gas from the top of the 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 WashCost and Performance Baseline

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### Water Pump , cooled by the Wash Water Cooler, and recirculated to the top of the CO 2 

### Absorber. The wash water level is maintained by wash water makeup

. Rich/Lean Amine Heat Exchange System
The rich solvent from the bottom of the CO 2 

### Absorber is preheated by the lean solvent from the Solvent Stripper in the Lean/Rich Cross Exchanger. The heated rich so lvent 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 th e 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.

Solvent St ripper 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 sections of the steam turbine and is 0. 51 MPa ( 74 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 St ripper 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 p ortion 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 s tripper overhead system.

Solvent Stripper Reclaimer A small slipstream of the lean solvent from the Solvent Stripper bottoms is fed to the Solvent Stripper Reclaimer for the removal of high

- boiling nonvolatile impurities (HSS), volatile acids, and iron pr oducts 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 to the Solvent Stripper and the spent solvent is pumped via the Solvent Reclaimer Drain Pump to the Solvent Reclaimer Drain Tank.

Steam Condensate Steam condensate from the Solvent Stripper Reclaimer accumulates in the Solvent Reclaimer Condensate Drum and level controlled to the Solvent Reboiler Condensate Drum. Steam condensate from the Solvent Stripper Reboilers is also collected in the Solvent Reboiler Condensate Drum and returned to the steam cycle just downstream of the deaerator via the Sol vent Reboiler Condensate Pumps.Cost and Performance Baseline

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### Corrosion Inhibitor System 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.

Gas Compression and Drying 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 Exhibit 3

- 3

.

Exhibit 3

- 3 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 perce nt 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 moi sture

- 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 i n Section 2.6

.

3.1.6 Steam Turbine

The steam turbin e consists of an HP section, an IP section, and one double

- flow LP section, all connected to the generator by a common shaft. The HP and IP sections are contained in a single span, opposed

- flow casing, with the double

- flow LP section in a separate casing.
Main steam from the boiler passes through the stop valves and control valves and enters the turbine at 16.5 MPa/566°C (2400 psig/1050°F). The steam initially enters the turbine near the middle of the HP span, flows through the turbine, and returns to t he 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 64 °C (3 60 psia/ 1047 °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 theCost and Performance Baseline

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50 

### cross

- over line. The steam divides into two paths and flows through the LP sections exhausting downward into th e condenser.

Turbine bearings are lubricated by a closed

- loop (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 low

- pressure 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 m ounted 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/operat or interfacing, and datalink interfaces to the balance

- of

- plant DCS, and incorporates on

- line repair capability.

3.1.7 Water and Steam Systems

Condensate The function of the condensate system is to pump condensate from both the air

- cooled and water

- cooled conden ser to the deaerator, through the gland steam condenser and the low

temperature economizer section in the HRSG.

Feedwater The function of the FW system is to pump the various FW streams from the deaerator storage tank in the HRSG to the respective steam dr ums. One 100 percent capacity motor

- driven feed pump is provided per each HRSG (total of two pumps for the plant). The FW pumps are equipped with an interstage takeoff to provide IP and LP FW . Each pump is provided with inlet and outlet isolation valves , outlet check valves, and individual minimum flow recirculation lines discharging back to the deaerator storage tank. The recirculation flow is controlled by pneumatic flow control valves. In addition, the suctions of the boiler feed pumps are equipped with startup strainers, which are utilized during initial startup and following major outages or system maintenance.
Steam System The steam system is comprised of main, reheat, intermediate, and LP steam systems. The function of the main steam system is t o 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 RH and from the HRSG RH outlet to the turbine reheat stop valves.

Main steam e xits 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 RH . Hot rehea t steam exits at the HRSG RH through a motor

- operated gate valve and is routed to the IP turbines.Cost and Performance Baseline

- Volume 3c (NGCC Cases)

51 

### Circulating Water System Exhaust steam from the steam turbine is split 50/50 to a surface condenser cooled with cooling water and to an air

- cooled condense r using ambient air and forced convection. A decision to use a parallel wet/dry cooling system was based primarily on the Xcel Energy Comanche 3 PC plant, and the desire to reduce the plant water requirement. The major impact of parallel cooling is a sign ificant reduction in water requirement when compared to a wet cooling system. This impact is included in the water balance presented later in this report.
Because of the low ambient temperatures at the sites in this study, a condenser pressure of 4.81 kil opascal absolute ( kPa ) (0.698 psia) (condensing temperature of 32°C [90°F]) is used in the model as compared to 6.77 kPa (0.983 psia) (condensing temperature of 38°C [101°F]) used in Volume 1 of this report.

The CWS is a closed

- cycle cooling water system that rejects heat through a wet cooling tower and supplies cooling water to the surface condenser to condense one

- half of the main turbine exhaust steam. The system also supplies cooling water to the CDR plant as required, and to the auxiliary cooling sys tem. 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 surface condenser and other applications is removed by a mechanical draft cooling tower.
The system consists of two 50 percent capacity vertical CWPs , a mechanical draft evaporat ive cooling tower, and carbon steel (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 w ood frame counterflow mechanical draft cooling tower.
The surface 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 f or cleaning or for plugging tubes. This can be done during normal operation at reduced load. The air

- cooled condenser utilizes ambient air and forced convection across tube bundles to condense the balance of the turbine exhaust steam.

Both condensers are 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 st eam to the condenser.

3.1.8 Buildings and Structures

Structures assumed for NGCC cases can be summarized as follows:

1. Generation Building housing the STGCost and Performance Baseline

- Volume 3c (NGCC Cases)

52 

### 2. CWP House

3. Administration / Office / Control Room / Maintenance Building

4. Water Treatment Building

5. Fire Water Pump House

3.1.9 Accessory Electric Plant
The accessory electric plant consists of all switchgear and control equipment, generator equipment, station service equipment, conduit and cable trays, wire, and cable. It also includes the main transformer, required fo undations
, and standby equipment.

3.1.10 Instrumentation and Control
An integrated plant

- wide DCS is provided. The DCS is a redundant microprocessor

- based, functionally distributed system. The control room houses an array of video monitors and keyboard units. The monitor/keyboard units are the primary interface between the generating process and operations personnel. The DCS incorporates plant monitoring and control functions for all the major plant equipment. The DCS is designed to provide 99.5 percent avail ability.
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 rout ines available.

3.2 NGCC P ROCESS D ESCRIPTION

This section contains an evaluation of plant designs for each of the four c ases

. All cases use a single reheat 16.5 MPa/566°C/566 °C (2400 psig/1050 **°** F/10 50 **°** F) cycle. Cases S31A and L31A as well as S31B and L31B dif fer from each other by ambient conditions , carbon capture, and hence the amount of n atu ral gas feed to maintain the CT loading to the discrete value provided by the manufacturer.

The balance of Section 3.2 is organized as follo ws:

**•** Key Assumptions provides a summary of study and modeling assumptions relevant to all

c ases

.

**•** Sparing Philosophy is provided for all c ases.Cost and Performance Baseline

- Volume 3c (NGCC Cases)

53 

### 3.2.1 Key System Assumptions
System assumptions for NGCC with and without CO 2 

### capture are compiled in Exhibit 3

- 4

. Exhibit 3

- 4 NGCC Plant Study Configuration Matrix
Cases S31A/ L31A w/o CO 2 

### Capture Cases S31B/ L31B 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) 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) 36.0 ( 1.4 ) 36.0 ( 1.4 ) Cooling Water to Condenser, °C (oF) 9 ( 48 ) /8 (47) 9 (48)/8 ( 47 ) Coolin g Water from Condenser, °C (oF) 2 0 ( 68 ) /19 (67) 20 (68)/19 ( 67 ) Stack Temperature, °C (°F) 10 2 ( 215 ) /102 (216) 29 (85) SO 2 

### Control Low Sulfur Fuel Low Sulfur Fuel NOx Control LNB and SCR LNB and SCR SCR Efficiency, % 1 

### 90 90 Ammonia Slip (End of Cataly st Life), ppmv 10 10

Particulate Control N/A N/A Hg Control N/A N/A CO 2 

### Control N/A Econamine
CO 2 

### Capture, % 1 

### N/A 90.7

CO 2 

### Sequestration N/A Off

- site Saline Formation

1 Removal efficiencies are based on the flue gas content 

### Balance of Plant
The bala nce of plan t assumptions are common to all NGCC cases and are presented in Exhibit 3

- 5

.Cost and Performance Baseline

- Volume 3c (NGCC Cases)

54 

### Exhibit 3

- 5 NGCC Balance of Plant Assumptions Cooling System Recirculating Wet Cooling Tower 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 Horsepower ( 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 s ufficient quantities to meet plant makeup requirements. Makeup for potable, process, and de

- ionized (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 pe r 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.

3.2.2 Sparing Philosophy

Dual trains are used to accommodate the size of commerci al gas turbines. There is no redundancy other than normal sparing of rotating equipment. The plant design consists of the following major subsystems:

**•** Two advanced F class CTGs (2 x 50%)Cost and Performance Baseline

- Volume 3c (NGCC Cases)

55 

### • Two 3

- pressure reheat HRSGs with self supporting stacks and SCR syst ems (2 x 50%)

**•** One 3

- pressure reheat, triple

- admission STG (1 x 100%)

**•** Two trains of Econamine CO 2 

### capture (2 x 50%) (Capture cases)

3.3 CASE S S31A AND L31A PROCESS DESCRIPTION
In this section the NGCC process without CO 2 

### capture is described. The system descri ption follows the block flow diagram s (BFD) in Exhibit 3

- 6

. The stream numbers in the following description reference the BFD in Exhibit 3

- 6 . The ta ble s in Exhibit 3

- 7 and Exhibit 3

- 18
, for cases S31A and L31A respectively, 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 (250 0°F). The flue gas exits the turbine around 6 28 °C (116 3 °F) (stream 3) and passes into the HRSG. The HR SG generates both the main steam and reheat steam for the steam turbine. Flue gas exits the HRSG at 102 °C (2 15 °F) and passes to the plant stack

.Cost and Performance Baseline

- Volume 3c (NGCC Cases)

56 

### Exhibit 3

- 6 Case s S31A and L31A Process Flow Diagram, NGCC w ithout CO 2 

### Capture

The balance of Section 3.3 is organized as follows:

**•** Performance Results

- provides the main modeling results including the performance summary, environmental performance, water balance, mass and energy b alance diagrams
, and energy balance table.

**•** Major Equipment List

- provides an itemized list of major equipment with account codes that correspond to the cost accounts in the Cost Estimating section.

**•** Cost Estimating

- provides a summary of capital and opera ting costs.Cost and Performance Baseline

- Volume 3c (NGCC Cases)

57 

### 3.3.1 Case S31A

– Performance Results
The plant produ ces a net output of 5 12 MW a t a net plant efficiency of 50.5 percent (HHV basis).
Major stream flows are shown in Exhibit 3

- 7 and o verall plant performance is summari zed in Exhibit 3

- 8
, which includes auxiliary power requirements.

Exhibit 3

- 7 Case S31A Stream Table, NGCC without CO 2 

### Capture

1 2 3 4 5 6 7 8 V-L Mole Fraction

Ar 0.0093 0.0000 0.0089 0.0089 0.0000 0.0000 0.0000 0.0000 CH 4 0.0000 0.9310 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 C 2 H 6 0.0000 0.0320 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 C 3 H 8 0.0000 0.0070 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 C 4 H 10 0.0000 0.0040 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 2 0.0003 0.0100 0.0413 0.0413 0.0000 0.0000 0.0000 0.0000 H 2 O 0.0064 0.0000 0.0849 0.0849 1.0000 1.0000 1.0000 1.0000 N 2 0.7759 0.0160 0.7451 0.7451 0.0000 0.0000 0.0000 0.0000 O 2 0.2081 0.0000 0.1198 0.1198 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 98,174 4,020 102,311 102,311 19,410 12,552 12,552 25,662 V-L Flowrate (kg/hr) 2,836,748 69,653 2,906,401 2,906,401 349,679 226,125 226,125 462,303 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0

Temperature (°C) 6 38 628 102 566 32 32 32 Pressure (MPa, abs) 0.09 3.10 0.09 0.09 16.65 0.005 0.005 0.90 Enthalpy (kJ/kg) A 15.26 46.30 832.10 241.77 3,472.36 2,360.91 2,360.91 135.69 Density (kg/m 3 ) 1.1 22.2 0.4 0.8 47.7 0.04 0.04 995.4 V-L Molecular Weight 28.895 17.328 28.408 28.408 18.015 18.015 18.015 18.015

V-L Flowrate (lb mol /hr) 216,437 8,862 225,556 225,556 42,792 27,672 27,672 56,574 V-L Flowrate (lb/hr) 6,253,958 153,559 6,407,517 6,407,517 770,911 498,521 498,521 1,019,203 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0

Temperature (°F) 42 100 1,163 215 1,050 90 90 90 Pressure (psia) 13.0 450.0 13.5 13.0 2,414.7 0.7 0.7 130.0 Enthalpy (Btu/lb) A 6.6 19.9 357.7 103.9 1,492.8 1,015.0 1,015.0 58.3 Density (lb/ft 3 ) 0.070 1.384 0.022 0.051 2.977 0.002 0.002 62.141 A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Baseline

- Volume 3c (NGCC Cases)

58 

### Exhibit 3

- 8 Case S31A Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) Gas Turbine Power 335,300 Steam Turbine Power 186,800 TOTAL POWER, kWe 522,100 AUXILIARY LOAD SUMMARY, kWe Condensate Pumps 150 Boiler Feedwater P umps 2,450 Circulating Water Pump 1,060 Ground Water Pumps 100 Cooling Tower Fans 700 Air Cooled Condenser Fan 2,330 SCR 10 Gas Turbine Auxiliaries 700 Steam Turbine Auxiliaries 100 Miscellaneous Balance of Plant 1 

### 500 Transformer Losses 1,590 TOT AL AUXILIARIES, kWe 9,690 NET POWER, kWe 512,410 Net Plant Efficiency (HHV) 50.5% Net Plant Efficiency (LHV) 56.0% Net Plant Heat Rate (HHV), kJ/kWhr (Btu/kWhr) 7,130 (6,757) Net Plant Heat Rate (LHV), kJ/kWhr (Btu/kWhr) 6,428 (6,093) CONDENSER COOLI NG DUTY, 10 6 

### kJ/h (10 6 

### Btu/h) 1,023 (970) CONSUMABLES Natural Gas Feed Flow, kg/hr (lb/hr) 69,653 (153,559) Thermal Input (HHV), kW th 

### 1,014,787 Thermal Input (LHV) , kW th 

### 914,961 Raw Water Withdrawal, m 3 

### /min (gpm) 4.1 (1,084) Raw Water Consumption, m 3 

### /min (gpm) 3.2 (841)

1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loadsCost and Performance Baseline

- Volume 3c (NGCC Cases)

59 

### Environmental Performance The environmental targets for emissions of NOx, SO 2 

### , and PM were presented in Section 2.3 . A summary of th e plant air emissions for Case S31A is presented in Exhibit 3

- 9

. Exhibit 3

- 9 Case S31A Air Emissions
kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 85% CF kg/MWh (lb/ MWh)

SO 2 

### Negligible Negligible Negligible NO x 0.004 (0.009) 106 (117) 0.027 ( 0 .060)
Particulates Negligible Negligible Negligible Hg Negligible Negligible Negligible

CO 2 

### 50.8 (118.3) 1,383,150 (1,524,662) 356 (784)

CO 2 1 

### 363 (799)

1 CO 2 emissions b ased on net power instead of gross power


### The operation of the modern, state

- of

- the

- art gas turbine 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 2.3 , if the fuel contains the maximum amount of sulfur compounds allowed in pipeline natural gas, the NGCC SO 2 

### emissions would be 9.7 tonnes/yr (10.7 tons/yr) at 85 percent CF , or 0.00073 kg/GJ (0.0017 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 is shown in Exhibit 3

- 10

. The carbon input to the plant consi sts of carbon in the air in addition to carbon in the natural gas. One hundred percent carbon conversion is assumed since carbon conversion for NGCC plants is typically about 99.9 percent. Carbon in the air is not neglected here since the model accounts f or air components throughout. Carbon leaves the plant as CO 2 

### in the stack gas.Cost and Performance Baseline

- Volume 3c (NGCC Cases)

60 

### Exhibit 3

- 10 Cases S31A Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)
Natural Gas 50,310 (110,914) Stack Gas 50,696 (111,766) Air (CO 2 

### ) 387 (852)
Total 50,696 (111,766) Total 50,696 (111,766)

Exhibit 3

- 11 shows the overall water balance for the plant. Water demand represents the total amount of water required for a particular p rocess. Some water is recovered within the process, such as BFW blowdown, 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 dive rted 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. 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, i ncorporated 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 3

- 11 Case S31A 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 0.08 (20) 0 (0) 0.08 (20) 0 (0) 0 .08 (20) BFW Makeup 0.08 (20) 0 (0) 0.08 (20) Cooling Tower 4.11 (1 , 084) 0.08 (20) 4.03 (1 , 064) 0.92 (244) 3.10 (820)

BFW Blowdown 0 (0) 0.08 (20)

- 0.08 (

- 20)
Total 4.18 (1,105) 0.08 (20) 4.11 (1,084) 0.92 (244) 3.18 (841)

Heat and Mass Ba lance Diagrams
A heat and mass balance diagram is shown for the NGCC in Exhibit 3

- 12

. An overall plant energy balance is provided in tabular form in Exhibit 3

- 13 . The power out is the combined CT and ste am turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 3

- 8 ) is calculated by multiplying the power out by a combined generator efficiency of 98.4 percent.Cost and Performance Baseline

- Volume 3c (NGCC Cases)

61 

### Exhibit 3

- 12 Case S 3 1A 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 T 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 S 31 A 2 X ADVANCED F

- CLASS GT 2400 / 1050 / 1050

DWG

. NO

.

LROF

- HMB

- CS

- S 31 A

- PG

- 1 Flue Gas

A MBIENT

A IR 1 6
, 253
, 958 W 42

. 0 T 13

. 0 P 6

. 5 H Gross Plant Power : 522 MWe Auxiliary Load : 10 MWe Net Plant Power : 512 MWe Net Plant Efficiency
, HHV : 50

. 5 % Net Plant Heat Rate : 6
, 757 Btu / kWh A DVANCED F C LASS G AS T URBINES

COMBUSTOR N ATURAL GAS 153
, 559 W

100

. 0 T 450

. 0 P 19

. 9 H 2

6
, 407
, 517 W 215

. 5 T 13

. 0 P 103

. 9 H 6
, 407
, 517 W

1
, 163

. 2 T

13

. 5 P 357

. 7 H GENERATOR

CONDENSATE PUMPS8,801W1,302W

90

. 0 T 130

. 0 P 58

. 3 H 1
, 019
, 203 W 89

. 9 T 0

. 7 P 57

. 9 H

1
, 400 W 581

. 0 T 75

. 0 P 1
, 321

. 3 H 913
, 182 W

641

. 1 T 75

. 0 P 1
, 351

. 0 H 997
, 042 W 632

. 3 T 75

. 0 P 1
, 346

. 6 H

498
, 521 W 89

. 9 T 0

. 7 P 1
, 015

. 0 H 7 6 498
, 521 W 89

. 9 T 0

. 7 P 1
, 015

. 0 H

HOT WELL AIR

- COOLED CONDENSER CONDENSER

S TACK 4 8 S TEAM T URBINE MAKEUP 10
, 192 W

42

. 0 T 13

. 0 P 10

. 1 H

AIR INLET

FILTER 3

HP PUMP 1
, 019
, 203 W 253

. 0 T 100

. 0 P 221

. 9 HBLOWDOWN

84
, 707 W

300

. 1 T 95

. 0 P 269

. 4 H

155
, 798 W

300

. 7 T 400

. 0 P 270

. 7 H

778
, 698 W

305

. 3 T 2
, 540

. 0 P 279

. 3 H10,192W GLAND SEAL CONDENSER 1
, 400 W 212

. 0 T 14

. 7 P 179

. 9 H LP TURBINE

89

. 9 T 0

. 7 P 1
, 015

. 0 H

9
, 569 W

1
, 019
, 203 W 92

. 9 T 120

. 0 P 61

. 2 H

Three Pressure Heat Recovery Steam Generator ( HRSG ) 743
, 251 W 1
, 055

. 0 T 360

. 0 P 1
, 553

. 4 H

A A 154
, 240 W 1
, 055

. 0 T 360

. 0 P 1
, 553

. 4 HHOT REHEAT

C OLD R EHEAT

743
, 251 W

588

. 0 T 390

. 0 P 1
, 300

. 7 H STEAM SEAL REGULATOR

83
, 860 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 TURBINE766,391W 2
, 654 W 1
, 050

. 0 T 2
, 414

. 7 P 1
, 492

. 8 H914,484WMAIN STEAM

770
, 911 W 1
, 050

. 0 T 2
, 414

. 7 P 1
, 492

. 8 H 5

10
, 969 W866W IP STEAM

IP PUMP

LP PUMP DOE / NETL

SC PC P LANT C ASE S 31 ACost and Performance Baseline

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### This page intentionally left blankCost and Performance Baseline

- Volume 3c (NGCC Cases)

63 

### Exhibit 3

- 13 Case S31A Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)
Natural Gas 3,653 (3,463) 0.9 (0.9) 3,654 (3,463) GT Air 43.3 (41.0) 43 (41) Raw Water Withdrawal 5.7 (5.4) 6 (5) Auxiliary Power 35 (33) 35 (33)
Totals 3,653 (3,463) 49.9 (47.3) 35 (3 3) 3,738 (3,543)
Heat Out GJ/hr (MMBtu/hr) Cooling Tower BD 5.1 (4.9) 5 (5) Stack Gas 703 (666) 703 (666) Condenser 1,019 (966) 1,019 (966)
Process Losses 1 

### 131 (124 ) 131 (124 )
Power 1,880 (1,781) 1,880 (1,781)
Totals 0 (0) 1,858 (1,761) 1, 880 (1,781) 3,738 (3,543)

1 Process Losses are calculated by difference and reflect various turbine and other heat and work losses not modeled

in Aspen

.Cost and Performance Baseline

- Volume 3c (NGCC Cases)

64 

### 3.3.2 Case S31A

– Major Equipment List
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 3.3.3 . In general, the design conditions include a 10 percent contingency for flow s and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 FUEL HANDLING

N/A

ACCOUNT 2 FUEL AND SORBENT PREPARATION AND FEED

N/A

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment No. Description Type De sign Condition Operating Qty (Spares)

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 609,456 liters (161,000 gal) 2 (0)

2 Condensate Pumps Vertical canned 4,278 lpm @ 110 m H 2 

### O (1,130 gpm @ 360 ft H 2 

### O) 2 (1)

3 Boiler Feedwater Pump Ho rizontal, split case, multi

- stage, centrifugal, with interstage bleed for IP and LP feedwater HP water: 3,255 lpm @ 2,103 m H 2 

### O (860 gpm @

6,900 ft H 2 

### O)

2 (1) IP water: 644 lpm @ 283 m H 2 

### O (170 gpm @ 930 ft H 2 

### O) LP water: 341 lpm @ 24.4 m H 2 

### O (9 0 gpm @ 80 ft H 2 

### O)

4 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 (0)Cost and Performance Baseline

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65 

### Equipment No. Description Type De sign Condition Operating Qty (Spares)

5 Service Air Compressors Flooded Screw 13 m 3 

### /min @ 0.7 MPa (450 scfm @ 100 psig) 2 (1)

6 Instrument Air Dryers Duplex, regenerative 13 m 3 

### /min (450 scfm) 2 (1)

7 Closed Cycle Cooling Heat Exchangers Plate and frame 13 MMkJ/hr (13 MMBtu/hr) 2(0)

8 Closed Cycle Cooling Water Pumps Horizontal centrifugal 5,300 lpm @ 21 m H 2 

### O (1,400 gpm @ 70 ft H 2 

### O) 2 (1)

9 Engine

- Driven F ire Pump Vertical turbine, diesel engine 3,785 lpm @ 107 m H 2 

### O (1,000 gpm @ 350 ft H 2 

### O) 1 (1)

10 Fire Service Booster Pump Two

- stage horizontal centrifugal 2,650 lpm @ 76 m H 2 

### O (700 gpm @ 250 ft H 2 

### O) 1 (1)

11 Raw Water Pumps Stainless steel, single sucti on 2,271 lpm @ 18 m H 2 

### O (600 gpm @ 60 ft H 2 

### O) 2 (1)

12 Filtered Water Pumps Stainless steel, single suction 151 lpm @ 49 m H 2 

### O (40 gpm @ 160 ft H 2 

### O) 2 (1)

13 Filtered Water Tank Vertical, cylindrical 143,847 liter (38,000 gal) 1 (0)

14 Makeup Water Demi neralizer Multi

- media filter, cartridge filter, RO membrane assembly and electro

deionization unit 341 lpm (90 gpm) 1 (0)Cost and Performance Baseline

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### Equipment No. Description Type De sign Condition Operating Qty (Spares)

1 5 Gas Pipeline Underground, coated carbon steel, wrapped cathodic protection 58 m 3 

### /min @ 3.1 MPa (2,033 acfm @ 450 psia) 41 cm (16 in) standard wall pipe 16 km (0)

16 Gas Metering Station -- 58 m 3 

### /min (2,033 acfm) 1 (0)

17 Liquid Waste Treatment System 10 years, 24

- hour storm 1 (0)

ACCOUNT 4 GASIFIER, BOILER AND ACCESSORIES

N/A

ACCOUNT 5 FLUE GAS CLEANUP

N/A

ACCOUNT 6 COMBUSTION TURBINE GENERATORS AND AUXILIARIES

Equipment No. Description Type Design Condition Operating Qty (Spares)

1 Gas Turbine Advanced F class w/ dry low

- NOx burner 170 MW 2 (0)

2 Gas Turbine Generator TEWAC 190 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phas e 2 (0)Cost and Performance Baseline

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### ACCOUNT 7 WASTE HEAT BOILER, DUCTING, AND STACK

Equipment No. Description Type Design Condition Operating Qty (Spares)

1 Stack CS plate, type 409SS liner 46 m (150 ft) high x 7.5 m (25 ft) diameter 2 (0)

2 Heat Recovery Steam Generator Drum, m ulti

pressure with economizer section and integral deaerator Main steam

- 192,324 kg/hr, 16.5 MPa/566°C

(424,001 lb/hr, 2,400 psig/1,050°F) 2 (0) Reheat steam

- 223,903 kg/hr, 2.4 MPa/566°C

(493,620 lb/hr, 345 psig/1,050°F)

3 SCR Reactor Space for s pare layer 1,596,647 kg/h (3,520,000 lb/h) 2 (0)

4 SCR Catalyst

-- Space available for an additional catalyst layer 1 layer (0)

5 Dilution Air Blowers Centrifugal 10 m 3 

### /min @ 107 cm WG (350 scfm @ 42 in WG) 2 (1)

6 Ammonia Feed Pump Centrifugal 3.8 lpm @ 91 m H 2 

### O (1 gpm @ 300 ft H 2 

### O) 2 (1)

7 Ammonia Storage Tank Horizontal tank 60,567 liter (16,000 gal) 1 (0)

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment No. Description Type Design Condition Operating Qty. (Spares)

1 Steam Turbine Tand em compound, HP, IP, and two

- flow LP turbines 197 MW 16.5 MPa/566°C/566°C (2,400 psig/ 1050°F/1050°F) 1 (0)

2 Steam Turbine Generator Hydrogen cooled, static excitation 220 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 1 (0)

3 Steam Bypass One per HRSG 50% steam flow @ design steam conditions 2 (0)Cost and Performance Baseline

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### Equipment No. Description Type Design Condition Operating Qty. (Spares)

4 Surface Condenser Single pass, divided waterbox including vacuum pumps 560 MMkJ/hr, (530 MMBtu/hr), Inlet water temperature 9°C (48°F), Water temperature rise 11°C (20°F) 1 (0)

5 Air

- co oled Condenser --- 560 GJ/hr (530 MMBtu/hr), Condensing temperature 32°C (90°F), Ambient temperature 6°C (42°F) 1 (0)

ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type Design Condition Operating Qty (Spares)

1 Circulating Water Pumps Vertica l, wet pit 105,992 lpm @ 30.5 m (28,000 gpm @ 100 ft) 2 (1)

2 Cooling Tower Evaporative, mechanical draft, multi

- cell 3°C (37°F) wet bulb / 9°C (48°F) CWT / 20°C (68°F) HWT 1,149

MMkJ/hr (1,090 MMBtu/hr) heat load 1 (0)

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING

N/A

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type L12A Design Condition Operating Qty. (Spares)

1 CTG Transformer Oil

- filled 24 kV/345 kV, 190 MVA, 3

- ph, 60 Hz 2 (0)Cost and Performance Baseline

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### Equipment No. Description Type L12A Design Condition Operating Qty. (Spares)

2 STG Transformer Oil

- filled 2 4 kV/345 kV, 210 MVA, 3

- ph, 60 Hz 1 (0)

3 Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 09 MVA, 3

- ph, 60 Hz 1 (1)

4 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 1 MVA, 3

- ph, 60 Hz 1 (1)

5 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 2 (0)

6 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 1 (0)

7 Medium Voltage Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 1 (1)

8 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph , 60 Hz 1 (1)

9 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3

- ph, 60 Hz 1 (0)

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment No. Description Type L12A Design Condition Operating Qty (Spares)

1 DCS

- Main Control Monitor/key board, Operator printer, Engineering printer Operator stations/printers and engineering stations/printers 1 (0)

2 DCS

- Processor Microprocessor with redundant input/output N/A 1 (0)

3 DCS

- Data Highway Fiber optic Fully redundant, 25% spare 1 (0)Cost and Performance Baseline

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### 3.3.3 Cas e S31A

– Cost Estimating
The cost estimating methodology was described previously in Section 2.6

. Exhibit 3

- 14 shows the total plant capital cost summary organized by cost account and Exhibit 3

- 15 shows a more detailed breakdown of the capital costs. Exhibit 3

- 16 itemizes the owner’s costs and Exhibit 3

- 17 shows the initial and annual O&M costs.

The estimated T O C of the NGCC with no CO 2 

### capture is $8 17 /kW. No process contingency was included in this case because all elements of the technology are commercially proven. The project c ontingency is 9

. 1 percent of TO C. The COE is 64

. 4 mills/kWh.Cost and Performance Baseline

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### Exhibit 3

- 14 Case S31A Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S31A - 1x512 MWnet 2x1 7FB NGCC Plant Size: 512.4 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2 COAL & SORBENT PREP & FEED $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

3 FEEDWATER & MISC. BOP SYSTEMS $20,716 $3,813 $4,914 $0 $0 $29,442 $2,480 $0 $5,018 $36,941 $72

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4-4.9 Other gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A GAS CLEANUP & PIPING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B CO2 REMOVAL & COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $75,295 $0 $4,804 $0 $0 $80,099 $6,800 $0 $8,690 $95,589 $187 6.2-6.9 Combustion Turbine Other $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $4 SUBTOTAL 6 $75,295 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,491 $190

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $87 7.2-7.9 SCR System, Ductwork and Stack $1,006 $851 $978 $0 $0 $2,835 $241 $0 $505 $3,582 $7 SUBTOTAL 7 $33,964 $851 $5,257 $0 $0 $40,071 $3,412 $0 $4,546 $48,029 $94

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $22,586 $0 $3,614 $0 $0 $26,200 $2,251 $0 $2,845 $31,297 $61 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $27,599 $753 $8,980 $0 $0 $37,331 $3,509 $0 $7,451 $48,290 $94 SUBTOTAL 8 $50,185 $753 $12,594 $0 $0 $63,531 $5,760 $0 $10,296 $79,587 $155

9 COOLING WATER SYSTEM $4,569 $3,118 $3,227 $0 $0 $10,914 $912 $0 $1,693 $13,519 $26

10 ASH/SPENT SORBENT HANDLING SYS $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

11 ACCESSORY ELECTRIC PLANT $16,014 $3,593 $8,565 $0 $0 $28,172 $2,160 $0 $3,223 $33,555 $65

12 INSTRUMENTATION & CONTROL $5,631 $578 $4,679 $0 $0 $10,888 $907 $0 $1,352 $13,147 $26

13 IMPROVEMENTS TO SITE $1,659 $901 $4,414 $0 $0 $6,974 $617 $0 $1,518 $9,109 $18

14 BUILDINGS & STRUCTURES $0 $3,885 $4,135 $0 $0 $8,020 $652 $0 $1,301 $9,973 $19

TOTAL COST $208,031 $18,210 $53,333 $0 $0 $279,574 $23,822 $0 $37,954 $341,350 $666 TOTAL PLANT COST SUMMARYCost and Performance Baseline

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### Exhibit 3

- 15 Case S31A Total Plant Cost Details

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S31A - 1x512 MWnet 2x1 7FB NGCC Plant Size: 512.4 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.2 Coal Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.3 Coal Conveyors & Yd Crush $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.4 Other Coal Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 1. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.3 Slurry Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 2. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,247 $2,315 $1,904 $0 $0 $6,466 $533 $0 $1,050 $8,049 $16 3.2 Water Makeup & Pretreating $843 $88 $440 $0 $0 $1,371 $117 $0 $298 $1,786 $3 3.3 Other Feedwater Subsystems $1,025 $346 $291 $0 $0 $1,662 $134 $0 $269 $2,065 $4 3.4 Service Water Systems $100 $205 $666 $0 $0 $970 $85 $0 $211 $1,266 $2 3.5 Other Boiler Plant Systems $668 $259 $600 $0 $0 $1,527 $130 $0 $249 $1,906 $4 3.6 Natural Gas, incl. pipeline $14,655 $482 $420 $0 $0 $15,557 $1,319 $0 $2,531 $19,407 $38 3.7 Waste Treatment Equipment $304 $0 $173 $0 $0 $478 $42 $0 $104 $623 $1 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $874 $117 $419 $0 $0 $1,410 $122 $0 $306 $1,838 $4 SUBTOTAL 3. $20,716 $3,813 $4,914 $0 $0 $29,442 $2,480 $0 $5,018 $36,941 $72 4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4 LT Heat Recovery & FG Saturation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.5 Misc. Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Other Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.8 Major Component Rigging $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 

### TOTAL PLANT COST SUMMARYCost and Performance Baseline

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73 

### Exhibit 3

- 15 Case S31A Total Plant Cost Detai ls (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S31A - 1x512 MWnet 2x1 7FB NGCC Plant Size: 512.4 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 MDEA-LT AGR $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.2 Elemental Sulfur Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.3 Mercury Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.4 COS Hydrolysis $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.5 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Fuel Gas Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.9 HGCU Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $75,295 $0 $4,804 $0 $0 $80,099 $6,800 $0 $8,690 $95,589 $187 6.2 Combustion Turbine Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $4 SUBTOTAL 6. $75,295 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,491 $190 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $87 7.2 SCR System $1,006 $422 $593 $0 $0 $2,022 $174 $0 $329 $2,525 $5 7.3 Ductwork $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.4 Stack $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.9 HRSG,Duct & Stack Foundations $0 $428 $385 $0 $0 $813 $68 $0 $176 $1,057 $2 SUBTOTAL 7. $33,964 $851 $5,257 $0 $0 $40,071 $3,412 $0 $4,546 $48,029 $94 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $22,586 $0 $3,614 $0 $0 $26,200 $2,251 $0 $2,845 $31,297 $61 8.2 Turbine Plant Auxiliaries $152 $0 $348 $0 $0 $500 $44 $0 $54 $598 $1 8.3a Condenser & Auxiliaries $2,332 $0 $696 $0 $0 $3,028 $259 $0 $329 $3,616 $7 8.3b Air Cooled Condenser $21,369 $0 $4,284 $0 $0 $25,654 $2,565 $0 $5,644 $33,863 $66 8.4 Steam Piping $3,746 $0 $2,463 $0 $0 $6,208 $476 $0 $1,003 $7,687 $15 8.9 TG Foundations $0 $753 $1,189 $0 $0 $1,941 $165 $0 $421 $2,527 $5 SUBTOTAL 8. $50,185 $753 $12,594 $0 $0 $63,531 $5,760 $0 $10,296 $79,587 $155 9 COOLING WATER SYSTEM 9.1 Cooling Towers $3,592 $0 $459 $0 $0 $4,052 $345 $0 $440 $4,836 $9 9.2 Circulating Water Pumps $662 $0 $29 $0 $0 $691 $52 $0 $74 $817 $2 9.3 Circ.Water System Auxiliaries $58 $0 $8 $0 $0 $66 $6 $0 $7 $79 $0 9.4 Circ.Water Piping $0 $1,700 $412 $0 $0 $2,112 $171 $0 $342 $2,625 $5 9.5 Make-up Water System $143 $0 $191 $0 $0 $335 $29 $0 $55 $418 $1 9.6 Component Cooling Water Sys $113 $135 $90 $0 $0 $338 $28 $0 $55 $421 $1 9.9 Circ.Water System Foundations $0 $1,283 $2,038 $0 $0 $3,320 $281 $0 $720 $4,322 $8 SUBTOTAL 9. $4,569 $3,118 $3,227 $0 $0 $10,914 $912 $0 $1,693 $13,519 $26 TOTAL PLANT COST SUMMARYCost and Performance Baseline

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### Exhibit 3

- 15 Case S31A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S31A - 1x512 MWnet 2x1 7FB NGCC Plant Size: 512.4 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.7 Ash Transport & Feed Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.9 Ash/Spent Sorbent Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 10. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $3,886 $0 $2,335 $0 $0 $6,221 $527 $0 $506 $7,254 $14 11.2 Station Service Equipment $1,192 $0 $100 $0 $0 $1,292 $107 $0 $105 $1,504 $3 11.3 Switchgear & Motor Control $1,469 $0 $250 $0 $0 $1,718 $143 $0 $186 $2,047 $4 11.4 Conduit & Cable Tray $0 $702 $2,164 $0 $0 $2,865 $248 $0 $467 $3,580 $7 11.5 Wire & Cable $0 $2,235 $1,372 $0 $0 $3,607 $232 $0 $576 $4,415 $9 11.6 Protective Equipment $0 $533 $1,814 $0 $0 $2,347 $205 $0 $255 $2,808 $5 11.7 Standby Equipment $99 $0 $91 $0 $0 $190 $16 $0 $21 $227 $0 11.8 Main Power Transformers $9,368 $0 $138 $0 $0 $9,506 $645 $0 $1,015 $11,166 $22 11.9 Electrical Foundations $0 $123 $302 $0 $0 $425 $36 $0 $92 $554 $1 SUBTOTAL 11. $16,014 $3,593 $8,565 $0 $0 $28,172 $2,160 $0 $3,223 $33,555 $65 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $716 $0 $447 $0 $0 $1,163 $98 $0 $189 $1,451 $3 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $214 $0 $128 $0 $0 $342 $29 $0 $56 $427 $1 12.7 Computer & Accessories $3,425 $0 $102 $0 $0 $3,527 $290 $0 $382 $4,199 $8 12.8 Instrument Wiring & Tubing $0 $578 $1,105 $0 $0 $1,683 $127 $0 $271 $2,081 $4 12.9 Other I & C Equipment $1,277 $0 $2,897 $0 $0 $4,173 $363 $0 $454 $4,990 $10 SUBTOTAL 12. $5,631 $578 $4,679 $0 $0 $10,888 $907 $0 $1,352 $13,147 $26 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $89 $1,770 $0 $0 $1,858 $165 $0 $405 $2,428 $5 13.2 Site Improvements $0 $812 $1,009 $0 $0 $1,821 $161 $0 $396 $2,379 $5 13.3 Site Facilities $1,659 $0 $1,636 $0 $0 $3,294 $291 $0 $717 $4,302 $8 SUBTOTAL 13. $1,659 $901 $4,414 $0 $0 $6,974 $617 $0 $1,518 $9,109 $18 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $236 $125 $0 $0 $361 $28 $0 $58 $447 $1 14.2 Steam Turbine Building $0 $1,879 $2,502 $0 $0 $4,381 $360 $0 $711 $5,452 $11 14.3 Administration Building $0 $443 $300 $0 $0 $743 $59 $0 $120 $923 $2 14.4 Circulation Water Pumphouse $0 $148 $73 $0 $0 $221 $17 $0 $36 $274 $1 14.5 Water Treatment Buildings $0 $182 $166 $0 $0 $348 $28 $0 $56 $432 $1 14.6 Machine Shop $0 $384 $246 $0 $0 $630 $50 $0 $102 $782 $2 14.7 Warehouse $0 $248 $150 $0 $0 $398 $31 $0 $64 $494 $1 14.8 Other Buildings & Structures $0 $74 $54 $0 $0 $128 $10 $0 $21 $159 $0 14.9 Waste Treating Building & Str. $0 $291 $519 $0 $0 $810 $67 $0 $132 $1,009 $2 SUBTOTAL 14. $0 $3,885 $4,135 $0 $0 $8,020 $652 $0 $1,301 $9,973 $19

TOTAL COST $208,031 $18,210 $53,333 $0 $0 $279,574 $23,822 $0 $37,954 $341,350 $666 TOTAL PLANT COST SUMMARYCost and Performance Baseline

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75 

### Exhibit 3

- 16 Case S31A Owner’s Costs

Owner's Costs $x1000 $/kW Preproduction Costs 6 Months Fixed O&M $3,038 $6 1 Month Variable O&M $508 $1 25% of 1 Months Fuel Cost at 100% CF $4,505 $9 2% of TPC $6,827 $13 Total $14,878 $29
Inventory Capital 60 day supply of consumables at 100% CF $164 $0 0.5% of TPC (spare parts) $1,707 $3 Total $1,871 $4
Initial Cost for Catalyst and Chemicals $0 $0 Land $300 $1 Other Owner's Costs $51,202 $100 Financing Costs $9,216 $18

Total Owner's Costs $77,468 $151 Total Overnight Cost (TOC) $418,817 $817 TASC Multiplier 1.075 Total As-Spent Cost (TASC) $450,229 $879Cost and Performance Baseline

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### Exhibit 3

- 17 Case S31A Initial and Annual Operating and Maintenance Cost Summary

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case S31A - 1x512 MWnet 2x1 7FB NGCC Heat Rate-net (Btu/kWh): 6,757 MWe-net: 512 Capacity Factor (%): 85 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total

Skilled Operator 1.0 1.0 Operator 2.0 2.0 Foreman 1.0 1.0 Lab Tech's, etc. 1.0 1.0 TOTAL-O.J.'s 5.0 5.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $1,972,971 $3.850 Maintenance Labor Cost $2,888,333 $5.637 Administrative & Support Labor $1,215,326 $2.372 Property Taxes and Insurance $6,826,992 $13.323 TOTAL FIXED OPERATING COSTS $12,903,622 $25.182 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $4,332,499 $0.00114

Consumables Consumption Unit Initial Initial /Day Cost Cost
Water (/1000 gallons) 0.00 780.48 1.08 $0 $261,921 $0.00007

Chemicals

MU & WT Chem. (lbs) 0.00 4649.87 0.17 $0 $249,672 $0.00007 MEA Solvent (ton) 0.00 0.00 2249.89 $0 $0 $0.00000 Activated Carbon (lb) 0.00 0.00 1.05 $0 $0 $0.00000 Corrosion Inhibitor 0.00 0.00 0.00 $0 $0 $0.00000 SCR Catalyst (m3) w/equip. 0.06 5775.94 $0 $116,099 $0.00003 Ammonia (19% NH3) ton 0.00 5.45 129.80 $0 $219,434 $0.00006 Subtotal Chemicals $0 $585,205 $0.00015

Other

Supplemental Fuel (MBtu) 0.00 0.00 0.00 $0 $0 $0.00000 Gases, N2 etc.(/100scf) 0.00 0.00 0.00 $0 $0 $0.00000 L.P. Steam (/1000 pounds) 0.00 0.00 0.00 $0 $0 $0.00000 Subtotal Other $0 $0 $0.00000
Waste Disposal

Flyash (ton) 0.00 0.00 0.00 $0 $0 $0.00000 Bottom Ash (ton) 0.00 0.00 0.00 $0 $0 $0.00000 Subtotal Waste Disposal $0 $0 $0.00000
By-products

Sulfur (tons) 0.00 0.00 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $0 $5,179,625 $0.00136

Fuel (MMBtu) 0 83,097 7.13 $0 $183,795,700 $0.04817Cost and Performance Baseline

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### 3.3.4 Case L31A

– Performance Results
The pl ant produces a net output of 547 MW a t a net plant efficiency of 50.6 percent (HHV basis).
Major stream flows are described in Exhibit 3

- 18 and overall plant performance is summarized in Exhibit 3

- 19 , which includes auxiliary power requirements.

Exhibit 3

- 18 Case L31A Stream Tab le, NGCC without CO 2 

### Capture

1 2 3 4 5 6 7 8 V-L Mole Fraction

Ar 0.0093 0.0000 0.0089 0.0089 0.0000 0.0000 0.0000 0.0000 CH 4 0.0000 0.9310 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 C 2 H 6 0.0000 0.0320 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 C 3 H 8 0.0000 0.0070 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 C 4 H 10 0.0000 0.0040 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 2 0.0003 0.0100 0.0413 0.0413 0.0000 0.0000 0.0000 0.0000 H 2 O 0.0064 0.0000 0.0851 0.0851 1.0000 1.0000 1.0000 1.0000 N 2 0.7759 0.0160 0.7451 0.7451 0.0000 0.0000 0.0000 0.0000 O 2 0.2081 0.0000 0.1196 0.1196 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 104,424 4,282 108,830 108,830 20,569 13,340 13,340 27,253 V-L Flowrate (kg/hr) 3,017,333 74,190 3,091,523 3,091,523 370,555 240,318 240,318 490,976 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0

Temperature (°C) 4 38 628 102 566 32 32 32 Pressure (MPa, abs) 0.10 3.10 0.10 0.10 16.65 0.005 0.005 0.90 Enthalpy (kJ/kg) A 14.12 46.30 831.54 242.05 3,472.36 2,360.98 2,360.98 135.69 Density (kg/m 3 ) 1.2 22.2 0.4 0.9 47.7 0.04 0.04 995.4 V-L Molecular Weight 28.895 17.328 28.407 28.407 18.015 18.015 18.015 18.015

V-L Flowrate (lb mol /hr) 230,215 9,439 239,928 239,928 45,347 29,409 29,409 60,083 V-L Flowrate (lb/hr) 6,652,082 163,560 6,815,642 6,815,642 816,935 529,812 529,812 1,082,416 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0

Temperature (°F) 40 100 1,162 216 1,050 90 90 90 Pressure (psia) 13.8 450.0 14.3 13.8 2,414.7 0.7 0.7 130.0 Enthalpy (Btu/lb) A 6.1 19.9 357.5 104.1 1,492.8 1,015.0 1,015.0 58.3 Density (lb/ft 3 ) 0.074 1.384 0.023 0.054 2.977 0.002 0.002 62.141 A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Baseline

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### Exhibit 3

- 19 Case L31A Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe)
Gas Turbine Power 358,600 Steam Turbine Power 198,400 TOTAL POWER, kWe 557,000 AUXILIARY LOAD SUMMARY, kWe Condensate Pumps 160 Boiler Feedwater Pumps 2,600 Circulating Water Pump 1,120 Ground Water Pumps 100 Cooling Tower Fans 700 Air Cooled Condenser Fan 2,340 SCR 10 Gas Turbine Auxiliaries 700 Steam Turbine Auxiliaries 100 Miscellaneous Balance of Plant 1 

### 500 Transformer Losses 1,690 TOTAL AUXILIARIES, kWe 10,020 NET POWER, kWe 546,980 Net Plant Efficiency (HHV) 50.6% Net Plant Efficiency (LHV) 56.1% Net Plant Heat Rate (HHV), kJ/kWhr (Btu/kWhr) 7,114 (6,743) Net Plant Heat Rate (LHV), kJ/kWhr (Btu/kWhr) 6,414 (6,079) CONDENSER COOLING DUTY, 10 6 

### kJ/h (10 6 

### Btu/h) 1,087 (1,030) CONSUMABLES Natural Gas Feed Flow, kg/hr (lb/hr) 74,190 (163,560) Thermal Input (HHV), kW th 

### 1,080,880 Thermal Input (LHV) , kW th 

### 974,553 Raw Water Withdrawal, m 3 

### /min (gpm) 4.3 (1,148) Raw Water Consumption, m 3 

### /min (gpm) 3.4 (890)

1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

.Cost and Performance Baseline

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### Environmental Performance The environmental targets for e missions of NOx, SO 2
, 

### and PM were presented in Section 2.3

. A summary of the plant air emissions for Case L31A is presented in Exhibit 3

- 20

. Exhibit 3

- 20 Case L31A Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 85% CF kg/MWh (lb/MWh)

SO 2 

### Negligible Negligible Negligible NO x 0.004 (0.009) 113 (124) 0.027 ( 0 .060)
Particulates Negligible Negligible Negligible Hg Negligible Negligible Negligib le

CO 2 

### 50.8 (118.3) 1,473,220 (1,623,947) 355 (783)

CO 2 1 

### 362 (797)

1 CO 2 emissions based on net power instead of gross power


### The operation of the modern, state

- of

- the

- art gas turbine 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.
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 produce d 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 is s hown in Exhibit 3

- 21

. The carbon input to the plant consists of carbon in the air in addition to carbon in the natural gas. One hundred percent carbon conversion is assumed since carbon conversion for NGCC plants is typically ab out 99.9 percent. Carbon in the air is not neglected here since the model accounts for air components throughout. Carbon leaves the plant as CO 2 

### in the stack gas.Cost and Performance Baseline

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80 

### Exhibit 3

- 21 Cases L31A Carbon Balance
Car bon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)
Natural Gas 53,586 (118,138) Stack Gas 53,998 (119,044)
Air (CO 2 

### ) 411 (907)

Total 53,998 (119,044) Total 53,998 (119,044)

Exhibit 3

- 22 shows the overall water balance for the plant. The exhibit is presented in an identical manner as was for Case S31A.

Exhibit 3

- 22 Case L31A 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 0.08 (22) 0 (0) 0.08 (22) 0 (0) 0.08 (22)

BFW Makeup 0.08 (22) 0 (0) 0.08 (22) Cooling Tower 4.35 (1 , 148) 0.08 (22) 4.27 (1 , 127) 0.98 (258) 3. 29 (868)

BFW Blowdown 0 (0) 0.08 (22)

- 0.08 (

- 22)
Total 4.43 (1,170) 0.08 (22) 4.35 (1,148) 0.98 (258) 3.37 (890)

Heat and Mass Balance Diagrams A heat and mass balance diagram is shown for the NGCC in Exhibit 3

- 23

. An overall plant energy balance is provided in tabular form in Exhibit 3

- 24 . 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

- 19 ) is calculated by multiplying the power out by a combined generator efficiency of 98.4 percent.Cost and Performance Baseline

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81 

### Exhibit 3

- 23 Case L31A 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 T 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 L 31 A 2 X ADVANCED F

- CLASS GT 2400 / 1050 / 1050

DWG

. NO

.

LROF

- HMB

- CS

- L 31 A

- PG

- 1 Flue Gas

A MBIENT

A IR 1 6
, 652
, 082 W 40

. 0 T 13

. 8 P 6

. 0 H Gross Plant Power : 557 MWe Auxiliary Load : 10 MWe Net Plant Power : 547 MWe Net Plant Efficiency
, HHV : 50

. 6 % Net Plant Heat Rate : 6
, 743 Btu / kWh A DVANCED F C LASS G AS T URBINES

COMBUSTOR N ATURAL GAS 163
, 560 W

100

. 0 T 450

. 0 P 19

. 9 H 2

6
, 815
, 642 W 215

. 7 T 13

. 8 P 104

. 0 H 6
, 815
, 642 W

1
, 162

. 0 T

14

. 3 P 357

. 4 H GENERATOR

CONDENSATE PUMPS8,801W1,302W

90

. 0 T 130

. 0 P 58

. 3 H 1
, 082
, 416 W 89

. 9 T 0

. 7 P 57

. 9 H

1
, 400 W 581

. 0 T 75

. 0 P 1
, 321

. 3 H 970
, 326 W

641

. 3 T 75

. 0 P 1
, 351

. 1 H 1
, 059
, 623 W 632

. 4 T 75

. 0 P 1
, 346

. 7 H

529
, 812 W 89

. 9 T 0

. 7 P 1
, 015

. 0 H 7 6 529
, 812 W 89

. 9 T 0

. 7 P 1
, 015

. 0 H

HOT WELL AIR

- COOLED CONDENSER CONDENSER

S TACK 4 8 S TEAM T URBINE MAKEUP 10
, 824 W

40

. 0 T 13

. 8 P 8

. 1 H

AIR INLET

FILTER 3

HP PUMP 1
, 082
, 416 W 253

. 0 T 100

. 0 P 221

. 9 HBLOWDOWN

90
, 199 W

300

. 1 T 95

. 0 P 269

. 4 H

167
, 030 W

300

. 7 T 400

. 0 P 270

. 7 H

825
, 187 W

305

. 3 T 2
, 540

. 0 P 279

. 3 H10,824W GLAND SEAL CONDENSER 1
, 400 W 212

. 0 T 14

. 7 P 179

. 9 H LP TURBINE

89

. 9 T 0

. 7 P 1
, 015

. 0 H

9
, 569 W

1
, 082
, 416 W 92

. 8 T 120

. 0 P 61

. 0 H

Three Pressure Heat Recovery Steam Generator ( HRSG ) 789
, 275 W 1
, 055

. 0 T 360

. 0 P 1
, 553

. 4 H

A A 165
, 360 W 1
, 055

. 0 T 360

. 0 P 1
, 553

. 4 HHOT REHEAT

C OLD R EHEAT

789
, 275 W

588

. 0 T 390

. 0 P 1
, 300

. 6 H STEAM SEAL REGULATOR

89
, 297 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 TURBINE812,415W 2
, 654 W 1
, 050

. 0 T 2
, 414

. 7 P 1
, 492

. 8 H971,628WMAIN STEAM

816
, 935 W 1
, 050

. 0 T 2
, 414

. 7 P 1
, 492

. 8 H 5

10
, 969 W866W IP STEAM

IP PUMP

LP PUMP DOE / NETL

SC PC P LANT C ASE L 31 ACost and Performance Baseline

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### This page intentionally left blankCost and Performance Baseline

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83 

### Exhibit 3

- 24 Case L31A Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total
Heat In GJ/hr (MMBtu/hr)
Natural Gas 3,891 (3,688) 0.8 (0.7) 3,892 (3,689) GT Air 42.6 (40.4) 43 (40)
Raw Water Withdrawal 4.8 (4.6) 5 (5) Auxiliary Power 36 (34) 36 (34)
Totals 3,891 (3,688) 48.2 (45.7) 36 (34) 3,975 (3,768) Heat Out GJ/hr (MMBtu/hr) Cooling Tower Blowdown 5.3 (5.0) 5 (5) Stack Gas 748 (709) 748 (709) Condenser 1,083 (1,026) 1,083 (1,026)
Process Losses 1 

### 134 ( 127 ) 134 (127)
Power 2,005 (1,901) 2,005 (1,901)
Totals 0 (0) 1,970 (1,867) 2,005 (1,901) 3,975 (3,768)

1 Process Losses are calculated by difference and reflect various turbine and other heat and work losses not

modeled in Aspen

.Cost and Performance Baseline

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### 3.3.5 Case L31A

– Major Equipment List
Major equipment items for the NGCC plant with no CO 2 

### capture are shown in the following tables. The accounts used in the equipm ent list correspond to the account numbers used in the cost estimates in Section 3.3.6 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pum ps and fans.

ACCOUNT 1 FUEL HANDLING

N/A

ACCOUNT 2 FUEL AND SORBENT PREPARATION AND FEED

N/A

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT
Equipment No. Description Type Design Condition Operating Qty (Spares)

1 Demineralized Water Sto rage Tank Vertical, cylindrical, outdoor 647,310 liters (171,000 gal) 2 (0)

2 Condensate Pumps Vertical canned 4,543 lpm @ 110 m H 2 O (1,200 gpm @ 360 ft H 2 O) 2 (1)

3 Boiler Feedwater Pump Horizontal, split case, multi

- stage, centrifugal, with interstage bleed for IP and LP feedwater HP water: 3,445 lpm @ 2,103 m H 2 O (910 gpm @ 6,900 ft H 2 O)

2 (1) IP water: 681 lpm @ 283 m H 2 O (180 gpm @ 930 ft H 2 O) LP water: 379 lpm @ 24.4 m H 2 O (100 gpm @ 80 ft H 2 O)

4 Auxiliary Boiler Shop fabricated, w ater tube 18,144 kg/h, 2.8 MPa, 343°C (40,000 lb/h, 400 psig, 650°F) 1 (0)

5 Service Air Compressors Flooded Screw 13 m 3 /min @ 0.7 MPa (450 scfm @ 100 psig) 2 (1)

6 Instrument Air Dryers Duplex, regenerative 13 m 3 /min (450 scfm) 2 (1)

7 Closed Cycle Cooling Heat Exchangers Plate and frame 13 MMkJ/hr (13 MMBtu/hr) 2 (0)

8 Closed Cycle Cooling Water Pumps Horizontal centrifugal 5,300 lpm @ 21 m H 2 O (1,400 gpm @ 70 ft H 2 O) 2 (1)Cost and Performance Baseline

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85 Equipment No. Description Type Design Condition Operating Qty (Spares)

9 Engine

- Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 107 m H 2 O (1,000 gpm @ 350 ft H 2 O) 1 (1)

10 Fire Service Booster Pump Two

- stage horizontal centrifugal 2,650 lpm @ 76 m H 2 O (700 gpm @ 250 ft H 2 O) 1 (1)

11 Raw Water Pumps Stainless steel, single suction 2,650 lpm @ 18 m H 2 O (700 gpm @ 60 ft H 2 O) 2 (1)

12 Filtere d Water Pumps Stainless steel, single suction 151 lpm @ 49 m H 2 O (40 gpm @ 160 ft H 2 O) 2 (1)

13 Filtered Water Tank Vertical, cylindrical 143,847 liter (38,000 gal) 1 (0)

14 Makeup Water Demineralizer Multi

- media filter, cartridge filter, RO membrane ass embly and electro

- deionization unit 341 lpm (90 gpm) 1 (0)

15 Gas Pipeline Underground, coated carbon steel, wrapped cathodic protection 61 m 3 /min @ 3.1 MPa (2,166 acfm @ 450 psia) 41 cm (16 in) standard wall pipe 16 km (0)

16 Gas Metering Station

-- 61 m 3 /min (2,166 acfm) 1 (0)

1 7 Liquid Waste Treatment System 10 years, 24

- hour storm 1 (0)



### ACCOUNT 4 GASIFIER, BOILER AND ACCESSORIES

N/A

ACCOUNT 5 FLUE GAS CLEANUP

N/A

ACCOUNT 6 COMBUSTION TURBINE GENERATORS AND AUXILIARIES

Equipment No. Descrip tion Type Design Condition Operating Qty (Spares)

1 Gas Turbine Advanced F class w/ dry low

- NOx burner 180 MW 2 (0)

2 Gas Turbine Generator TEWAC 200 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 2 (0)Cost and Performance Baseline

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### ACCOUNT 7 WASTE HEAT BOILER, DUCTING, AND STACK

Equipmen t No. Description Type Design Condition Operating Qty (Spares)

1 Stack CS plate, type 409SS liner 46 m (150 ft) high x 7.5 m (25 ft) diameter 2 (0)

2 Heat Recovery Steam Generator Drum, multi

- pressure with economizer section and integral deaerator Main s team

- 203,806 kg/h, 16.5 MPa/566°C (449,314 lb/h, 2,400 psig/1,050°F) 2 (0) Reheat steam

- 238,159 kg/h, 2.4 MPa/566°C (525,049 lb/h, 345 psig/1,050°F)
3 SCR Reactor Space for spare layer 1,700,973 kg/h (3,750,000 lb/h) 2 (0)

4 SCR Catalyst

- - Space available for an additional catalyst layer 1 layer (0)

5 Dilution Air Blowers Centrifugal 10 m 3 /min @ 107 cm WG (370 scfm @ 42 in WG) 2 (1)

6 Ammonia Feed Pump Centrifugal 3.8 lpm @ 91 m H 2 O (1 gpm @ 300 ft H 2 O) 2 (1)

7 Ammonia Storage Tank Hor izontal tank 64,353 liter (17,000 gal) 1 (0)



### ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment No. Description Type Design Condition Operating Qty (Spares)

1 Steam Turbine Tandem compound, HP, IP, and two

- flow LP turbines 209 MW 16.5 MPa/566° C/566°C (2,400 psig/ 1050°F/1050°F) 1 (0)

2 Steam Turbine Generator Hydrogen cooled , static excitation 230 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 1 (0)

3 Steam Bypass One per HRSG 50% steam flow @ design steam conditions 2 (0)

4 Surface Condenser Single pass, divided waterbox including vacuum pumps 590 MMkJ/hr (560 MMBtu/hr), Inlet water temperature 8°C (47°F), Water temperature rise 11°C (20°F) 1 (0)

5 Air

- cooled Condenser --- 590 GJ/hr (560 MMBtu/hr), Condensing temperature 32°C (90°F), Ambient tempera ture 4°C (40°F) 1 (0)Cost and Performance Baseline

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### ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type Design Condition Operating Qty (Spares)

1 Circulating Water Pumps Vertical, wet pit 113,563 lpm @ 30.5 m (30,000 gpm @ 100 ft) 2 (1)

2 Cooling Tower Evaporative, mechani cal draft, multi

- cell 2°C (36°F) wet bulb / 8°C (47°F) CWT / 19°C (67°F) HWT 1,219 MMkJ/hr (1,156 MMBtu/hr) heat load 1 (0)



### ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING

N/A

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type L 12A Design Condition Operating Qty (Spares)

1 CTG Transformer Oil

- filled 24 kV/345 kV, 200 MVA, 3

- ph, 60 Hz 2 (0)

2 STG Transformer Oil

- filled 24 kV/345 kV, 220 MVA, 3

- ph, 60 Hz 1 (0)

3 Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 09 MVA, 3

- ph, 60 Hz 1 (1)

4 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 1 MVA, 3

- ph, 60 Hz 1 (1)

5 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 2 (0)

6 STG Isolated Phase Bus Duct and Ta p Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 1 (0)

7 Medium Voltage Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 1 (1)

8 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 1 (1)

9 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3

- ph, 60 Hz 1 (0)Cost and Performance Baseline

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### ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment No. Description Type L12A Design Condition Operating Qty (Spares)

1 DCS

- Main Control Monitor/keyboard, Operator printer, Engineering printer Operator stations/printers and engineer ing stations/printers 1 (0)

2 DCS

- Processor Microprocessor with redundant input/output N/A 1 (0)

3 DCS

- Data Highway Fiber optic Fully redundant, 25% spare 1 (0)Cost and Performance Baseline

- Volume 3c (NGCC Cases)

89 

### 3.3.6 Case L31A

– Cost Estimating
The cost estimating methodology was described previously in Section 2.6

. Exhibit 3

- 25 shows the total plant capital cost summary organized by cost account and Exhibit 3

- 26 shows a more detailed breakdown of the capital costs. Exhibit 3

- 27 itemizes the owner’s costs and Exhibit 3

- 28 shows the initial and annual O&M costs.

The estimated TO C of the NGCC with no CO 2 

### capture is $ 782 /kW. No process contingency was included in this case b ecause all elements of the technology are commercially proven. The project contingency is 9

. 1 percent of TOC. The COE is 63

. 6 mills/kWh

.Cost and Performance Baseline

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90 

### Exhibit 3

- 25 Case L31A Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case L31A - 1x547 MWnet 2x1 7FB NGCC Plant Size: 547.0 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2 COAL & SORBENT PREP & FEED $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

3 FEEDWATER & MISC. BOP SYSTEMS $20,979 $3,972 $5,118 $0 $0 $30,069 $2,533 $0 $5,129 $37,732 $69

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4-4.9 Other gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A GAS CLEANUP & PIPING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B CO2 REMOVAL & COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $75,294 $0 $4,804 $0 $0 $80,098 $6,800 $0 $8,690 $95,589 $175 6.2-6.9 Combustion Turbine Other $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $3 SUBTOTAL 6 $75,294 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,490 $178

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $81 7.2-7.9 SCR System, Ductwork and Stack $1,138 $906 $1,056 $0 $0 $3,100 $264 $0 $549 $3,913 $7 SUBTOTAL 7 $34,096 $906 $5,335 $0 $0 $40,337 $3,434 $0 $4,589 $48,361 $88

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $23,537 $0 $3,793 $0 $0 $27,329 $2,349 $0 $2,968 $32,646 $60 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $28,692 $786 $9,346 $0 $0 $38,825 $3,649 $0 $7,748 $50,222 $92 SUBTOTAL 8 $52,229 $786 $13,139 $0 $0 $66,154 $5,997 $0 $10,716 $82,868 $152

9 COOLING WATER SYSTEM $4,765 $3,241 $3,350 $0 $0 $11,356 $949 $0 $1,760 $14,065 $26

10 ASH/SPENT SORBENT HANDLING SYS $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

11 ACCESSORY ELECTRIC PLANT $16,538 $3,697 $8,860 $0 $0 $29,096 $2,231 $0 $3,326 $34,653 $63

12 INSTRUMENTATION & CONTROL $5,758 $591 $4,785 $0 $0 $11,134 $927 $0 $1,382 $13,443 $25

13 IMPROVEMENTS TO SITE $1,710 $929 $4,552 $0 $0 $7,191 $636 $0 $1,566 $9,393 $17

14 BUILDINGS & STRUCTURES $0 $3,996 $4,263 $0 $0 $8,259 $671 $0 $1,340 $10,270 $19

TOTAL COST $211,369 $18,839 $54,950 $0 $0 $285,158 $24,302 $0 $38,816 $348,275 $637 TOTAL PLANT COST SUMMARYCost and Performance Baseline

- Volume 3c (NGCC Cases)

91 

### Exhibit 3

- 26 Case L31A Total Plant Cost Details

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case L31A - 1x547 MWnet 2x1 7FB NGCC Plant Size: 547.0 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.2 Coal Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.3 Coal Conveyors & Yd Crush $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.4 Other Coal Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 1. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.3 Slurry Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 2. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,343 $2,414 $1,985 $0 $0 $6,742 $556 $0 $1,095 $8,392 $15 3.2 Water Makeup & Pretreating $878 $92 $459 $0 $0 $1,429 $122 $0 $310 $1,860 $3 3.3 Other Feedwater Subsystems $1,068 $361 $304 $0 $0 $1,733 $139 $0 $281 $2,153 $4 3.4 Service Water Systems $104 $214 $693 $0 $0 $1,011 $88 $0 $220 $1,319 $2 3.5 Other Boiler Plant Systems $696 $270 $625 $0 $0 $1,591 $135 $0 $259 $1,985 $4 3.6 Natural Gas, incl. pipeline $14,665 $501 $436 $0 $0 $15,602 $1,322 $0 $2,539 $19,463 $36 3.7 Waste Treatment Equipment $317 $0 $181 $0 $0 $498 $43 $0 $108 $649 $1 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $908 $121 $436 $0 $0 $1,465 $127 $0 $318 $1,909 $3 SUBTOTAL 3. $20,979 $3,972 $5,118 $0 $0 $30,069 $2,533 $0 $5,129 $37,732 $69 4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4 LT Heat Recovery & FG Saturation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.5 Misc. Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Other Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.8 Major Component Rigging $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 

### TOTAL PLANT COST SUMMARYCost and Performance Baseline

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92 

### Exhibit 3

- 26 Case L31A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case L31A - 1x547 MWnet 2x1 7FB NGCC Plant Size: 547.0 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 MDEA-LT AGR $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.2 Elemental Sulfur Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.3 Mercury Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.4 COS Hydrolysis $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.5 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Fuel Gas Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.9 HGCU Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $75,294 $0 $4,804 $0 $0 $80,098 $6,800 $0 $8,690 $95,589 $175 6.2 Combustion Turbine Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $3 SUBTOTAL 6. $75,294 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,490 $178 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $81 7.2 SCR System $1,138 $478 $671 $0 $0 $2,288 $197 $0 $373 $2,857 $5 7.3 Ductwork $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.4 Stack $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.9 HRSG,Duct & Stack Foundations $0 $428 $385 $0 $0 $813 $68 $0 $176 $1,057 $2 SUBTOTAL 7. $34,096 $906 $5,335 $0 $0 $40,337 $3,434 $0 $4,589 $48,361 $88 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $23,537 $0 $3,793 $0 $0 $27,329 $2,349 $0 $2,968 $32,646 $60 8.2 Turbine Plant Auxiliaries $159 $0 $363 $0 $0 $522 $46 $0 $57 $625 $1 8.3a Condenser & Auxiliaries $2,423 $0 $724 $0 $0 $3,147 $270 $0 $342 $3,758 $7 8.3b Air Cooled Condenser $22,209 $0 $4,453 $0 $0 $26,662 $2,666 $0 $5,866 $35,193 $64 8.4 Steam Piping $3,901 $0 $2,565 $0 $0 $6,466 $495 $0 $1,044 $8,005 $15 8.9 TG Foundations $0 $786 $1,242 $0 $0 $2,029 $172 $0 $440 $2,641 $5 SUBTOTAL 8. $52,229 $786 $13,139 $0 $0 $66,154 $5,997 $0 $10,716 $82,868 $152 9 COOLING WATER SYSTEM 9.1 Cooling Towers $3,743 $0 $479 $0 $0 $4,222 $359 $0 $458 $5,039 $9 9.2 Circulating Water Pumps $695 $0 $31 $0 $0 $726 $55 $0 $78 $859 $2 9.3 Circ.Water System Auxiliaries $61 $0 $8 $0 $0 $69 $6 $0 $7 $82 $0 9.4 Circ.Water Piping $0 $1,772 $429 $0 $0 $2,201 $178 $0 $357 $2,736 $5 9.5 Make-up Water System $148 $0 $198 $0 $0 $346 $30 $0 $56 $433 $1 9.6 Component Cooling Water Sys $118 $141 $94 $0 $0 $352 $30 $0 $57 $439 $1 9.9 Circ.Water System Foundations $0 $1,329 $2,111 $0 $0 $3,440 $292 $0 $746 $4,477 $8 SUBTOTAL 9. $4,765 $3,241 $3,350 $0 $0 $11,356 $949 $0 $1,760 $14,065 $26 TOTAL PLANT COST SUMMARYCost and Performance Baseline

- Volume 3c (NGCC Cases)

93 

### Exhibit 3

- 26 Case L31A Tot al Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case L31A - 1x547 MWnet 2x1 7FB NGCC Plant Size: 547.0 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.7 Ash Transport & Feed Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.9 Ash/Spent Sorbent Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 10. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $4,036 $0 $2,425 $0 $0 $6,461 $547 $0 $526 $7,534 $14 11.2 Station Service Equipment $1,222 $0 $103 $0 $0 $1,325 $109 $0 $108 $1,541 $3 11.3 Switchgear & Motor Control $1,506 $0 $256 $0 $0 $1,762 $146 $0 $191 $2,099 $4 11.4 Conduit & Cable Tray $0 $719 $2,218 $0 $0 $2,937 $254 $0 $479 $3,670 $7 11.5 Wire & Cable $0 $2,291 $1,407 $0 $0 $3,698 $238 $0 $590 $4,526 $8 11.6 Protective Equipment $0 $558 $1,898 $0 $0 $2,456 $215 $0 $267 $2,938 $5 11.7 Standby Equipment $102 $0 $93 $0 $0 $196 $17 $0 $21 $234 $0 11.8 Main Power Transformers $9,672 $0 $144 $0 $0 $9,817 $666 $0 $1,048 $11,531 $21 11.9 Electrical Foundations $0 $129 $316 $0 $0 $445 $38 $0 $97 $580 $1 SUBTOTAL 11. $16,538 $3,697 $8,860 $0 $0 $29,096 $2,231 $0 $3,326 $34,653 $63 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $732 $0 $457 $0 $0 $1,189 $101 $0 $193 $1,483 $3 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $219 $0 $131 $0 $0 $350 $30 $0 $57 $436 $1 12.7 Computer & Accessories $3,502 $0 $105 $0 $0 $3,607 $297 $0 $390 $4,293 $8 12.8 Instrument Wiring & Tubing $0 $591 $1,130 $0 $0 $1,721 $130 $0 $278 $2,128 $4 12.9 Other I & C Equipment $1,305 $0 $2,962 $0 $0 $4,268 $371 $0 $464 $5,102 $9 SUBTOTAL 12. $5,758 $591 $4,785 $0 $0 $11,134 $927 $0 $1,382 $13,443 $25 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $91 $1,825 $0 $0 $1,916 $170 $0 $417 $2,504 $5 13.2 Site Improvements $0 $838 $1,040 $0 $0 $1,878 $166 $0 $409 $2,453 $4 13.3 Site Facilities $1,710 $0 $1,687 $0 $0 $3,397 $300 $0 $739 $4,436 $8 SUBTOTAL 13. $1,710 $929 $4,552 $0 $0 $7,191 $636 $0 $1,566 $9,393 $17 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $236 $125 $0 $0 $361 $28 $0 $58 $447 $1 14.2 Steam Turbine Building $0 $1,948 $2,594 $0 $0 $4,542 $373 $0 $737 $5,652 $10 14.3 Administration Building $0 $452 $307 $0 $0 $759 $60 $0 $123 $943 $2 14.4 Circulation Water Pumphouse $0 $151 $75 $0 $0 $226 $18 $0 $37 $280 $1 14.5 Water Treatment Buildings $0 $190 $173 $0 $0 $362 $29 $0 $59 $450 $1 14.6 Machine Shop $0 $393 $251 $0 $0 $644 $51 $0 $104 $799 $1 14.7 Warehouse $0 $254 $153 $0 $0 $406 $32 $0 $66 $504 $1 14.8 Other Buildings & Structures $0 $76 $55 $0 $0 $131 $10 $0 $21 $163 $0 14.9 Waste Treating Building & Str. $0 $297 $531 $0 $0 $828 $69 $0 $134 $1,031 $2 SUBTOTAL 14. $0 $3,996 $4,263 $0 $0 $8,259 $671 $0 $1,340 $10,270 $19

TOTAL COST $211,369 $18,839 $54,950 $0 $0 $285,158 $24,302 $0 $38,816 $348,275 $637 TOTAL PLANT COST SUMMARYCost and Performance Baseline

- Volume 3c (NGCC Cases)

94 

### Exhibit 3

- 27 Case L31A Owner’s Costs

Owner's Costs $x1000 $/kW Preproduction Costs 6 Months Fixed O&M $3,056 $6 1 Month Variable O&M $517 $1 25% of 1 Months Fuel Cost at 100% CF $4,799 $9 2% of TPC $6,966 $13 Total $15,337 $28
Inventory Capital 60 day supply of consumables at 100% CF $174 $0 0.5% of TPC (spare parts) $1,741 $3 Total $1,915 $4
Initial Cost for Catalyst and Chemicals $0 $0 Land $300 $1 Other Owner's Costs $52,241 $96 Financing Costs $9,403 $17

Total Owner's Costs $79,197 $145 Total Overnight Cost (TOC) $427,473 $782 TASC Multiplier 1.075 Total As-Spent Cost (TASC) $459,533 $840Cost and Performance Baseline

- Volume 3c (NGCC Cases)

95 

### Exhibit 3

- 28 Case L31A Initial and Annual Operating and Maintenance Cost Summar y

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case L31A - 1x547 MWnet 2x1 7FB NGCC Heat Rate-net (Btu/kWh): 6,743 MWe-net: 547 Capacity Factor (%): 85 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total

Skilled Operator 1.0 1.0 Operator 2.0 2.0 Foreman 1.0 1.0 Lab Tech's, etc. 1.0 1.0 TOTAL-O.J.'s 5.0 5.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $1,972,971 $3.607 Maintenance Labor Cost $2,916,909 $5.333 Administrative & Support Labor $1,222,470 $2.235 Property Taxes and Insurance $6,965,508 $12.734 TOTAL FIXED OPERATING COSTS $13,077,858 $23.909 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $4,375,364 $0.00107

Consumables Consumption Unit Initial Initial /Day Cost Cost
Water (/1000 gallons) 0.00 826.56 1.08 $0 $277,385 $0.00007

Chemicals

MU & WT Chem. (lbs) 0.00 4924.41 0.17 $0 $264,413 $0.00006 MEA Solvent (ton) 0.00 0.00 2249.89 $0 $0 $0.00000 Activated Carbon (lb) 0.00 0.00 1.05 $0 $0 $0.00000 Corrosion Inhibitor 0.00 0.00 0.00 $0 $0 $0.00000 SCR Catalyst (m3) w/equip. 0.07 5775.94 $0 $123,497 $0.00003 Ammonia (19% NH3) ton 0.00 5.80 129.80 $0 $233,416 $0.00006 Subtotal Chemicals $0 $621,326 $0.00015

Other

Supplemental Fuel (MBtu) 0.00 0.00 0.00 $0 $0 $0.00000 Gases, N2 etc.(/100scf) 0.00 0.00 0.00 $0 $0 $0.00000 L.P. Steam (/1000 pounds) 0.00 0.00 0.00 $0 $0 $0.00000 Subtotal Other $0 $0 $0.00000
Waste Disposal

Flyash (ton) 0.00 0.00 0.00 $0 $0 $0.00000 Bottom Ash (ton) 0.00 0.00 0.00 $0 $0 $0.00000 Subtotal Waste Disposal $0 $0 $0.00000
By-products

Sulfur (tons) 0.00 0.00 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $0 $5,274,074 $0.00129

Fuel (MMBtu) 0 88,519 7.13 $0 $195,789,067 $0.04807Cost and Performance Baseline

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96 

### 3.4 CASES S31B AND L31B PROCESS DESCRIPTION
The plant configuration for these cases is the same as cases S31A and L31A with the exception being the Econamine FG Plus CDR technology was added for CO 2 

### capture. The nomin al net output decreases because the C T fixes the output and the CDR facility significantly increases the auxiliary power load.

A BFD is shown in Exhibit 3

- 29

. Flue gas from the heat recovery system is processed in the E conamine system before exiting the stack. Sinc e the CDR facility process description was provided in Section 3.1.5 , it is not repeated here.

The tables in Exhibit 3

- 30 and Exhibit 3

- 41
, for cases S31B and L31B respective ly, 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

.

Exhibit 3

- 29 Cas es S31B and L31B Pr ocess Flow Diagram, NGCC with CO 2 

### CaptureCost and Performance Baseline

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97 

### The balance of Section 3.4 is organized as follows:

**•** Performance Results

- provides the main modeling results including the performance summary, environmental perf ormance, water balance, mass and energy balance diagrams
, and energy balance table.

**•** Major Equipment List

- provides an itemized list of major equipment with account codes that correspond to the cos t accounts in the Cost Estimating section.

**•** Cost Estimating

- provides a summary of capital and operating costs.

3.4.1 Case S31B

– Performance Results
The pl ant produces a net output of 435 MW a t a net plant efficiency of 42.9 percent (HHV basis).
Major stream flows are described in Exhibit 3

- 30 and overall plant performance is summarized in Exhibit 3

- 31
, which includes auxiliary power requirements.Cost and Performance Baseline

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98 

### Exhibit 3

- 30 Case S31B Stream Table, NGCC with CO 2 

### Capture

1 2 3 4 5 6 7 8 9 10 11 12 13 V-L Mole Fraction

Ar 0.0093 0.0000 0.0089 0.0089 0.0098 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CH 4 0.0000 0.9310 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 C 2 H 6 0.0000 0.0320 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 C 3 H 8 0.0000 0.0070 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 C 4 H 10 0.0000 0.0040 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 2 0.0003 0.0100 0.0413 0.0413 0.0045 0.9893 1.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 O 0.0064 0.0000 0.0849 0.0849 0.0385 0.0107 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 N 2 0.7759 0.0160 0.7451 0.7451 0.8161 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 0.2081 0.0000 0.1198 0.1198 0.1312 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 98,174 4,020 102,311 102,311 93,416 3,840 3,799 16,400 16,400 19,410 5,646 5,646 11,850 V-L Flowrate (kg/hr) 2,836,748 69,653 2,906,401 2,906,401 2,647,417 167,925 167,182 295,457 295,457 349,679 101,713 101,713 213,479 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 6 38 628 142 30 21 51 152 151 566 32 32 32 Pressure (MPa, abs) 0.09 3.10 0.09 0.09 0.09 0.16 15.27 0.51 0.49 16.65 0.005 0.005 0.90 Enthalpy (kJ/kg) A 15.26 46.30 832.10 284.57 91.45 26.65 -164.90 2,746.79 635.72 3,472.36 2,354.18 2,354.18 135.69 Density (kg/m 3 ) 1.1 22.2 0.4 0.7 1.0 2.9 653.5 2.7 915.8 47.7 0.04 0.04 995.4 V-L Molecular Weight 28.895 17.328 28.408 28.408 28.340 43.731 44.010 18.015 18.015 18.015 18.015 18.015 18.015

V-L Flowrate (lb mol /hr) 216,437 8,862 225,556 225,556 205,947 8,466 8,375 36,157 36,157 42,792 12,447 12,447 26,124 V-L Flowrate (lb/hr) 6,253,958 153,559 6,407,517 6,407,517 5,836,555 370,210 368,573 651,371 651,371 770,911 224,240 224,240 470,640 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 42 100 1,163 288 85 69 124 306 304 1,050 90 90 90 Pressure (psia) 13.0 450.0 13.5 13.0 13.0 23.5 2,214.7 73.5 71.0 2,414.7 0.7 0.7 130.0 Enthalpy (Btu/lb) A 6.6 19.9 357.7 122.3 39.3 11.5 -70.9 1,180.9 273.3 1,492.8 1,012.1 1,012.1 58.3 Density (lb/ft 3 ) 0.070 1.384 0.022 0.046 0.063 0.183 40.800 0.169 57.172 2.977 0.002 0.002 62.141 A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Baseline

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99 

### Exhibit 3

- 31 Case S31B Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe)
Gas Turbine Power 335,300 Steam Turbine Power 134,700 TOTAL POWER, kWe 470,000 AUXILIARY LOAD SUMMARY, kWe Condensate Pumps 70 Boiler Feedwater Pumps 2,440 Amine System Auxiliaries 8,800 CO 2 

### Compression 13,950 Circulating Water Pump 3,400 Ground Water Pumps 280 Cooling Tower Fans 2,210 Air Cooled Condenser Fan 1,040 SCR 10 Gas Turbine Auxiliaries 700 Steam Turbine Auxiliaries 100 Miscellaneous Balance of Plant 1 

### 500 Transformer Losses 1,440 TOTAL AUXILIARIES, kWe 34,940 NET POWER, kWe 435,060 Net Plant Efficiency (HHV) 42.9% Net Plant Efficiency (LHV) 47.5% Net Plant Heat Rate (HHV), kJ/kWhr (Bt u/kWhr) 8,397 (7,959) Net Plant Heat Rate (LHV), kJ/kWhr (Btu/kWhr) 7,571 (7,176) CONDENSER COOLING DUTY, 10 6 

### kJ/h (10 6 

### Btu/h) 464 (440) CONSUMABLES Natural Gas Feed Flow, kg/hr (lb/hr) 69,653 (153,559) Thermal Input (HHV), kW th 

### 1,014,787 Thermal In put (LHV) , kW th 

### 914,961 Raw Water Withdrawal, m 3 

### /min (gpm) 11.8 (3,107) Raw Water Consumption, m 3 

### /min (gpm) 8.8 (2,3 15 )

1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loadsCost and Performance Baseline

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100 

### Environmental Performance
The environmental ta rgets for emissions of NOx, SO 2 

### , and PM were presented in Section 2.3 . A summary of the plant air emissions for Case S31B is presented in Exhibit 3

- 32

. Exhibit 3

- 32 Case S31B Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 85% CF kg/MWh (lb/MWh)

SO 2 

### Negligible Negligible Negligible NO x 0.004 (0.009) 106 (117) 0.030 ( 0 .067 )
Particulates Negligible Negligible Negligible Hg Negligible Negligib le Negligible CO 2 

### 5.1 (11.8 ) 138,315 ( 152,466 ) 40 (87 )
CO 2 1 

### 43 (94 )

1 CO 2 emissions based on net power instead of gross power


### The operation of the modern, state

- of

- the

- art gas turbine fueled by natural gas, coupled to a HRSG, results in very low level s of NOx emissions and negligible levels of SO 2 

### , particulate
, and Hg emissions. As noted in Section 2.3 , if the fuel contains the maximum amount of sulfur compounds allowed in pipeline natural gas, the NGCC SO 2 

### emissions would be 9.7 tonnes/yr ( 10.7 tons/yr) at 85 percent CF , or 0.00073 kg/GJ ( 0.00 17 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.

The carbon balance is shown in Exhibit 3

- 33

. The carbon input to the plant consists of carbon in the air in addition to carbon in the natural gas. One hundred percent carbon conversion is assumed since carbon conversion for NGCC plants is typically about 99.9 percent.

Carb on in the air is not neglected here since the model accounts for air components throughout. Carbon leaves the plant as CO 2 

### in the stack gas. 90.7 percent of carbon is separated in the MEA process , compressed and sent to seque s t r ation, reducing CO 2 

### emissi ons to 94 lb/ net

- MWh. 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 natural gas , represented by the following fraction:
(Carbon in CO 2 

### Product)/ (Carbon in the Natural Gas ) *100 or 100,590 /( 110,914 ) *100 or 90.7 percentCost and Performance Baseline

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101 

### Exhibit 3

- 33 Cases S31B Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)
Natural Gas 50,310 (110,914) Stack Gas 5,070 (11,177) Air (CO 2 

### ) 38 7 (852) CO 2 

### Product 45,627 (100,590)
Total 50,696 (111,766) Total 50,696 (111,766)

Exhibit 3

- 34 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, such as BFW blowdown, 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 f rom 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

a ny and all purposes, such as 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, incorpo rated 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 3

- 34 Cas e S31B 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 (11) 0 (0) 0.04 (11) 0 (0) 0.0 4 (11)

Con denser Makeup 0.08 (20) 0 (0) 0.08 (20) 0 (0) 0.08 (20)

BFW Makeup 0.08 (20) 0 (0) 0.08 (20)
Cooling Tower 13.23 (3 , 494) 1.61 (425) 11.62 (3 , 069) 2.97 (786) 8.64 (2 , 283)

BFW Blowdown 0 (0) 0.08 (20)

- 0.08 (

- 20)

Flue Gas Condensate 0 (0) 1 .51 (398)

- 1.51 (

- 398)

CO 2 

### Product Condensate 0 (0) 0.03 (7)

- 0.03 (

- 7)

Total 13.35 (3,526) 1.61 (425) 11.74 (3,100) 2.97 (786) 8.76 (2 , 315)Cost and Performance Baseline

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102 

### Heat and Mass Balance Diagrams A heat and mass balance diagram is shown for the NGCC in Exhibit 3

- 35

. An overall plant energy balance is provided in tabular form in Exhibit 3

- 36 . The power out is the combined CT and steam turbine power prior to generator losses. The power at the generator terminals (sh own in Exhibit 3

- 31 ) is calculated by multiplying the power out by a combined generator efficiency of 98.4 percent.Cost and Performance Baseline

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103 

### Exhibit 3

- 35 Case S31B Hea t and Mass Balance, NGCC with CO 2 

### Ca pture

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 T 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 S 31 B 2 X ADVANCED F

- CLASS GT 2400 / 1050 / 1050

DWG

. NO

.

LROF

- HMB

- CS

- S 31 B

- PG

- 1 Flue Gas

368
, 573 W

123

. 8 T 2
, 214

. 7 P

CO 2 PRODUCT

A MBIENT

A IR 1 6
, 253
, 958 W 42

. 0 T 13

. 0 P 6

. 5 H CO 2 COMPRESSION ( INTERSTAGE COOLING ) & DRYING 370
, 210 W

69

. 0 T 23

. 5 P 11

. 5 H KNOCKOUT

WATER 198
, 938 W

85

. 2 T 13

. 0 P 8

. 7 H Gross Plant Power : 470 MWe Auxiliary Load : 35 MWe Net Plant Power : 435 MWe Net Plant Efficiency
, HHV : 42

. 9 % Net Plant Heat Rate : 7 , 959 Btu / kWh A DVANCED F C LASS G AS T URBINES

COMBUSTOR N ATURAL GAS 153
, 559 W

100

. 0 T 450

. 0 P 19

. 9 H 2

5 , 836
, 555 W 85

. 2 T 13

. 0 P 39

. 2 H 6
, 407
, 517 W 287

. 9 T 13

. 0 P 122

. 3 H

6
, 407
, 517 W

1
, 163

. 2 T

13

. 5 P 357

. 7 H GENERATOR

CONDENSATE PUMPS8,801W1,302W

90

. 0 T 130

. 0 P 58

. 3 H 470
, 640 W

89

. 9 T 0

. 7 P 57

. 9 H

5 1
, 400 W 581

. 0 T 75

. 0 P 1
, 321

. 3 H 913
, 182 W

641

. 1 T 75

. 0 P 1
, 351

. 0 H 448
, 479 W 621

. 5 T 75

. 0 P 1
, 341

. 3 H

224
, 240 W 89

. 9 T 0

. 7 P 1
, 012

. 1 H 12 11 224
, 240 W 89

. 9 T 0

. 7 P 1
, 012

. 1 H

HOT WELL AIR

- COOLED CONDENSER CONDENSER

S TACK
4REBOILER CONDENSATE 13

CONDENSATE PUMPS S TEAM T URBINE MAKEUP 10
, 192 W

42

. 0 T 13

. 0 P 10

. 1 H

DOE / NETL

SC PC P LANT C ASE S 31 B

AIR INLET

FILTER 3

HP PUMP 470
, 640 W

253

. 0 T 100

. 0 P 221

. 9 HBLOWDOWN

84
, 707 W

300

. 1 T 95

. 0 P 269

. 4 H

155
, 798 W

300

. 7 T 400

. 0 P 270

. 7 H

778
, 698 W

305

. 3 T 2
, 540

. 0 P 279

. 3 H10,192WSTRIPPERABSORBER FLUE GAS ACID GAS

ECONAMINE FG + BLOWER

548
, 563 W 641

. 1 T 75

. 0 P 1
, 351

. 0 H WATER 1
, 638 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

651
, 371 W

306

. 2 T 73

. 5 P 1
, 180

. 9 H 89

. 9 T 0

. 7 P 1
, 012

. 1 H

9
, 569 W

470
, 640 W

96

. 3 T 120

. 0 P 64

. 5 H

Three Pressure Heat Recovery Steam Generator ( HRSG ) 743
, 251 W 1
, 055

. 0 T 360

. 0 P 1
, 553

. 4 H

A A 154
, 240 W 1
, 055

. 0 T 360

. 0 P 1
, 553

. 4 HHOT REHEAT

C OLD R EHEAT

743
, 251 W

588

. 0 T 390

. 0 P 1
, 300

. 7 H STEAM SEAL REGULATOR

83
, 860 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 TURBINE766,391W 2
, 654 W 1
, 050

. 0 T 2
, 414

. 7 P 1
, 492

. 8 H914,484WMAIN STEAM

770
, 911 W 1
, 050

. 0 T 2
, 414

. 7 P 1
, 492

. 8 H

6

7

8

9 10

10
, 969 W866W IP STEAM

548
, 563 W 303

. 9 T 73

. 5 P 273

. 3 H

IP PUMP

LP PUMP 651
, 371 W 303

. 9 T 71

. 0 P 273

. 3 HCost and Performance Baseline

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104 

### This page intentionally left blankCost and Performance Baseline

- Volume 3c (NGCC Cases)

105 

### Exhibit 3

- 36 Case S31B Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total
Heat In GJ/hr (MMBtu/hr)
Natural Gas 3,653 (3,463) 0.9 ( 0.9) 3,654 (3,463) GT Air 43.3 (41.0) 43 (41) Raw Water Withdrawal 16.4 (15.5) 16 (16 ) Auxiliary Power 126 (119) 126 (119)
Totals 3,653 (3,463) 60.6 (57.4 ) 126 (119) 3,840 (3,639) Heat Out GJ/hr (MMBtu/hr)
CO 2 

### - 27.6 (

- 26.1)

- 28 (

- 26) Coolin g Tower Blowdown 16.6 (15.7) 17 (16)

Econamine Losses 891.3 (844.8) 891 (845)
CO 2 

### Compression Intercooling 77.9 (73.9) 78 (74)

Stack Gas 242 (229) 242 (229) Condenser 464 (440) 464 (440)
Process Losses 1 

### 4 83 (4 58 ) 4 83 (4 58 )
Power 1,692 ( 1,604) 1,692 (1,604)
Totals 0 (0) 2,148 (2,036 ) 1,692 (1,604) 3,840 (3,639)

1 Process Losses are calculated by difference and reflect various turbine and other heat and work losses not modeled

in Aspen

.Cost and Performance Baseline

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106 

### 3.4.2 Case S31B

– Major Equipment List
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 3.4.3 . In general, the design condi tions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 FUEL HANDLING

N/A

ACCOUNT 2 FUEL AND SORBENT PREPARATION AND FEED

N/A

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS A ND EQUIPMENT
Equipment No. Description Type Design Condition Operating Qty (Spares)

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 609,456 liters (161,000 gal) 2 (0)

2 Condensate Pumps Vertical canned 1,968 lpm @ 110 m H 2 

### O (520 gpm @ 6 ,900 ft H 2 

### O) 2 (1)

3 Boiler Feedwater Pump Horizontal, split case, multi

- stage, centrifugal, with interstage bleed for IP and LP feedwater HP water: 3,255 lpm @ 2,103 m H 2 

### O (860 gpm @ 6,900 ft H 2 

### O)

2 (1) IP water: 644 lpm @ 283 m H 2 

### O (170 gpm @ 930 ft H 2 

### O) LP water: 341 lpm @ 24.4 m H 2 

### O (90 gpm @ 80 ft H 2 

### O)

4 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 (0)Cost and Performance Baseline

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### Equipment No. Description Type Design Condition Operating Qty (Spares)

5 Service Air Compressors Flooded Screw 13 m 3 

### /min @ 0.7 MPa (450 scfm @ 1 00 psig) 2 (1)

6 Instrument Air Dryers Duplex, regenerative 13 m 3 

### /min (450 scfm) 2 (1)

7 Closed Cycle Cooling Heat Exchangers Plate and frame 13 MMkJ/hr (13 MMBtu/hr) 2 (0)

8 Closed Cycle Cooling Water Pumps Horizontal centrifugal 5,300 lpm @ 21 m H 2 

### O (1,400 gpm @ 70 ft H 2 

### O) 2 (1)

9 Engine

- Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 107 m H 2 

### O (1,000 gpm @ 350 ft H 2 

### O) 1 (1)

10 Fire Service Booster Pump Two

- stage horizontal centrifugal 2,650 lpm @ 76 m H 2 

### O (700 gpm @ 250 ft H 2 

### O) 1 (1)

11 Raw Water Pumps Stainless steel, single suction 6,435 lpm @ 18 m H 2 

### O (1,700 gpm @ 60 ft H 2 

### O) 2 (1)

12 Filtered Water Pumps Stainless steel, single suction 151 lpm @ 49 m H 2 

### O (40 gpm @ 160 ft H 2 

### O) 2 (1)

13 Filtered Water Tank Vertical, cylindrical 143, 847 liter (38,000 gal) 1 (0)

14 Makeup Water Demineralizer Multi

- media filter, cartridge filter, RO membrane assembly and electro

deionization unit 341 lpm (90 gpm) 1 (0)

1 5 Gas Pipeline Underground, coated carbon steel, wrapped cathodic protection 58 m 3 

### /min @ 3.1 MPa (2,033 acfm @ 450 psia) 41 cm (16 in) standard wall pipe 16 km (0)Cost and Performance Baseline

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108 

### Equipment No. Description Type Design Condition Operating Qty (Spares)

16 Gas Metering Station -- 58 m 3 

### /min (2,033 acfm) 1 (0)

1 7 Liquid Waste Treatment System 10 years, 24

- hour storm 1 (0)

ACCOUNT 4 GASIFIER, BOILER AND ACCESSORIES

N/A

ACCOUNT 5 FLUE GAS CLEANUP

N/A

ACCOUNT 6 COMBUSTION TURBINE GENERATORS AND AUXILIARIES

Equipment No. Description Type Design Condition Operating Qty (Spares)

1 Gas Turbine Advanced F class w/ dry low

- NOx burner 170 MW 2 (0)

2 Gas Turbine Generato r TEWAC 190 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 2 (0)



### ACCOUNT 7 WASTE HEAT BOILER, DUCTING, AND STACK

Equipment No. Description Type Design Condition Operating Qty (Spares)

1 Stack CS plate, type 409SS liner 46 m (150 ft) high x 6.5 m (21 ft) diamete r 2 (0)

2 Heat Recovery Steam Generator Drum, multi

pressure with economizer section and integral deaerator Main steam

- 192,324 kg/hr, 16.5 MPa/566°C

(424,001 lb/hr, 2,400 psig/1,050°F) 2 (0) Reheat steam

- 223,903 kg/hr, 2.4 MPa/566°C

(493,620 lb/h r, 345 psig/1,050°F)

3 SCR Reactor Space for spare layer 1,456,033 kg/h (3,210,000 lb/h) 2 (0)Cost and Performance Baseline

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109 

### Equipment No. Description Type Design Condition Operating Qty (Spares)

4 SCR Catalyst

-- Space available for an additional catalyst layer 1 layer (0)

5 Dilution Air Blowers Centrifugal 10 m 3 

### /min @ 107 cm WG (350 scfm @ 42 in WG ) 2 (1)

6 Ammonia Feed Pump Centrifugal 3.8 lpm @ 91 m H 2 

### O (1 gpm @ 300 ft H 2 

### O) 2 (1)

7 Ammonia Storage Tank Horizontal tank 60,567 liter (16,000 gal) 1 (0)

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment No. Description Type Design Condit ion Operating Qty (Spares)

1 Steam Turbine Tandem compound, HP, IP, and two

- flow LP turbines 142 MW 16.5 MPa/566°C/566°C (2,400

psig/ 1050°F/1050°F) 1 (0)

2 Steam Turbine Generator Hydrogen cooled, static excitation 160 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 1 (0)

3 Steam Bypass One per HRSG 50% steam flow @ design steam conditions 2 (0)

4 Surface Condenser Single pass, divided waterbox including vacuum pumps 250 MMkJ/hr, (240 MMBtu/hr), Inlet H 2 

### O temperature 9°C (48°F), H 2 

### O temperature rise 11°C (20°F ) 1 (0)

5 Air

- cooled Condenser --- 250 GJ/hr (240 MMBtu/hr), Condensing temperature 32°C (90°F), Ambient temperature 6°C (42°F) 1 (0)Cost and Performance Baseline

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110 

### ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type Design Condition Operating Qty (Spares)

1 Circulating Wa ter Pumps Vertical, wet pit 340,690 lpm @ 30.5 m (90,000 gpm @ 100 ft) 2 (1)

2 Cooling Tower Evaporative, mechanical draft, multi

- cell 3°C (37°F) wet bulb / 9°C (48°F) CWT / 20°C

(68°F) HWT 539 MMkJ/hr (511 MMBtu/hr) heat load 1 (0)

ACCOUNT 10 ASH/S PENT SORBENT RECOVERY AND HANDLING

N/A

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type L12A Design Condition Operating Qty (Spares)

1 CTG Transformer Oil

- filled 24 kV/345 kV, 190 MVA, 3

- ph, 60 Hz 2 (0)

2 STG Transformer Oil

- filled 24 kV/345 kV, 130 MVA, 3

- ph, 60 Hz 1 (0)

3 High Voltage Auxiliary Transformer Oil

- filled 345 kV/13.8 kV, 8 MVA, 3

- ph, 60 Hz 2 (1)

4 Medium Voltage Transformer Oil

- filled 24 kV/4.16 kV, 22 MVA, 3

- ph, 60 Hz 1 (1)

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 3 MVA, 3

- ph, 60 Hz 1 (1)

6 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 2 (0)Cost and Performance Baseline

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### Equipment No. Description Type L12A Design Condition Operating Qty (Spares)

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self

- cooled 24 kV, 3

- p h, 60 Hz 1 (0)

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 1 (1)

9 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 1 (1)

10 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3

- ph, 60 Hz 1 (0)

ACCOUNT 12 IN STRUMENTATION AND CONTROL
Equipment No. Description Type L12A Design Condition Operating Qty (Spares)

1 DCS

- Main Control Monitor/keyboard, Operator printer, Engineering printer Operator stations/printers and engineering stations/printers 1 (0)

2 DCS

- Processor Microprocessor with redundant input/output N/A 1 (0)

3 DCS

- Data Highway Fiber optic Fully redundant, 25% spare 1 (0)Cost and Performance Baseline

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### 3.4.3 Case S31B

– Cost Estimating
The cost estimating methodology was described previously in Section 2 .6

. Exhibit 3

- 37 shows the total plant capital cost summary organized by cost account and Exhibit 3

- 38 shows a more detailed breakdown of the capital costs. Exhibit 3

- 39 itemi zes the owner’s costs and Exhibit 3

- 40 shows the initial and annual O&M costs.

The estimated T O C of the NGC C with CO 2 

### capture is $ 1,6 07 /kW. P rocess contingency accounts for 3. 9 percent of the TOC . The project contingency is 10. 9 percent of T O C. The COE
, including CO 2 

### TS&M costs of 3.4 mills/kWh, is 92

. 9 mills/kWh.Cost and Performance Baseline

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### Exhibit 3

- 37 Case S31B Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-19 Project: Low Rank Western Coal Baseline Study

Case: Case S31B - 1x435 MWnet 2x1 7FB NGCC w/ CO2 Capture Plant Size: 435.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2 COAL & SORBENT PREP & FEED $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

3 FEEDWATER & MISC. BOP SYSTEMS $22,829 $4,396 $6,973 $0 $0 $34,198 $2,888 $0 $5,963 $43,049 $99

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4-4.9 Other gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A GAS CLEANUP & PIPING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B CO2 REMOVAL & COMPRESSION $115,518 $0 $35,189 $0 $0 $150,707 $12,909 $26,586 $38,040 $228,242 $525

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $75,295 $0 $4,804 $0 $0 $80,099 $6,800 $0 $8,690 $95,589 $220 6.2-6.9 Combustion Turbine Other $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $4 SUBTOTAL 6 $75,295 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,491 $224

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $102 7.2-7.9 SCR System, Ductwork and Stack $1,006 $851 $978 $0 $0 $2,835 $241 $0 $505 $3,582 $8 SUBTOTAL 7 $33,963 $851 $5,257 $0 $0 $40,071 $3,412 $0 $4,546 $48,029 $110

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $17,924 $0 $3,200 $0 $0 $21,124 $1,816 $0 $2,294 $25,234 $58 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $17,489 $593 $6,554 $0 $0 $24,636 $2,265 $0 $4,811 $31,712 $73 SUBTOTAL 8 $35,413 $593 $9,754 $0 $0 $45,760 $4,081 $0 $7,105 $56,946 $131

9 COOLING WATER SYSTEM $7,217 $5,431 $4,875 $0 $0 $17,523 $1,456 $0 $2,686 $21,664 $50

10 ASH/SPENT SORBENT HANDLING SYS $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

11 ACCESSORY ELECTRIC PLANT $19,399 $5,344 $11,597 $0 $0 $36,341 $2,798 $0 $4,235 $43,373 $100

12 INSTRUMENTATION & CONTROL $6,097 $626 $5,066 $0 $0 $11,789 $982 $589 $1,531 $14,891 $34

13 IMPROVEMENTS TO SITE $1,657 $900 $4,409 $0 $0 $6,966 $616 $0 $1,516 $9,098 $21

14 BUILDINGS & STRUCTURES $0 $3,767 $3,888 $0 $0 $7,656 $621 $0 $1,242 $9,519 $22

TOTAL COST $317,388 $22,627 $92,556 $0 $0 $432,571 $36,686 $27,175 $75,870 $572,302 $1,315 TOTAL PLANT COST SUMMARYCost and Performance Baseline

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### Exhibit 3

- 38 Ca se S31B Total Plant Cost Details

Client: USDOE/NETL Report Date: 2009-Oct-19 Project: Low Rank Western Coal Baseline Study

Case: Case S31B - 1x435 MWnet 2x1 7FB NGCC w/ CO2 Capture Plant Size: 435.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.2 Coal Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.3 Coal Conveyors & Yd Crush $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.4 Other Coal Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 1. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.3 Slurry Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 2. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,247 $2,315 $1,904 $0 $0 $6,466 $533 $0 $1,050 $8,049 $19 3.2 Water Makeup & Pretreating $1,776 $186 $928 $0 $0 $2,889 $246 $0 $627 $3,763 $9 3.3 Other Feedwater Subsystems $1,025 $346 $291 $0 $0 $1,662 $134 $0 $269 $2,065 $5 3.4 Service Water Systems $210 $432 $1,402 $0 $0 $2,044 $179 $0 $445 $2,668 $6 3.5 Other Boiler Plant Systems $1,408 $546 $1,264 $0 $0 $3,218 $273 $0 $524 $4,015 $9 3.6 Natural Gas, incl. pipeline $14,640 $453 $395 $0 $0 $15,488 $1,313 $0 $2,520 $19,320 $44 3.7 Waste Treatment Equipment $641 $0 $365 $0 $0 $1,006 $88 $0 $219 $1,313 $3 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $883 $118 $424 $0 $0 $1,424 $123 $0 $309 $1,857 $4 SUBTOTAL 3. $22,829 $4,396 $6,973 $0 $0 $34,198 $2,888 $0 $5,963 $43,049 $99 4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4 LT Heat Recovery & FG Saturation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.5 Misc. Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Other Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.8 Major Component Rigging $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 

### TOTAL PLANT COST SUMMARYCost and Performance Baseline

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### Exhibit 3

- 38 Case S31B Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-19 Project: Low Rank Western Coal Baseline Study

Case: Case S31B - 1x435 MWnet 2x1 7FB NGCC w/ CO2 Capture Plant Size: 435.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 MDEA-LT AGR $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.2 Elemental Sulfur Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.3 Mercury Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.4 COS Hydrolysis $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.5 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Fuel Gas Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.9 HGCU Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $101,984 $0 $30,944 $0 $0 $132,928 $11,386 $26,586 $34,180 $205,079 $471 5B.2 CO2 Compression & Drying $13,534 $0 $4,246 $0 $0 $17,779 $1,523 $0 $3,861 $23,163 $53 SUBTOTAL 5. $115,518 $0 $35,189 $0 $0 $150,707 $12,909 $26,586 $38,040 $228,242 $525 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $75,295 $0 $4,804 $0 $0 $80,099 $6,800 $0 $8,690 $95,589 $220 6.2 Combustion Turbine Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $4 SUBTOTAL 6. $75,295 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,491 $224 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $102 7.2 SCR System $1,006 $422 $593 $0 $0 $2,022 $174 $0 $329 $2,525 $6 7.3 Ductwork $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.4 Stack $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.9 HRSG,Duct & Stack Foundations $0 $428 $385 $0 $0 $813 $68 $0 $176 $1,057 $2 SUBTOTAL 7. $33,963 $851 $5,257 $0 $0 $40,071 $3,412 $0 $4,546 $48,029 $110 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $17,924 $0 $3,200 $0 $0 $21,124 $1,816 $0 $2,294 $25,234 $58 8.2 Turbine Plant Auxiliaries $131 $0 $294 $0 $0 $426 $37 $0 $46 $510 $1 8.3 Condenser & Auxiliaries $1,339 $0 $400 $0 $0 $1,739 $149 $0 $189 $2,077 $5 8.3b Air Cooled Condenser $12,273 $0 $2,461 $0 $0 $14,733 $1,473 $0 $3,241 $19,448 $45 8.4 Steam Piping $3,746 $0 $2,463 $0 $0 $6,208 $476 $0 $1,003 $7,687 $18 8.9 TG Foundations $0 $593 $936 $0 $0 $1,529 $130 $0 $332 $1,990 $5 SUBTOTAL 8. $35,413 $593 $9,754 $0 $0 $45,760 $4,081 $0 $7,105 $56,946 $131 9 COOLING WATER SYSTEM 9.1 Cooling Towers $5,103 $0 $653 $0 $0 $5,756 $490 $0 $625 $6,871 $16 9.2 Circulating Water Pumps $1,500 $0 $83 $0 $0 $1,583 $119 $0 $170 $1,872 $4 9.3 Circ.Water System Auxiliaries $117 $0 $16 $0 $0 $133 $11 $0 $14 $159 $0 9.4 Circ.Water Piping $0 $3,426 $830 $0 $0 $4,256 $344 $0 $690 $5,290 $12 9.5 Make-up Water System $269 $0 $359 $0 $0 $628 $54 $0 $102 $784 $2 9.6 Component Cooling Water Sys $227 $272 $181 $0 $0 $681 $57 $0 $111 $848 $2 9.9 Circ.Water System Foundations $0 $1,733 $2,753 $0 $0 $4,486 $380 $0 $973 $5,840 $13 SUBTOTAL 9. $7,217 $5,431 $4,875 $0 $0 $17,523 $1,456 $0 $2,686 $21,664 $50 TOTAL PLANT COST SUMMARYCost and Performance Baseline

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### Exhibit 3

- 38 Case S31B Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-19 Project: Low Rank Western Coal Baseline Study

Case: Case S31B - 1x435 MWnet 2x1 7FB NGCC w/ CO2 Capture Plant Size: 435.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.7 Ash Transport & Feed Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.9 Ash/Spent Sorbent Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 10. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $5,116 $0 $3,074 $0 $0 $8,190 $694 $0 $666 $9,550 $22 11.2 Station Service Equipment $1,906 $0 $161 $0 $0 $2,066 $171 $0 $168 $2,405 $6 11.3 Switchgear & Motor Control $2,349 $0 $399 $0 $0 $2,748 $228 $0 $298 $3,274 $8 11.4 Conduit & Cable Tray $0 $1,122 $3,460 $0 $0 $4,583 $397 $0 $747 $5,726 $13 11.5 Wire & Cable $0 $3,574 $2,195 $0 $0 $5,769 $372 $0 $921 $7,062 $16 11.6 Protective Equipment $0 $533 $1,814 $0 $0 $2,347 $205 $0 $255 $2,808 $6 11.7 Standby Equipment $94 $0 $86 $0 $0 $181 $15 $0 $20 $216 $0 11.8 Main Power Transformers $9,934 $0 $128 $0 $0 $10,062 $683 $0 $1,074 $11,819 $27 11.9 Electrical Foundations $0 $114 $281 $0 $0 $395 $34 $0 $86 $515 $1 SUBTOTAL 11. $19,399 $5,344 $11,597 $0 $0 $36,341 $2,798 $0 $4,235 $43,373 $100 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $775 $0 $484 $0 $0 $1,259 $107 $63 $214 $1,643 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $232 $0 $139 $0 $0 $370 $31 $19 $63 $483 $1 12.7 Computer & Accessories $3,708 $0 $111 $0 $0 $3,819 $314 $191 $432 $4,756 $11 12.8 Instrument Wiring & Tubing $0 $626 $1,196 $0 $0 $1,822 $137 $91 $308 $2,358 $5 12.9 Other I & C Equipment $1,382 $0 $3,136 $0 $0 $4,519 $393 $226 $514 $5,651 $13 SUBTOTAL 12. $6,097 $626 $5,066 $0 $0 $11,789 $982 $589 $1,531 $14,891 $34 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $89 $1,768 $0 $0 $1,856 $165 $0 $404 $2,425 $6 13.2 Site Improvements $0 $811 $1,008 $0 $0 $1,819 $161 $0 $396 $2,376 $5 13.3 Site Facilities $1,657 $0 $1,634 $0 $0 $3,291 $291 $0 $716 $4,297 $10 SUBTOTAL 13. $1,657 $900 $4,409 $0 $0 $6,966 $616 $0 $1,516 $9,098 $21 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $236 $125 $0 $0 $361 $28 $0 $58 $447 $1 14.2 Steam Turbine Building $0 $1,544 $2,056 $0 $0 $3,600 $296 $0 $584 $4,480 $10 14.3 Administration Building $0 $449 $305 $0 $0 $754 $60 $0 $122 $936 $2 14.4 Circulation Water Pumphouse $0 $143 $71 $0 $0 $214 $17 $0 $35 $265 $1 14.5 Water Treatment Buildings $0 $383 $350 $0 $0 $733 $59 $0 $119 $911 $2 14.6 Machine Shop $0 $390 $249 $0 $0 $639 $51 $0 $103 $793 $2 14.7 Warehouse $0 $252 $152 $0 $0 $404 $32 $0 $65 $501 $1 14.8 Other Buildings & Structures $0 $75 $55 $0 $0 $130 $10 $0 $21 $162 $0 14.9 Waste Treating Building & Str. $0 $295 $527 $0 $0 $822 $68 $0 $133 $1,023 $2 SUBTOTAL 14. $0 $3,767 $3,888 $0 $0 $7,656 $621 $0 $1,242 $9,519 $22

TOTAL COST $317,388 $22,627 $92,556 $0 $0 $432,571 $36,686 $27,175 $75,870 $572,302 $1,315 TOTAL PLANT COST SUMMARYCost and Performance Baseline

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### Exhibit 3

- 39 Case S31B Owner’s Costs

Owner's Costs $x1000 $/kW Preproduction Costs 6 Months Fixed O&M $4,197 $10 1 Month Variable O&M $844 $2 25% of 1 Months Fuel Cost at 100% CF $4,505 $10 2% of TPC $11,446 $26 Total $20,992 $48
Inventory Capital 60 day supply of consumables at 100% CF $441 $1 0.5% of TPC (spare parts) $2,862 $7 Total $3,303 $8
Initial Cost for Catalyst and Chemicals $755 $2 Land $300 $1 Other Owner's Costs $85,845 $197 Financing Costs $15,452 $36

Total Owner's Costs $126,647 $291 Total Overnight Cost (TOC) $698,949 $1,607 TASC Multiplier 1.078 Total As-Spent Cost (TASC) $753,467 $1,732Cost and Performance Baseline

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### Exhibit 3

- 40 Case S31B Initial and Annual Operating and Maintenance Cost Summary

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case S31B - 1x435 MWnet 2x1 7FB NGCC w/ CO2 Capture Heat Rate-net (Btu/kWh): 7,959 MWe-net: 435 Capacity Factor (%): 85 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total

Skilled Operator 1.0 1.0 Operator 3.3 3.3 Foreman 1.0 1.0 Lab Tech's, etc. 1.0 1.0 TOTAL-O.J.'s 6.3 6.3 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $2,497,781 $5.741 Maintenance Labor Cost $4,216,800 $9.692 Administrative & Support Labor $1,678,645 $3.858 Property Taxes and Insurance $11,446,039 $26.309 TOTAL FIXED OPERATING COSTS $19,839,265 $45.601 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $6,325,200 $0.00195

Consumables Consumption Unit Initial Initial /Day Cost Cost
Water (/1000 gallons) 0.00 2,229.12 1.08 $0 $748,070 $0.00023

Chemicals

MU & WT Chem.(lbs) 0.00 13,280.45 0.17 $0 $713,086 $0.00022 MEA Solvent (ton) 316.29 0.44 2,249.89 $711,622 $310,049 $0.00010 Activated Carbon (lb) 0.00 530.59 1.05 $0 $172,875 $0.00005 Corrosion Inhibitor 0.00 0.00 0.00 $43,332 $2,063 $0.00000 SCR Catalyst (m3) w/equip. 0.06 5,775.94 $0 $116,099 $0.00004 Ammonia (19% NH3) (ton) 0.00 5.45 129.80 $0 $219,434 $0.00007 Subtotal Chemicals $754,953 $1,533,607 $0.00047

Other

Supplemental Fuel (MBtu) 0.00 0.00 0.00 $0 $0 $0.00000 Gases,N2 etc. (/100scf) 0.00 0.00 0.00 $0 $0 $0.00000 L.P. Steam (/1000 pounds) 0.00 0.00 0.00 $0 $0 $0.00000 Subtotal Other $0 $0 $0.00000
Waste Disposal

Flyash (ton) 0.00 0.00 0.00 $0 $0 $0.00000 Bottom Ash (ton) 0.00 0.00 0.00 $0 $0 $0.00000 Subtotal Waste Disposal $0 $0 $0.00000
By-products

Sulfur (tons) 0.00 0.00 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $754,953 $8,606,876 $0.00266

Fuel (MMBtu) 0 83,103 7.13 $0 $183,810,997 $0.05674Cost and Performance Baseline

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### 3.4.4 Case L31B

– Performance Results
The pl ant p roduces a net output of 465 MW a t a net plant efficiency of 43 .0 percent (HHV basis).
Major stream flows are described in Exhibit 3

- 41 and overall plant performance is summarized in Exhibit 3

- 42 which in cludes auxiliary power requirements.Cost and Performance Baseline

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120 

### Exhibit 3

- 41 Case L31B Stream Table, NGCC without CO 2 

### Capture

1 2 3 4 5 6 7 8 9 10 11 12 13 V-L Mole Fraction

Ar 0.0093 0.0000 0.0089 0.0089 0.0098 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CH 4 0.0000 0.9310 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 C 2 H 6 0.0000 0.0320 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 C 3 H 8 0.0000 0.0070 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 C 4 H 10 0.0000 0.0040 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 2 0.0003 0.0100 0.0413 0.0413 0.0045 0.9893 1.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 O 0.0064 0.0000 0.0851 0.0851 0.0362 0.0107 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 N 2 0.7759 0.0160 0.7451 0.7451 0.8181 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 0.2081 0.0000 0.1196 0.1196 0.1314 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 104,424 4,282 108,830 108,830 99,118 4,090 4,046 17,468 17,468 20,569 5,985 5,985 12,543 V-L Flowrate (kg/hr) 3,017,333 74,190 3,091,523 3,091,523 2,811,389 178,860 178,068 314,689 314,689 370,555 107,817 107,817 225,973 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 4 38 628 142 30 21 51 152 151 566 32 32 32 Pressure (MPa, abs) 0.10 3.10 0.10 0.10 0.10 0.16 15.27 0.51 0.49 16.65 0.005 0.005 0.90 Enthalpy (kJ/kg) A 14.12 46.30 831.54 284.90 87.73 26.65 -164.90 2,746.79 635.72 3,472.36 2,354.20 2,354.20 135.69 Density (kg/m 3 ) 1.2 22.2 0.4 0.8 1.1 2.9 653.5 2.7 915.8 47.7 0.04 0.04 995.4 V-L Molecular Weight 28.895 17.328 28.407 28.407 28.364 43.731 44.010 18.015 18.015 18.015 18.015 18.015 18.015

V-L Flowrate (lb mol /hr) 230,215 9,439 239,928 239,928 218,518 9,017 8,920 38,510 38,510 45,347 13,194 13,194 27,653 V-L Flowrate (lb/hr) 6,652,082 163,560 6,815,642 6,815,642 6,198,051 394,318 392,574 693,772 693,772 816,935 237,696 237,696 498,185 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 40 100 1,162 288 85 69 124 306 304 1,050 90 90 90 Pressure (psia) 13.8 450.0 14.3 13.8 13.8 23.5 2,214.7 73.5 71.0 2,414.7 0.7 0.7 130.0 Enthalpy (Btu/lb) A 6.1 19.9 357.5 122.5 37.7 11.5 -70.9 1,180.9 273.3 1,492.8 1,012.1 1,012.1 58.3 Density (lb/ft 3 ) 0.074 1.384 0.023 0.049 0.067 0.183 40.800 0.169 57.172 2.977 0.002 0.002 62.141 A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Baseline

- Volume 3c (NGCC Cases)

121 

### Exhibit 3

- 42 Case L31B Plant Performance Summary
POWE R SUMMARY (Gross Power at Generator Terminals, kWe)
Gas Turbine Power 358,600 Steam Turbine Power 143,000 TOTAL POWER, kWe 501,600 AUXILIARY LOAD SUMMARY, kWe Condensate Pumps 70 Boiler Feedwater Pumps 2,580 Amine System Auxiliaries 9,400 CO 2 

### Comp ression 14,860 Circulating Water Pump 3,640 Ground Water Pumps 300 Cooling Tower Fans 2,230 Air Cooled Condenser Fan 1,040 SCR 10 Gas Turbine Auxiliaries 700 Steam Turbine Auxiliaries 100 Miscellaneous Balance of Plant 1 

### 500 Transformer Losses 1,53 0 TOTAL AUXILIARIES, kWe 36,960 NET POWER, kWe 464,640 Net Plant Efficiency (HHV) 43.0% Net Plant Efficiency (LHV) 47.7% Net Plant Heat Rate (HHV), kJ/kWhr (Btu/kWhr) 8,375 (7,938) Net Plant Heat Rate (LHV), kJ/kWhr (Btu/kWhr) 7,551 (7,157) CONDENSE R COOLING DUTY, 10 6 

### kJ/h (10 6 

### Btu/h) 496 (470) CONSUMABLES Natural Gas Feed Flow, kg/hr (lb/hr) 74,190 (163,560) Thermal Input (HHV), kW th 

### 1,080,880 Thermal Input (LHV) , kW th 

### 974,553 Raw Water Withdrawal, m 3 

### /min (gpm) 12.5 (3, 309 ) Raw Water Consump tion, m 3 

### /min (gpm) 9.3 (2,46 1 )

1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loadsCost and Performance Baseline

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122 

### Environmental Performance The environmental targets for emissions of NOx, SO 2 

### , and PM were presented in Section 2.3 . A summary of the plant air emissions for Case L31B is presented in Exhibit 3

- 43

. Exhibit 3

- 43 Case L31B Air Emissions
kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 85% CF kg/ MWh (lb/MWh)

SO 2 

### Negligible Negligible Negligible
NO x 0.004 (0.009) 113 (124) 0.030 ( 0 .066 )

Particulates Negligible Negligible Negligible
Hg Negligible Negligible Negligible

CO 2 

### 5.1 (11.8 ) 147,322 (162,395 ) 39 (87 )

CO 2 1 

### 43 (94 )

1 CO 2 emissions bas ed on net power instead of gross power


### The operation of the modern, state

- of

- the

- art gas turbine 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.

The low leve l of NOx production (2.5 ppmvd at 15 percent O 2 

### ) is achieved by utilizing a dry LNB coupled with an SCR system.

The carbon balance is shown in Exhibit 3

- 44

. The carbon input to the plant consists of carbon in the air in addition to carbon in the natural gas. One hundred percent carbon conversion is assumed since carbon conversion for NGCC plants is typically about 99.9 percent. Carbon in the air is not neglected here since the model accounts for air components throughout. Carbon leaves the plant as CO 2 

### in the stack gas. 90.7 percent of carbon is separated in the MEA process , compressed and sent to seque s t r ation, reducing CO 2 

### emissions to 94 lb/MWh of net power. 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 natural gas , represented by the following fraction:
(Carbon in CO 2 

### Product)/(Carbon in the Natural Gas)*100 or 107,140/(118,138) *100 or 90.7 percentCost and Performance Baseline

- Volume 3c (NGCC Cases)

123 

### Exhibit 3

- 44 Case L31B Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)
Natural Gas 53,586 (118,138) Stack Gas 5,400 (11,904)
Air (CO 2 

### ) 411 (907) CO 2 

### Product 48,598 (107,140)

Total 53,998 (119,044) Total 53,998 (119,044)

Exhibit 3

- 45 shows the overall water balance for the plant. The exhibit is presented in an identical manner as was for Case S31B.

Exhibit 3

- 45 Case L31B 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) 0.04 (12) 0 (0) 0.0 4 (12)
Condenser Makeup 0.08 (22) 0 (0) 0.08 (22 ) 0 (0) 0.08 (22)

BFW Makeup 0.08 (22) 0 (0) 0.08 (22)
Cooling Tower 14.16 (3 , 740) 1.79 (472) 12.37 (3 , 269) 3.18 (841) 9.19 (2 , 427)

BFW Blowdown 0 (0) 0.08 (22)

- 0.08 (

- 22)

Flue Gas Condensate 0 (0) 1.68 (443)

- 1.68 (

- 443)

CO 2 

### Prod uct Condensate 0 (0) 0.03 (7)

- 0.03 (

- 7)

Total 14.28 (3,773) 1.79 (472) 12.50 (3,302) 3.18 (841) 9.31 (2 , 461)

Heat and Mass Balance Diagrams
A heat and mass balance diagram is shown for the NGCC in Exhibit 3

- 46

. An overall plant energy balance is provided in tabular form in Exhibit 3

- 47 . The power out is the combined CT and steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibi t 3

- 42 ) is calculated by multiplying the power out by a combined generator efficiency of 98.4 percent.Cost and Performance Baseline

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124 

### This page intentionally left blankCost and Performance Baseline

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125 

### Exhibit 3

- 46 Case L31B Heat and Mass Balance, NGCC wi thout 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 T 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 L 31 B 2 X ADVANCED F

- CLASS GT 2400 / 1050 / 1050

DWG

. NO

.

LROF

- HMB

- CS

- L 31 B

- PG

- 1 Flue Gas

392
, 574 W

123

. 8 T 2
, 214

. 7 P

CO 2 PRODUCT

A MBIENT

A IR 1 6
, 652
, 082 W 40

. 0 T 13

. 8 P 6

. 0 H CO 2 COMPRESSION ( INTERSTAGE COOLING ) & DRYING 394
, 318 W

69

. 0 T 23

. 5 P 11

. 5 H KNOCKOUT

WATER 221
, 341 W

85

. 2 T 13

. 8 P 8

. 6 H Gross Plant Power : 502 MWe Auxiliary Load : 37 MWe Net Plant Power : 465 MWe Net Plant Efficiency
, HHV : 43

. 0 % Net Plant Heat Rate : 7 , 938 Btu / kWh A DVANCED F C LASS G AS T URBINES

COMBUSTOR N ATURAL GAS 163
, 560 W

100

. 0 T 450

. 0 P 19

. 9 H 2

6
, 198
, 051 W 85

. 2 T 13

. 8 P 37

. 6 H 6
, 815
, 642 W 288

. 2 T 13

. 8 P 122

. 4 H

6
, 815
, 642 W

1
, 162

. 0 T

14

. 3 P 357

. 4 H GENERATOR

CONDENSATE PUMPS8,801W1,302W

90

. 0 T 130

. 0 P 58

. 3 H 498
, 185 W

89

. 9 T 0

. 7 P 57

. 9 H

5 1
, 400 W 581

. 0 T 75

. 0 P 1
, 321

. 3 H 970
, 326 W

641

. 3 T 75

. 0 P 1
, 351

. 1 H 475
, 392 W 621

. 5 T 75

. 0 P 1
, 341

. 3 H

237
, 696 W 89

. 9 T 0

. 7 P 1
, 012

. 1 H 12 11 237
, 696 W 89

. 9 T 0

. 7 P 1
, 012

. 1 H

HOT WELL AIR

- COOLED CONDENSER CONDENSER

S TACK
4REBOILER CONDENSATE 13

CONDENSATE PUMPS S TEAM T URBINE MAKEUP 10
, 824 W

40

. 0 T 13

. 8 P 8

. 1 H

AIR INLET

FILTER 3

HP PUMP 498
, 185 W

253

. 0 T 100

. 0 P 221

. 9 HBLOWDOWN

90
, 199 W

300

. 1 T 95

. 0 P 269

. 4 H

167
, 030 W

300

. 7 T 400

. 0 P 270

. 7 H

825
, 187 W

305

. 3 T 2
, 540

. 0 P 279

. 3 H10,824WSTRIPPERABSORBER FLUE GAS ACID GAS

ECONAMINE FG + BLOWER

584
, 232 W 641

. 3 T 75

. 0 P 1
, 351

. 1 H WATER 1
, 745 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

693
, 772 W

306

. 2 T 73

. 5 P 1
, 180

. 9 H 89

. 9 T 0

. 7 P 1
, 012

. 1 H

9
, 569 W

498
, 185 W

95

. 9 T 120

. 0 P 64

. 2 H

Three Pressure Heat Recovery Steam Generator ( HRSG ) 789
, 275 W 1
, 055

. 0 T 360

. 0 P 1
, 553

. 4 H

A A 165
, 360 W 1
, 055

. 0 T 360

. 0 P 1
, 553

. 4 HHOT REHEAT

C OLD R EHEAT

789
, 275 W

588

. 0 T 390

. 0 P 1
, 300

. 6 H STEAM SEAL REGULATOR

89
, 297 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 TURBINE812,415W 2
, 654 W 1
, 050

. 0 T 2
, 414

. 7 P 1
, 492

. 8 H971,628WMAIN STEAM

816
, 935 W 1
, 050

. 0 T 2
, 414

. 7 P 1
, 492

. 8 H

6

7

8

9 10

10
, 969 W866W IP STEAM

584
, 232 W 303

. 9 T 73

. 5 P 273

. 3 H

IP PUMP

LP PUMP 693
, 772 W 303

. 9 T 71

. 0 P 273

. 3 H DOE / NETL

SC PC P LANT C ASE L 31 BCost and Performance Baseline

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### Th is page intentionally left bl ankCost and Performance Baseline

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127 

### Exhibit 3

- 47 Case L31B Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total
Heat In GJ/hr (MMBtu/hr)
Natural Gas 3,8 91 (3,688) 0.8 (0.7) 3,892 (3,689) GT Air 42.6 (40.4) 43 (40) Raw Water Withdrawal 13.9 (13.2) 14 (13) Auxiliary Power 133 (126) 133 (126)
Totals 3,891 (3,688) 57.3 (54.3) 133 (126) 4,082 (3,869) Heat Out GJ/hr (MMBtu/hr)
CO 2 

### - 29.4 (

- 27.8)

- 29 (

- 28) Cooling Tower Blowdown 17.2 (16.3) 17 (16)

Econamine Losses 960.6 (910.5) 961 (911)
CO 2 

### Compression Intercooling 83.0 (78.7) 83 (79)

Stack Gas 247 (234) 247 (234) Condenser 491 (465) 491 (465)
Process Losses 1 

### 506 (480) 506 (480)
Power 1,806 (1,712) 1,806 (1,712)
Totals 0 (0) 2,276 (2,157) 1,806 (1,712) 4,082 (3,869)

1 Process Losses are calculated by difference and reflect various turbine and other heat and work losses not modeled

in Aspen

.Cost and Performance Baseline

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128 

### 3.4.5 Case L31B

– Major Equipment List
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 3.4.6 . In general, t he 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 HANDLING

N/A

ACCOUNT 2 FUEL AND SORBENT PREPARATION AND FEED

N/A

ACCOUNT 3 FEEDWATER AND MISCELLAN EOUS SYSTEMS AND EQUIPMENT
Equipment No. Description Type Design Condition Operating Qty (Spares)

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 647,310 liters (171,000 gal) 2 (0)

2 Condensate Pumps Vertical canned 2,082 lpm @ 110 m H 2 O (550 gpm @ 360 ft H 2 O) 2 (1)

3 Boiler Feedwater Pump Horizontal, split case, multi

- stage, centrifugal, with interstage bleed for IP and LP feedwater HP water: 3,445 lpm @ 2,103 m H 2 O (910 gpm @ 6,900 ft H 2 O)

2 (1) IP water: 681 lpm @ 283 m H 2 O (18 0 gpm @ 930 ft H 2 O) LP water: 379 lpm @ 24.4 m H 2 O (100 gpm @ 80 ft H 2 O)

4 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/h, 2.8 MPa, 343°C (40,000 lb/h, 400 psig, 650°F) 1 (0)

5 Service Air Compressors Flooded Screw 13 m 3 /min @ 0.7 MPa (4 50 scfm @ 100 psig) 2 (1)

6 Instrument Air Dryers Duplex, regenerative 13 m 3 /min (450 scfm) 2 (1)

7 Closed Cycle Cooling Heat Exchangers Plate and frame 13 MMkJ/hr (13 MMBtu/hr) 2 (0)

8 Closed Cycle Cooling Water Pumps Horizontal centrifugal 5,300 lpm @ 21 m H 2 O (1,400 gpm @ 70 ft H 2 O) 2 (1)Cost and Performance Baseline

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129 

### Equipment No. Description Type Design Condition Operating Qty (Spares)

9 Engine

- Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 107 m H 2 O (1,000 gpm @ 350 ft H 2 O) 1 (1)

10 Fire Service Booster Pump Two

- stage horizontal centrifugal 2,650 lpm @ 76 m H 2 O (700 gpm @ 250 ft H 2 O) 1 (1)

11 Raw Water Pumps Stainless steel, single suction 6,814 lpm @ 18 m H 2 O (1,800 gpm @ 60 ft H 2 O) 2 (1)

12 Filtered Water Pumps Stainless steel, single suction 151 lpm @ 49 m H 2 O (40 gpm @ 160 ft H 2 O) 2 (1)

13 Filtered Water Tank Vertical, cylin drical 143,847 liter (38,000 gal) 1 (0)

14 Makeup Water Demineralizer Multi

- media filter, cartridge filter, RO membrane assembly and electro

- deionization unit 341 lpm (90 gpm) 1 (0)

1 5 Gas Pipeline Underground, coated carbon steel , wrapped cathodic prote ction 61 m 3 /min @ 3.1 MPa (2,166 acfm @ 450 psia) 41 cm (16 in) standard wall pipe 16 km (0)

16 Gas Metering Station

-- 61 m 3 /min (2,166 acfm) 1 (0)

1 7 Liquid Waste Treatment System 10 years, 24

- hour storm 1 (0)



### ACCOUNT 4 GASIFIER, BOILER AND ACCE SSORIES

N/A

ACCOUNT 5 FLUE GAS CLEANUP

N/ACost and Performance Baseline

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130 

### ACCOUNT 6 COMBUSTION TURBINE GENERATORS AND AUXILIARIES

Equipment No. Description Type Design Condition Operating Qty (Spares)

1 Gas Turbine Advanced F class w/ dry low

- NOx burner 180 MW 2 (0)

2 Gas Turb ine Generator TEWAC 200 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 2 (0)



### ACCOUNT 7 WASTE HEAT BOILER, DUCTING, AND STACK

Equipment No. Description Type Design Condition Operating Qty (Spares)

1 Stack CS plate, type 409SS liner 46 m (150 ft) high x 6.5 m (21 ft) diameter 2 (0)

2 Heat Recovery Steam Generator Drum, multi

pressure with economizer section and integral deaerator Main steam

- 203,806 kg/h, 16.5 MPa/566°C (449,314 lb/h, 2,400 psig/1,050°F) 2 (0) Reheat steam

- 238,159 kg/h, 2.4 MPa/566°C (525,049 lb/h, 345 psig/1,050°F) 3 SCR Reactor Space for spare layer 1,546,752 kg/h (3,410,000 lb/h) 2 (0)

4 SCR Catalyst

-- Space available for an additional catalyst layer 1 layer (0)

5 Dilution Air Blowers Centrifugal 10 m 3 /min @ 107 cm WG (370 scf m @ 42 in WG) 2 (1)

6 Ammonia Feed Pump Centrifugal 3.8 lpm @ 91 m H 2 O (1 gpm @ 300 ft H 2 O) 2 (1)

7 Ammonia Storage Tank Horizontal tank 64,353 liter (17,000 gal) 1 (0)



### ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment No. Description Type De sign Condition Operating Qty (Spares)

1 Steam Turbine Tandem compound, HP, IP, and two

flow LP turbines 151 MW 16.5 MPa/566°C/566°C (2,400 psig/ 1050°F/1050°F) 1 (0)

2 Steam Turbine Generator Hydrogen cooled, static excitation 170 MVA @ 0.9 p.f., 24 kV
, 60 Hz, 3

- phase 1 (0)

3 Steam Bypass One per HRSG 50% steam flow @ design steam conditions 2 (0)Cost and Performance Baseline

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131 

### Equipment No. Description Type De sign Condition Operating Qty (Spares)

4 Surface Condenser Single pass, divided waterbox including vacuum pumps 270 MMkJ/hr, (260 MMBtu/hr), Inlet water temperature 8°C (47°F), Water temperature rise 11°C (20°F) 1 (0)

5 Air

- cooled Condenser -- 270 GJ/hr (260 MMBtu/hr), Condensing temperature 32°C (90°F), Ambient temperature 4°C (40°F) 1 (0)



### ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type Design Condition Operating Qty (Spares)

1 C irculating Water Pumps Vertical, wet pit 363,402 lpm @ 30.5 m (96,000 gpm @ 100 ft) 2 (1)

2 Cooling Tower Evaporative, mechanical draft, multi

- cell 2°C (36°F) wet bulb / 8°C (47°F) CWT / 19°C (67°F) HWT 569 MMkJ/hr (540

MMBtu/hr) heat load 1 (0)



### ACC OUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING

N/A

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type L12A Design Condition Operating Qty (Spares)

1 CTG Transformer Oil

- filled 24 kV/345 kV, 200 MVA, 3

- ph, 60 Hz 2 (0)

2 STG Transformer Oil

- filled 24 kV/345 kV, 140 MVA, 3

- ph, 60 Hz 1 (0)

3 High Voltage Auxiliary Transformer Oil

- filled 345 kV/13.8 kV, 8 MVA, 3

- ph, 60 Hz 1 (1)

4 Medium Voltage Transformer Oil

- filled 24 kV/4.16 kV, 23 MVA, 3

- ph, 60 Hz 1 (1)

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 3 MVA, 3

- ph, 60 Hz 1 (1)

6 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 2 (0)Cost and Performance Baseline

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132 

### Equipment No. Description Type L12A Design Condition Operating Qty (Spares)

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self

coole d 24 kV, 3

- ph, 60 Hz 1 (0)

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 1 (1)

9 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 1 (1)

10 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3

- ph, 60 Hz 1 (0)



### A CCOUNT 12 INSTRUMENTATION AND CONTROL
Equipment No. Description Type L12A Design Condition Operating Qty (Spares)

1 DCS

- Main Control Monitor/keyboard, Operator printer, Engineering printer Operator stations/printers and engineering stations/printers 1 ( 0)

2 DCS

- Processor Microprocessor with redundant input/output N/A 1 (0)

3 DCS

- Data Highway Fiber optic Fully redundant, 25% spare 1 (0)Cost and Performance Baseline

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133 

### 3.4.6 Case L31B

– Cost Estimating
The cost estimating methodology was described previously in Section 2.6

. Exhibit 3

- 48 shows the total plant capital cost summary organized by cost account and Exhibit 3

- 49 shows a more detailed breakdown of the capital costs. Exhibi t 3

- 50 itemizes the owner’s costs and Exhibit 3

- 51 shows the initial and annual O&M costs.

The estimated TOC of the NGCC with CO 2 

### capture is $ 1, 548 /kW. Process contingency accounts for 3. 9 percent of the TOC . The project contin gency is 10. 9 percent of TOC. The COE, including CO 2 

### TS&M costs of 3.3 mills/kWh, is 91.4 mills/kWh

.Cost and Performance Baseline

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134 

### Exhibit 3

- 48 Case L31B Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-19 Project: Low Rank Western Coal Baseline Study

Case: Case L31B - 1x465 MWnet 2x1 7FB NGCC w/ CO2 Capture Plant Size: 464.6 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2 COAL & SORBENT PREP & FEED $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

3 FEEDWATER & MISC. BOP SYSTEMS $23,198 $4,585 $7,280 $0 $0 $35,063 $2,961 $0 $6,122 $44,146 $95

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4-4.9 Other gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A GAS CLEANUP & PIPING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B CO2 REMOVAL & COMPRESSION $119,974 $0 $36,547 $0 $0 $156,521 $13,407 $27,611 $39,508 $237,047 $510

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $75,294 $0 $4,804 $0 $0 $80,098 $6,800 $0 $8,690 $95,589 $206 6.2-6.9 Combustion Turbine Other $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $4 SUBTOTAL 6 $75,294 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,490 $210

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $96 7.2-7.9 SCR System, Ductwork and Stack $1,138 $906 $1,056 $0 $0 $3,100 $264 $0 $549 $3,913 $8 SUBTOTAL 7 $34,096 $906 $5,335 $0 $0 $40,337 $3,434 $0 $4,589 $48,361 $104

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $18,712 $0 $3,357 $0 $0 $22,068 $1,897 $0 $2,397 $26,362 $57 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $18,435 $619 $6,876 $0 $0 $25,930 $2,386 $0 $5,067 $33,382 $72 SUBTOTAL 8 $37,147 $619 $10,232 $0 $0 $47,998 $4,283 $0 $7,464 $59,744 $129

9 COOLING WATER SYSTEM $7,556 $5,648 $5,090 $0 $0 $18,293 $1,520 $0 $2,801 $22,614 $49

10 ASH/SPENT SORBENT HANDLING SYS $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

11 ACCESSORY ELECTRIC PLANT $20,098 $5,521 $12,017 $0 $0 $37,636 $2,898 $0 $4,383 $44,917 $97

12 INSTRUMENTATION & CONTROL $6,236 $640 $5,181 $0 $0 $12,057 $1,004 $603 $1,566 $15,230 $33

13 IMPROVEMENTS TO SITE $1,709 $928 $4,547 $0 $0 $7,184 $636 $0 $1,564 $9,384 $20

14 BUILDINGS & STRUCTURES $0 $3,876 $4,009 $0 $0 $7,885 $640 $0 $1,279 $9,804 $21

TOTAL COST $325,306 $23,444 $95,786 $0 $0 $444,536 $37,706 $28,214 $78,282 $588,738 $1,267 TOTAL PLANT COST SUMMARYCost and Performance Baseline

- Volume 3c (NGCC Cases)

135 

### Exhibit 3

- 49 Case L31B Total Plant Cost Details

Client: USDOE/NETL Report Date: 2009-Oct-19 Project: Low Rank Western Coal Baseline Study

Case: Case L31B - 1x465 MWnet 2x1 7FB NGCC w/ CO2 Capture Plant Size: 464.6 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.2 Coal Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.3 Coal Conveyors & Yd Crush $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.4 Other Coal Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 1. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.3 Slurry Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 2. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,343 $2,414 $1,985 $0 $0 $6,742 $556 $0 $1,095 $8,392 $18 3.2 Water Makeup & Pretreating $1,858 $194 $970 $0 $0 $3,022 $258 $0 $656 $3,935 $8 3.3 Other Feedwater Subsystems $1,068 $361 $304 $0 $0 $1,733 $139 $0 $281 $2,153 $5 3.4 Service Water Systems $220 $452 $1,467 $0 $0 $2,138 $187 $0 $465 $2,790 $6 3.5 Other Boiler Plant Systems $1,473 $571 $1,322 $0 $0 $3,366 $286 $0 $548 $4,199 $9 3.6 Natural Gas, incl. pipeline $14,649 $471 $410 $0 $0 $15,530 $1,316 $0 $2,527 $19,373 $42 3.7 Waste Treatment Equipment $670 $0 $382 $0 $0 $1,053 $92 $0 $229 $1,373 $3 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $917 $123 $440 $0 $0 $1,480 $128 $0 $322 $1,930 $4 SUBTOTAL 3. $23,198 $4,585 $7,280 $0 $0 $35,063 $2,961 $0 $6,122 $44,146 $95 4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4 LT Heat Recovery & FG Saturation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.5 Misc. Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Other Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.8 Major Component Rigging $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 

### TOTAL PLANT COST SUMMARYCost and Performance Baseline

- Volume 3c (NGCC Cases)

136 

### Exhibit 3

- 49 Case L31B Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-19 Project: Low Rank Western Coal Baseline Study

Case: Case L31B - 1x465 MWnet 2x1 7FB NGCC w/ CO2 Capture Plant Size: 464.6 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 MDEA-LT AGR $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.2 Elemental Sulfur Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.3 Mercury Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.4 COS Hydrolysis $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.5 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Fuel Gas Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.9 HGCU Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $105,919 $0 $32,137 $0 $0 $138,056 $11,825 $27,611 $35,498 $212,990 $458 5B.2 CO2 Compression & Drying $14,056 $0 $4,409 $0 $0 $18,465 $1,582 $0 $4,009 $24,057 $52 SUBTOTAL 5. $119,974 $0 $36,547 $0 $0 $156,521 $13,407 $27,611 $39,508 $237,047 $510 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $75,294 $0 $4,804 $0 $0 $80,098 $6,800 $0 $8,690 $95,589 $206 6.2 Combustion Turbine Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $4 SUBTOTAL 6. $75,294 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,490 $210 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $96 7.2 SCR System $1,138 $478 $671 $0 $0 $2,288 $197 $0 $373 $2,857 $6 7.3 Ductwork $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.4 Stack $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.9 HRSG,Duct & Stack Foundations $0 $428 $385 $0 $0 $813 $68 $0 $176 $1,057 $2 SUBTOTAL 7. $34,096 $906 $5,335 $0 $0 $40,337 $3,434 $0 $4,589 $48,361 $104 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $18,712 $0 $3,357 $0 $0 $22,068 $1,897 $0 $2,397 $26,362 $57 8.2 Turbine Plant Auxiliaries $137 $0 $308 $0 $0 $445 $39 $0 $48 $532 $1 8.3 Condenser & Auxiliaries $1,416 $0 $423 $0 $0 $1,839 $158 $0 $200 $2,196 $5 8.3b Air Cooled Condenser $12,980 $0 $2,602 $0 $0 $15,583 $1,558 $0 $3,428 $20,569 $44 8.4 Steam Piping $3,901 $0 $2,565 $0 $0 $6,466 $495 $0 $1,044 $8,005 $17 8.9 TG Foundations $0 $619 $978 $0 $0 $1,597 $135 $0 $347 $2,079 $4 SUBTOTAL 8. $37,147 $619 $10,232 $0 $0 $47,998 $4,283 $0 $7,464 $59,744 $129 9 COOLING WATER SYSTEM 9.1 Cooling Towers $5,349 $0 $684 $0 $0 $6,033 $514 $0 $655 $7,201 $15 9.2 Circulating Water Pumps $1,569 $0 $99 $0 $0 $1,668 $126 $0 $179 $1,973 $4 9.3 Circ.Water System Auxiliaries $122 $0 $16 $0 $0 $138 $12 $0 $15 $165 $0 9.4 Circ.Water Piping $0 $3,561 $863 $0 $0 $4,424 $358 $0 $717 $5,499 $12 9.5 Make-up Water System $279 $0 $373 $0 $0 $652 $56 $0 $106 $815 $2 9.6 Component Cooling Water Sys $236 $283 $188 $0 $0 $707 $59 $0 $115 $882 $2 9.9 Circ.Water System Foundations $0 $1,804 $2,867 $0 $0 $4,671 $396 $0 $1,013 $6,080 $13 SUBTOTAL 9. $7,556 $5,648 $5,090 $0 $0 $18,293 $1,520 $0 $2,801 $22,614 $49 TOTAL PLANT COST SUMMARYCost and Performance Baseline

- Volume 3c (NGCC Cases)

137 

### Exhibit 3

- 49 Case L31B Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-19 Project: Low Rank Western Coal Baseline Study

Case: Case L31B - 1x465 MWnet 2x1 7FB NGCC w/ CO2 Capture Plant Size: 464.6 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.7 Ash Transport & Feed Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.9 Ash/Spent Sorbent Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 10. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $5,314 $0 $3,193 $0 $0 $8,507 $721 $0 $692 $9,920 $21 11.2 Station Service Equipment $1,965 $0 $166 $0 $0 $2,131 $176 $0 $173 $2,480 $5 11.3 Switchgear & Motor Control $2,422 $0 $412 $0 $0 $2,834 $235 $0 $307 $3,376 $7 11.4 Conduit & Cable Tray $0 $1,157 $3,569 $0 $0 $4,726 $409 $0 $770 $5,905 $13 11.5 Wire & Cable $0 $3,686 $2,263 $0 $0 $5,949 $383 $0 $950 $7,282 $16 11.6 Protective Equipment $0 $558 $1,898 $0 $0 $2,456 $215 $0 $267 $2,938 $6 11.7 Standby Equipment $97 $0 $89 $0 $0 $186 $16 $0 $20 $222 $0 11.8 Main Power Transformers $10,298 $0 $134 $0 $0 $10,432 $708 $0 $1,114 $12,254 $26 11.9 Electrical Foundations $0 $120 $294 $0 $0 $414 $35 $0 $90 $539 $1 SUBTOTAL 11. $20,098 $5,521 $12,017 $0 $0 $37,636 $2,898 $0 $4,383 $44,917 $97 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $793 $0 $495 $0 $0 $1,288 $109 $64 $219 $1,680 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $237 $0 $142 $0 $0 $379 $32 $19 $64 $494 $1 12.7 Computer & Accessories $3,792 $0 $113 $0 $0 $3,906 $321 $195 $442 $4,864 $10 12.8 Instrument Wiring & Tubing $0 $640 $1,223 $0 $0 $1,864 $140 $93 $315 $2,412 $5 12.9 Other I & C Equipment $1,414 $0 $3,208 $0 $0 $4,622 $401 $231 $525 $5,779 $12 SUBTOTAL 12. $6,236 $640 $5,181 $0 $0 $12,057 $1,004 $603 $1,566 $15,230 $33 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $91 $1,823 $0 $0 $1,914 $170 $0 $417 $2,501 $5 13.2 Site Improvements $0 $837 $1,039 $0 $0 $1,876 $166 $0 $408 $2,451 $5 13.3 Site Facilities $1,709 $0 $1,685 $0 $0 $3,394 $300 $0 $739 $4,432 $10 SUBTOTAL 13. $1,709 $928 $4,547 $0 $0 $7,184 $636 $0 $1,564 $9,384 $20 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $236 $125 $0 $0 $361 $28 $0 $58 $447 $1 14.2 Steam Turbine Building $0 $1,601 $2,131 $0 $0 $3,732 $307 $0 $606 $4,644 $10 14.3 Administration Building $0 $459 $311 $0 $0 $770 $61 $0 $125 $956 $2 14.4 Circulation Water Pumphouse $0 $146 $72 $0 $0 $218 $17 $0 $35 $271 $1 14.5 Water Treatment Buildings $0 $401 $366 $0 $0 $766 $62 $0 $124 $953 $2 14.6 Machine Shop $0 $398 $255 $0 $0 $653 $52 $0 $106 $810 $2 14.7 Warehouse $0 $257 $155 $0 $0 $412 $33 $0 $67 $512 $1 14.8 Other Buildings & Structures $0 $77 $56 $0 $0 $133 $11 $0 $22 $165 $0 14.9 Waste Treating Building & Str. $0 $301 $538 $0 $0 $839 $70 $0 $136 $1,046 $2 SUBTOTAL 14. $0 $3,876 $4,009 $0 $0 $7,885 $640 $0 $1,279 $9,804 $21

TOTAL COST $325,306 $23,444 $95,786 $0 $0 $444,536 $37,706 $28,214 $78,282 $588,738 $1,267 TOTAL PLANT COST SUMMARYCost and Performance Baseline, Volume 3c (NGCC Cases)

138 

### Exhibit 3

- 50 Case L31B Owner’s Costs

Owner's Costs $x1000 $/kW Preproduction Costs 6 Months Fixed O&M $4,249 $9 1 Month Variable O&M $871 $2 25% of 1 Months Fuel Cost at 100% CF $4,799 $10 2% of TPC $11,775 $25 Total $21,693 $47
Inventory Capital 60 day supply of consumables at 100% CF $470 $1 0.5% of TPC (spare parts) $2,944 $6 Total $3,414 $7
Initial Cost for Catalyst and Chemicals $804 $2 Land $300 $1 Other Owner's Costs $88,311 $190 Financing Costs $15,896 $34

Total Owner's Costs $130,417 $281 Total Overnight Cost (TOC) $719,155 $1,548 TASC Multiplier 1.078 Total As-Spent Cost (TASC) $775,249 $1,668Cost and Performance Baseline, Volume 3c (NGCC Cases)

139 

### Exhibit 3

- 51 Case L31B Initial and Annual Operating and Maintenance Cost Summary

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case L31B - 1x465 MWnet 2x1 7FB NGCC w/ CO2 Capture Heat Rate-net (Btu/kWh): 7,938 MWe-net: 465 Capacity Factor (%): 85 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total

Skilled Operator 1.0 1.0 Operator 3.3 3.3 Foreman 1.0 1.0 Lab Tech's, etc. 1.0 1.0 TOTAL-O.J.'s 6.3 6.3 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $2,497,781 $5.376 Maintenance Labor Cost $4,300,603 $9.256 Administrative & Support Labor $1,699,596 $3.658 Property Taxes and Insurance $11,774,756 $25.342 TOTAL FIXED OPERATING COSTS $20,272,736 $43.631 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $6,450,905 $0.00186

Consumables Consumption Unit Initial Initial /Day Cost Cost
Water (/1000 gallons) 0.00 2,374.56 1.08 $0 $796,878 $0.00023

Chemicals

MU & WT Chem.(lbs) 0.00 14,146.94 0.17 $0 $759,611 $0.00022 MEA Solvent (ton) 336.89 0.47 2,249.89 $757,962 $330,240 $0.00010 Activated Carbon (lb) 0.00 565.14 1.05 $0 $184,133 $0.00005 Corrosion Inhibitor 0.00 0.00 0.00 $46,153 $2,198 $0.00000 SCR Catalyst (m3) w/equip. 0.07 5,775.94 $0 $123,497 $0.00004 Ammonia (19% NH3) (ton) 0.00 5.80 129.80 $0 $233,416 $0.00007 Subtotal Chemicals $804,115 $1,633,094 $0.00047

Other

Supplemental Fuel (MBtu) 0.00 0.00 0.00 $0 $0 $0.00000 Gases,N2 etc. (/100scf) 0.00 0.00 0.00 $0 $0 $0.00000 L.P. Steam (/1000 pounds) 0.00 0.00 0.00 $0 $0 $0.00000 Subtotal Other $0 $0 $0.00000
Waste Disposal

Flyash (ton) 0.00 0.00 0.00 $0 $0 $0.00000 Bottom Ash (ton) 0.00 0.00 0.00 $0 $0 $0.00000 Subtotal Waste Disposal $0 $0 $0.00000
By-products

Sulfur (tons) 0.00 0.00 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $804,115 $8,880,877 $0.00257

Fuel (MMBtu) 0 88,519 7.13 $0 $195,790,457 $0.05659Cost and Performance Baseline, Volume 3c (NGCC Cases)

140 

### This page intentionally left b lankCost and Performance Baseline, Volume 3c (NGCC Cases)

141 

### 4. SUMMARY The performance results of the four NGCC plant configurations modeled in this study are summarized in Exhibit 4

- 1

. Exhibit 4

- 1 Performance and Cost Res ults for NGCC Cases

PERFORMANCE Case S31A Case L31A Case S31B Case L31B CO 2 Capture 0% 0% 90% 90% Gross Power Output (kW e ) 522,100 557,000 470,000 501,600 Auxiliary Power Requirement (kW e ) 9,690 10,020 34,940 36,960 Net Power Output (kW e ) 512,410 546,980 435,060 464,640 Natural Gas Flowrate (lb/hr) 153,559 163,560 153,559 163,560 HHV Thermal Input (kW th ) 1,014,787 1,080,880 1,014,787 1,080,880 Net Plant HHV Efficiency (%) 50.5% 50.6% 42.9% 43.0% Net Plant HHV Heat Rate (Btu/kWh) 6,757 6,743 7,959 7,938 Raw Water Withdrawal (gpm/MW net ) 2.1 2.1 7.1 7.1 Process Water Discharge (gpm/MW net ) 0.5 0.5 1.8 1.8 Raw Water Consumption (gpm/MW net ) 1.6 1.6 5.3 5.3 CO 2 Emissions (lb/MMBtu) 118 118 12 12 CO 2 Emissions (lb/MWh gross ) 784 783 87 87 CO 2 Emissions (lb/MWh net ) 799 797 94 94 SO 2 Emissions (lb/MMBtu) Negligible Negligible Negligible Negligible SO 2 Emissions (lb/MWh gross ) Negligible Negligible Negligible Negligible NOx Emissions (lb/MMBtu) 0.009 0.009 0.009 0.009 NOx Emissions (lb/MWh gross ) 0.060 0.060 0.067 0.066 PM Emissions (lb/MMBtu) Negligible Negligible Negligible Negligible PM Emissions (lb/MWh gross ) Negligible Negligible Negligible Negligible Hg Emissions (lb/TBtu) Negligible Negligible Negligible Negligible Hg Emissions (lb/MWh gross ) Negligible Negligible Negligible Negligible COST Total Plant Cost (2007$/kW) 666 637 1,315 1,267 Total Overnight Cost (2007$/kW) 817 782 1,607 1,548 **Bare Erected Cost** 546 521 994 957 **Home Office Expenses** 46 44 84 81 **Project Contingency** 74 71 174 168 **Process Contingency** 0 0 62 61 **Owner's Costs** 151 145 291 281 Total Overnight Cost (2007$ x 1,000) 418,817 427,473 698,949 719,155 Total As Spent Capital (2007$/kW) 879 840 1,732 1,668 COE (mills/kWh, 2007$) 1 64.4 63.6 92.9 91.4 **CO 2**  **TS&M Costs** 0.0 0.0 3.4 3.3 **Fuel Costs** 48.2 48.1 56.7 56.6 **Variable Costs** 1.4 1.3 2.7 2.6 **Fixed Costs** 3.4 3.2 6.1 5.9 **Capital Costs** 11.5 11.0 24.0 23.1 LCOE (mills/kWh, 2007$) 1 81.7 80.6 117.8 115.8 NGCC with Advanced F Class

1 COE and Levelized COE are defined in Section 2.6

.Cost and Performance Baseline, Volume 3c (NGCC Cases)

142 

### The TO C for each of the four NGCC cases is shown in Exhibit 4

- 2 . The TOC of the NDL site

non

- capture case, $ 78 2 /kW, is the lowest of the four NGCC cases

. The TOC of the non

- capture NGCC plant at the Montana site is $8 17 /kW, or approximately four percent greater. Addition of CO 2 

### capture nearly doubles the TOC at each location . The process contingency included f o r the Econamine process averages $ 6 0 /kW for the capture cases , which represents approximately 8 percent of the incremental cost due to the addition of CO 2 

### capture and 4 percent of the total TO C.

The COE for NGCC plants is heavily dependent on the price of natural gas as shown in Exhibit 4

- 3 . The fuel component of COE represents 75 percent of the total in the non

- capture
cases and 62 percent of the t otal in the CO 2 

### capture case.

Exhibit 4

- 2 Total Overnight Costs

817 1,607

782 1,548

879 1,732

840 1,668

0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000

TOC TASC TOC TASC TOC TASC TOC TASC

NGCC NGCC w/ CO2 Capture NGCC NGCC w/ CO2 CaptureTOC and TASC ($/kW) TASC Owner's Cost Process Contingency Project Contingency Home Office Expense Bare Erected Cost North Dakota Site Elevation: 1,900 ft Montana Site Elevation: 3,400 ftCost and Performance Baseline, Volume 3c (NGCC Cases)

143 

### Exhibit 4

- 3 COE of NGCC Cases

11.5 24.0

11.0 23.1 3.4 6.1

3.2 5.9

1.4 2.7

1.3 2.6 48.2 56.7

48.1 56.6 3.4 3.3

64.4 92.9

63.6 91.4

0 20 40 60 80 100 120

NGCC PRB NGCC PRB w/Capture NGCC Lig NGCC Lig w/CaptureCOE (2007 mills/kWh) CO2 TS&M Cost Fuel Cost
Variable O&M Cost
Fixed O&M Cost Capital Cost Montana Site Elevation: 3,400 ft North Dakota Site Elevation: 1,900 ft



### Because the NGCC COE has a relatively small capital component, it is less sensitive to CF changes than it is to changes in fuel prices

. The sensitivity of NGCC to CF is shown in Exhibit 4

- 4 while the sensitivity of NGCC to natural gas price is shown in Exhibit 4

- 5

. A 50 percent reduction in C F (80 percent to 40 percent) results in approximate ly a 2 4 percent increase in COE for the non

- capture cases and a 37 percent increase for the capture cases. The capture cases are more capital intensive and are more sensitive to changes in the CF

. Increas ing the price of natural gas 50 percent (from $ 7

. 13 to $ 1 0

. 70 /MMBtu) results in a COE increase of 3 8 percent in the non

- capture case s and 32 percent in the CO 2 

### capture case s . B ecause the fuel cost s are a smaller proportion o f the total COE in the CO 2 

### capt ure case s , the impact of fuel price variations is less for those cases

.Cost and Performance Baseline, Volume 3c (NGCC Cases)

144 

### Exhibit 4

- 4 Sensitivity of COE to Capacity Factor in NGCC Cases

0 20 40 60 80 100 120 140 160 180

0 10 20 30 40 50 60 70 80 90 100COE (2007 mills/kWh)

Capacity Factor, % NGCC w/CO2 Capture Montana Site

NGCC w/CO2 Capture North Dakota Site NGCC No Capture Montana Site

NGCC No Capture North Dakota Site Study Capacity Factor is 85% for all cases



### Exhibit 4

- 5 Sensit ivity of COE to Fuel Price in NGCC Cases

0 20 40 60 80 100 120 140 160

0 2 4 6 8 10 12 14COE (2007 mills/kWh)

Natural Gas Price, $/MMBtu NGCC w/CO2 Capture Montana Site
NGCC w/CO2 Capture North Dakota Site
NGCC No Capture Montana Site
NGCC No Capture North Dakota Site

Capacity Factor = 85% for all cases Study Natural Gas Cost: $7.13/MMBtuCost and Performance Baseline, Volume 3c (NGCC Cases)

145 

### The following observations can be made regarding plant performance with reference to Exhibit 4

- 1 : The efficiency for cases S31A and L31A are 50.5 and 50.6 percent (HHV bas is) , respectively

. 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) [ 32

**•** The increase in elevation, going from the NDL to the Montana site, has minimal impact on efficiency but does cause a derate in the gas turbine compressor, reducing the net plant output by six percent for both CO 2 

### capture and non

- capture cases

. As the a ir becomes less dense at higher elevations, the maximum volumetric capacity of the compressor results in less mass flow through the combustion turbine. ]

. Adjusting the results from this study to an LHV basis results in efficiencies of 56.0 and 56.1 percent for cases S31A and L31A
, respectively. A portion of the efficiency difference can be attributed to the higher condenser pressure used in this study relative to the Gas Turbine World reference cas e.

**•** The efficiency penalty to add CO 2 

### capture in the NGCC case s is 7.6 percentage points (a relative reducti on of 15 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 coo ling tower fan. CO 2 

### capture results in a 25 and 27 MW increase in auxiliary load compared to the Montana and ND site non

- capture case s, respectively

. Additionally, the extraction steam required to regenerate the Econamine solvent results in a reduction o f steam turbine output of over 50 MW at both site locations.

**•** 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 9.7 tonnes/yr (10.7 tons/yr) at 85 perc ent CF , or 0.00073 kg/GJ (0.0017 lb/MMBtu).

**•** NOx emissions are similar for the two non

- capture NGCC cases on a mass basis. This is a result of the fixed output from the gas turbine (25 ppmv at 15 percent O 2 

### ) and the fixed efficiency of the SCR (90 percent)

. The capture cases have slightly higher NOx emissions because they are normalized by a smaller gross power output

. As presented in Section 2.6 the cost of CO 2 

### avoided was compared in two ways, relative to the analogous plant design and compared to a baseline SC PC plant. The cost of CO 2 

### avoided , shown in Exhibit 4

- 6 , averages $88.0/tonne ($79.9/ton) compared to the analogous non

- capture (A) design and $38.4/tonne ($34.8/ton) compared to the baseline S C PC non

- capture (SC PC A) design. NGCC plants have low carbon emissions, even before capturing CO 2 

### , so the cost of CO 2 

### avoided compared to a baseline SC PC plant is very low. The cost of avoiding CO 2 

### compared to the analogous non

- capture NGCC case shows costs compar a ble to the addition of a typical post combustion CO 2 

### capture process.Cost and Performance Baseline, Volume 3c (NGCC Cases)

146 

### Exhibit 4

- 6 CO 2 

### Avoided Costs

89.1 87.0

43.0

33.8

0 10 20 30 40 50 60 70 80 90 100 110

NGCC PRB w/Capture NGCC Lig w/CaptureFirst YEar CO2Avoided Cost, (2007$/Tonne) Avoided Cost (Analogous Technology w/o Capture Reference Avoided Cost (SC PC w/o Capture Reference)

Montana Site Elevation: 3,400 ft North Dakota Site Elevation: 1,900 ft



### The normalized water withdrawal
, process discharge and raw water consumption are shown in Exhibit 4

- 7 for each case. The following observations can be made:

**•** Normalized water withdrawal and normalized raw water consumption more than triple when CO 2 

### capture technology is added . The high cooling water demand of the Econamine process results in a large increase in cooling tower makeup requirements.

**•** The use of the parallel wet/dry cooling system reduces water demand relative to an all wet cooling tower system. For the non

- capture cases, the reductions are appr oximately 3

. 1 m 3 

### /min ( 8 20 gpm) resulting in a 4 9 percent reduction

. For the CO 2 

### capture cases, the reductions are 2

. 1 m 3 

### /min (3 70 gpm) resulting in a 1 4 percent reduction. The water savings is less in the CO 2 

### capture cases because a significant amount of extraction steam is used in the Econamine system and therefore not condensed in the surface condenser.

**•** Cooling tower makeup comprises over 9 7 percent of the raw water consumption in each case. 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 s condensate is recovered from the flue gas as it is cooled to the absorber temperature of 32°C (89°F) as well as from the CO 2 

### product stream during compression. These stre ams are also recycled to the cooling tower.Cost and Performance Baseline, Volume 3c (NGCC Cases)

147 

### Exhibit 4

- 7 Water Usage in NGCC Costs

2.1 2.1 7.1 7.1

0.5 0.5 1.8 1.8

1.6 1.6 5.3 5.3

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0

NGCC PRB NGCC Lig NGCC PRB w/ Capture NGCC Lig w/ CaptureWater Usage, gpm/MWhnet Raw Water Withdrawal Process Water Discharge Raw Water ConsumptionCost and Performance Baseline, Volume 3c (NGCC Cases)

148 

### This page intentionally left blankCost and Performance Baseline, Volume 3c (NGCC Cases)

149 

### 5. R EFERENCES

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2 “Annual Energy Outlook 2008 with Projections to 2030,” AEO Reference Case Table 108, EIA, April 2008

3 Gross Domestic Product: Chain

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4 Gleitz, Robert, “Advanced GT Technology,” GE Power Systems, Jul y 2003

5 Eldrid, Roberta, Kaufman, Lynda and Marks, Paul, “The 7FB: The Next Evolution of the F Gas Turbine,” GER

- 4194, April 2001

6 “Resolution of “Natural Gas” and “Pipeline Natural Gas” Definition Issues, EPA’s Clean Air Market Programs, http://www.epa.gov/airmarkt/monitoring/gasdef/

7 North American Electric Reliability Council website, http://www.nerc.com/~gads/
8 “Cooling Tower Fundamentals,” ed. John C. Hensley, 2nd Edition, The Marley C ooling Tower Company, Mission, Kansas, 1985
9 Personal Correspondence with Frank Ortega, Product Manager

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10 “EPA Technical Development Document for the Final Regulations Addressi ng Cooling Water Intake Structures for New Facilities,” EPA

- 821

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- 036, November 2001

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– Cost Estimating and Bu dgeting,” AACE International Recommended Practice No. 18R

- 97, 2005

12 Herzog, Howard J., “The Economics of CO 2 

### Separation and Capture,” MIT Energy Laboratory

13 “Merit Shop Wage & Benefit Survey,” PAS, Inc., http://www.pas1.com/

14 “Conducting Technical and Economic Evaluations

– As Applied for the Process and Utility Industries; TCM Framework: 3.2

– Asset Planning, 3.3 Investment Decision Making, AACE International Recommended Practice 16R

- 90, 2003Cost and Performance Baseline, Volume 3c (NGCC Cases)

150 

### 15 Economic Evaluation of CO 2 

### Storage and Sink Enhancement Options, Tennessee Valley Authority, NETL and EPRI, December 2002

16 Smith, Lawrence A., Gupta, Neeraj, Sass, Bruce M. and Bubenik, Thomas A.,

“ Engineering and Economic Assessment of Carbon Dioxide Sequestration in Saline Formations ,” Battelle Memorial Inst itute, 2001

17 Ciferno, Jared P. and McIlvried, Howard, “CO 2 

### Flow Modeling and Pipe Diameter Determination,” February, 2003

18 Parker, N., “Using Natural Gas Transmission Pipeline Costs to Estimate Hydrogen Pipeline Costs,” Institute of Transportation Studie s, University of California, Davis, CA, 2004.

19 Gresham, R. L., Apt, J., et. al, “Implications of Compensating Property

- Owners for Geologic Sequestration of CO2,” Department of Engineering and Public Policy, Carnegie Mellon University, Pittsburgh, PA, 1999

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- 401/090808, September 2008

26 GER

- 3567H, GE Gas Turbine Perfor mance Characteristics, Frank J. Brooks, GE Power Systems, 10/00, http://www.gepower.com/prod_serv/products/tech_docs/en/downloads/ger3567h.pdf

27 GER

- 3568G, Dry Low NOx Combustions Systems for GE Heavy

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28 Improvement in Power Generation with Post

- Combustion Capture of CO 2 

### , IEA Greenhouse Gas R&D Programme, Report PH4/33, November 2004Cost and Performance Baseline, Volume 3c (NGCC Cases)

151 

### 29 Reddy, Satish, Johnson, Dennis, and Gilmartin, John, “Fluor’s Econamine FG Plus SM 

### Technology for C O 2 

### Capture at Coal

- Fired Power Plants,” Power Plant Air Pollutant Control “Mega” Symposium, Baltimore, MD, August 2008

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### ,” IEA Greenhouse Gas R&D Programme, 2003

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